10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

ý	ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

Commission File Number: 0-692

NORTHWESTERN CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

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

Common Stock, $0.01 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large Accelerated Filer ý           Accelerated Filer o           Non-accelerated Filer o

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

The aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant was $1,103,000,000 computed using the last sales price of $30.96 per share of the registrant’s common stock on June 30, 2005, the last business day of the registrant’s most recently completed second fiscal quarter.

As of February 28, 2006, 35,567,721 shares of the registrant’s common stock, par value $0.01 per share, were outstanding.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Yes ý No o

Documents Incorporated by Reference

None

INDEX

		Page
	Part I	5
Item 1.	Business	5
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	29
Item 3.	Legal Proceedings	30
Item 4.	Submission of Matters to a Vote of Security Holders	33
	Part II	34
Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	66
Item 8.	Financial Statements and Supplementary Data	67
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	67
Item 9A.	Controls and Procedures	68
Item 9B.	Other Information	69
	Part III	70
Item 10.	Directors and Executive Officers of the Registrant	70
Item 11.	Executive Compensation	73
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	75
Item 13.	Certain Relationships and Related Transactions	77
Item 14.	Principal Accountants Fees and Services	77
	Part IV	78
Item 15.	Exhibits and Financial Statement Schedules	78
Signatures		84
Index to Financial Statements		F-1

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Annual Report on Form 10-K regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference herein relating to management’s current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

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

•  our ability to avoid or mitigate adverse rulings or judgments against us in our pending litigation arising from our bankruptcy proceeding, the formal investigation being conducted by the Securities and Exchange Commission (SEC), the City of Livonia class action and derivative action, and the Harbinger action contesting our shareholder rights plan;

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

•  our ability to fund and execute our business plan;

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

•  adverse changes in general economic and competitive conditions in our service territories; and

•  potential additional adverse federal, state, or local legislation or regulation or adverse determinations by regulators could have a material adverse effect on our liquidity, results of operations and financial condition.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is included in Item 1A of this Report.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. Although we believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable, any or all of the forward-looking statements in this Annual Report on Form 10-K, our reports on Forms 10-Q and 8-K, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions which turn out to be inaccurate or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Annual Report on Form 10-K, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results

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may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of a forward-looking statement in this Annual Report on Form 10-K or other public communications that we might make as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

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

Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Corporation,” “NorthWestern Energy” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries. “Predecessor Company” refers to us prior to emergence from bankruptcy (operations prior to October 31, 2004). “Successor Company” refers to us after emergence from bankruptcy (operations after November 1, 2004).

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Part I

ITEM 1.       BUSINESSES

OVERVIEW

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 628,500 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. On February 15, 2002, we acquired electricity and natural gas transmission and distribution assets and natural gas storage assets of the former Montana Power Company, which have been in operation since 1912.

Our utility operations are regulated primarily by the Montana Public Service Commission, or 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 operations;

•  unregulated electric operations;

•  regulated natural gas 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. 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.

REGULATED ELECTRIC 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, and includes approximately 723,000 people according to the 2004 census estimates. We also transmit electricity for nonregulated entities owning generation facilities, other utilities and power marketers in Montana. In 2005, by category, residential, commercial and industrial, and other sales accounted for approximately 35%, 52%, and 13% of our Montana electric utility revenue, respectively.

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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, 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 key assets 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 electricity generated from the 2,180 megawatt Colstrip generation facility 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.

We deliver electricity to approximately 316,000 customers in 187 communities and their surrounding rural areas in Montana, including Yellowstone National Park, five rural electric cooperatives in western Montana, six rural electric cooperatives in southern Montana, and four rural electric cooperatives in central Montana. Our Montana electric distribution system consists of approximately 20,300 miles of overhead and underground distribution lines and approximately 335 transmission and distribution substations

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 99,900 people according to the 2000 census. We provide retail electricity to more than 59,000 customers in 110 communities in South Dakota. In 2005, by category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 37%, 50%, 9% and 4% 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 3,200 miles of overhead and underground transmission and distribution lines across South Dakota as well as 120 substations. 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 larger 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

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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 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 1,614 megawatts, the average daily load was approximately 1,144 megawatts, and more than 8.8 million megawatt hours were supplied to choice and default supply customers during the year ended December 31, 2005. In our South Dakota service territory, peak demand was approximately 296 megawatts, the average daily load was approximately 145 megawatts, and more than 1.3 million megawatt hours were supplied during the year ended December 31, 2005.

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 entered into under the Public Utility Regulatory Policies Act of 1978, which provide a total of 101 megawatts of winter peak capacity. We have additional contracts for 135 megawatts of wind generation, 50 megawatts of gas-fired generation and 5 megawatts of seasonal baseload hydro supply. These purchases account for approximately 74% of our customer load requirements on average. The remaining customer load requirements are met with market purchases. In addition, we have entered into short-term fixed price energy purchases to fulfill the default obligation and provide rate stability. In December 2005, we filed with the MPSC our second biennial Electric Default Supply Resource Procurement Plan. This Plan focuses on the resource options and strategies to replace approximately 55 percent of the supply contracts that are expiring on June 30, 2007. For more information about our obligations as a result of deregulation in Montana during the statutory transition period, see “Utility Regulation—Montana.”

In July 2004, we issued a Montana electric default supply request for proposal (RFP) for baseload, dispatchable, wind and other electric supply resources. Two resources were selected for contract negotiation. On February 7, 2005, we filed an advanced approval filing for a 20-year contract to purchase up to 150 megawatts from the Judith Gap wind generation project. As part of the 2004 RFP, our Colstrip Unit 4 division

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submitted an offer to supply 90 megawatts of unit contingent, baseload energy for a term of 11.5 years, commencing on July 1, 2007,  to default supply. The offer contemplates using the power available under our arrangement with Duke Energy Trading and Marketing (Duke) to repurchase 111 megawatts of power through December 2010; thereafter, the power is expected to come from currently uncommitted energy from Colstrip Unit 4. This repurchase arrangement was part of Amendment #2 to the Duke Power Purchase Agreement, a FERC jurisdictional power sales contract, which was negotiated during our bankruptcy proceeding and approved by the Bankruptcy Court on February 23, 2004. This offer was a result of our commitment to offer a portion of the Duke power to default supply in order to resolve intervention by the MPSC and MCC regarding Bankruptcy Court approval of the Duke amendment. The offer has not been formally approved by the MPSC. Further procurement activities will continue, focusing on replacement of significant baseload contracts that expire in June 2007.

The MPSC approved energy supply resources, along with open market and other purchases, are being recovered through an electricity cost tracking process pursuant to which rates are adjusted on a monthly basis for electricity loads and electricity costs for the upcoming twelve month period. On an annual basis rates are adjusted by the MPSC to include any differences in the previous tracking year’s actual to estimated information, for recovery in the subsequent tracking year. 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 the prudency of our energy supply procurement activities as part of the annual tracking filing.

 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 eight 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 2005, approximately 15% of the power was sold in the wholesale market. Our facilities had a total net summer peaking capacity in 2005 of approximately 310 megawatts.

Name and Location of Plant	Fuel Source	Our Ownership Interest		Our Share of 2005 Peak Summer Demonstrated Capacity	% of Total 2005 Peak Summer Demonstrated Capacity
Big Stone Plant, located near Big Stone City in northeastern South Dakota	Sub-bituminous coal	23.4	%	106.41 megawatts	34.4	%
Coyote I Electric Generating Station, located near Beulah, North Dakota	Lignite coal	10.0	%	42.70 megawatts	13.8	%
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	%	104.46 megawatts	33.8	%
Total Capacity				309.48 megawatts	100.0	%

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We have agreements with MidAmerican Energy Company (MidAmerican) to supply firm capacity during the summer months as follows during the years 2006-2009: 40 megawatts in 2006; 40 megawatts in 2007; 43 megawatts in 2008; and 46 megawatts in 2009. During 2005, MidAmerican provided 36 megawatts of firm capacity during the summer months. In addition, we are a member of the Midcontinent Area Power Pool (MAPP), 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 MAPP,  agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The 2005 peak demand in our South Dakota service areas was approximately 296 megawatts, and the 2005 average daily load in South Dakota was approximately 145 megawatts. The 2005 MAPP accredited capacity was approximately 301 megawatts. We believe we have adequate supplies through our share of generation from jointly owned plants, existing supply contracts, MAPP power swap availability, and capacity for sale in the current market to meet our power supply needs through the remainder of the decade.

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.

Electric Generation Costs

Coal was used to generate approximately 99% of the electricity utilized for South Dakota operations for the year ended December 31, 2005. 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 2005 Megawatt
Fuel Type	2005		2004		2003		Hours Generated
Sub-bituminous-Big Stone	$	1.43	$	1.47	$	1.34	49.75	%
Lignite-Coyote*	.85		.77		.79		21.88
Sub-bituminous-Neal	.90		.90		.77		28.35
Natural Gas	8.49		6.29		6.68		0.01
Oil	7.52		7.64		2.04		0.01

*       Includes pollution control reagent.

During the year ended December 31, 2005, the average delivered cost per ton of fuel burned for our base-load plants was $24.97 at Big Stone, $12.20 at Coyote and $14.28 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.”

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.

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The South Dakota Department of Environment and Natural Resources has given approval for Big Stone to burn a variety of alternative fuels, including tire-derived fuel and refuse-derived fuel. In 2005, approximately 1.4% 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 2005, our costs for services under this contract totaled approximately $4.0 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 740 megawatt demonstrated-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 was necessary to enable us to fulfill our 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. As a result  of the Colstrip 4 lease extension, we will have approximately 132 megawatts of uncommitted baseload 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. We are also assessing our option to buy out our Colstrip Unit 4 operating lease, which would give us a 30% undivided interest in the generation facility.

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 and to Puget Sound Energy under agreements expiring December 20, 2010. We also have a separate agreement to repurchase 111 megawatts through December 2010, which are available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 megawatts have been offered to supply a portion of the Montana default supply load. On January 23, 2004, during the period we operated under Chapter 11 protection, we amended our contract with Duke, which modified the pricing terms of the power sales arrangement to our benefit. In December 2005, we consented to the novation of the Duke contract, wherein DB Energy Trading LLC, a wholly owned subsidiary of Deutsche Bank AG, will replace Duke as the contracting party under the Duke contract. The novation transaction involving Duke and DB Energy Trading LLC was approved by the FERC in January 2006. As a result of this novation, we expect to improve our counter party credit terms.

Our unregulated electric operations also include the operations of the Milltown Dam, a 3.2 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, Clark Fork and Blackfoot, LLC (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. Pursuant to the terms of the settlement set forth in the Milltown Reservoir

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Superfund consent decree, generation from the Milltown Dam will cease upon the effective date of the consent decree, which is anticipated to occur during the second quarter of 2006.

REGULATED NATURAL GAS OPERATIONS

Services, Service Areas and Customers

Our regulated natural gas utility operations purchase, transport, distribute and store natural gas for approximately 253,500 commercial and residential customers in Montana, South Dakota and Nebraska. Natural gas service generally includes transportation, storage and distribution, 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 170,000 customers located in 105 Montana communities. 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 six years, eighteen of our municipal franchises, which accounts for approximately 77,000 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 30,000 customers. Our natural gas distribution system consists of approximately 3,700 miles of underground distribution pipelines. 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 37.6 billion cubic feet in the year ended December 31, 2005. Our peak capacity was approximately 300 million cubic feet per day during the year ended December 31, 2005. Our Montana natural gas transmission system consists of more than 2,000 miles of pipeline, which vary in diameter from two inches to 20 inches, and serve more than 130 city gate stations. 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, 2005. 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 0.02 million cubic feet per day with approximately 60 million cubic feet of remaining reserves as of December 31, 2005.

South Dakota and Nebraska

We provide natural gas to approximately 83,500 customers in 59 South Dakota communities and four Nebraska communities. 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, three of our South Dakota and Nebraska municipal franchises, which account for approximately 41,500 customers, are scheduled to expire. In addition, our franchise in Kearney, Nebraska expired during 2003 and we have been pursuing a new franchise agreement while continuing to provide service. The City Council of Kearney, however, has approved an indefinite extension of our current franchise right until completion of the new franchise ordinance. 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, 2005. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska, and in

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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 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 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 5.85 million MMBTU of third-party transportation volume on our South Dakota distribution system and approximately 1.86 million MMBTU of third-party transportation volume on our Nebraska distribution system during 2005.

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.

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.

Regulated 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, 2005, were approximately 19.7 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, 2005, 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.

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Our Nebraska natural gas supply requirements for the year ended December 31, 2005, 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), provides gas supply and gas management services, including pipeline balancing and capacity services, to 93 large volume customers in eastern South Dakota. In addition, NSC also provides gas distribution service to 7 large volume customers in eastern South Dakota through its subsidiary, Nekota Resources, Inc., which owns and operates 88 miles of intrastate natural gas pipeline. In total, NSC transported 15.4 million MMBTU of natural gas in 2005.

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 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 significant market price fluctuations.

Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts and short-term market purchases, which were approximately 13 million MMBTU for the year ended December 31, 2005. We have contracted with various suppliers to manage transportation, and procurement of supply in order to minimize cost and price volatility to our customers. To limit cost exposure related to gas supply, and as we receive little to no margin on supply costs, certain customers have been encouraged to contract directly with other providers for their supply needs.

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 for cooling and heating, respectively. 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, these weather patterns could adversely affect our results of operations and financial condition.

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.

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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, incurrence of certain long-term debt, 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, and quarterly filings of certain financial information on the FERC Form No. 3-Q, Quarterly Financial Report of Electric Companies, Licensees, and Natural Gas Companies.

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. The OATTs in our filings 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.

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.

We are participating with other transmission owners in the Pacific Northwest in the pursuit of independent regional transmission management. The independent entity, currently 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)

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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 are not participating in the MISO markets that began operation on April 1, 2005, but continue to utilize WAPA to handle our scheduling requirements. We have negotiated a settlement as a grandfathered 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. We are working with the other non-MISO MAPP members in developing an Independent Transmission Services Coordinator.

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, 2003B, and 2003C, 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 Order No. 2003 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.

As a complement to its Order No. 2003 and related clarifying orders, on June 2, 2005, FERC issued Order No. 661 related to interconnection of wind generation. Order No. 661 includes certain technical requirements that transmission owners must apply to interconnection service for wind generating plants and establishes certain conditions that wind generators greater than 20 MW must meet. These requirements and conditions must be applied in addition to the standard interconnection procedures adopted in Order No. 2003. FERC claims its rule will remedy undue discrimination by providing fair terms for interconnection of wind plants larger than 20 MW in capacity. As with Order No. 2003, the impact this order will have on our earnings, revenues or prices will depend on the number of new wind 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 adopted standards of conduct that apply uniformly to interstate gas pipelines and public utilities (jointly referred to as Transmission Providers) that are subject to the gas and electric standards of conduct in Part 161 and Part 37 of FERC’s regulations, respectively. The standards of conduct govern the relationship between regulated Transmission Providers and their Energy 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

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additional information and the FERC still 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 Order No. 2004.

It is possible that compliance with Order No. 2004 may require some level of reorganization of our operations. Although we cannot predict 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.

We are in the process of conducting an “Open Season” for the development of new electric transmission capacity from Montana to Idaho. Although still early in the development stages, potential customers have made transmission service requests for 975 MW of capacity in the project. These requests can be revoked at any time by the customer up to the point of an executed service agreement between NorthWestern Energy and the customer. The customer(s) is responsible for the costs of development through defined FERC Tariff procedures. If successful, the process could lead to a significant transmission project for the movement of energy from Montana to the south or vice versa and would be the first large-scale bulk transmission project in our control area in nearly twenty years. Customers would be expected to provide funding for part or all of the transmission facility, however, rate mechanisms, allocation of costs, and other financial impacts cannot be predicted at this time.

Our subsidiary, CFB operates the Milltown Dam, a 3.2 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 has filed an application to extend that license until 2010. On July 18, 2005, CFB and we executed the Milltown Reservoir superfund site consent decree. The Department of Justice filed a motion to enter the consent decree with the United States District Court for the District of Montana, Butte Division, on January 4, 2006. The consent decree was approved by the court on February 8, 2006 and becomes effective in 60 days if no appeals are filed. CFB’s FERC operating license will be surrendered as of the effective date of the consent decree. Upon surrender of its FERC operating license, CFB will cease all generation activity at the Milltown Dam, see “Environmental — Milltown Mining Waste”.

One of the principal legislative initiatives of the current administration is the adoption of comprehensive federal energy legislation. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (2005 Act). The 2005 Act includes a wide range of provisions addressing many aspects of the energy industry. Specifically, with respect to the electric utility industry, the 2005 Act includes provisions which, among other things, repeals the Public Utility Holding Company Act of 1935 (PUHCA) as of February 8, 2006, creates incentives for the construction of transmission infrastructure, eliminates the statutory restrictions on ownership of qualifying facilities by electric utilities, and expands the authority of the FERC to include overseeing the reliability of the bulk power system. While we continue to monitor the impact of this new federal legislation, we cannot predict the impact of the 2005 Act on our operations at this time.

Montana

Our Montana operations are subject to the jurisdiction of the MPSC with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our 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 our Electric, Natural Gas, and Propane Utilities. A bankruptcy stipulation and agreement between the MPSC, MCC and us requires us to file a Montana electric and natural gas informational rate filing by September 30, 2006.

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 2029, with certain “qualifying facilities” as established under the Public Utility Regulatory Policies Act of 1978.

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On January 31, 2002, the MPSC approved a stipulation, 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 $1.6 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, 2005, the liability was $140.5 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 provide assurance that our actions will be successful.

Montana’s Electric Utility Restructuring Act (Montana 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. 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, our initial default supply portfolio, containing a mix of long and short-term contracts from new and existing power suppliers and generators was filed with the MPSC. On April 25, 2002, the MPSC approved the 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, we filed with the MPSC our first biennial 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 were 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 in the Electric Supply section, on February 7, 2005, we made a filing with the MPSC, seeking advanced approval of a substantial wind contract based upon offers received during our July 2004 RFP process. The MPSC granted preapproval for this project in the spring of 2005. We began receiving wind generated electricity in November 2005. In December 2005, we filed with the MPSC our second biennial Electric Default Supply Resource Procurement Plan. This Plan focuses on the resource options and strategies to replace approximately 55 percent of the supply contracts that are expiring on June 30, 2007.

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 December 16, 2005, a final order was issued by the MPSC approving recovery of electric supply costs for the 24-month period ended June 30, 2004.

On September 30, 2005, we filed our revised annual electric supply cost tracker request with the MSPC for the 12-month period ended June 30, 2005, and for projected costs for the 12-month period ended June 30, 2006. On October 14, 2005, an interim order was approved by the MPSC for the projected electric supply cost.

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For further discussion of supply related risks, see “Risk Factors—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” included in Item 1A hereof.

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 November 2, 2005, a final order was issued by the MPSC for $0.4 million, allowing about 60% of the originally estimated increase in state and local taxes and fees for 2005. On December 2, 2005, we filed with the MPSC for an automatic rate adjustment of $13.0 million, which reflected 100% of the under recovery of 2005 actual state and local taxes and fees and estimated state and local taxes and fees for 2006. In February 2006, the MPSC issued an order allowing recovery of approximately $5.6 million, which represents 60% of the 2005 actual increase and approximately 25% of the 2006 estimated increase. We are disputing the reduction by the MPSC and have filed a Petition for Judicial Review in Montana District Court regarding the 2005 order.

South Dakota

We are subject to SDPUC jurisdiction with respect to rates, terms and conditions of service, accounting records, electric service territorial issues 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 upon filing, and is deemed approved within 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.

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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. 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. On July 3, 2003, the MPSC issued orders disallowing the recovery of certain gas supply costs of $6.2 million for the July 2002 — June 2003 tracker year and $4.6 million for the July 2003 — June 2004 tracker year. The MPSC also rejected a motion for reconsideration filed by us on July 14, 2003. We filed suit in Montana District court on July 28, 2003, seeking to overturn the MSPC’s decision to disallow recovery of these costs. The MPSC has approved a stipulation between us and the Montana Consumer Counsel regarding the recovery of natural gas costs for the 2003 and 2004 tracking years. With this stipulation as a foundation, we have settled with the MPSC and have been allowed recovery of previously disallowed gas costs of $4.6 million. As a result of the settlement, we recorded gas supply revenue of $4.6 million in the second quarter of 2005. Also, as part of this settlement, on June 15, 2005, we filed a proposed set of Natural Gas Procurement Rules (Rules) with the MPSC laying out a framework for future natural gas procurement. On January 13, 2006, the MPSC issued an interim order authorizing a tariff containing the draft Rules in the form of guidelines. We are proceeding to prepare and file the initial natural gas procurement plan required under the Interim Tariff.

On August 23, 2005, we filed a revised annual gas cost tracker request with the MPSC for any unrecovered actual gas costs for the 12-month period ended June 30, 2005, and for the projected gas costs for the 12-month period ending June 30, 2006. On September 2, 2005, the MSPC issued an interim order with respect to our recovery of gas costs.

On November 17, 2004, we filed with the MPSC for an automatic rate adjustment of $0.1 million under a Montana statute allowing the recovery of increased state and local taxes and fees. On November 3, 2005, a final order was issued by the MPSC allowing only about 60% of the originally estimated increase in state and local taxes and fees for 2005. On December 2, 2005, we filed with the MPSC for an automatic rate adjustment of $5.2 million, which reflected 100% of the under recovery of 2005 actual and 2006 estimated state and local taxes and fees. In February 2006, the MPSC issued an order allowing recovery of approximately $2.7 million, which represents 60% of the 2005 actual increase and approximately 44% of the 2006 estimated increase. We are disputing the reduction by the MPSC and have filed a Petition for Judicial Review in Montana District Court regarding the 2005 order.

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. The adjustment goes into effect upon filing, and is deemed approved within 10 days after the information filing unless the SDPUC staff requests changes during that period.

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

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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, 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.

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ENVIRONMENTAL

We 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 2005. 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.

Air Emissions

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. These proposals, like all legislative actions, are subject to the normal legislative processes, and we cannot make any prediction about whether the proposals will pass, or the final terms of these or any other actions if they were to pass. EPA supports the legislative proposal to adopt “Clear Skies” and has already proposed several regulatory actions which will impact our operations regardless of Congressional action. Included in these actions is the EPA’s issuance, in March 2005, of the Clean Air Interstate Rule, which permanently caps emissions of sulfur dioxide and nitrogen oxide and provides for tradeable allowances in the eastern United States, including Iowa. Also, in March 2005, the EPA issued the Clean Air Mercury Rule, which requires coal-fired power plants to reduce their emissions of mercury. It is possible that additional EPA actions in the future could impact our operations.

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, including the Colstrip power plants, of which we continue to lease a 30% interest in Unit #4. The Section 114 information

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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, and there can be no assurance that we could recover such costs.

Manufactured Gas Plants

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.

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 be necessary at the Aberdeen site, commencing in 2006. Our current reserve for remediation costs at the Aberdeen site is approximately $14.4 million, and we estimate that approximately $13.1 million of this amount will be incurred during the next five years. At present, we cannot estimate with a reasonable degree of certainty the timing of remediation cleanup at other South Dakota sites.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas plants 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 (TBA) Program. During 2005, the NDEQ conducted Phase 2 investigations of soil and groundwater at these two locations using funding provided by the TBA Program. At present, we do not have Phase 2 investigation reports from NDEQ for either location and therefore cannot determine with a reasonable degree of certainty the timing of any remediation cleanup at our Nebraska locations.

In addition, we also own sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An 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 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 conducted additional groundwater monitoring during 2005 at the Butte and Missoula sites and, at this time, we believe that natural attenuation should address the problems at these sites. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may be necessary to prevent certain contaminants from migrating offsite. We are currently evaluating the results of a pilot program meant to promote aerobic degradation of certain targeted contaminants. During 2006, we will complete our evaluation of the pilot program and also evaluate other alternatives including monitored natural attenuation. In light of these activities, 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 the timing of additional remediation at the Helena site.

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Milltown Mining Waste

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three 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 pre-Record of Decision 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. 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 resolved both our liability with Atlantic Richfield in general accordance with the previously negotiated settlement agreement and established 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. As of December 31, 2005, we have fully funded the State of Montana escrow account in the amount of $2.5 million and have funded the Atlantic Richfield account in the amount of $6.0 million.

On July 18, 2005, CFB and we executed the Milltown Reservoir superfund site consent decree. After completion of the public comment period and formulation of EPA responses to the filed public concerns, the Department of Justice, on behalf of the EPA, filed a motion to enter the consent decree with the United States District Court for the District of Montana, on January 4, 2006. The consent decree was approved by the court on February 8, 2006 and becomes effective in 60 days if no appeals are filed. In light of the material environmental risks associated with the catastrophic failure of the Milltown Dam, 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. We are obligated under the settlement to continue to maintain the environmental insurance policy until the Milltown Dam is removed during implementation of the remedy.

Other

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. Under the terms of the settlement agreement between PPL Montana and us dated September 13, 2005, we no longer have any environmental indemnification obligation to PPL Montana for the contamination existing at this site.

We continue to manage polychlorinated biphenyl (PCB)-containing oil and equipment in accordance with the EPA’s Toxic Substance Control Act 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. We have other sites in Montana and South Dakota for which we expect to incur residual cleanup costs, however we do not expect these costs to be material.

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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. As of December 31, 2005, we have a reserve of approximately $44.6 million to cover all estimated environmental liabilities. We anticipate that as environmental costs become fixed and reliably determinable we will seek insurance coverage and/or rate recovery, and therefore do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

We routinely engage the services of a third-party environmental consulting firm to perform a comprehensive evaluation of our environmental reserve. 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 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.

EMPLOYEES

As of December 31, 2005, we had 1,353 employees. Of these, 1,029 employees were in Montana and 324 were in South Dakota or Nebraska. Of our Montana employees, 414 were covered by six collective bargaining agreements involving five unions. In addition, our South Dakota and Nebraska operations had 191 employees covered by the System Council U-26 of the IBEW. This IBEW contract in South Dakota expired on December 31, 2005. We have negotiated the contract, which has been submitted to the union membership for ratification. There is no assurance that the contract will be ratified, although we believe this to be the case. We consider our relations with employees to be in good standing.

ITEM 1A.    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.

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

We have incurred and will continue to incur significant costs associated with outstanding litigation. These costs, which are being expensed as incurred, are expected to have an adverse affect on our results of operations and cash flows. Although our Plan of Reorganization (Plan) 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 appeals and certain pending litigation. Pending litigation includes significant matters such as Magten/Law Debenture and McGreevey, as well as various other matters, which are discussed in detail under Item 3, Legal Proceedings. An adverse result in any of these litigated matters could have an adverse effect on our business.

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

Under our Plan, holders of certain claims received distributions of shares of our common stock. Harbinger Capital Partners Master Fund I, Ltd. f/k/a Harbert Distressed Investment Master Fund Ltd. (Harbinger) is affiliated with or manages funds, which based on the most recent information made available to us, collectively received more than 20% of our new common stock. Harbinger 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 90% of our new common stock. Other than Harbinger, however, we are not aware of any entity that owns or controls 10% or more of our common stock distributed upon emergence pursuant to our Plan.

On December 5, 2005, we adopted a shareholders’ rights plan in order to protect NorthWestern against coercive actions by third parties that could be detrimental to the best interests of all the shareholders and to permit the Board of Directors to review and evaluate its strategic alternatives in an orderly fashion. Under the rights plan, preferred stock purchase rights will be distributed as a dividend at the rate of one right for each share of common stock of NorthWestern held by shareholders of record as of the close of business on December 15, 2005. The rights will expire on December 5, 2015. The rights generally will be exercisable only if a person or group acquires beneficial ownership of 15% or more of our common stock. A person or group who beneficially owns 15% or more of the outstanding shares of our common stock prior to the adoption of the rights plan will not cause the rights to become exercisable upon adoption of the rights plan. As a result, the rights will not be triggered even though Harbinger beneficially owned approximately 20% of the outstanding shares of our common stock prior to the adoption of the rights plan. However, Harbinger will cause the rights to become exercisable if it (subject to certain exceptions) becomes the beneficial owner of additional shares of our common stock or its beneficial ownership decreases below 15% and subsequently, increases to 15% or more.

If any holders of a significant number of the shares of our common stock were to act as a group, then such holders could cause the rights to become exercisable. If the rights plan could not be enforced as a result of an adverse decision by the federal District Court in the City of Livonia lawsuit or by the Court of Chancery in the Harbinger lawsuit, 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 shareholder approval, such as an amendment to our articles 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.

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, 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 and informal requests from the SEC requesting documents and testimony from former and current employees as well as third parties regarding these matters. In January 2006, the SEC issued several Wells notices to individuals formerly associated with a now-defunct subsidiary. There have been no findings or adjudication of the underlying allegations in the Wells notices, and the SEC’s investigation is ongoing and it could issue additional Wells notices. In addition, certain of our former directors and several former and current employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the Federal Bureau of Investigation (FBI) and Internal Revenue Service (IRS) concerning certain of the allegations made in the now resolved class action securities and derivative litigation as well as

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other matters. We have not been advised that NorthWestern is the subject of any FBI or IRS investigation. We are not aware of any other governmental inquiry or investigation related to these matters. We are fully cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are requested to do so 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, as a result of a ruling by the Bankruptcy Court, the SEC may not be able to pursue civil sanctions, including, but not limited to, monetary penalties against NorthWestern. The SEC has not appealed such order. The SEC could, however, pursue other remedies and penalties against NorthWestern.

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 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, then 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 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 review the regulated utility’s books and records, which could result in rate changes and have a material adverse effect on our results of operations and financial condition.

Competition for various aspects of electric and natural gas services has been 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 could 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, additional competitors could become active in the generation, transmission and distribution segments of our industry.

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

Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking 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. During the fourth quarter of 2005, the Montana Consumer Counsel submitted testimony alleging we were imprudent and recommending the MPSC consider disallowing portions of our electric and natural gas supply costs for the 2005 and 2006 tracker years. We cannot predict how the MPSC will act on these recommendations and to the extent our energy supply costs are deemed imprudent by the MPSC or other applicable state regulatory commissions, we would under-recover our costs, which could adversely impact our results of operations.

We do not own any natural gas reserves or regulated 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/or electricity supply

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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 obligation to supply a minimum annual quantity of qualifying facility (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 high commodity prices.

We perform management of the QF portfolio of resources under the terms and conditions of the QF Tier II Stipulation. This Stipulation, may subject us to commodity price risk if the QF portfolio does not perform in a manner to meet the annual minimum energy requirement.

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. The annual minimum energy requirement is achievable under normal operations, including normal periods of planned and forced outages. Furthermore, we will not realize commodity price risk, unless any required replacement energy cost is in excess of the total amount recovered under the QF contracts, which is currently approximately $65.00 per MWH for base-load energy.

However, to the extent the supplied QF power for any year does 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. A recent stipulation with the MCC addresses how any energy shortfall will be managed and further restricts some of our ability to protect against such events.

The value of our Colstrip Unit 4 leasehold improvements could be impaired if we are unable to obtain adequate terms on 132 megawatts of power that are not under contract after 2010.

During the course of our bankruptcy reorganization proceedings, we offered to provide 90 megawatts of baseload energy from Colstrip 4 into the Montana default supply for a term of 11.5 years, commencing on July 1, 2007, at an average nominal price of $35.80 per megawatt hour. This offer was made as part of a negotiated process with the MPSC and the MCC to settle their intervention in opposition to our request that the Bankruptcy Court approve our contract amendment with Duke and was below prevailing market prices. We expect that the sale of the 132 megawatts of our remaining output, which is not under contract after 2010, will be sufficient to allow us to recover the carrying value of our Colstrip Unit 4 leasehold improvements. If we are unable to sell the 132 megawatts at such a sufficient price, the value of our Colstrip Unit 4 leasehold improvements would be materially adversely impacted.

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, then 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.

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,

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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.

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

Our utility business is subject to extensive laws and regulations imposed by federal, state and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and 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 the timing of 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, upgrade or expansion 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 $29.5 million to $66.2 million. We had an environmental reserve of $44.6 million at December 31, 2005. 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 new regulations, 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 were not extinguished pursuant to our Plan. 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.

Our non-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 and liquidity.

Upon emergence from bankruptcy, we were assigned a non-investment grade credit rating. Our current non-investment grade ratings have impacted our borrowing costs. While we have obtained favorable credit terms with many of our suppliers, we cannot be assured these suppliers will continue to allow such terms if we

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do not achieve an investment grade rating. A reduction in credit terms could adversely affect our liquidity. We also began payment of quarterly dividends on our common stock in the first quarter of 2005, which 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.

Our ability to access the capital markets is dependent on our ability to obtain certain regulatory approvals and constrained by 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, prior to our obtaining investment grade ratings, specific debt convents restrict our ability to borrow above a 60% debt to capital threshold without further lender approval.

We may receive, respond to and not pursue, as appropriate, unsolicited indications of interest, proposals or offers to acquire us or some or all of our assets, and if not pursued, our shareholders may not be able to obtain a premium for their shares of common stock offered in the proposed transaction.

We have in the past received and may receive in the future unsolicited indications of interest, proposals or offers to acquire us or some or all of our assets or our outstanding stock. We have begun a process of evaluating strategic alternatives with a view to maximizing long-term shareholder value. As we have stated on prior occasions, as a public company we may receive such indications of interest, proposals or offers, and if we do, our Board of Directors will evaluate them to consider the best interests of all shareholders and respond as appropriate. There can be no assurance that we will pursue any such indication of interest, proposal or offer, and our Board of Directors reserves the right not to pursue any offer to acquire us, or any of our assets. As a consequence of any decision not to pursue an acquisition of us, our shareholders would not be able to sell or exchange their shares of common stock at any premium offered by the prospective buyer in the proposed transaction.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None

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, 2007.

Our principal 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 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.

For further information regarding our operating properties, including generation and transmission, see the descriptions included in Item 1.

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ITEM 3.       LEGAL PROCEEDINGS

Magten/Law Debenture/QUIPS Litigation

On April 16, 2004, Magten Asset Management Corporation (Magten) and Law Debenture Trust Company (Law Debenture) initiated an adversary proceeding, which we refer to as the QUIPs Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets and liabilities 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. As a result of filing the appeal of the confirmation order, the Bankruptcy Court has stayed the prosecution of this case until the appeal is finally decided. On September 22, 2005, the Delaware District Court withdrew the reference of this action to the Bankruptcy Court and will now hear this lawsuit. The parties will now prepare for trial of this lawsuit.

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. That lawsuit has now been transferred to the Federal District Court in Delaware. The parties will now prepare for trial of this lawsuit.

On October 19, 2004, the Bankruptcy Court entered a written order confirming our Plan. On October 25, 2004, 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’s efforts to obtain a stay of the enforcement of the confirmation order to prevent our Plan from becoming effective were denied by the Bankruptcy Court on October 25, 2004 and by the United States District Court for the District of Delaware on October 29, 2004. With no stay imposed, our Plan became effective November 1, 2004. On October 26, 2004, Magten filed a notice of appeal of the Bankruptcy Court’s approval of the memorandum of understanding (MOU), which memorialized the settlement of the consolidated securities class actions and consolidated derivative litigation against NorthWestern and others. In March 2005, we moved to dismiss Magten’s appeal of the confirmation order on equitable mootness grounds. Magten’s appeals of the confirmation order and the order approving the MOU have been consolidated before the Delaware District Court. While we cannot currently predict the impact or resolution of Magten’s appeal of the confirmation order or the MOU, we intend to vigorously defend against the appeals.

On February 9, 2005, we agreed to settlement terms with Magten and Law Debenture to release all claims, including Magten’s and Law Debenture’s fraudulent conveyance action pending against NorthWestern 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. On March 10, 2005, the Bankruptcy Court entered an order denying the motion filed by Magten and Law Debenture. Magten and Law Debenture have appealed that order. This appeal has been docketed with the District Court, briefing has been completed, and we are awaiting a decision of the District Court. On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern Corporation, Gary Drook, Michael Hanson, Brian Bird, Thomas Knapp and Roger Schrum alleging that NorthWestern and the former and current officers committed fraud by failing to include a sufficient amount of shares in the Class 9 reserve set aside for payment of unsecured claims and thus the confirmation order should be revoked and set

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aside. We filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of the confirmation order appeal. The Federal District Court withdrew the reference, will now hear the lawsuit, and we intend to vigorously defend against the lawsuit.

Twice during 2005, Magten, Law Debenture, the Plan Committee and NorthWestern unsuccessfully engaged in mediation to resolve the pending appeals and other pending litigation described above. At this time, we cannot predict the impact or resolution of any of these lawsuits, appeals or reasonably estimate a range of possible loss, which could be material. We intend to vigorously defend against the adversary proceedings, lawsuits, appeals 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 Class 9 disputed claims reserve established under the Plan. We cannot currently predict the impact or resolution of this litigation.

McGreevey Litigation

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 The Montana Power L.L.C., 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. that temporarily stayed the litigation, as against NorthWestern, CFB, The Montana Power Company, The Montana Power L.L.C. and Jack Haffey. As a result of the confirmation of our Plan, the stay has been made permanent. On July 10, 2004, we and the other insured parties 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. There are various issues preventing a consensus on a global settlement and the Federal District Court has now stayed the case pending resolution of bankruptcy issues in the Touch America and NorthWestern bankruptcy cases. In the event the parties do not reach a global settlement agreement, a settlement is not approved or it does not take effect for any other reason, we intend to vigorously defend against this lawsuit. If we are unsuccessful in defending against this class action lawsuit, the plaintiffs’ litigation claims are channeled to the Directors & Officers Trust established under our Plan, or alternatively would be treated as securities, or Class 14, claims and would be entitled to no recovery 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 are not material to our operations or financial position.

On August 9, 2005, McGreevey plaintiffs filed an action in Montana state court claiming that our transfer of certain assets to CFB was a fraudulent transfer. (The plaintiffs received approval in our bankruptcy case to initiate a similar fraudulent conveyance action as an adversary proceeding in our bankruptcy case, which they

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did not do. Under the terms of the settlement with the plaintiffs in the McGreevey case discussed above, they would not file such proceeding.) We have removed the action to the federal court in Montana and filed a motion to transfer the action to the Bankruptcy Court in Delaware. We also filed an adversary action in our Bankruptcy Case seeking injunctive relief against the McGreevey plaintiffs to stop them from pursuing their fraudulent conveyance action outside our bankruptcy case. McGreevey plaintiffs answered the adversary complaint and asserted counterclaims against us alleging the same fraudulent conveyance claims. McGreevey plaintiffs also filed a motion to remand the fraudulent conveyance action to state court in Montana and the same motion to certify certain issues to the Montana Supreme Court. On October 25, 2005 the Bankruptcy Court preliminarily enjoined the plaintiffs from further prosecuting their claim. The McGreevey plaintiffs have asked for leave to appeal this order and we have asked the Bankruptcy Court to deny the request. We cannot currently predict the impact or resolution of this litigation.

Other Litigation

In April 2005, a group of former employees of the Montana Power Company filed a lawsuit in the state court of Montana against us and certain officers styled Ammondson, et al. v. NorthWestern Corporation, et al., Case No. DV-05-97. The former employees have alleged that by moving to terminate their supplemental retirement contracts in our bankruptcy proceeding without having listed them as claimants or giving them notice of the disclosure statement and Plan, that we breached those contracts, and breached a covenant of good faith and fair dealing under Montana law and by virtue of filing a complaint in our Bankruptcy Case against those employees from seeking to prosecute their state court action against NorthWestern, we had engaged in malicious prosecution and should be subject to punitive damages. On May 4, 2005, the Bankruptcy Court found that it did not have jurisdiction over these contracts, dismissed our action against these former employees, and transferred our motion to terminate the contracts to Montana state court where the former employees’ lawsuit is pending. We unsuccessfully engaged in mediation of this dispute in November 2005. We recorded a loss of $2.6 million in the third quarter of 2005 to reestablish a liability for the present value of amounts due to these former employees under their supplemental retirement contracts and we have reestablished monthly payments to these former employees under the terms of their contracts. We intend to vigorously defend against this lawsuit, however we cannot currently predict the ultimate impact of this litigation.

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 and informal requests from the SEC requesting documents and testimony from former and current employees as well as third parties regarding these matters. In January 2006, the SEC issued several Wells notices to individuals formerly associated with a now-defunct subsidiary. There have been no findings or adjudication of the underlying allegations in the Wells notices, and the SEC’s investigation is ongoing and it could issue additional Wells notices. In addition, certain of our former directors and several former and current employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the FBI and IRS concerning certain of the allegations made in the now resolved class action securities and derivative litigation as well as other matters. We have not been advised that NorthWestern is the subject of any FBI or IRS investigation. We are not aware of any other governmental inquiry or investigation related to these matters. We are fully cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are requested to do so 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, as a result of a ruling by the Bankruptcy Court, the SEC may not be able to pursue civil sanctions, including, but not limited to, monetary penalties against NorthWestern. The SEC has not appealed such order. The SEC could, however, pursue other remedies and penalties against NorthWestern.

In November 2005, we and our directors were named as defendants in a shareholder class action and derivative action entitled City of Livonia Employee Retirement System v. Draper, et al., pending in the U.S. District Court for the District of South Dakota. The plaintiff claims, among other things, that the directors breached their fiduciary duties by not sufficiently negotiating with Montana Public Power Inc. and Black Hills Corporation, two entities that had made public, unsolicited offers to purchase NorthWestern. After the Board of Directors adopted our shareholders’ rights plan on December 5, 2005, this plaintiff also sought a temporary restraining order and preliminary injunction to prevent the implementation of the rights plan or any other defensive measures. On December 16, 2005, the Federal District Court denied the plaintiff’s application. The Federal District Court has scheduled a trial on plaintiffs’ request for a permanent injunction against the rights plan and other measures, which will commence on March 21, 2006.. We intend to vigorously defend against the plainitffs’ claims; however, we cannot currently predict the ultimate impact of this litigation.

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In February 2006, we and our directors were named as defendants in an action entitled Harbinger Capital Partners Master Fund I, LTD v. Hanson, et al., pending in the Delaware Court of Chancery for Newcastle County. The plaintiffs sought a preliminary and permanent injunction finding that the application of the beneficial ownership provisions of the shareholders’ rights plan may not prevent plaintiff from seeking to build a coalition slate with other shareholders or circulate a referendum to shareholders. On February 22, 2006, the Delaware Court of Chancery denied plaintiff’s request for expedited proceedings on their preliminary injunction motion, ruling that it would await rulings on the issue by the federal court in South Dakota. The court has not set a schedule in this action. We intend to vigorously defend against the plaintiff’s claims; however, we cannot currently predict the ultimate outcome of this litigation.

Relative to Colstrip Unit 4’s long-term coal supply contract with Western Energy Company (WECO), Mineral Management Service of the United States Department of Interior issued orders to 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 this matter is currently pending before the Interior Board of Land Appeals of the Department of Interior. In addition, the Montana Department of Revenue has asserted various tax and royalty demands, which are being appealed. We are monitoring the progression of these matters. 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 these matters nor the associated costs can be predicted at this time.

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, 2005.

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Part II

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

In connection with the consummation of our 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, 114,164 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.

Dividends

We pay dividends on our common stock after our Board of Directors declares them. 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 during 2005. Quarterly dividends were declared and paid on our common stock during 2005 as set forth in the table below.

The following table sets forth the high and low bid prices for our common stock for the year ended December 31, 2005 and 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
2005—
Fourth Quarter	$	31.80	$	27.88	$	0.31
Third Quarter	31.95		30.11		0.25
Second Quarter	31.52		26.43		0.22
First Quarter	28.75		25.73		0.22
2004—
November 1, 2004—December 31, 2004	$	28.00	$	24.82	$	—

On February 24, 2006, the last reported sale price on the NASDAQ for our common stock was $32.66.

Shareholder Rights Plan

On December 5, 2005, our Board of Directors adopted a shareholder rights plan, which declared a dividend of one right (Right) for each outstanding share of our common stock at the close of business on December 15, 2005. Each Right entitles the registered holder to purchase from us a unit consisting of 1/1000 of a share (Unit) of Preferred Stock at a purchase price of $100 per Unit, subject to adjustment. The shareholder rights plan is intended to allow the board of directors to pursue its review of strategic alternatives in order to maximize value for all shareholders, ensure the fair treatment of all shareholders in the event of a hostile takeover attempt and to encourage a potential acquirer to negotiate with the Board of Directors a fair price for all shareholders before attempting a takeover.

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Holders

As of February 24, 2006, there were 562 common shareholders of record of 32,422,211 outstanding shares of our common stock. An additional 3,145,510 shares were held in reserve by our transfer agent for claims dispute resolution.

Repurchase of Common Stock

On November 8, 2005, our Board of Directors authorized a common stock repurchase program that allows us to repurchase up to $75 million of common stock under a specific trading plan. Purchases under the stock repurchase program may be made in the general open market in accordance with Rule 10b-18 under the Securities Exchange Act of 1934. We are also authorized to make privately negotiated repurchases in appropriate circumstances. The purchases will be based on a number of factors, including price, volume and timing. The following table provides information regarding stock repurchases since the inception of the program. All of the following were open market transactions:

	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased Under Publicly Announced Plans or Programs	Dollar Value of Shares That May Yet Be Purchased Under the Plan
November 8, 2005 — November 30, 2005	83,342	$	28.59	83,342	$	72.6 million
December 1, 2005 — December 31, 2005	13,100	$	31.00	13,100	$	72.2 million
Total	96,442			96,442

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 our plans as of the close of business on December 31, 2005:

(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 (i) above.

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

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	N/A	N/A
Equity compensation plans not approved by security holders
New Incentive Plan(1)	—	—	1,954,216
Total	—		1,954,216

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(1)Upon emergence from bankruptcy, a New Incentive Plan, which is described more fully in Item 11 herein, was established pursuant to the Plan, which set aside 2,265,957 shares for the new Board of Directors to establish equity-based compensation plans for employees and directors. As the New Incentive Plan was provided for by provisions of the Plan, shareholder approval was not required. Upon emergence 228,315 shares of restricted stock were granted (Special Recognition Grants) under the New Incentive Plan to certain officers and key employees. There are 35,164 remaining unvested shares under this grant. In addition, during 2005 the NorthWestern Corporation 2005 Long-Term Incentive Plan was established under the New Incentive Plan, under which a broad-based employee restricted stock grant of 91,651 shares was distributed and 20,934 deferred stock units and 6,000 shares of restricted stock were granted to our Board of Directors.

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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 2001 and 2002.

FIVE-YEAR FINANCIAL SUMMARY

	Successor Company					Predecessor Company
	December 31,		November 1- December 31,			January 1- October 31,		Year Ended December 31,
	2005		2004			2004(1)		2003			2002			2001
Financial Results (in thousands, except per share data)
Operating revenues	$	1,165,750	$	205,952		$	833,037	$	1,012,515		$	783,744		$	255,151
Income (loss) from continuing operations	61,547		(6,520		)	548,889		(71,582		)	(9,356		)	4,175
Basic earnings (loss) per share from continuing operations(2)	1.73		(0.18		)
Diluted earnings (loss) per share from continuing operations(2)	1.71		(0.18		)
Dividends declared & paid per common share	1.00		—
Financial Position
Total assets	$	2,400,403	$	2,448,869		$	2,554,740	$	2,456,849		$	2,785,061		$	2,641,685
Long-term debt, including current portion	742,970		836,946			910,154		1,784,237			1,668,431			583,651
Preferred stock not subject to mandatory redemption	—		—			—		—			—			3,750
Preferred stock subject to mandatory redemption	—		—			—		365,550			370,250			187,500
Ratio of earnings to fixed charges(3)	2.6		—			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 and $9.5 million for the years ended December 31, 2003, 2002 and 2001, respectively.

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

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

OVERVIEW

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 628,000 customers in Montana, South Dakota and Nebraska. As you read this discussion and analysis, refer to our Consolidated Statements of Income (Loss), which present the results of our operations for 2005, 2004 and 2003. Following is a brief overview of highlights for 2005, followed by a discussion of our strategy. Additional details on our results of operations follow the Critical Accounting Policies and Estimates section.

Consolidated net income in 2005 was $59.5 million as compared to $544.4 million in 2004. When excluding the effects of our bankruptcy reorganization items, consolidated net income increased in 2005 by approximately $55.2 million. This improvement was primarily due to

•increased margins of $48.8 million,

•decreased interest expense and loss on debt extinguishment totaling $43.3 million,

•increased investment income and other of $14.3 million,

•partly offset by an increase in income taxes of $44.8 million.

We are focused on maintaining a strong liquidity position and strengthening our balance sheet. During the year ended December 31, 2005, we repaid $94.3 million of debt. In addition to these repayments we paid dividends on common stock of $35.6 million, and contributed $37.3 million to our pension and other postretirement benefit plans. We increased our quarterly dividend twice during 2005 and our annualized dividend for 2006 is expected to be $1.24 per share.

We have also substantially completed the wind-down of our subsidiaries Netexit and Blue Dot, along with the sale of our Montana First Megawatts generation assets. Related proceeds received during 2005 totaled $45.7 million and we received an additional $22.5 million during the first two months of 2006. This effectively completes the divestitures of our non-core assets, allowing complete focus on our energy operations.

During the fourth quarter of 2005, we finalized a settlement with PPL Montana, LLC (PPL) to settle all claims and counterclaims associated with a dispute over an asset purchase agreement, covering the anticipated sale of transmission assets to PPL. Under the terms of the settlement, we retained the transmission assets and PPL paid us $9.0 million in cash. In addition, the settlement covered the cancellation of various environmental related and other indemnity obligations.

For more than 80 years, we have provided our customers with reliable, cost-competitive energy with industry-leading service. Our utility operations are cost competitive, comparing favorably to national averages reported by our industry trade association, the Edison Electric Institute. Our financial plans and fiscal policies have been designed to be consistent with the conservative business profile of a regulated utility. This will allow us to pursue cash flow and earnings growth, which is linked to the stable growth from our existing transmission and distribution system.

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Strategy

Our primary focuses during 2006 will be toward having MPSC reviewed energy procurement plans for our ongoing default supply needs in Montana to help provide recovery of energy supply costs, accomplishing a successful general rate filing in Montana, resolving our outstanding litigation (see Item 3. Legal Proceedings), continuing necessary actions to improve our credit rating to investment grade and implementing plans to execute our growth strategy, particularly in electric transmission and natural gas distribution.

Our core transmission and distribution business generates a significant amount of cash, which is at the center of our value creation strategy. The available cash flows from operations are first used to invest in maintaining our existing utility business and for investing in system integrity and service quality within our service territory. Then, while maintaining an appropriate level of debt, we plan to use cash to pay competitive dividends and repurchase up to $75 million of our outstanding common shares in order to continuously increase shareholder value. Finally, we plan to use any remaining cash to fund targeted growth opportunities.

We are currently focusing on strategic alternatives to reduce our QF liability and mitigate exposure to current variability and regulatory uncertainty. We are also assessing a potential buyout of our Colstrip Unit 4 operating lease, which would give us ownership of a 30% undivided interest in the generation facility.

Our Montana assets are strategically located to take advantage of the potential transmission grid expansion in the Northwest part of United States. We feel these types of projects would be able to provide stable and reliable returns regulated by the FERC. There are a number of potential paths and more than a dozen points of interconnection with major players in the Northwest.

An example is the pathway from Montana to Idaho, which we believe to have high market interest. We have performed a market test and completed an “open season,” which indicated significant market interest in this project. Participants expressed interest for 2,250 MW of transmission service requests. A cross section of these participants included: new/existing power plants, coal & wind projects, power marketers, and load serving entities.

An initial study has been completed and indicates a new transmission line would be needed, costing up to $815 million. We have begun a second phase of the process, which requires participants to sign a facilities studies agreement and provide a one-month transmission revenue deposit. Market interest remains strong in that participants have made 850 MW in transmission reservations. We plan to complete a detailed engineering study to determine what type of facility is required for this project.

In addition, we have benefited from the growth in ethanol plants in our service territory, as we are providing natural gas to many plants through our pipelines and are well positioned to take advantage of additional growth in this industry. With the Energy Policy Act of 2005, enhanced potential exists for future expansion and investment in this area due to the focus on alternative fuel sources. In 2006, we plan to make an approximate $2.6 million pipeline investment to serve a new ethanol plant in Mitchell, South Dakota, and pursue other opportunities where new ethanol plants are scheduled for construction or expansion. Additional opportunities are possible into the future in many South Dakota and Nebraska areas.

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 of America. 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.

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

Goodwill and Long-lived Assets

We believe that the accounting estimate related to determining the fair value of goodwill and long-lived assets, 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 could have 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 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.

We evaluate our property, plant and equipment for impairment whenever indicators of impairment exist. SFAS No. 144, Accounting for the Impairment or the Disposal of Long-Lived Assets, 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.

Qualifying Facilities Liability

Certain QFs under the Public Utility Regulatory Policy Act (PURPA) require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. As of December 31, 2005, our gross contractual obligation related to the QFs is approximately $1.6 billion. A portion of the costs incurred to purchase this energy is recoverable though rates authorized by the MPSC, totaling approximately $1.3 billion through 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. During the first quarter of 2005, we amended one of these contracts, which reduced our capacity and energy rates over the term of the contract (through 2028). As a result of this amendment, we reduced our QF liability based on the new rates, resulting in a $4.9 million gain. At December 31, 2005, our estimated QF liability was $140.5 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 QF utilization, QF contract amendments and future regulatory changes relating to QFs could significantly impact our results of operations.

Revenue Recognition

Revenues are recognized differently depending on the various jurisdictions. For our South Dakota and Nebraska operations, consistent with historic treatment in the respective jurisdictions, electric and natural gas utility revenues are based on billings rendered to customers. For our Montana operations, 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 Regulation. 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 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, then we would need to evaluate the probable future recovery of or reduction in revenue with respect to the related regulatory assets and liabilities. 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 assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results.

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Pension and Postretirement Benefit Plans

We sponsor defined benefit pension plans, which cover substantially all employees, and provide postretirement health care and life insurance benefits for certain of our employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 16 to the consolidated financial statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics and economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, 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. Due to the complexity of these calculations, long-term nature of the obligations, and the importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

•Discount rates used in determining the future benefit obligations;

•Projected health care cost trend rates;

•Expected long-term rate of return on plan assets; and

•Rate of increase in future compensation levels.

We review these assumptions on an annual basis and adjust them as necessary. The assumptions 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.

We set the discount rate based upon our review of the Citigroup Pension Index and Moody’s Aa bond rate index. Based on this analysis, we used a discount rate of 5.5% in 2005 and 2004.

The health care cost trend rates are established through a review of actual recent cost trends and projected future trends. Our retiree medical trend assumptions are the best estimate of expected inflationary increases to our healthcare costs. Due to the relative size of our retiree population (under 700 members), the assumptions used are based upon both nationally expected trends and our specific expected trends. Our average increase remains consistent with the nationally expected trends. The long-term trend assumption is based upon our actuary’s macroeconomic forecast, which includes assumed long-term nominal gross domestic product (GDP) growth plus the expected excess growth in national health expenditures versus GDP, the assumed impact of population growth and aging, and variations by healthcare sector. Based on this review, the health care cost trend rate used in calculating the December 31, 2005 accumulated postretirement benefit obligation was a 9% increase in health care costs in 2006 gradually decreasing each successive year until it reaches a 5.0% annual increase in health care costs in 2010.

The expected long-term rate of return assumption on plan assets 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. We target an asset allocation of roughly 70% equity securities, and 30% fixed-income securities. Considering this information and future expectations for asset returns, we are decreasing our expected long-term rate of return on assets assumption from 8.5% during 2005 to 8.00% for 2006. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.30% for union and 3.37% for nonunion employees in 2005 and 2004.

Cost Sensitivity

The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):

Actuarial Assumption	Change in Assumption		Impact on Pension Cost			Impact on Projected Benefit Obligation
Discount rate	0.25	%	$	(144	)	$	(11,851	)
	(0.25	)%	142			12,466
Rate of return on plan assets	0.25	%	(598		)	N/A
	(0.25	)%	598			N/A

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Accounting Mechanisms

In accordance with SFAS No. 87, Employers’ Accounting for Pensions, we utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. Through fresh-start reporting in 2004 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.

In addition, our regulated operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulations. 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. 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. A pension regulatory asset has been recognized for the obligation that will be included in future cost of service. In 2005, the MPSC authorized the recognition of pension costs based on an average of the funding to be made over a 5-year period for the calendar years 2005 through 2009.

Income Taxes

We realized substantial cancellation of indebtedness (COD) income in 2004. For tax purposes, we were not required to include any COD income in our taxable income when we emerged from bankruptcy, however we were required to reduce certain tax attributes up to the amount of COD income. Under our Plan, there was 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 consolidated net operating loss carryforwards(CNOLs). Based on this limitation and our current assumptions, we estimate the majority of our CNOLs will be utilized. Upon the adoption of fresh-start reporting, we removed substantially all of the valuation allowance against our deferred tax assets related to continuing operations 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 affect our results. During the third quarter of 2005, we filed our 2004 tax return and reduced our consolidated net operating loss carryforwards (CNOLs) by approximately $583 million of COD income. We currently estimate that as of December 31, 2005 we have approximately $468.6 million of CNOLs (including approximately $333.0 million related to Blue Dot discussed below) to offset federal taxable income in future years.

During the third quarter of 2005, Blue Dot sold its last remaining operating location and during the fourth quarter of 2005, we completed an assessment of our tax position as it relates to our investment in Blue Dot. We expect to claim a worthless stock deduction of approximately $333.0 million on our 2005 tax return related to our investment in Blue Dot. Consistent with our accounting policy discussed below, we have not recorded a benefit in our financial statements for the Blue Dot worthless stock deduction. Due to the amount of our CNOLs, we will not actually realize the benefit of this deduction for several years.

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. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are 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.

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In July 2005, the Financial Accounting Standards Board (FASB) issued a proposed interpretation titled, Accounting for Uncertain Tax Positions, an Interpretation of FASB Statement No. 109. Under this new interpretation, the criteria for recognizing the financial statement impacts of tax positions could become more stringent. Until the new standard is finalized, we are unable to assess the impact on our results of operations or financial position. Under the proposed interpretation, the impact of adoption would be recorded as a change in accounting principle.

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RESULTS OF OPERATIONS

The following is a summary of our results of operations in 2005, 2004, and 2003. 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.

Factors Affecting Results of Continuing Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is primarily affected by weather. 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 affects the demand for electricity and natural gas, especially among residential and commercial customers. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity. 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. Cooling degree-days result when the average daily actual temperature is greater than the baseline. The statistical weather information provided in our regulated segments represents a comparison of these degree-days.

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 our results of operations (in thousands):

	Successor Company			Unaudited Successor & Predecessor Combined
	Year Ended December 31,
	2005			2004
OPERATING REVENUES	$	1,165,750		$	1,038,989
COST OF SALES	641,755			563,829
GROSS MARGIN	523,995			475,160
TOTAL OPERATING EXPENSES	379,543			(162,903		)
OPERATING INCOME	144,452			638,063
Interest Expense	(61,295		)	(83,843		)
Loss on Debt Extinguishment	(548		)	(21,310		)
Investment and Other Income	17,448			3,160
Income From Continuing Operations Before Income Taxes	100,057			536,070
Income Tax (Expense) Benefit	(38,510		)	6,299
Income From Continuing Operations	61,547			542,369
Discontinued Operations, Net of Taxes	(2,080		)	2,064
Net Income	$	59,467		$	544,433

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Unaudited Combined)

Consolidated revenues in 2005 were $1,165.8 million, an increase of $126.8 million, or 12.2%, over 2004. Revenue from our regulated electric and natural gas segments increased $102.0 million primarily from higher supply costs, which are collected in rates from our customers. In addition, our regulated electric segment

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revenue increased $14.4 million from higher transmission and distribution sales. Our unregulated gas segment revenues increased $20.9 million mainly from increased supply costs, and our unregulated electric revenues increased $7.1 million due primarily to higher prices on increased volumes. This increase in revenues was partially offset by $13.6 million in higher intersegment eliminations due to higher market prices.

Consolidated cost of sales in 2005 was $641.8 million, an increase of $78.0 million, or 13.8%, over 2004. Consistent with revenue, the increase in our regulated business cost of sales was primarily due to higher supply costs of $30.7 million in our regulated electric segment and $46.8 million in our regulated gas segment. The increase in regulated electric supply costs was due to a combination of higher prices and volumes, partially offset by decreases in out of market costs of approximately $9.1 million associated with our QF contracts, including a $4.9 million gain in the first quarter of 2005 related to a QF contract amendment. In addition, we incurred a $2.1 million loss in the second quarter of 2004 related to a contract dispute settlement with a wholesale power supply vendor. The increase in regulated gas supply costs was due to a combination of higher prices and volumes, offset by the recovery in the second quarter 2005 of $4.6 million of gas costs previously disallowed by the MPSC. In 2004, we recorded $2.8 million of disallowed gas costs and a $2.8 million loss on a fixed price sales contract. Our unregulated gas costs increased $18.4 million, primarily due to higher average gas prices. Partially offsetting this increase was a $13.9 million increase in intersegment eliminations.

Consolidated gross margin in 2005 was $524.0 million, an increase of $48.8 million, or 10.3%, over 2004. Margins in our regulated electric segment increased $25.9 million primarily due to $14.4 million higher volume sales to our transmission and distribution customers due to increased volumes and decreases in out of market costs of approximately $9.1 million associated with our QF contracts. A $2.3 million decrease in wholesale revenues partially offset these increases. In addition, we recorded a $2.1 million loss in the second quarter of 2004 related to a contract dispute settlement with a wholesale power supply vendor. Margins in our regulated gas segment increased $12.7 million due to the recovery of $4.6 million in the second quarter of 2005 of gas supply costs previously disallowed by the MPSC combined with $5.6 million of unrecovered gas costs during 2004, and an approximate $2.5 million improvement due to increased volumes. Our unregulated electric segment margins increased $7.8 million primarily due to increased volumes, and our unregulated natural gas segment margins increased $2.5 million due to losses recorded during 2004 on fixed price sales contracts.

Gross margin as a percentage of revenues was 44.9% in 2005, a decrease from 45.7% in 2004. 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.

	Successor Company		Unaudited Successor & Predecessor Combined
	Year Ended December 31,
	2005		2004
Operating Expenses
Operating, general and administrative	$	225,514	$	221,740
Property and other taxes	72,087		65,135
Depreciation	74,413		72,848
Reorganization items	7,529		(532,626		)
Impairment on assets held for sale	—		10,000
	$	379,543	$	(162,903	)

Consolidated operating, general and administrative expenses were $225.5 million in 2005, an increase of $3.8 million, or 1.7%, over 2004. There were various increases and offsetting reductions accounting for this overall increase in operating, general and administrative expenses. The increases were primarily due to increased pension expense of approximately $9.9 million, lower overhead capitalization in 2005 of

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approximately $5.7 million, and other increases aggregating approximately $9.2 million consisting primarily of increases in compensation expenses, professional fees and fleet fuel costs. The overhead capitalization reduction in 2005 was due to a change in estimate based on an updated overhead capitalization study of administrative time spent supporting construction activity. We expect 2006 overhead capitalization levels to be consistent with amounts capitalized in 2005. Increases in compensation expenses were primarily due to broad based stock grants to employees, severance costs and increased directors fees. Offsetting these increases in operating, general and administrative expenses were reduced lease expense of approximately $10.2 million related to the extension of our operating lease for the Colstrip Unit 4 generation facility, a $5.8 million decrease in directors and officers insurance, and a $5.0 million decrease in our self-insurance reserves primarilybased on claims settled for less than anticipated and positive loss experience during 2005.

Property and other taxes were $72.1 millionin 2005 as compared to $65.1 million in 2004. This increase was primarily due to a higher valuation assessment and increased mill levies in our Montana service territory. Under Montana law, utilities are allowed to reflect changes in state and local taxes and fees, and to track these changes such that the actual level of taxes and fees are recovered. The MPSC has authorized recovery of approximately 60% of the increase in our local taxes and fees (primarily property taxes) in 2005 as compared to the amount of these taxes included in our last general rate case in 1999. While we have recorded a regulatory asset consistent with the MPSC’s authorization, we have filed a Petition for Judicial Review in Montana District Court seeking to recover 100% of the increase in these local taxes and fees. We anticipate resolving this issue in 2006, however we cannot currently predict an outcome.

Depreciation expense was $74.4 million in 2005 as compared to $72.8 million in 2004.

Reorganization items consist of bankruptcy related professional fees and expenses. These expenses totaled $7.5 million in 2005 as compared to reorganization income of $532.6 million in 2004. During 2005 reorganization related professional fees were primarily associated with the attempted resolution of the QUIPs litigation and the resolution of other disputed Class 9 claims. Reorganization expenses for 2005 include a $2.6 million loss for the reestablishment of a liability that was removed from our balance sheet upon emergence from bankruptcy. We continued to pay professional fees incurred by the Plan Committee in addition to our own professional fees. Reorganization items associated with our emergence from bankruptcy in 2004 included the following:

•$558.0 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 in 2004 related to a decline in the estimated realizable value of our Montana First Megawatts generation assets.

Consolidated loss on extinguishment of debt in 2005 was $0.5 million, resulting from an early principal payment of $25.0 million on our senior secured term loan B on April 22, 2005. Consolidated loss on extinguishment of debt for 2004 was $21.3 million, resulting from the write off of financing costs associated with our senior secured term loan that we replaced on November 1, 2004.

Consolidated operating income in 2005 was $144.5 million, as compared to $638.1 million in 2004. This $493.6 million decrease was primarily due to the $532.6 million of reorganization income included in operating income during 2004 partially offset by higher gross margins during 2005.

Consolidated interest expense in 2005 was $61.3 million, a decrease of $22.5 million, or 26.8%, from 2004. This decrease was attributable to repayment of approximately $175 million in secured debt since September 30, 2004, as well as our November 1, 2004 financing transaction, which replaced our $390 million senior secured

46

term loan with lower interest rate debt. See “Liquidity and Capital Resources” for additional information regarding our financing transactions.

Consolidated investment and other income in 2005 was $17.4 million, an increase of $14.2 million from 2004. This increase was primarily due to a $4.7 million gain from the sale of sulfur dioxide (SO2) emission allowances and a $9.0 million gain from a dispute settlement. The market value of SO2 emission allowances increased significantly during the third quarter of 2005 and we sold our excess SO2 emission allowances covering years 2011 through 2016. Proceeds from the sale of these emission allowances are not subject to regulatory jurisdiction. We have excess SO2 emission allowances remaining for years 2017 through 2031, however the market for these years is presently illiquid and these emission allowances have no carrying value in our financial statements.

Consolidated provision for income taxes in 2005 was $38.5 million as compared to a benefit of $6.3 million in 2004. While we were in bankruptcy, we maintained a valuation allowance against our deferred tax assets. Due to our significant net operating losses, the valuation allowance had the effect of minimizing our income tax expense as most changes in income were offset by an increase or decrease in the valuation allowance. Upon emergence from bankruptcy, we reduced our valuation allowance based on our estimated realizability of these tax benefits. Our effective tax rate for 2005 was 38.5%. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through 2010, based on our anticipated use of net operating losses.

Loss from discontinued operations in 2005 was $2.1 million as compared to income of $2.1 million in 2004. The loss in 2005 is primarily related to professional fees and settlement of claims in Netexit’s bankruptcy proceedings. The 2004 results were primarily due to a Netexit settlement related gain of $11.5 million offset by an increase in liabilities for claims filed in the Netexit bankruptcy proceedings..

Consolidated net income in 2005 was $59.5 million as compared to $544.4 million in 2004. When excluding the effects of our bankruptcy reorganization items, consolidated net income increased approximately $55.2 million. This improvement was primarily due to higher margins, particularly in our regulated segments, the effects of our debt reduction and financing transaction, including a decrease in interest expense and the prior year loss on debt extinguishment, and higher investment income, partly offset by an increase in income taxes discussed above.

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

	Unaudited Successor & Predecessor Combined			Predecessor Company
	Year Ended December 31,
	2004			2003
OPERATING REVENUES	$	1,038,989		$	1,012,515
COST OF SALES	563,829			535,667
GROSS MARGIN	475,160			476,848
TOTAL OPERATING EXPENSES	(162,903		)	398,175
OPERATING INCOME	638,063			78,673
Interest Expense	(83,843		)	(147,626		)
Gain (Loss) on Debt Extinguishment	(21,310		)	3,300
Investment and Other Income	3,160			(5,977		)
Income (Loss) From Continuing Operations Before Income Taxes	536,070			(71,630		)
Income Tax Benefit	6,299			48
Income (Loss) From Continuing Operations	542,369			(71,582		)
Discontinued Operations, Net of Taxes	2,064			(42,143		)
Net Income (Loss)	$	544,433		$	(113,725	)

Consolidated revenues in 2004 were $1,039.0 million, 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 $29.7 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 $10.0 million due primarily to a renegotiated power purchase agreement with a wholesale customer. Offsetting this increase was a $21.9 million increase in intersegment eliminations.

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. Partially offsetting this increase was a $21.8 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.

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	Unaudited Successor & Predecessor Combined			Predecessor Company
	Year Ended December 31,
	2004			2003
Operating Expenses
Operating, general and administrative	$	221,740		$	239,716
Property and other taxes	65,135			67,542
Depreciation	72,848			70,252
Reorganization items	(532,626		)	8,266
Impairment on assets held for sale	10,000			12,399
	$	(162,903	)	$	398,175

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.

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

•$558.0 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 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.

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. 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

49

$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.

The following tables and discussion present information regarding our operating segments.

REGULATED ELECTRIC SEGMENT

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Unaudited Combined)

	Results
	2005			2004			Change			Change %
	(in millions)
Electric supply revenue	$	292.8		$	248.0		$	44.8		18.1	%
Transmission & distribution revenue	281.4			267.0			14.4			5.4
Rate schedule revenue	574.2			515.0			59.2			11.5
Transmission	40.2			38.6			1.6			4.1
Wholesale	9.8			12.1			(2.3		)	(19.0	)
Miscellaneous	7.5			6.2			1.3			21.0
Total Revenues	631.7			571.9			59.8			10.5	%
Supply costs	286.5			255.8			30.7			12.0
Other cost of sales	20.0			16.8			3.2			19.0
Total Cost of Sales	306.5			272.6			33.9			12.4	%
Gross Margin	$	325.2		$	299.3		$	25.9		8.7	%
% GM/Rev	51.5		%	52.3		%

	Volumes MWH
	2005	2004	Change		Change %
	(in thousands)
Retail Electric
Residential	2,580	2,458	122		5.0	%
Commercial	3,814	3,693	121		3.3
Industrial	3,034	2,908	126		4.3
Other	170	169	1		0.6
Total Retail Electric	9,598	9,228	370		4.0	%
Wholesale Electric	219	402	(183	)	(45.5	)%

	2005 as compared to:
Cooling Degree-Days	2004	Historic Average
Montana	20% warmer	7% warmer
South Dakota	80% warmer	32% warmer

Average Customer Counts	2005	2004	Change	% Change
Montana	314,131	308,553	5,578	1.8	%
South Dakota	58,540	58,122	418	0.7	%
Total	372,671	366,675	5,996	1.6	%

Rate Schedule Revenue

Rate schedule revenue consists of revenue for electric supply, transmission and distribution. This includes fully bundled rates for supplying, transmitting, and distributing electricity to customers who utilize us as their commodity supplier. Customers that have chosen other commodity suppliers are billed for moving their

50

electricity across our lines and their distribution revenues are reflected as rate schedule revenue, while their transmission revenues are reflected as transmission revenue.

Electric rate schedule revenue increased $59.2 million, or 11.5%. This increase consisted of $44.8 million related to increased electric supply revenues, which consists of our supply costs that are collected in rates from customers. This $44.8 million increase includes $25.8 million due to higher supply prices and $19.0 million due to an increase in volumes related to a combination of customer growth and warmer summer weather. Transmission and distribution revenue increased $14.4 million due to a 4.0% increase in volumes related to the combination of warmer summer weather and customer growth.

Transmission Revenue

Transmission revenue consists of revenue 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 into the California market than by buying electricity within California. We refer to these differences as price differentials. These price differentials were the primary reasons for the $1.6 million, or 4.1%, increase in transmission revenue.

Wholesale Revenues

Wholesale revenues are from our joint ownership in generation facilities. Excess power not used by our South Dakota customers is sold in the wholesale market. These revenues decreased $2.3 million, or 19.0%, in 2005 primarily due to an $8.1 million, or 45.5%, decrease in volumes sold in the secondary markets partially offset by $5.8 million, or 47.8% higher average prices. We had less wholesale energy available to sell because our retail customers used greater volume due to warmer summer weather and there was decreased plant availability resulting from scheduled maintenance.

Gross Margin

Gross margin in 2005 increased $25.9 million, or 8.7% over 2004, primarily related to the $14.4 million increase in transmission and distribution revenues due to higher volumes and decreases in out of market costs of approximately $9.1 million associated with our QF contracts, including a $4.9 million gain related to a QF contract amendment. This amendment reduces our capacity and energy rates over the term of the contract (through 2028) and we have reduced our QF liability based on the new rates. QF costs can differ substantially from year to year depending on the actual output of the QFs as compared to the estimates we used in recording our QF liability. A $2.3 million decrease in wholesale revenues partially offset the increases discussed above. We also recorded a $2.1 million loss in the second quarter of 2004 related to a dispute settlement with a wholesale power supply vendor.

Margin as a percentage of revenues decreased to 51.5% in 2005, from 52.3% in 2004. 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.

Volumes

Regulated retail electric volumes in 2005 totaled 9,598,361 MWHs, compared with 9,228,028 MWHs in 2004. This increase was primarily related to customer growth of 1.6% and warmer summer weather as compared to the prior period in all regulated markets.Regulated wholesale electric volumes in 2005 were 215,752 MWHs, compared with 401,691 MWHs in 2004. Regulated wholesale electric volumes decreased during 2005 resulting from increased retail demand due to warmer summer weather and lower generation plant availability due to scheduled maintenance.

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

	Results
	2004			2003			Change			Change %
	(in millions)
Electric supply revenue	$	248.0		$	230.5		$	17.5		7.6	%
Transmission & distribution revenue	267.0			267.3			(0.3		)	(0.1	)
Rate schedule revenue	515.0			497.8			17.2			3.5
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
Miscellaneous	6.2			5.1			1.1			21.6
Total Revenues	571.9			601.6			(29.7		)	(4.9	)%
Supply costs	255.8			224.3			31.5			14.0
Sales for resale	—			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		%

	Volumes MWH
	2004	2003	Change		Change %
	(in thousands)
Retail Electric
Residential	2,458	2,543	(85	)	(3.3	)%
Commercial	3,693	3,695	(2	)	(0.1	)
Industrial	2,908	2,488	420		16.9
Other	169	175	(6	)	(3.4	)
Total Retail Electric	9,228	8,901	327		3.7	%
Wholesale Electric	402	304	98		32.2	%

	2004 as compared to:
Cooling Degree-Days	2003	Historic Average
Montana	57% colder	12% colder
South Dakota	36% colder	25% colder

Average Customer Counts	2004	2003	Change	% Change
Montana	308,553	303,166	5,387	1.8	%
South Dakota	58,122	57,752	370	0.6	%
Total	366,675	360,918	5,757	1.6	%

Rate Schedule 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 relatively 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.

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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 they are netted against cost of sales.

Transmission Revenue

Transmission revenue consists of revenue 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 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 32.2% 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.

Volumes

Regulated retail electric volumes in 2004 totaled 9,228,028 MWHs, compared with 8,901,082 MWHs in 2003. This increase was primarily related to an overall increase of 1.6% in customer growth in all regulated markets.Regulated wholesale electric volumes in 2004 were 401,691 MWHs, compared with 303,532 MWHs in 2003. Regulated wholesale electric volumes increased during 2004 as a result of higher generation plant availability.

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. 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.

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REGULATED NATURAL GAS SEGMENT

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Unaudited Combined)

	Results
	2005			2004			Change			Change %
	(in millions)
Gas supply revenue	$	228.4		$	171.2		$	57.2		33.4	%
Transportation, distribution & storage revenue	95.2			93.9			1.3			1.4
Rate schedule revenue	323.6			265.1			58.5			22.1
Wholesale revenue	20.2			25.8			(5.6		)	(21.7	)
Transportation	17.8			16.9			0.9			5.3
Miscellaneous	4.4			3.9			0.5			12.8
Total Revenues	366.0			311.7			54.3			17.4	%
Supply costs	224.2			177.4			46.8			26.4
Wholesale supply costs	20.2			25.8			(5.6		)	(21.7	)
Other cost of sales	2.4			2.0			0.4			20.0
Total Cost of Sales	246.8			205.2			41.6			20.3	%
Gross Margin	$	119.2		$	106.5		$	12.7		11.9	%
% GM/Rev	32.6		%	34.2		%

	Volumes MMbtu
	2005	2004	Change		Change %
	(in thousands)
Retail Gas
Residential	18,026	17,934	92		0.5	%
Commercial	10,769	10,645	124		1.2
Industrial	181	196	(15	)	(7.7	)
Other	131	111	20		18.0
Total Retail Gas	29,107	28,886	221		0.8	%

	2005 as compared to:
Heating Degree-Days	2004	Historic Average
Montana	3% colder	Remained flat
South Dakota	Remained flat	9% warmer
Nebraska	1% warmer	9% warmer

Average Customer Counts	2005	2004	Change	% Change
Montana	167,043	163,511	3,532	2.2	%
South Dakota & Nebraska	82,164	81,597	567	0.7	%
Total	249,207	245,108	4,099	1.7	%

Rate Schedule Revenue

Rate schedule revenue consists of revenue for supply, transportation, and distribution of natural gas. This includes fully bundled rates for supplying, transporting, and distributing natural gas to customers who utilize us as their commodity supplier. 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.

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Gas supply revenues in 2005 increased $57.2 million, or 33.4% over results in 2004. Gas supply revenues essentially consist of our supply costs that are collected in rates from customers. This increase primarily consisted of a $50.9 million increase in supply prices and the recognition of $4.6 million for the recovery of supply costs previously disallowed by the MPSC.

Wholesale Revenue

Wholesale revenue decreased $5.6 million due to reduced 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

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 increased $0.9 million in 2005 as compared to 2004.

Gross Margin

Gross margin was $119.2 million in 2005, an increase of $12.7 million, or 11.9%, from 2004 due to the recovery of previously disallowed gas costs as discussed above and the higher transmission, distribution and storage revenue. In addition, during 2004, we wrote off $2.8 million associated with the MPSC’s disallowance of gas costs and $2.8 million related to a fixed price sales contract.

Margin as a percentage of revenue decreased to 32.6% for 2005, from 34.2% for 2004. 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.

Volumes

Regulated retail natural gas volumes were 29,107,170 MMbtu (million British Thermal Units) during 2005, compared with 28,885,705 MMbtu in 2004. This increase resulted primarily from a 1.7% increase in customer growth and 3% colder weather as compared to the prior period in Montana.

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

	Results
	2004			2003			Change			Change %
	(in millions)
Gas supply revenue	$	171.2		$	141.5		$	29.7		21.0	%
Transportation, distribution & storage revenue	93.9			96.5			(2.6		)	(2.7	)
Rate schedule revenue	265.1			238.0			27.1			11.4
Wholesale revenue	25.8			23.6			2.2			9.3
Transportation	16.9			14.5			2.4			16.6
Miscellaneous	3.9			3.0			0.9			30.0
Total Revenues	311.7			279.1			32.6			11.7	%
Supply costs	177.4			149.8			27.6			18.4
Wholesale supply 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		%

	Volumes MMbtu
	2004	2003	Change		Change %
	(in thousands)
Retail Gas
Residential	17,934	18,534	(600	)	(3.2	)%
Commercial	10,645	10,844	(199	)	(1.8	)
Industrial	196	215	(19	)	(8.8	)
Other	111	106	5		4.7
Total Retail Gas	28,886	29,699	(813	)	(2.7	)%

	2004 as compared to:
Heating Degree-Days	2003	Historic Average
Montana	Remained flat	3% warmer
South Dakota	7% warmer	11% warmer
Nebraska	3%warmer	9% warmer

Average Customer Counts	2004	2003	Change	% Change
Montana	163,511	160,351	3,160	2.0	%
South Dakota & Nebraska	81,597	81,235	362	0.4	%
Total	245,108	241,586	3,522	1.5	%

Rate Schedule 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. This decrease in volumes was also the primary cause of the $2.6 million decrease in transmission, distribution and storage revenue.

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Wholesale Revenue

Wholesale revenue 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

Transportation revenue consists of revenue for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. A 2.6% increase in volumes caused the $2.4 million increase in 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 transportation, distribution and storage revenue of $2.6 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.

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.

Volumes

Regulated retail natural gas volumes were 28,885,705 MMbtu during 2004, compared with 29,698,930 MMbtu in 2003. This decrease resulted primarily from warmer weather as compared to the prior period in South Dakota and Nebraska.

UNREGULATED ELECTRIC 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 three-megawatt Milltown Dam hydroelectric facility. We sell our leased share of Colstrip Unit 4 generation, representing approximately 222 megawatts at full load, principally to two unrelated third parties under agreements through December, 2010. We also have a separate agreement to repurchase 111 megawatts through December 2010. These 111 megawatts are available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 megawatts have been offered to supply a portion of the Montana default supply load (included in our regulated electric segment) for a term of 11.5 years at an average nominal price of $35.80 per megawatt hour.

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Unaudited Combined)

	Results
	2005			2004			Change			Change %
	(in millions)
Revenues	$	87.0		$	79.9		$	7.1		8.9	%
Cost of Sales	17.4			$	18.1		(0.7		)	(3.9	)
Gross Margin	$	69.6		$	61.8		$	7.8		12.6	%
% GM/Rev	80.0		%	77.3		%

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	Volumes MWH
	2005	2004	Change	Change %
	(in thousands)
Wholesale Electric	1,785	1,572	213	13.5	%

Revenue

Unregulated electric revenue increased $7.1 million, or 8.9% due to a combination of factors, including higher market prices on increased volumes generated, partially offset by less favorable pricing under existing agreements. We had more energy available to sell due to increased plant availability in 2005 with less down time for scheduled maintenance.

Gross Margin

Gross margin increased $7.8 million, or 12.6%, primarily due to higher market prices on increased volumes generated, partially offset by less favorable pricing under existing agreements. Unless Colstrip Unit 4 experiences unplanned outages, we expect our margins to increase to approximately $76.0 million in 2006 due to forward contracts with an overall average sales price of $59.42 per MWH. However, we expect our revenues and margins to decrease in 2007 under the terms of our Colstrip 4 default supply offer with our regulated segment. This offered power supply arrangement provides that we will sell approximately 788,400 MWH per year of unit contingent power to our regulated segment at prices ranging from $35.25 to $36.25 per MWH from July 1, 2007 through December 31, 2018. Including this commitment and our other forward sales contracts we estimate that our 2007 overall average sales price will decrease to $44.58 per MWH.

Volumes

Unregulated electric volumes were 1,785,293 MWHs in 2005, compared with 1,571,811 MWHs in 2004. The 2005 increase in volumes was due primarily to increased generation plant availability with less down time for scheduled maintenance.

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

	Results
	2004			2003			Change			Change %
	(in millions)
Total Revenues	$	79.9		$	69.9		$	10.0		14.3	%
Supply costs	14.9			16.5			(1.6		)	(9.7	)
Wheeling costs	3.2			6.3			(3.1		)	(49.2	)
Total Cost of Sales	$	18.1		$	22.8		$	(4.7	)	20.6	%
Gross Margin	$	61.8		$	47.1		$	14.7		31.2	%
% GM/Rev	77.3		%	67.4		%

	Volumes MWH
	2004	2003	Change		Change %
	(in thousands)
Wholesale Electric	1,572	1,701	(129	)	(7.6	)%

Revenue

Unregulated electric revenue increased $10.0 million, or 14.3%, 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.

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Gross Margin

Gross margin increased $14.7 million, or 31.2%, primarily due to the renegotiated PPA, including less wheeling costs as a result of the PPA.

Volumes

Unregulated electric volumes were 1,571,811 MWHs in 2004, compared with 1,701,325 MWHs in 2003. The 2004 decrease in volumes was due primarily to less generation plant availability with more down time for scheduled maintenance.

UNREGULATED NATURAL GAS SEGMENT

Our unregulated natural gas segment reflects the operations of our subsidiary, NorthWestern Services Corporation, which markets gas supply services and, through its subsidiary, Nekota, operates pipelines that provides gas delivery service to large volume customers. In addition, this segment also reflects the results of our unregulated Montana retail propane operations.

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Unaudited Combined)

	Results
	2005			2004			Change		Change %
	(in millions)
Total Revenue	$	157.9		$	137.0		$	20.9	15.3	%
Supply costs	$	146.6		$	128.2		$	18.4	14.4	%
Gross Margin	$	11.3		$	8.8		$	2.5	28.4	%
% GM/Rev	7.2		%	6.4		%

	Volumes MMbtu
	2005	2004	Change	Change %
	(in thousands)
Wholesale Gas	21,038	19,803	1,235	6.2	%

Revenue

Unregulated natural gas revenue increased $20.9 million, or 15.3%, due primarily to a 9.2% increase in average price and a 6.2% increase in volumes. We expect revenues to decline in 2006 because we are encouraging certain customers to contract directly with other providers for their supply needs as we receive little to no margin on supply costs.

Gross Margin

Gross margin increased $2.5 million, or 28.4%, primarily due to a $2.3 million loss recorded on out of market fixed price sales contracts in 2004.

Volumes

Unregulated wholesale natural gas volumes delivered totaled 21,038,000 MMbtu in 2005, compared with 19,802,960 MMbtu in 2004. The increase in volumes in 2005 is due primarily to sales to ethanol facilities in South Dakota.

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

	Results
	2004			2003			Change			Change %
	(in millions)
Total Revenue	$	137.0		$	100.7		$	36.3		36.0	%
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		%
	Volumes Mmbtu
	2004			2003			Change			Change %
	(in thousands)
Wholesale Gas	19,803			15,450			4,353			28.2	%

Revenue

Unregulated natural gas revenue increased $36.3 million, or 36.0%, due primarily to a $29.7 million, or 28.2%, 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.

Volumes 

Unregulated wholesale natural gas volumes delivered totaled 19,802,960 MMbtu in 2004, compared with 15,449,500 MMbtu in 2003. The increase in volumes in 2004 is due primarily to sales to ethanol facilities in South Dakota.

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.

In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. Netexit’s amended and restated liquidating plan of reorganization was confirmed by the Bankruptcy Court on September 14, 2005 and the plan became effective on September 29, 2005. Netexit resolved the majority of claims filed against it and made distributions on allowed claims prior to December 31, 2005, including distributions to NorthWestern totaling $42.2 million. NorthWestern received an additional $5.0 million distribution from Netexit in February 2006. Netexit expects to complete its liquidation during the first half of 2006 and any final distributions to NorthWestern will be minimal. 

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

	Successor Company						Predecessor Company
	Year Ended			Period Ended						Year Ended
	December 31, 2005			November 1- December 31, 2004			January 1- October 31, 2004			December 31, 2003
Revenues	$	—		$	—		$	—		$	541,211
Income (Loss) before income taxes	$	(1,179	)	$	(78	)	$	(8,893	)	$	1,360
Gain (loss) on disposal	—			—			11,500			(49,250		)
Income tax provision	—			—			—			—
Income (Loss) from discontinued operations, net of income taxes	$	(1,179	)	$	(78	)	$	2,607		$	(47,890	)

During the third quarter of 2005, Blue Dot sold its final operating location.  Summary financial information for the discontinued Blue Dot operations is as follows (in thousands):

	Successor Company						Predecessor Company
	Year Ended			Period Ended						Year Ended
	December 31, 2005			November 1- December 31, 2004			January 1- October 31, 2004			December 31, 2003
Revenues	$	3,177		$	724		$	28,209		$	400,679
Loss before income taxes	$	(901	)	$	(248	)	$	(4,282	)	$	(3,356	)
Gain (loss) on disposal	—			(98		)	4,163			14,352
Income tax provision	—			—			—			—
Income (Loss) from discontinued operations, net of income taxes	$	(901	)	$	(346	)	$	(119	)	$	10,996

LIQUIDITY AND CAPITAL RESOURCES

We are focused on maintaining a strong liquidity position and strengthening our balance sheet, thereby improving our credit profile. As of December 31, 2005, we had cash and cash equivalents of $2.7 million, and revolver availability of $91.4 million. During the year ended December 31, 2005, we used existing cash to repay $94.3million of debt, including an early principal payment of $25 million on our senior secured term loan B. In addition to these repayments we paid dividends on common stock of $35.6 million, and contributed $37.3 million to our pension and other postretirement benefit plans. In August 2005, we utilized our line of credit to repay $60 million of term debt that matured. During 2005, we also received distributions totaling $42.2 million related to our allowed claim in Netexit’s bankruptcy, which were used to repay borrowings on our line of credit and fund our operating requirements.

Sources and Uses of Funds

We believe that our cash on hand, operating cash flows, and borrowing capacity, taken as a whole, provide sufficient resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, share repurchases and estimated future capital expenditures during the next twelve months. In January 2006, we finalized the sale of our Montana First Megawatts generation assets for $20.0 million and used the proceeds to repay borrowings on our revolving line of credit. As of February 24, 2006, our availability under the line of credit was approximately $121.4 million. We anticipate refinancing our $150 million, 7.30% first mortgage bonds that are set to mature on December 1, 2006.

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The common stock repurchase program announced during the fourth quarter of 2005 allows us to repurchase up to $75 million of common stock. We have repurchased approximately $2.8 million of common stock as of December 31, 2005.

The amount of debt reduction, dividends and repurchase of common stock is subject to certain factors including the use of existing cash, cash equivalents and the receipt of cash from operations. A material adverse change in operations or available financing could impact our ability to fund our current liquidity and capital resource requirements.

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 (excluding strategic growth opportunities discussed in our strategy section above) for the next five years is as follows (in thousands):

Year	Amount
2006	$	90,000	(1)
2007	81,800		(2)
2008	83,500
2009	86,000
2010	88,500

(1) The increase in 2006 capital requirements is due primarily to planned natural gas distribution and fleet upgrades.

(2) We are assessing a potential buy out of our Colstrip Unit 4 operating lease, which would give us ownership of a 30% undivided interest in the generation facility. This contemplated transaction is not reflected in the amounts above.

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Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of December 31, 2005. See additional discussion in Note 10 to the Consolidated Financial Statements.

	Total			2006		2007		2008		2009		2010		Thereafter
	(in thousands)
Long-term Debt	$		742,970	$	156,445	$	6,771	$	6,057	$	87,049	$	6,123	$	480,525
Future minimum operating lease payments(1)	281,532			34,435		33,838		32,773		32,358		32,282		115,846
Estimated Pension and Other Postretirement Obligations(2)	96,200			24,200		22,000		22,000		22,000		6,000		N/A
Qualifying Facilities(3)	1,631,609			56,398		58,420		60,574		62,598		64,580		1,329,039
Supply and Capacity Contracts(4)	1,858,444			625,701		293,237		194,268		179,362		170,955		394,921
Contractual interest payments on debt (5)	428,700			46,339		35,254		35,001		32,774		29,637		249,695
Total Commitments	$	5,039,455		$	943,518	$	449,520	$	350,673	$	416,141	$	309,577	$	2,570,026

(1)Our operating leases include a lease agreement for our share of the Colstrip Unit 4 generation facility requiring payments of $32.2 million annually through 2010 and decreasing to $14.5 million annually through 2018. We are assessing a potential buy out of this lease during 2007.

(2)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. Based on our projected contribution levels and current assumptions, we estimate that our pension plans will be fully funded in 2009.

(3)The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2032. Our estimated gross contractual obligation related to the QFs is approximately $1.6 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, 2005.

(4)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.

(5)Contractual interest payments include an assumed average interest rate of 5.6% on an estimated line of credit balance of $60.0 million, which is our only variable rate debt.

Cash Flows

Factors Impacting our Liquidity

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 typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing line of credit, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.

The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual

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tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of supply and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above, therefore we usually under collect in the fall and winter and over collect in the spring.  A regulatory procedural delay in implementing our 2004/2005 Montana annual electric and natural gas tracker filings, combined with the rapid increase in electric and natural gas costs, have significantly increased our short-term tracking under collection. As of December 31, 2005, we are under collected on our current Montana natural gas and electric trackers by approximately $46.5 million. Our ability to utilize our company-owned gas inventory currently in storage during the winter period will limit the impact of this natural gas under collection on our liquidity. Based on current forecasted commodity price and volume assumptions, we anticipate our under collected position will decrease to a range of approximately $6-8 million by June 30, 2006, which is the end of the tracking year. Any under collected balance at the end of the tracking year will be amortized and collected in rates over the following tracker year.

Fresh-start reporting has impacted the comparability of our financial statements. The consummation of the Plan on November 1, 2004 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 35.5 million shares of new common stock and 4.6 million warrants were issued in exchange for unsecured debt and other unsecured claims. As the consummation of the Plan and 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. The following table summarizes our consolidated cash flows for 2005, 2004, and 2003.

	Successor Company			Unaudited Successor and Predecessor Combined			Predecessor Company
	Year Ended December 31,
	2005			2004			2003
Operating Activities
Net income (loss)	$	59.5		$	544.4		$	(113.7	)
Non-cash adjustments to net income	117.1			(456.2		)	143.6
Changes in working capital	29.2			30.3			(55.0		)
Other	(55.3		)	18.6			(81.8		)
	150.5			137.1			(106.9		)
Investing Activities
Property, plant and equipment additions	(80.9		)	(80.1		)	(70.7		)
Restricted cash	(3.8		)	9.3			1.2
Net proceeds from purchases / sales of investments	4.7			0.1			—
Sale of assets	7.5			15.5			75.7
	(72.5		)	(55.2		)	6.2
Financing Activities
Net (repayment) issuance of debt	(94.3		)	(82.7		)	115.2
Dividends on common stock	(35.6		)	—			—
Other	(5.4		)	(7.1		)	(37.6		)
	(135.3		)	(89.8		)	77.6
Discontinued Operations	42.9			9.8			11.7
Net (Decrease) Increase in Cash and Cash Equivalents	$	(14.4	)	$	1.9		$	(11.4	)
Cash and Cash Equivalents, beginning of period	$	17.1		$	15.2		$	26.6
Cash and Cash Equivalents, end of period	$	2.7		$	17.1		$	15.2

Cash Flows Provided By (Used In) Continuing Operations

As of December 31, 2005, cash and cash equivalents were $2.7 million, compared with $17.1 million at December 31, 2004, and $15.2 million at December 31, 2003. Cash provided by continuing operations totaled $150.5 million during 2005, compared to $137.1 million during 2004. This improvement in operating cash flows is due to improved operating income, primarily offset by increased pension and other postretirement benefits funding of $19.3 million and the natural gas and electric tracker under collectionsdiscussed above. 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 bankruptcy 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.

Cash Flows Provided By (Used In) Investing Activities

Cash used in investing activities of continuing operations totaled $72.5 million during 2005 compared to $55.2 million in 2004, and cash provided of $6.2 million during 2003. In 2005, we received approximately $4.7 million of net proceeds from the sale of short-term investments, approximately $7.5 million of proceeds from the sale of assets and we used approximately $80.9 million for property, plant and equipment additions. During 2004, we used approximately $80.1 million to make property, plant and equipment additions offset primarily by proceeds from sale of assets of $15.5 million and a decrease in restricted cash of $9.3 million. Cash provided in 2003 was primarily due to proceeds from investment sales offset by property, plant and equipment additions.

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Cash Flow Provided By (Used In) Financing Activities

Cash used in financing activities of continuing operations totaled $135.3 million during 2005 compared to $89.8 million in 2004, and cash provided of $77.6 million during 2003. In 2005 we made debt repayments of $94.3 million, and paid dividends on common stock of $35.6 million. On November 8, 2005, our Board of Directors authorized a common stock repurchase program that allows us to repurchase up to $75 million of common stock. Cash used to repurchase shares during the fourth quarter of 2005 was approximately $2.8 million.

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.

Discontinued Operations Cash Flows

The decrease in restricted cash held by discontinued operations during 2005 was primarily due to Netexit’s $42.2 million distribution to us, along with payment of other allowed claims pursuant to its liquidating plan of reorganization. The increase in restricted cash held by discontinued operations during 2004 was primarily due to a settlement in which Netexit received $17.5 million, offset by a Blue Dot distribution to us of $10.0 million. The increase in restricted cash held by discontinued operations during 2003 was primarily due to proceeds received from location sales by Blue Dot and the sale of Netexit’s assets to Avaya offset by cash used in operations through the sale date.

Financing Transaction

On June 30, 2005, we entered into an amended and restated credit agreement that replaced our existing $225 million secured credit facility with an unsecured $200 million senior revolving line of credit with lower borrowing costs. The previous credit facility consisted of a $125 million five-year revolving tranche and a $100 million seven-year term tranche (senior secured term loan B.) In addition, because the amended and restated line of credit is unsecured, the $225 million of first mortgage bond collateral securing the previous facility was released by the lenders. The unsecured revolving line of credit will mature on November 1, 2009 and does not amortize. The facility bears interest at a variable rate based upon a grid which is tied to our credit rating from Fitch Investors Service (Fitch), Moody’s Investors Service (Moody’s), and Standard and Poor’s Rating Group (S&P). The ‘spread’ or ‘margin’ ranges from 0.625% to 1.75% over the London Interbank Offered Rate (LIBOR). The facility currently bears interest at a rate of approximately 5.8%, which is 1.125% over LIBOR.

The amended and restated line of credit continues to include covenants similar to the previous credit facility, which require us to meet certain financial tests, including a minimum interest coverage ratio and a minimum debt to capitalization ratio. The amended and restated line of credit 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, and enter into transactions with affiliates. Many of these restrictive covenants will fall away upon the line of credit being rated “investment grade” by two of the three major credit rating agencies consisting of Fitch, Moody’s and S&P. As of December 31, 2005, we are in compliance with all of the covenants under the amended and restated line of credit.

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Credit Ratings

S&P, Moody’s and 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 February 24, 2006, our ratings with these agencies are as follows:

	Senior Secured Rating		Senior Unsecured Rating		Corporate Rating	Outlook
S&P	BB+	*	B+	*	BB	Developing
Moody’s	Ba1		Ba2		N/A	Positive
Fitch	BBB-		BB+		BB+	Evolving

*S&P ratings are tied to the corporate credit rating. By formula, the secured rating is one level above the corporate rating, and the unsecured rating is two levels below the corporate rating.

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. Our credit ratings have remained consistent during the fourth quarter.

NEW ACCOUNTING STANDARDS

See Note 2 of “Notes to Consolidated Financial Statements,” included in Item 8 herein for a discussion of new accounting standards.

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.

Interest Rate Risk

We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We primarily use fixed rate debt and limited variable rate long-term debt to partially finance mandatory debt retirements. These variable rate debt agreements expose us to market risk related to changes in interest rates. We manage this risk by taking advantage of market conditions when timing the placement of long-term or permanent financing. All of our debt has fixed interest rates, with the exception of our new credit facility entered into on June 30, 2005, which bears interest at a variable rate (currently approximately 5.8%) tied to the London Interbank Offered Rate (LIBOR). Based upon amounts outstanding as of December 31, 2005, a 1% increase in the LIBOR would increase annual interest expense on this line of credit by approximately $0.8 million.

During the second quarter of 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposure associated with anticipated refinancing transactions. While we are exposed to changes in the fair value of these instruments, they are designed such that any economic loss in value is generally offset by interest rate savings at the time the future anticipated financing is completed. Changes in the fair value of these instruments are recorded into equity and then reclassified into earnings in the same period during which the item being hedged affects earnings. At December 31, 2005, the market value of these instruments, representing the amount we would receive upon their termination, was approximately $8.8 million.

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Commodity Price Risk

Commodity price risk is one our most significant risks due to our position as the default supplier in Montana, and our lack of ownership of regulated generation assets within the Montana market. Several factors influence price levels and volatilities. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

As part of our overall strategy for fulfilling our requirement as the default supplier in Montana, we employ the use of market purchases, including forward purchase and sales contracts. These types of contracts are included in our default supply portfolio and are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. While we may incur gains or losses on individual contracts, the overall portfolio approach is intended to provide price stability for consumers, therefore these supply costs are included in our cost tracking mechanisms.

In our unregulated electric segment, due to our lease of the Colstrip Unit 4 generation facility, we are exposed to the market price fluctuations of electricity. We have entered into forward contracts for the sale of a significant portion of Colstrip Unit 4’s generation through 2006. To the extent Colstrip Unit 4 experiences any unplanned outages, we would need to secure the quantity deficiency from the wholesale market to fulfill our forward sales contracts. As of December 31, 2005, market prices exceeded our contracted forward sales prices by approximately $8.6 million. To mitigate price risk, during the second quarter of 2005 we implemented a risk management strategy of utilizing put options in conjunction with our forward fixed price sales of expected generation output. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Income (Loss) until delivery or settlement occurs. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement.

In our unregulated natural gas segment, we currently have a capacity contract with a pipeline that gives us basis risk depending on gas prices at two different delivery points. We have sales contracts with certain customers that provide for a selling price based on the index price of gas coming from a delivery point in Ventura, Iowa. The pipeline capacity contract allows us to take delivery of gas from Canada, which is typically cheaper than gas coming from Ventura, even when including transportation costs. If the Canadian gas plus transportation cost exceeds the index price at Ventura, then we will lose money on these gas sales.

Counterparty Credit Risk

We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management’s view, reduce our overall credit risk. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The consolidated financial information, including the reports of independent accountants, the quarterly financial information, and the financial statement schedules, required by this Item 8 is set forth on pages F-1 to F-48 of this Annual Report on Form 10-K and is hereby incorporated into this Item 8 by reference.

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

None

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ITEM 9A.CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to NorthWestern is made known to the officers who certify the financial statements and to other members of senior management and the Audit Committee of the Board of Directors.

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation our principal executive officer and principal financial officer have concluded that, as of December 31, 2005, our disclosure controls and procedures are effective to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

Changes in Internal Control Over Financial Reporting

Improved policies, procedures and control activities over regulated and unregulated energy procurement have been developed throughout 2004 and 2005.

During 2005, we believe we have improved control activities to meet the following objectives:

•Timely identification, evaluation, and reporting of energy supply transactions;

•Proper segregation of duties among front, mid, and back-office functions; and

•Proper assignment of responsibilities between regulated and unregulated front office employees.

These control activities and specific actions include:

•Reviewing and further developing our Energy Risk Management Policies which provide comprehensive and specific governance relating to the procurement of regulated and unregulated energy supply;

•Reorganizing our energy procurement front office to clarify employee roles and transactional responsibilities among front office, middle and back office functions, and providing for segregation of regulated and unregulated duties;

•Implementing new control activities to ensure the timely communication and evaluation of relevant contract and transactional information for financial reporting, thereby increasing the depth and frequency of back-office accounting reviews;

•Developing enhanced middle office control activities consisting of independent confirmation of transactions and the creation, communication and review of counter party credit reports, position reports, non-standard transactions, and other risk analyses;

•Ensuring that long-term commitments are properly hedged or fall within acceptable risk tolerances;

•Prohibiting speculative trading; and

•Improving our documentation of our energy procurement processes and control activities.

We will continue to monitor the sustainability of new controls on an ongoing basis and seek to identify improvements to existing controls. Except for these improvements described above, there have been no other changes in our internal control over financial reporting during the year ended December 31, 2005 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Management’s Report on Internal Controls over Financial Reporting

The management of NorthWestern is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to

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our management and Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal controls over financial reporting, no matter how well designed, have inherent limitations, including the possibility of human error and the circumvention or overriding of controls. Therefore, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal controls over financial reporting may vary over time.

Our management, including our chief executive officer and chief financial officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2005. In making its assessment of internal control over financial reporting, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework. Based on our evaluation, management concluded that as of December 31, 2005 our internal control over financial reporting was effective based on those criteria.

NorthWestern’s independent auditors have issued an attestation report on our assessment of our internal control over financial reporting. This report appears on page F-3.

ITEM 9B.OTHER INFORMATION

Not applicable.

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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 Feb. 28, 2006
Michael J. Hanson	President and Chief Executive Officer since May 20, 2005; formerly President since March 2005; Chief Operating Officer since August 2003; and formerly President and Chief Executive Officer of NorthWestern’s utility operations (1998-2003). Prior to joining NorthWestern, Mr. Hanson was General Manager and Chief Executive of Northern States Power Company of South Dakota and North Dakota in Sioux Falls, S.D. (1994-1998). Mr. Hanson serves on the board of directors of various NorthWestern subsidiaries.	47
Brian B. Bird	Vice President and Chief Financial Officer since December 2003. Prior to joining NorthWestern, 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, MN (1997-2002). Mr. Bird serves on the board of directors of various NorthWestern subsidiaries.	43
Patrick R. Corcoran	Vice President-Government and Regulatory Affairs since February 2002; and formerly Vice President-Regulatory Affairs for the former Montana Power Company since September 2000.	54
David G. Gates	Vice President-Wholesale Operations since September 2005; formerly Vice President-Transmission Operations since May 2003; and formerly Executive Director-Distribution Operations since January 2003; formerly Executive Director-Distribution Operations for the former Montana Power Company (1996-2002).	49
Kendall G. Kliewer	Controller since June 2004, formerly Chief Accountant since November 2002. Prior to joining NorthWestern, Mr. Kliewer was a Senior Manager at KPMG LLP (1999-2002).	36
Thomas J. Knapp	Vice President, General Counsel and Corporate Secretary since November 2004; and formerly Vice President and Deputy General Counsel since March 2003; formerly consultant to NorthWestern since May 2002. Prior to joining NorthWestern, Mr. Knapp was Of Counsel at Paul, Hastings, Janofsky &Walker (2000-2002). Mr. Knapp serves on the board of directors of various NorthWestern subsidiaries.	53
Curtis T. Pohl	Vice President-Retail Operations since September 2005; formerly Vice President-Distribution Operations since August 2003; formerly Vice President-South Dakota/Nebraska Operations since June 2002; and formerly Vice President-Engineering and Construction since June 1999. Mr. Pohl serves on the board of directors of various NorthWestern subsidiaries.	41
Bobbi L. Schroeppel	Vice President-Customer Care and Communications since September 2005; formerly Vice President-Customer Care since June 2002; formerly Director-Staff Activities and Corporate Strategy since August 2001; and formerly Director-Corporate Strategy since June 2000.	37
Bart A. Thielbar	Vice President-Information Technology since June 2002; formerly Vice President-Communications & IT of NorthWestern’s utility operations since February 2000.	38
Gregory G. A. Trandem	Vice President-Administrative Services since September 2005; formerly Vice President-Support Services since March 2004; formerly Vice President-Asset Management since June 2002; and formerly Vice President-Energy Operations since August 1999.	54

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The Chief Executive Officer, President, Corporate Secretary and Treasurer are elected annually by the Board of Directors. Other officers may be elected or appointed by the Board of Directors at any meeting but are generally also elected annually by the Board. All officers serve at the pleasure of the Board of Directors. Mr. Hanson was serving as an executive officer at the time NorthWestern Corporation filed for bankruptcy.  Mr. Bird was serving as an executive officer of Netexit, Inc. when the entity 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 Feb. 28, 2006
Stephen P. Adik	Retired Vice Chairman (2001-2003) of NiSource Inc. (NYSE: NI), an electric and natural gas production, transmission and distribution company; and formerly Senior Executive Vice President and Chief Financial Officer (1998-2001), and Executive Vice President and Chief Financial Officer (1996-1998), of NiSource. Mr. Adik serves on the board of Beacon Power (NASDAQ: BCON), a designer and manufacturer of power conversion and sustainable energy storage systems for the distributed generation, renewable energy, and backup power markets.	2004	62
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), Dr. Draper serves on the boards of directors of Alliance Data Systems Corporation (NYSE: ADS), a provider of transaction services, credit services and marketing services; Alpha Natural Resources Inc. (NYSE: ANR), a coal producer; Temple-Inland Inc. (NYSE: TIN), a corrugated packing, forest products and financial services business; and TransCanada (NYSE: TRP) transporter and marketer of natural gas in Canada and the United States.	2004	64
Jon S. Fossel	Retired Chairman, President and Chief Executive Officer of Oppenheimer Management Corporation, a mutual fund investment company (“Oppenheimer”) (1989-1996). Mr. Fossel serves on the board of directors of UnumProvident Corporation (NYSE: UNM), a disability and life insurance provider.	2004	64
Michael J. Hanson	President and Chief Executive Officer of NorthWestern Corporation since May 20, 2005; formerly President since March 2005; formerly Chief Operating Officer since August 2003; and formerly President and Chief Executive Officer of NorthWestern’s utility operations (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, S.D. (1994-1998). Mr. Hanson serves on the board of directors of various NorthWestern subsidiaries.	2005	47

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Director	Principal Occupation or Employment	Director Since	Age on Feb. 28, 2006
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; and was formerly Sr. Vice President-Communications & Marketing for Military Commercial Technologies, Inc. (MILCOM). Ms. Johnson served as Commission Chairman (1997-1999) and Commissioner (1992-1997) for the Florida Public Service Commission. 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	43
Philip L. Maslowe	Formerly nonexecutive Chairman of the Board (2002-2004) for AMF Bowling Worldwide, Inc.; formerly Executive Vice President and Chief Financial Officer (1997-2002) of The Wackenhut Corporation, a security, staffing and privatized prisons corporation; and formerly Executive Vice President and Chief Financial Officer (1993-1997) of Kindercare Learning Centers, a provider of learning programs for preschoolers.	2004	59
D. Louis Peoples	President and Founder of Nyack Management Company, Inc., a nationwide general business consulting firm, since 2004; and retired Chief Executive Officer and Vice Chairman of the board of directors of Orange and Rockland Utilities, Inc. (1994-1999). Mr. Peoples serves on the board of directors of the Center for Clean Air Policy and the Nevada Area Council, Boy Scouts of America.	2006	65

Audit Committee

The Audit Committee provides oversight of (i) the financial reporting process, the system of internal controls and the audit process of NorthWestern, and (ii) NorthWestern’s independent auditor. The Audit Committee also recommends to the Board the appointment of NorthWestern’s independent auditor. On September 23, 2005, the Board adopted a revised Audit Committee Charter (Audit Charter). As required by the Audit Charter, each of the members of the Audit Committee is an independent director as defined by NASD Rule 4200(a)(15).

The Audit Committee is composed of four nonemployee directors who are financially literate in financial and auditing matters and are “independent” as defined by the SEC. The members of the Audit Committee are Chairman Stephen P. Adik, Jon S. Fossel, Philip L. Maslowe and D. Louis Peoples. Audit Committee Chairman Adik has been identified as the Committee’s financial expert, as defined in Item 401(h)(2) of Regulation S-K. The Audit Committee held 10 meetings during 2005.

Code of Ethics

Our Board of Directors adopted our revised Code of Business Conduct and Ethics (Code of Conduct) on January 26, 2005, and reviews it annually. Our Code of Conduct sets forth standards of conduct for all officers, directors and employees of NorthWestern and our subsidiary companies, including all full- and part-time employees and certain persons that provide services on our behalf, such as agents. Our Code of Conduct 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 Conduct. In addition, on August 26, 2003, our former 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. The CEO and CFO Code of Ethics along with the complaint procedures are also available on NorthWestern’s Web site.

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ITEM 11.EXECUTIVE COMPENSATION

Compensation of Directors and Executive Officers

We are required to disclose compensation earned during fiscal years 2005, 2004 and 2003 for our Chief Executive Officer and each of the four most highly compensated persons who were executive officers as of December 31, 2005. 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 2005. 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 2005:

Name and Principal Position	Year	Salary $	Bonus $(1)	Restricted Stock Awards ($)(2)	Awards (Securities Underlying Options)(2)(#)	LTIP Payouts ($)	All Other Compensation ($)(3)
Michael J. Hanson	2005	350,000	258,241	—	—	—	368,189
President and	2004	350,000	233,334	714,400	—	—	31,539
Chief Executive Officer	2003	355,609	—	—	—	—	27,916
Brian B. Bird	2005	275,000	84,541	—	—	—	111,645
Vice President and	2004	275,000	350,000	428,800	—	—	43,081
Chief Financial Officer	2003	15,865	75,000	—	—	—	37
Thomas J. Knapp	2005	250,000	134,765	—	—	—	59,332
Vice President, General Counsel	2004	224,038	66,000	106,000	—	—	23,526
and Corporate Secretary	2003	177,692	35,000	—	15,000	—	5,751
Gregory G. A. Trandem	2005	189,000	111,056	—	—	—	229,305
Vice President -	2004	182,000	43,680	87,400	—	—	24,653
Administrative Services	2003	184,917	—	—	—	—	36,921
Curtis T. Pohl	2005	185,000	110,253	—	—	—	30,588
Vice President -	2004	185,000	44,400	88,800	—	—	24,382
Retail Operations	2003	169,022	—	—	—	—	76,292
Gary G. Drook (4)	2005	260,769	282,500	—	—	—	1,204,267
Former President and Chief	2004	565,000	565,000	2,059,200	—	—	98,189
Executive Officer	2003	544,355	600,000	1,143,332	335,643	—	216,744

(1)Bonuses in 2005 include amounts related to NorthWestern’s 2005 Employee Incentive Plan earned for 2005 and payable in 2006. The 2005 amounts also include bonuses earned and paid on January 31, 2005 in accordance with the court-approved Incentive Compensation and Severance Plan of $116,666 for Mr. Hanson, $66,000 for Mr. Knapp, $43,680 for Mr. Trandem, $44,400 for Mr. Pohl, and $282,500 for Mr. Drook. 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. Mr. Bird’s bonuses for 2004 and 2003 were in accordance with an employment agreement that expired during 2005. Mr. Knapp’s 2003 bonus was related to a retention agreement, and Mr. Drook’s bonus for 2003 was related to the start of his employment, and were earned and paid in the year shown.

(2)All options and restricted stock granted prior to October 31, 2004, were cancelled upon emergence from bankruptcy. Restricted stock was awarded on 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. Hanson was awarded 35,720 shares, which had a market value $1,109,820 at December 31, 2005. Mr. Bird was awarded 21,440 shares, which had a market value of $666,141 at December 31, 2005. Mr. Knapp was awarded 5,300 shares, which had a market value of $164,671 at December 31, 2005. Mr. Trandem was awarded 4,370 shares, which had a market value of $135,776 at December 31, 2005.  Mr. Pohl was awarded 4,440 shares, which had a market value of $137,951 at December 31, 2005. Pursuant to the Plan, 50% of the Grants vested on November 1, 2004. Based upon a vesting scheduled approved by the Board, 10% of the remaining restricted stock vested on November 1, 2005, and the remaining 40% of the Grants vest for Named Executive Officers according to the following schedule:  20% on November 1, 2006; and 20% on November 1, 2007. Mr. Drook’s remaining 51,480 shares vested effective June 1, 2005, pursuant to agreement, with a market value of $1,489,316.

(3)The 2004 and 2005 amounts include employer benefit contributions, as applicable, for medical, dental, vision, employee assistance program, group term life, and 401(k) company matching contribution, vehicle lease or car allowances, relocation expenses (Mr. Bird, $77,053), tax gross up payments (where provided), severance (Mr. Drook), merit cash, imputed income for use of company-owned properties and imputed income for reimbursement of temporary living expenses (Mr. Knapp, $25,000) as well as an airplane allowance for Mr. Drook ($60,950 in 2004 and $17,375 in 2005) and Mr. Hanson ($7,533 in 2004). On March 10, 2005, the Board amended NorthWestern’s Aircraft Use Policy to no longer allow personal use of the company aircraft. Bankruptcy settlements associated with termination of the supplemental excess retirement plan are included for Mr. Hanson ($329,714), and Mr. Trandem ($205,807) in 2005. Amounts for 2003 include employer benefit contributions for supplement 401(k) and other post-retirement plans prior to termination of those plans.

(4)Mr. Drook served as President and Chief Executive Officer through March 29, 2005 but continued as an employee until June 3, 2005. Mr. Drook’s other compensation includes severance payments totaling $1,130,000 that were paid between June 3 and December 31, 2005, and $35,222 for health and welfare benefit coverage continuation that was paid on June 24, 2005.  In addition, Mr. Drook’s remaining 51,480 shares of unvested restricted stock were fully vested on June 1, 2005.  The severance and benefit continuation payments and restricted stock vesting were required as part of a

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June 1, 2005, agreement with Mr. Drook. Mr. Drook’s 2005 bonus of $282,500 was paid on January 31, 2005, and was in accordance with the Bankruptcy Court approved Incentive Compensation and Severance Plan.  In consideration of the severance and benefits continuation payments, Mr. Drook has agreed to make himself available to respond to reasonable requests for information or assistance on matters in which Mr. Drook was involved during his employment. In addition, pursuant to terms included in Mr. Drook’s severance agreement, NorthWestern purchased his Sioux Falls residence at a fair market value of $930,000 determined pursuant to an agreed-upon appraisal process.

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 Contracts

An Employment Agreement with Chief Financial Officer Brian B. Bird, as amended and approved by the Bankruptcy Court in its Order dated January 13, 2004, expired on December 1, 2005.

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, 2005, Mr. Hanson, Mr. Bird, Mr. Knapp, Mr. Trandem and Mr. Pohl were participants in the retirement plan applicable to South Dakota and Nebraska employees. Mr. Drook is no longer a participant in the retirement plan due to his termination of employment.

For the South Dakota and Nebraska plan, effective January 1, 2000, NorthWestern offered its employees two alternatives. An employee could convert his or her existing accrued benefit from the 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) 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, plus 1.75% of such earning in excess of the covered compensation base, multiplied by all years of credited service.

Assuming the Named Executive Officers reach the normal retirement age of 65, the projected life annuity benefits would be: Mr. Hanson, $37,828; Mr. Bird, $36,290; Mr. Knapp, $17,062; Mr. Trandem, $16,463 and Mr. Pohl, $68,912. In 2005, NorthWestern contributed the following amounts for the Named Executive Officers, through contributions and interest credits under the retirement plan: Mr. Hanson, $12,927; Mr. Bird, $10,396; Mr. Knapp, $10,766; Mr. Trandem, $10,558; Mr. Pohl, $16,276; and Mr. Drook, $10,832. As of December 31, 2005, the cash balance for the Named Executive Officers were as follows: Mr. Hanson, $74,829; Mr. Bird, $20,535; Mr. Knapp, $28,481; Mr. Trandem, $49,786; and Mr. Pohl, $131,534. Mr. Drook received a lump sum payment of $28,419 on July 5, 2005.

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Other Benefits

NorthWestern currently maintains a variety of benefit plans and programs, which are generally available to all NorthWestern employees, including executive officers, such as the 401(k) Retirement Plan under which an employee may contribute up to 100% of his or her salary subject to the IRS contribution limits (with NorthWestern matching up to 4% contributed by the employee), medical, dental, vision, term life and supplemental life insurance coverage, short-term and long-term disability, and other general employee benefits such as paid time off and educational assistance.

Human Resources Committee Interlocks and Insider Participation

The Human Resources Committee of the Board of Directors is composed of not less than three nonemployee directors. The members of the Human Resources Committee are Chairman Philip L. Maslowe, Stephen P. Adik, and Julia L. Johnson. None of the persons who served as members of the Human Resources Committee of the Board during fiscal 2005 are officers or employees or former employees of NorthWestern or any of our subsidiaries. In addition, no executive officer of NorthWestern or any of its subsidiaries served as a member of the board of directors or compensation committee of any other entity.

Director Compensation

Compensation rates for nonemployee directors for 2005 were as follows:

	$		Shares
Annual Board Retainer*
Initial Stock Grant (sign-on grant as a new member)	—		1,000
Board Chair	$	100,000	3,000
Board Member	$	25,000	2,000
Annual Committee Chair Retainer*
Audit Committee	$	8,000	—
Governance Committee	$	6,000	—
Human Resources Committee	$	6,000	—
Meeting Fees**
Board Meeting	$	1,250	—
Committee Meeting	$	1,250	—

* Cash-based retainers are paid quarterly in advance of the current fiscal quarter.

** The Chairman of the Board does not receive meeting fees.

NorthWestern also reimburses nonemployee directors for the cost of participation in certain continuing education programs and travel costs to meetings. Employee directors are not compensated for service on the Board.

Nonemployee directors may elect to defer up to 100% of any qualified compensation that would be otherwise payable to him or her, subject to compliance with NorthWestern’s 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Code. The deferred compensation may be invested in deferred stock units or designated investment funds. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall receive a distribution equal to one share of common stock for each deferred stock unit either in a lump sum or in approximately equal installments over a designated number years (not to exceed 10 years).

Once received, each member must retain at least one times his or her annual Board and committee chair retainer(s) in common stock or deferred stock units.

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

Security Ownership by Certain Beneficial Owners and Management

The following table sets forth certain information as of December 31, 2005, with respect to the beneficial ownership of shares of NorthWestern’s Common Stock owned by the directors, nominees for director, the

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Named Executive Officers, and by all directors and executive officers of NorthWestern as a group. Except under special circumstances, NorthWestern’s Common Stock is the only class of voting securities. Such information (other than with respect to our directors and executive officers) is based on a review of statements filed with the SEC pursuant to Sections 13(d), 13(f) and 13(g) of the Securities Exchange Act of 1934.

	Amount and Nature of Beneficial Ownership(1)		Percent of
Name of Beneficial Owner	Shares of Common Stock Beneficially Owned		Common Stock
HMC Investors LLC 1 Riverchase Parkway S Birmingham, AL 35244-2008	8,831,762	(2)	23.8	%
Fortress Investments Group LLC 1251 Avenue of the Americas, Suite 1600 New York, NY 10020	2,115,069		5.9	%
Fidelity Management and Research Co 1 Federal Street Boston, MA 02110-2003 US	2,000,000		5.6	%
Franklin Mutual Advisors, LLC 51 John F. Kennedy Parkway Short Hills, NJ 07078	1,890,468		5.3	%
Stephen P. Adik	4,000		*
E. Linn Draper, Jr.	6,949		*
Michael J. Hanson	35,122		*
Jon S. Fossel	3,000		*
Julia L. Johnson	4,799		*
Philip L. Maslowe	5,186		*
D. Louis Peoples.	—		—
Brian B. Bird	18,038		*
Thomas J. Knapp	4,207		*
Curtis T. Pohl	3,576		*
Gregory G. A. Trandem	3,533		*
Gary G. Drook	—		—
All directors and executive officers	101,978		*

*Less than 1%.

(1)The number of shares noted are those beneficially owned, as determined under the rules of the SEC, and such information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which a person has sole or shared voting power or investment power and any shares which the person has the right to acquire within 60 days through the exercise of option, warrant or right.

(2)Includes 1,525,367 warrants to purchase additional shares of NorthWestern’s Common Stock.

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

Section 16(A) Beneficial Ownership Reporting Compliance

Based solely on information furnished to us and contained in reports filed with the SEC, as well as written representations that no other reports were required, NorthWestern believes that during 2005 all SEC filings of its directors and executive officers complied with the requirements of Section 16 of the Securities Exchange

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Act of 1934, as amended except for the following: a Form 4 for Gregory G. A. Trandem reporting the sale of 4,424 shares of common stock on August 17, 2005.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None

ITEM 14.PRINCIPAL ACCOUNTANTS FEES AND SERVICES

The following table is a summary of the fees billed to us by Deloitte & Touche, LLP (Deloitte) for professional services for the fiscal years ended December 31, 2005 and December 31, 2004:

Fee Category	Fiscal 2005 Fees		Fiscal 2004 Fees
Audit fees	$	1,825,000	$	2,736,000
Audit-related fees	124,000		101,000
Tax fees	1,226,000		2,216,000
All other fees	—		—
Total fees	$	3,175,000	$	5,053,000

Audit Fees

Consists of fees billed for professional services rendered for the audit of our financial statements, internal control over financial reporting and review of the interim financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filings or engagements.

Audit-related Fees

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

Tax Fees

Consists of fees billed for professional services for tax compliance of $0.2 million and $1.4 million for the years ended December 31, 2005 and 2004, respectively, and tax consulting of $1.0 million and $0.8 million for the years ended December 31, 2005 and 2004, respectively. These services include assistance regarding federal and state tax compliance, tax audit defense and bankruptcy tax planning.

All Other Fees

Consists of fees for products and services other than the services reported above. In fiscal 2005 and 2004, 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 2005, the Audit Committee approved all such services undertaken by Deloitte before engagement for such services.

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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 Year Ended December 31, 2005, Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 and Year Ended December 31, 2003 (Predecessor Company)	F-4
Consolidated Statements of Cash Flows (as revised) for the Year Ended December 31, 2005, Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 and Years Ended December 31, 2003 (Predecessor Company)	F-5
Consolidated Balance Sheets as of December 31, 2005 and December 31, 2004 (Successor Company)	F-6
Consolidated Statement of Shareholders’ Equity (Deficit) for the Year Ended December 31, 2005, Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 (Successor Company) and Year Ended December 31, 2003 (Predecessor Company)	F-7
Notes to Consolidated Financial Statements	F-8
Quarterly Unaudited Financial Data for the Two Years Ended December 31, 2005	F-47

(2)Financial Statement Schedules

Schedule II. Valuation and Qualifying Accounts

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

(3)Exhibits.

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

Exhibit Number	Description of Document
2.1(a)	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).

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Exhibit Number	Description of Document
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).
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

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Exhibit Number	Description of Document
	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).

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Exhibit Number	Description of Document
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

81

Exhibit Number	Description of Document
	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, effective January 1, 2005 through December 31, 2005 (incorporated by reference to Exhibit 10.1(a) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 0-692).
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 (incorporated by reference to Exhibit 10.1(c) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 0-692).
10.1(d) †	NorthWestern Corporation Incentive Compensation and Severance Plan, effective through November 1, 2004 (incorporated by reference to Exhibit 10.1(d) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 0-692).
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).
10.1(f) †	NorthWestern Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation’s registration statement on Form S-8, dated May 4, 2005, Commission File No. 333-124624).
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).
10.2(b)	Credit Agreement, dated as of June 30, 2005, among NorthWestern Corporation, as borrower,

82

Exhibit Number	Description of Document
	the several lenders from time to time parties thereto, Deutsche Bank Securities Inc. and Lehman Brothers Inc., as joint lead arrangers, Lehman Commercial Paper Inc., as syndication agent, Union Bank of California, N.A. and KeyBank National Association, as co-documentation agents, and Deutsche Bank AG New York Branch, as administrative agent and collateral agent (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated June 28, 2005, 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 Michael J. Hanson 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.

**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.

83

SIGNATURES

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

	NORTHWESTERN CORPORATION
Dated: March 3, 2006	By:	/s/ MICHAEL J. HANSON
		Michael J. Hanson
		President and Chief Executive Officer

POWER OF ATTORNEY

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

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

Signature	Title	Date
/s/ E. LINN DRAPER, JR.	Chairman of the Board	March 3, 2006
E. Linn Draper, Jr.
/s/ MICHAEL J. HANSON	President, Chief Executive Officer and Director	March 3, 2006
Michael J. Hanson	(Principal Executive Officer)
/s/ BRIAN B. BIRD	Vice President and Chief Financial Officer	March 3, 2006
Brian B. Bird	(Principal Financial Officer)
/s/ KENDALL G. KLIEWER	Controller	March 3, 2006
Kendall G. Kliewer	(Principal Accounting Officer)
/s/ STEPHEN P. ADIK	Director	March 3, 2006
Stephen P. Adik
/s/ JULIA L. JOHNSON	Director	March 3, 2006
Julia L. Johnson
/s/ JON S. FOSSEL	Director	March 3, 2006
Jon S. Fossel
/s/ PHILIP L. MASLOWE	Director	March 3, 2006
Philip L. Maslowe
/s/ D. LOUIS PEOPLES	Director	March 3, 2006
D. Louis Peoples

84

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

	Page
Financial Statements
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated statements of income (loss) for the year ended December 31, 2005 (Successor Company), two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 and year ended December 31, 2003 (Predecessor Company)	F-4
Consolidated statements of cash flows for the year ended December 31, 2005 (Successor Company) for the two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 and year ended December 31, 2003 (Predecessor Company)	F-5
Consolidated balance sheets as of December 31, 2005 (Successor Company) and December 31, 2004 (Successor Company)	F-6
Consolidated statements of common shareholders’ equity (deficit) for the year ended December 31, 2005 (Successor Company) for the two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 (Successor Company) and year ended December 31, 2003 (Predecessor Company)	F-7
Notes to consolidated financial statements	F-8
Financial Statement Schedules
Schedule II. Valuation and Qualifying Accounts

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of NorthWestern Corporation:

We have audited the accompanying consolidated balance sheets of NorthWestern Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2005 and 2004 (Successor Company), and the related consolidated statements of income (loss), common shareholders’ equity (deficit), and cash flows for the year ended December 31, 2005 and the period November 1, 2004 through December 31, 2004 (Successor Company) and for the period January 1, 2004 through October 31, 2004 and year ended December 31, 2003 (Predecessor Company).  Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2).  These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of NorthWestern Corporation and subsidiaries as of December 31, 2005 and 2004 (Successor Company), and the results of their operations and their cash flows for the year ended December 31, 2005 and the period November 1, 2004 through December 31, 2004 (Successor Company) and for the period January 1, 2004 through October 31, 2004 and year ended December 31, 2003 (Predecessor Company), in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Notes 1 and 3 to the consolidated financial statements, the Predecessor NorthWestern Corporation filed a petition for reorganization under Chapter 11 of the Federal Bankruptcy Code on September 14, 2003. NorthWestern Corporation’s Plan of Reorganization was substantially consummated on October 31, 2004 and the Successor NorthWestern Corporation emerged from bankruptcy. In connection with its emergence from bankruptcy, the Successor NorthWestern Corporation adopted fresh-start reporting in conformity with AICPA Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code, for the Successor Company as a new entity having carrying values not comparable with prior periods.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 3, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 3, 2006

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of NorthWestern Corporation:

We have audited management’s assessment, included in the accompanying “Management’s Report on Internal Controls over Financial Reporting” included in Item 9A, that NorthWestern Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.  Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2005 of the Company and our report dated March 3, 2006 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 3, 2006

F-3

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(in thousands, except per share amounts)

	Successor Company						Predecessor Company
	Year Ended			November 1-			January 1-			Year Ended
	December 31,			December 31,			October 31,			December 31,
	2005			2004			2004			2003
OPERATING REVENUES	$	1,165,750		$	205,952		$	833,037		$	1,012,515
COST OF SALES	641,755			116,775			447,054			535,667
GROSS MARGIN	523,995			89,177			385,983			476,848
OPERATING EXPENSES
Operating, general and administrative	225,514			35,958			185,782			239,716
Property and other taxes	72,087			10,766			54,369			67,542
Depreciation	74,413			12,174			60,674			70,252
Reorganization items	7,529			437			(533,063		)	8,266
Impairment on assets held for sale	—			10,000			—			12,399
TOTAL OPERATING EXPENSES	379,543			69,335			(232,238		)	398,175
OPERATING INCOME	144,452			19,842			618,221			78,673
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)	(61,295		)	(11,021		)	(72,822		)	(147,626		)
Gain (Loss) on Debt Extinguishment	(548		)	(21,310		)	—			3,300
Investment and Other Income	17,448			1,039			2,121			(5,977		)
Income (Loss) From Continuing Operations Before Income Taxes	100,057			(11,450		)	547,520			(71,630		)
Income Tax (Expense) Benefit	(38,510		)	4,930			1,369			48
Income (Loss) From Continuing Operations	61,547			(6,520		)	548,889			(71,582		)
Discontinued Operations, Net of Taxes	(2,080		)	(424		)	2,488			(42,143		)
Net Income (Loss)	59,467			(6,944		)	551,377			(113,725		)
Minority Interests on Preferred Securities of Subsidiary Trusts	—			—			—			(14,945		)
Earnings (Loss) on Common Stock	$	59,467		$	(6,944	)	$	551,377		$	(128,670	)
Average Common Shares Outstanding	35,630			35,614
Basic Income (Loss) per Average Common Share
Continuing operations	$	1.73		$	(0.18	)
Discontinued operations	(0.06		)	(0.01		)
Basic	$	1.67		$	(0.19	)
Diluted Income (Loss) per Average Common Share
Continuing operations	$	1.71		$	(0.18	)
Discontinued operations	(0.06		)	(0.01		)
Diluted	$	1.65		$	(0.19	)
Dividends Declared per Average Common Share	$	1.00		$	—

See Notes to Consolidated Financial Statements

F-4

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Successor Company						Predecessor Company
	December 31, 2005			November 1- December 31, 2004			January 1- October 31, 2004			December 31, 2003
Operating Activities:
Net Income (Loss)	$	59,467		$	(6,944	)	$	551,377		$	(113,725	)
Items not affecting cash:
Depreciation	74,413			12,174			60,674			70,252
Amortization of debt issue costs, discount and deferred hedge gain	2,384			349			9,845			12,078
Amortization of restricted stock	4,716			190			2,639			731
(Gain) Loss on debt extinguishment	548			21,310			—			(3,300		)
Impairment on assets held for sale	—			10,000			—			12,399
(Income) Loss on discontinued operations, net of taxes	2,080			424			(2,488		)	42,143
Gain on qualifying facility contract amendment	(4,888		)	—			—			—
Cancellation of indebtedness income	—			—			(558,053		)	—
(Gain) Loss on reorganization items	2,039			—			(13,900		)	—
(Gain) Loss on sale of assets	(4,946		)	630			3,918			264
Impairment of note receivable	—			—			—			9,073
Deferred income taxes	40,746			(3,938		)	—			—
Changes in current assets and liabilities:
Accounts receivable	(18,639		)	(46,387		)	11,663			(14,819		)
Inventories	(3,776		)	1,579			(12,207		)	(614		)
Prepaid energy supply costs	28,524			(1,230		)	25,006			(53,391		)
Other current assets	4,204			7,416			14,267			(10,323		)
Accounts payable	12,364			(1,260		)	14,454			22,626
Accrued expenses	6,606			(27,925		)	44,970			1,502
Changes in regulatory assets	(5,762		)	5,225			23,638			(17,158		)
Changes in regulatory liabilities	(9,542		)	915			3,070			(19,369		)
Other noncurrent assets	(10,874		)	183			788			1,567
Other noncurrent liabilities	(29,154		)	(1,776		)	(13,479		)	(46,835		)
Cash flows provided by (used in) continuing operations	150,510			(29,065		)	166,182			(106,899		)
Investing Activities:
Restricted cash	(3,855		)	21,779			(12,501		)	1,226
Property, plant, and equipment additions	(80,877		)	(17,723		)	(62,391		)	(70,737		)
Proceeds from sale of assets	7,505			15,261			193			2,743
Proceeds from sale of investments	123,478			19,075			175,965			72,926
Purchases of investments	(118,800		)	(19,000		)	(175,875		)	—
Cash flows provided by (used in) investing activities of continuing Operations	(72,549		)	19,392			(74,609		)	6,158
Financing Activities:
Deferred gas storage	2,475			2,251			6,865			—
Proceeds from exercise of warrants	131			—			—			—
Dividends on common stock	(35,634		)	—			—			—
Minority interest on preferred securities of subsidiary trusts	—			—			—			(9,720		)
Issuance of long term debt	—			325,009			680			397,200
Repayment of long-term debt	(175,284		)	(398,284		)	(10,107		)	(26,979		)
Line of credit borrowings (repayments), net	81,000			—			—			(255,000		)
Equity registration fees	(140		)	—			—			—
Treasury stock purchases	(5,573		)	—			—			—
Financing costs	(2,257		)	(15,994		)	(207		)	(27,944		)
Cash flows provided by (used in) financing activities of continuing operations	(135,282		)	(87,018		)	(2,769		)	77,557
Discontinued operations
Operating cash flows of discontinued operations, net	(17,496		)	(44		)	(15,215		)	(16,928		)
Investing cash flows of discontinued operations, net	402			—			32,478			85,887
Financing cash flows of discontinued operations, net	—			—			—			(16,000		)
(Increase) decrease in restricted cash held by discontinued operations	60,048			9,964			(17,421		)	(41,146		)
Increase (Decrease) in Cash and Cash Equivalents	(14,367		)	(86,771		)	88,646			(11,371		)
Cash and Cash Equivalents, beginning of period	17,058			103,829			15,183			26,554
Cash and Cash Equivalents, end of period	$	2,691		$	17,058		$	103,829		$	15,183

See Notes to Consolidated Financial Statements

F-5

NORTHWESTERN CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	Successor Company
	December 31, 2005			December 31, 2004
ASSETS
Current Assets:
Cash and cash equivalents	$	2,691		$	17,058
Restricted cash	25,238			21,383
Accounts receivable, net	160,856			141,350
Inventories	40,925			37,149
Regulatory assets	38,640			13,152
Prepaid energy supply	1,754			30,278
Other	4,397			8,601
Assets held for sale	20,000			20,000
Deferred income taxes	10,520			26,237
Current assets of discontinued operations	8,472			71,091
Total current assets	313,493			386,299
Property, Plant, and Equipment, Net	1,409,205			1,379,060
Goodwill	435,076			435,076
Other:
Investments	1,297			5,608
Regulatory assets	204,466			224,192
Other	36,866			18,597
Noncurrent assets of discontinued operations	—			37
Total assets	$	2,400,403		$	2,448,869
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	156,455		$	73,380
Accounts payable	99,419			85,120
Accrued expenses	157,587			146,006
Regulatory liabilities	10,003			19,342
Current liabilities of discontinued operations	1,195			18,374
Total current liabilities	424,659			342,222
Long-term Debt	586,515			763,566
Deferred Income Taxes	100,192			72,366
Noncurrent Regulatory Liabilities	170,744			160,750
Other Noncurrent Liabilities	380,798			400,187
Noncurrent Liabilities of Discontinued Operations	—			443
Total liabilities	1,662,908			1,739,534
Commitments and Contingencies (Note 21)
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 35,794,494 and 35,602,253, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	358			355
Treasury stock at cost	(5,573		)	—
Paid-in capital	721,240			717,994
Unearned restricted stock	(383		)	(2,093		)
Retained earnings (deficit)	16,889			(6,944		)
Accumulated other comprehensive income	4,964			23
Total shareholders’ equity	737,495			709,335
Total liabilities and shareholders’ equity	$	2,400,403		$	2,448,869

See Notes to Consolidated Financial Statements

F-6

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, 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	)
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	114		—		—			4,566			(2,283		)	—			—			—			2,283
Issuance of warrants	—		—		—			3,782			—			—			—			—			3,782
Balance at October 31, 2004 (Successor Company)	35,614		—		$	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)	35,614		—		$	355		$	717,994		$	(2,093	)	$	—		$	(6,944	)	$	23		$	709,335
Net income	—		—		$	—		$	—		$	—		$	—		$	59,467		$	—		$	59,467
Other comprehensive income, net of tax:
Foreign currency translation adjustments	—		—		—			—			—			—			—			56			56
Unrealized gain on derivative instruments	—		—		—			—			—			—			—			4,885			4,885
Treasury stock repurchases	—		192		—			—			—			(5,573		)							(5,573		)
Issuance of restricted stock	98		—		3			3,255			—			—			—			—			3,258
Amortization of unearned restricted stock compensation	77		—		—			—			1,710			—			—			—			1,710
Warrants exercise	5		—		—			131			—			—			—			—			131
Equity registration fees	—		—		—			(140		)	—			—			—			—			(140		)
Dividends on common stock	—		—		—			—			—			—			(35,634		)	—			(35,634		)
Balance at December 31, 2005 (Successor Company)	35,794		192		$	358		$	721,240		$	(383	)	$	(5,573	)	$	16,889		$	4,964		$	737,495

See Notes to Consolidated Financial Statements

F-7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)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 628,500 customers in Montana, South Dakota and Nebraska under the trade name “NorthWestern Energy.” 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.

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.

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 after November 1, 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. For further information on the impact of fresh-start reporting see Note 3.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, Inc. (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 (f/k/a Expanets) 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 inclusion in discontinued operations results in a more meaningful presentation due to our negative investment, our expectation that the bankruptcy will be brief and our control of Netexit upon its emergence from bankruptcy. We expect Netexit to complete its liquidation during 2006.

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

F-8

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 $568.7 million through 2025. During the years ended December 31, 2005 and December 31, 2004 we purchased approximately $23.4 million and $24.2 million, respectively, of electric supply from this qualifying facility.  In addition, we have entered into a tolling contract with a third party to purchase up to 50 MW of power for twenty years beginning in 2006. The plant was under construction during 2005, is currently in a testing phase and is expected to be fully operational during 2006. This contract may constitute a VIE, however we have determined the contract is not material for consolidation and have included the estimated annual capacity and energy obligations of approximately $4.4 million in Note 21, Guarantees, Commitments and Contingencies.

(2)Significant Accounting Policies

Use of Estimates

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

Revenue Recognition

For our South Dakota and Nebraska operations, as prescribed by the respective regulatory authorities, electric and natural gas utility revenues are based on billings rendered to customers. For our Montana operations, as prescribed by the MPSC, operating revenues are recorded monthly on the basis of consumption or services rendered. Customers are billed monthly on a cycle basis. 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.

F-9

Accounts Receivable, Net

Accounts receivable are net of $2.2 million and $2.1 million of allowances for uncollectible accounts at December 31, 2005 and December 31, 2004, respectively. Receivables include unbilled revenues of $81.3 million and $58.1 million at December 31, 2005 and December 31, 2004, respectively.

Inventories

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

	December 31, 2005		December 31, 2004
Materials and supplies	$	14,073	$	13,653
Storage gas	26,852		23,496
	$	40,925	$	37,149

Regulation of Utility Operations

Our regulated operations are subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulations (SFAS No. 71). Accounting under SFAS No. 71 is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise’s cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers.

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 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 of $1.3 million and $5.6 million as of December 31, 2005 and December 31, 2004, respectively, consist primarily of life insurance contracts carried at their cash surrender value. Investments in life insurance contracts of $3.7 million that were held in trust and restricted for postretirement benefits as of December 31, 2004 were surrendered during 2005.

Derivative Financial Instruments

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price of electricity and natural gas commodities as discussed further in Note 8.  In order to manage these risks, we use both derivative and non-derivative contracts that may provide for settlement in cash or by delivery of a commodity, including:

•Forward contracts, which commit us to purchase or sell energy commodities in the future,

•Option contracts, which convey the right to buy or sell a commodity at a predetermined price, and

•Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity.

F-10

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchase and normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

For contracts in which we are hedging the variability of cash flows related to forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. The relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods in which earnings are affected by the variability of the cash flows of the related hedged item. Any ineffective portion of all hedges would be recognized in current-period earnings. Cash flows related to these contracts are classified in the same category as the transaction being hedged.

We have applied the normal purchases and normal sales scope exception, as provided by SFAS No. 133 and interpreted by Derivatives Implementation Guidance Issue C15, to certain contracts involving the purchase and sale of gas and electricity at fixed prices in future periods. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.  For certain regulated electric and gas contracts that do not physically deliver, in accordance with EITF 03-11, Reporting Gains and Losses on Derivative Instruments that are Subject to SFAS No. 133 and not “Held for Trading Purposes” as defined in Issue no. 02-3, revenue is reported net versus gross.

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 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 $6.0 million and $10.9 million as of December 31, 2005 and December 31, 2004, 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 8.7%, 9.0% and 8.9% for Montana for 2005, 2004 and 2003, and 8.7%, 7.9%, and 10.7% for South Dakota for 2005, 2004 and 2003, respectively. Interest capitalized totaled $1.3 million for the year ended December 31, 2005, $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 for the year ended December 31, 2003, respectively for Montana and South Dakota combined.

We may require contributions in aid of construction from customers when we extend service.  Amounts used from these contributions to fund capital additions were $8.9 million for the year ended December 31, 2005, $1.0 million for the two-months ended December 31, 2004, $2.9 million for the 10-months ended October 31, 2004.

F-11

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 3.4%, 3.5%, and 3.5% for 2005, 2004 and 2003, 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):

	December 31, 2005		December 31, 2004
Pension and other employee benefits	$	147,792	$	168,128
Future QF obligation, net	140,467		143,381
Environmental	44,600		45,317
Customer advances	28,060		25,269
Other	19,879		18,092
	$	380,798	$	400,187

Stock-based Compensation

We prospectively adopted SFAS No. 123-R, Share-Based Payment, upon emergence from bankruptcy, 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 was 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 earnings(loss) of the Predecessor Company would not have differed from the earnings(loss) reported for the period ended October 31, 2004 and year ended December 31, 2003.

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

F-12

company to transfer a portion of the insurance risk. Restricted cash held by this subsidiary was $8.0 million at December 31, 2005 and $10.0 million at December 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.

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. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are 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.

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 if we have prior regulatory authorization for recovery of 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 remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows.

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.

Emission Allowances

We have sulfur dioxide (SO2) emission allowances that we received with the acquisition of transmission and distribution assets in Montana.  Each allowance permits a generating unit to emit one ton of SO2 during or after a specified year.  We have approximately 3,200 excess SO2 emission allowances per year for years 2017 through 2031, however these allowances have no carrying value in our financial statements and the market for these years is presently illiquid.  These emission allowances are not subject to regulatory jurisdiction.  When excess SO2 emission allowances are sold, we reflect the gain in investment income and cash received is reflected as an investing activity.

New Accounting Standards

In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, or FIN 47. FIN 47 was issued to clarify the accounting for conditional asset retirement obligations in order to have more consistent recognition of liabilities relating to asset retirement obligations and additional information on expected future cash outflows and investments in long-lived assets. FIN 47 is effective for periods ended after December 15, 2005. Based on our evaluation, we recorded a conditional asset retirement obligation of approximately $3.2 million, primarily related to Department of Transportation requirements to

F-13

cut, purge and cap retired natural gas pipeline segments. Recognition of this amount increased our property, plant and equipment and other noncurrent liabilities. If we had applied the provisions of FIN 47 as of December 31, 2004, we would have recorded a conditional asset retirement obligation of approximately $3.0 million.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 requires retrospective application to prior periods’ financial statements of a voluntary change in accounting principle and that a change in method of depreciation, amortization, or depletion for long-lived, nonfinancial assets be accounted for as a change in accounting estimate that is effected by a change in accounting principle. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not believe the adoption of SFAS No. 154 will have a material impact on our results of operations or financial condition.

Reclassifications

Certain 2004 and 2003 amounts have been reclassified to conform to the 2005 presentation. We have revised the 2004 and 2003 Consolidated Statements of Cash Flows to reflect deferred gas storage arrangements as financing activities and reflect changes in restricted cash as investing activities. In the accompanying Consolidated Statements of Cash Flows we reclassified changes in restricted cash balances to be consistent with our 2005 presentation which resulted in a $21.8 million increase to investing cash flows and a corresponding decrease to operating cash flows, a $12.5 million decrease to investing cash flows and a corresponding increase to operating cash flows, and a $1.2 million increase to investing cash flows and a corresponding decrease to operating cash flows, for the two-months ended December 31, 2004, 10-months ended October 31, 2004 and year ended December 31, 2003, respectively, from the amounts previously reported. The reclassification of changes related to deferred gas storage arrangements to be consistent with our 2005 presentation resulted in a $2.3 million and $6.7 million increase to financing cash flows and corresponding decreases to operating cash flows, for the two-months ended December 31, 2004, and the 10-months ended October 31, 2004, respectively, from the amounts previously reported. Such reclassifications had no impact on net income (loss) or shareholders’ equity as previously reported.

Supplemental Cash Flow Information

	Successor Company					Predecessor Company
	December 31, 2005			November 1- December 31, 2004		January 1- October 31, 2004			Year Ended December 31, 2003
Cash paid (received) for
Income taxes	$	(308	)	$	203	$	(4,637	)	$	(13,038	)
Interest	51,131			16,192		47,364			101,778
Reorganization interest income	—			—		(381		)	(14		)
Reorganization professional fees and expenses	7,576			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			—

F-14

(3)Emergence from Bankruptcy and Fresh-Start Reporting

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 Plan of Reorganization (Plan), which became effective on November 1, 2004.

Plan of Reorganization

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 accordance with the Plan, we issued 31.1 million shares of new common stock to settle claims of debt holders. We also established a reserve of approximately 4.4 million shares of common stock upon emergence to be used to resolve various outstanding litigation matters and distributed pro rata to holders of allowed trade vendor and general unsecured claims in excess of $20,000.  As of December 31, 2005, approximately 1.3 million shares have been issued from this reserve in settlement of claims. 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
	Year Ended		Period Ended					Year Ended
	December 31, 2005		December 31, 2004		October 31, 2004			December 31, 2003
Reorganization Items
Professional fees	$	5,490	$	437	$	39,271		$	8,280
Interest earned on accumulated cash	—		—		(381		)	(14		)
Effects of the Plan and fresh-start reporting adjustments	2,039		—		(571,953		)	—
Total Reorganization Items	$	7,529	$	437	$	(533,063	)	$	8,266

F-15

The 2005 amount included in effects of the Plan is primarily due to a loss on the reestablishment of a liability that was removed upon emergence from bankruptcy. 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		)
Total	$	(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 reorganization value of the Successor Company as set forth in SOP 90-7, we developed a set of financial projections and engaged an independent financial advisor to assist in the determination. The reorganization 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. While the discounted cash flow approach was one of the three approaches used by the independent financial advisor to determine reorganization value, it was not the sole method used in the determination. This use of multiple approaches is consistent with methods used to determine value in most purchase business combinations. A discount rate of 7% was used in the calculation.

The independent financial advisor calculated NorthWestern’s enterprise value, which represents the net equity value of NorthWestern to be distributed to creditors plus its long-term debt to be reinstated upon emergence from bankruptcy, net of cash on hand, 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 enterprise value. This value is consistent with the Voting Creditors and Bankruptcy Court approval of our Plan. Under paragraph 09 of SOP 90-7, an entity’s reorganization value “generally approximates fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring.”

F-16

NorthWestern’s total asset value, which is a proxy for the “reorganization value” under SOP 90-7, is approximately $2.5 billion. The projected net distributable value to NorthWestern’s creditors, as calculated by an independent financial advisor, was approximately $710 million. This reflects the “reorganization value” (or total asset value) of approximately $2.5 billion, less NorthWestern’s indebtedness of approximately $1.8 billion (comprised of approximately $900 million of secured reinstated debt, approximately $300 million in current liabilities and approximately $600 million in other noncurrent liabilities).

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.

•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.

(4)Assets Held for Sale

Assets held for sale consist of 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.  In December 2005, MMI entered into an agreement to sell substantially all of its generation assets for $20 million and we received a deposit of $2.5 million (included in Accrued Expenses on our December 31, 2005 consolidated balance sheet).  The sale closed in January 2006 and we received the remaining sales proceeds.  We had recorded a $10 million impairment charge to reduce the assets to their estimated realizable value of $20 million in December 2004. We had previously recorded impairment charges of $12.4 million and $35.7 million for the years ended December 31, 2003 and 2002, respectively, in our Other segment based upon the estimated realizable value of our investment at that time.

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(5)Property, Plant and Equipment

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

	December 31,			December 31,
	2005			2004
Land and improvements	$	39,171		$	37,180
Building and improvements	89,346			84,041
Storage, distribution, and transmission	1,728,793			1,683,161
Generation	155,469			150,099
Construction work in process	28,760			10,472
Other equipment	195,635			198,960
	2,237,174			2,163,913
Less accumulated depreciation	(827,969		)	(784,853		)
	$	1,409,205		$	1,379,060

(6)Asset Retirement Obligations

We have identified asset retirement obligations, or ARO, liabilities related to our electric and natural gas transmission and distribution assets that have been 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, 2005 and December 31, 2004, we have recognized accrued removal costs of $142.6 million and $132.9 million, respectively, which are included in noncurrent regulatory liabilities.

For our generation properties, we have accrued decommissioning costs since the generating units were first put into service in the amount of $12.8 million and $12.3 million as of December 31, 2005 and December 31, 2004, respectively, which are classified as noncurrent regulatory liabilities. These amounts also do not represent SFAS No. 143 legal retirement obligations.

(7)Goodwill

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 allowable costs recoverable through utility rates, and the excess of reorganization value over the fair value of assets and liabilities on the date of our emergence of $435.1 million was recorded as goodwill.

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Goodwill by segment is as follows for December 31, 2005 and 2004(in thousands):

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

(8)Risk Management and Hedging Activities

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price of electricity and natural gas commodities. We employ established policies and procedures to manage our risk associated with these market fluctuations using various commodity and financial derivative and non-derivative instruments, including forward contracts, swaps and options.

Interest Rates

During the second quarter of 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions of approximately $380 million. These swaps are designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income in our Consolidated Balance Sheets. We will reclassify gains and losses on the hedges from accumulated other comprehensive income into interest expense in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur. At December 31, 2005, we had net unrealized pre-tax gains of $8.8 million recorded in other noncurrent assets and accumulated other comprehensive income based on the market value of our interest rate swaps. These hedging instruments are assessed on a quarterly basis in accordance with SFAS No. 133 to determine if they are effective in offsetting the interest rate risk associated with the forecasted transaction and as of December 31, 2005, we had no hedge ineffectiveness on these swaps.

Commodity Prices

During the second quarter of 2005, we implemented a risk management strategy of utilizing put options in conjunction with our forward fixed price sales to manage our commodity price risk exposure associated with our leased Colstrip 4 generation facility. These transactions are designated as cash-flow hedges of forecasted electric sales of approximately 120,000 Mwh in each of the third and fourth quarters of 2006 under the provisions of SFAS No. 133. We designated the put options as cash-flow hedges, therefore unrealized gains and losses are recorded in accumulated other comprehensive income in our Consolidated Balance Sheets prior to the settlement of the anticipated hedged physical transaction. Gains or losses will be reclassified into earnings upon settlement of the underlying hedged transaction.

At December 31, 2005, we had net unrealized losses of approximately $0.9 million on these hedges recorded in accumulated other comprehensive income, and $0.2 million (including option premium) in other noncurrent assets. We had no hedge ineffectiveness on these options. We expect to reclassify approximately $1.1 million of pre-tax losses on these cash flow hedges from accumulated other comprehensive income into earnings during the next twelve months based on the market prices at December 31, 2005. However, the actual amount reclassified into earnings could vary due to future changes in market prices.

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, we had three outstanding fixed price sales contracts in our unregulated natural gas segment that were not hedged. As of December 31, 2004, we had a liability related to these obligations of $2.6 million. In March 2005, we entered into fixed price purchase

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contracts to fully hedge these sales and recorded an additional loss of approximately $0.5 million, and as of December 31, 2005, no unhedged contracts were outstanding.

(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.

In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. Netexit’s amended and restated liquidating plan of reorganization was confirmed by the Bankruptcy Court on September 14, 2005 and the plan became effective on September 29, 2005. Netexit resolved the majority of claims filed against it and made distributions on allowed claims prior to December 31, 2005, including distributions to NorthWestern totaling $42.2 million.  NorthWestern received an additional $5.0 million distribution from Netexit in February 2006.  Netexit expects to complete its liquidation during the first half of 2006 and any final distributions to NorthWestern will be minimal.

As of December 31, 2005 and December 31, 2004, Netexit had current assets of $8.5 million and $66.3 million and current liabilities (excluding intercompany amounts) of $1.2 million and $15.6 million, respectively.

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

	Successor Company						Predecessor Company
	Year Ended			Period Ended						Year Ended
	December 31, 2005			November 1- December 31, 2004			January 1- October 31, 2004			December 31, 2003
Revenues	$	—		$	—		$	—		$	541,211
Income (Loss) before income taxes	$	(1,179	)	$	(78	)	$	(8,893	)	$	1,360
Gain (loss) on disposal	—			—			11,500			(49,250		)
Income tax provision	—			—			—			—
Income (Loss) from discontinued operations, net of income taxes	$	(1,179	)	$	(78	)	$	2,607		$	(47,890	)

No income tax provision or benefit has been recorded by Netexit because we currently believe it is not likely that deferred tax assets arising from Netexit net operating losses will be realized.

During the third quarter of 2005, Blue Dot sold its final operating location. As of December 31, 2004, Blue Dot had current assets of $4.8 million, and current liabilities (excluding intercompany amounts) of $2.8 million, noncurrent assets of $0.04 million and noncurrent liabilities of $0.4 million.

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

	Successor Company						Predecessor Company
	Year Ended			Period Ended						Year Ended
	December 31, 2005			November 1- December 31, 2004			January 1- October 31, 2004			December 31, 2003
Revenues	$	3,177		$	724		$	28,209		$	400,679
Loss before income taxes	$	(901	)	$	(248	)	$	(4,282	)	$	(3,356	)
Gain (loss) on disposal	—			(98		)	4,163			14,352
Income tax provision	—			—			—			—
Income (Loss) from discontinued operations, net of income taxes	$	(901	)	$	(346	)	$	(119	)	$	10,996

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During the second and third quarters of 2003, we also sold our interest in two other subsidiaries, including One Call Locators, Ltd. Summary financial information for these entities for the year ended December 31, 2003 is as follows (in thousands):

Revenues	$	19,493
Income (Loss) before income taxes, net of minority interests	$	456
Loss on disposal	(5,705		)
Income tax benefit	—
Loss from discontinued operations, net of income taxes and minority interests	$	(5,249	)

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(10)Long-Term Debt

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

		Successor Company
	Due	December 31, 2005			December 31, 2004
Unsecured Debt:
Senior Unsecured Revolver	2009	$	81,000		$	—
Secured Debt:
Senior Secured Term Loan B	2011	—			100,000
Mortgage bonds—
South Dakota—7.10%	2005	—			60,000
South Dakota—7.00%	2023	55,000			55,000
Montana—7.30%	2006	150,000			150,000
Montana—8.25%	2007	365			365
Montana—7.00%	2005	—			5,386
South Dakota & Montana—5.875%	2014	225,000			225,000
Pollution control obligations—
South Dakota—5.85%	2023	7,550			7,550
South Dakota—5.90%	2023	13,800			13,800
Montana—6.125%	2023	90,205			90,205
Montana—5.90%	2023	80,000			80,000
Montana Natural Gas Transition Bonds— 6.20%	2012	37,706			42,450
Capital leases	Various	4,468			9,623
Discount on Notes and Bonds	—	(2,124		)	(2,433		)
		742,970			836,946
Less current maturities		(156,455		)	(73,380		)
		$	586,515		$	763,566

Unsecured Debt

On June 30, 2005, we entered into an amended and restated credit agreement that replaced our existing $225 million secured credit facility with an unsecured $200 million senior revolving line of credit with lower borrowing costs. The previous credit facility consisted of a $125 million five-year revolving tranche and a $100 million seven-year term tranche (senior secured term loan B.) In addition, because the amended and restated line of credit is unsecured, the $225 million of first mortgage bond collateral securing the previous facility was released by the lenders. The unsecured revolving line of credit will mature on November 1, 2009 and does not amortize. The facility bears interest at a variable rate based upon a grid which is tied to our credit rating from Fitch, Moody’s, and S&P. The ‘spread’ or ‘margin’ ranges from 0.625% to 1.75% over the London Interbank Offered Rate (LIBOR). The facility currently bears interest at a rate of approximately 5.8%, which is 1.125% over LIBOR.  As of December 31, 2005 we had $27.6 million in letters of credit and $81 million of borrowings outstanding under the unsecured revolving line of credit. The weighted average interest rate on the outstanding revolver borrowings was 5.2% as of December 31, 2005.

Commitment fees for the unsecured revolving line of credit were $0.1 million for the year ended December 31, 2005. Commitment fees for the revolving tranche of the old credit facility were approximately $0.2 million for the first six months of 2005, and $63,000 for the two-months ended December 31, 2004. Commitment fees for our debtor-in-possession facility were approximately $218,000 for the 10-months ended October 31, 2004, and $102,000 for the year ended December 31, 2003.

The amended and restated line of credit continues to include covenants similar to the previous credit facility, which require us to meet certain financial tests, including a minimum interest coverage ratio and a

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minimum debt to capitalization ratio. The amended and restated line of credit 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, and enter into transactions with affiliates. Many of these restrictive covenants will fall away upon the line of credit being rated “investment grade” by two of the three major credit rating agencies consisting of Fitch, Moody’s and S&P. As of December 31, 2005, we are in compliance with all of the covenants under the amended and restated line of credit.

Secured Debt

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 $156.5 million in 2006, $6.8 million in 2007, $6.1 million in 2008, $87.0 million in 2009 and $6.1 million in 2010.

(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, 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
	Year Ended		Period Ended					Year Ended
	December 31, 2005		December 31, 2004			October 31, 2004		December 31, 2003
Net income (loss)	$	59,467	$	(6,944	)	$	551,377	$	(113,725	)
Other comprehensive income (loss):
Net unrealized loss on available-for-sale securities, net of tax of $(188) in 2003	—		—			—		(352		)
Net unrealized gain (loss) on derivative instruments qualifying as hedges, net of tax of $3,045 and $(224) in 2005 and 2003, respectively	4,885		—			—		(416		)
Minimum pension liability adjustment	—		—			—		(1,465		)
Foreign currency translation adjustment	56		23			—		298
Total other comprehensive income (loss)	4,941		23			—		(1,935		)
Total comprehensive income (loss)	$	64,408	$	(6,921	)	$	551,377	$	(115,660	)

F-23

The after tax components of accumulated other comprehensive income were as follows (in thousands):

	Successor Company
	December 31,		December 31,
	2005		2004
Balance at end of period,
Unrealized gain on derivative instruments qualifying as hedges	$	4,885	$	—
Foreign currency translation adjustment	79		23
Accumulated other comprehensive income	$	4,964	$	23

(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.

•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 estimates presented herein are based on pertinent information available to us as of December 31, 2005 and December 31, 2004. 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
	December 31, 2005				December 31, 2004
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Cash and cash equivalents	$	2,691	$	2,691	$	17,058	$	17,058
Restricted cash	25,238		25,238		21,383		21,383
Investments	1,297		1,297		5,608		5,608
Liabilities:
Long-term debt (including current portion)	742,970		746,536		836,946		843,207

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(13)Income Taxes

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

	Successor Company						Predecessor Company
	Year Ended			Period Ended						Year Ended
	December 31, 2005			November 1- December 31, 2004			January 1- October 31, 2004			December 31, 2003
Federal
Current	$	4		$	25		$	(810	)	$	(9,838	)
Deferred	36,156			(4,232		)	(106		)	10,334
Investment tax credits	(537		)	(89		)	(453		)	(544		)
State	2,887			(634		)	—			—
	$	38,510		$	(4,930	)	$	(1,369	)	$	(48	)

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

	Successor Company				Predecessor Company
	Year Ended		Period Ended				Year Ended
	December 31, 2005		November 1- December 31, 2004		January 1- October 31, 2004		December 31, 2003
Federal statutory rate	35.0	%	(35.0	)%	35.0	%	(35.0	)%
State income, net of federal provisions	3.4		(3.3	)	2.6		(3.9	)
Amortization of investment tax credit	(0.5	)	(0.8	)	(0.1	)	(0.8	)
Depreciation of flow through items	(0.9	)	(6.1	)	(0.5	)	1.3
Affiliated stock loss on disposition	—		—		—		(163.2	)
Prior year tax return refund	—		—		(0.1	)	(8.5	)
Valuation allowance	—		—		(30.6	)	221.8
Prior year permanent return to accrual adjustments	(1.8	)	—		(8.4	)	(7.3	)
Other, net	3.3		2.1		1.8		(4.5	)
	38.5	%	(43.1	)%	(0.3	)%	(0.1	)%

F-25

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

	Successor Company
	December 31, 2005			December 31, 2004
Excess tax depreciation	$	(100,951	)	$	(94,766	)
Regulatory assets	(33,597		)	(30,195		)
Regulatory liabilities	(839		)	169
Unbilled revenue	3,963			4,300
Unamortized investment tax credit	2,458			2,746
Compensation accruals	1,944			2,950
Reserves and accruals	32,351			50,815
Goodwill amortization	(33,395		)	(24,635		)
Net operating loss carryforward (NOL)	45,280			254,658
AMT credit carryforward	3,186			3,186
Capital loss carryforward	6,376			6,406
Deferred tax liability due to future attribute reduction	—			(207,029		)
Valuation allowance	(12,758		)	(12,758		)
Other, net	(3,690		)	(1,976		)
	$	(89,672	)	$	(46,129	)

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, 2005 against capital loss carryforwards and certain state NOL carryforwards as we do not believe these assets will be realized. During the third quarter of 2005, Blue Dot sold its last remaining operating location and during the fourth quarter of 2005, we completed an assessment of our tax position as it relates to our investment in Blue Dot.  We expect to claim a worthless stock deduction of approximately $333.0 million on our 2005 tax return related to our investment in Blue Dot.  Consistent with our accounting policy related to exposures discussed below, we have not recorded a benefit in our financial statements for the Blue Dot worthless stock deduction.  Due to the amount of our CNOLs, we will not actually realize the benefit of this deduction for several years.

At December 31, 2005 we estimate our total federal NOL carryforward to be approximately $468.6 million (including approximately $333.0 million related to Blue Dot discussed above). This amount reflects a reduction during 2005 of approximately $583 million due to cancellation of indebtedness income. If unused, $99.0 million will expire in the year 2023 and $369.6 million will expire in the year 2025. 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.

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. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and

F-26

established liabilities are 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.

(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, 2005
Ownership percentages	23.4		%	8.7		%	10.0		%
Plant in service	$	53,022		$	28,870		$	42,542
Accumulated depreciation	33,188			18,541			23,468
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

(15)Operating Leases

We lease a generation facility, vehicles, office equipment, an airplane and office and warehouse facilities under various long-term operating leases. At December 31, 2005, future minimum lease payments for the next five years under non-cancelable lease agreements are as follows (in thousands):

2006	$	34,435
2007	33,838
2008	32,773
2009	32,358
2010	32,282

Lease and rental expense incurred was $31.0 million, $6.8 million, $32.5 million and $40.1 million for the year ended December 31, 2005, two-month period ended December 31, 2004, 10-month period ended October 31, 2004, and the year ended December 31, 2003, 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 was 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,which includes two cash balance pension plans. The plan for our South Dakota and Nebraska

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employees is referred to as the NorthWestern Corporation pension plan, and the plan for our Montana employees is referred to as the NorthWestern Energy pension plan. 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. In 2005, we applied for and received an accounting order from the MPSC to utilize a five-year average of funding cost in our costs of service, therefore we maintain a regulatory asset and amortize it based on our five-year average funding requirement in Montana. 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. Actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market-related value of assets are normally amortized over the average remaining service period of active participants. However 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 recognizing 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.

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
	December 31, 2005			December 31, 2004			October 31, 2004			December 31, 2005			December 31, 2004			October 31, 2004
Reconciliation of Benefit Obligation
Obligation at beginning of period	$	373,979		$	372,485		$	356,373		$	52,391		$	53,015		$	66,948
Service cost	8,531			1,363			6,188			688			146			677
Interest cost	20,174			3,391			16,909			2,853			481			2,844
Actuarial (gain) loss	1,236			(71		)	14,116			1,705			(274		)	(2,189		)
Plan amendments	2,661			—			—			—			—			—
Settlement cost	—			—			—			—			—			—
Fresh-start reporting adjustments	—			—			(4,727		)	2,561			—			(11,354		)
Gross benefits paid	(19,666		)	(3,189		)	(16,374		)	(4,578		)	(977		)	(3,911		)
Benefit obligation at end of period	$	386,915		$	373,979		$	372,485		$	55,620		$	52,391		$	53,015

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 $386.9 million and $271.1 million, respectively, as of December 31, 2005. 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 $384.8 million and $271.1 million, respectively, as of December 31, 2005.

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.

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The NorthWestern Energy pension plan was amended effective January 1, 2005 to increase the retirement death benefit from 50% to 100% of the accrued benefit. This is reflected in the plan amendment amount above, and unrecognized prior service cost below.

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						Successor Company
	December 31, 2005			December 31, 2004			December 31, 2005			December 31, 2004
Accrued benefit cost	$	(117,585	)	$	(140,097	)	$	(44,333	)	$	(44,714	)
Intangible asset	502			—			—			—
Net amount recognized	$	(117,083	)	$	(140,097	)	$	(44,333	)	$	(44,714	)

Plan Assets and Funded Status

	Pension Benefits									Other Postretirement Benefits
	Successor Company									Successor Company
	December 31, 2005			December 31, 2004			October 31, 2004			December 31, 2005			December 31,  2004			October 31, 2004
Reconciliation of Fair Value of Plan Assets
Fair value of plan assets at beginning of period	$	244,643		$	233,865		$	229,771		$	8,333		$	7,844		$	5,434
Return on plan assets	14,754			13,967			10,254			637			489			87
Employer contributions	31,372			—			10,214			5,971			977			6,234
Gross benefits paid	(19,666		)	(3,189		)	(16,374		)	(4,578		)	(977		)	(3,911		)
Fair value of plan assets at end of period	$	271,103		$	244,643		$	233,865		$	10,363		$	8,333		$	7,844
Funded Status	$	(115,812	)	$	(129,335	)	$	(138,620	)	$	(45,258	)	$	(44,058	)	$	(45,171	)
Unrecognized net actuarial (gain) loss	(3,932		)	(10,762		)	—			925			(656		)	—
Unrecognized prior service cost	2,661			—			—			—			—			—
Accrued benefit cost	$	(117,083	)	$	(140,097	)	$	(138,620	)	$	(44,333	)	$	(44,714	)	$	(45,171	)

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

Our investment policy for fixed income investments are oriented toward risk averse, 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). 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.

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Equity investments 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, securities lending 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, 2005 and December 31, 2004, are as follows:

	NorthWestern Energy Pension				NorthWestern Corporation Pension				NorthWestern Energy Health and Welfare
	December 31, 2005		December 31, 2004		December 31, 2005		December 31, 2004		December 31, 2005		December 31, 2004
Cash and cash equivalents	2.0	%	2.0	%	1.1	%	.9	%	—	%	—	%
Debt securities	32.3		31.6		—		—		27.2		27.5
Domestic equity securities	55.2		55.8		51.5		50.4		72.3		71.9
International equity securities	10.5		10.6		9.8		9.5		0.5		0.6
Participating group annuity contracts	—		—		37.6		39.2		—		—
	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%

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

We continually evaluate 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.

Actuarial Assumptions

The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2005, December 31, 2004, October 31, 2004, and December 31, 2003. 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.

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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, 2003, 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 future expectations for asset returns, we selected an 8.5% long-term rate of return on assets assumption for 2005 and 2004. We have reduced this assumption to 8.0% for 2006.

The health care cost trend rates are established through a review of actual recent cost trends and projected future trends. Our retiree medical trend assumptions are the best estimate of expected inflationary increases to our healthcare costs. Due to the relative size of our retiree population (under 700 members), the assumptions used are based upon both nationally expected trends and our specific expected trends. Our average increase remains consistent with the nationally expected trends.

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
	Year Ended		Period Ended				Year Ended				Period Ended				Year Ended
			November 1-		January 1-						November 1-		January 1-
	December 31,		December 31,		October 31,		December 31,		December 31,		December 31,		December 31,		December 31,
	2005		2004		2004		2003		2005		2004		2004		2003
Discount rate	5.50	%	5.50	%	5.50	%	6.00	%	5.50	%	5.50	%	5.50	%	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)	3.64	%	3.37	%	3.37	%	3.97	%	3.64	%	3.37	%	3.37	%	4.00	%
Long-term rate of increase in compensation levels (union)	3.50	%	3.30	%	3.30	%	3.50	%	3.50	%	3.30	%	3.30	%	4.00	%

The postretirement benefit obligation is calculated assuming that health care costs increased by 10% in 2005 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 2010.

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
	Year Ended			Period Ended						Year Ended						Period Ended						Year Ended
				November 1-			January 1-									November 1-			January 1-
	December 31,			December 31,			October 31,			December 31,			December 31,			December 31,			October 31,			December 31,
	2005			2004			2004			2003			2005			2004			2004			2003
Components of Net Periodic Benefit Cost
Service cost	$	8,531		$	1,363		$	6,188		$	5,165		$	688		$	146		$	677		$	1,350
Interest cost	20,174			3,391			16,909			21,080			2,853			481			2,844			5,455
Expected return on plan assets	(20,347		)	(3,277		)	(15,711		)	(16,329		)	(562		)	(107		)	(262		)	(261		)
Amortization of transitional obligation	—			—			129			155			—			—			—			675
Amortization of prior service cost	—			—			311			505			—			—			—			—
Recognized actuarial (gain) loss	—			—			1,068			2,724			—			—			467			467
	8,358			1,477			8,894			13,300			2,979			520			3,726			7,686
Additional (income) or loss recognized:
Curtailment	—			—			—			—			—			—			—			13,511
Special termination benefits	—			—			—			785			—			—			—			—
Settlement cost	—			—			—			—			—			—			—			(13,586		)
Net Periodic Benefit Cost	$	8,358		$	1,477		$	8,894		$	14,085		$	2,979		$	520		$	3,726		$	7,611

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	$	208
on postretirement benefit obligation	2,328
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components	$	(179	)
on postretirement benefit obligation	(2,049		)

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 $24.0 million to our pension and other postretirement benefit plans in 2006. 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.

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

	Pension Benefits		Other Postretirement Benefits
2006	$	19,827	$	4,157
2007	20,019		4,187
2008	20,422		4,098
2009	20,579		4,172
2010	21,414		4,315
2011-2015	123,321		22,440

Predecessor Company

The Predecessor Company filed several motions to terminate various nonqualified benefit plans and individual supplemental retirement contracts for former employees. All liabilities associated with these plans were removed from our balance sheet upon emergence based on our expectation that these claims would be settled through the shares from the reserve established for Class 9 claimants. Various claimants objected to the Bankruptcy Court’s jurisdiction to terminate such plans and/or contracts. In July 2005, the Bankruptcy Court approved share-based settlements with most of the participants in the various nonqualified plans and supplemental retirement contracts. However, the Bankruptcy Court determined that it did not have jurisdiction to consider a motion to terminate various individual supplemental retirement contracts, therefore in 2005 we reestablished a liability of approximately $2.6 million and have resumed payments on those individual supplemental retirement contracts not covered by the Bankruptcy Court’s jurisdiction.

 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.

Defined Contribution Plans

On December 31, 2004, the NorthWestern Corporation savings plan was merged into the NorthWestern Energy savings plan. These plans 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 plan. We contribute various percentage amounts of the employee’s gross compensation contributed to the plan. Costs incurred under these plans were $3.4 million for 2005, $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 in 2003, respectively.

(17)         Director and Employee Incentive Plans

Employee Incentive Plans

In connection with the confirmation of our Plan, the Bankruptcy Court and Creditors Committee approved a New Incentive Plan to be established and administered by the new Board of Directors. The Plan reserved 2,265,957 shares of new common stock for the New Incentive Plan. Upon emergence from bankruptcy

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228,315 shares of restricted stock were granted (Special Recognition Grants) under this 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. 114,164 shares of the Special Recognition Grants vested upon emergence. The remaining shares vested on November 1, 2005 for non-officers. For officers, 10% vested on November 1, 2005, and the remaining shares vest 20% on November 1, 2006 and 20% on November 1, 2007.

In February 2005, the Board of Directors established an equity-based incentive plan, the NorthWestern Corporation 2005 Long-Term Incentive Plan (2005 LTIP), which provides for grants of stock options, share appreciation rights, restricted and unrestricted share awards, deferred share units and performance awards. The 2005 LTIP was developed in accordance with the New Incentive Plan provided for in the Plan as discussed above, and therefore did not require shareholder approval. Our directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by us, are eligible to receive grants. The purpose of the 2005 LTIP is to promote our long-term growth and profitability by providing these individuals with incentives to maximize shareholder value and otherwise contribute to our success and to enable us to attract, retain and reward the best available persons for positions of responsibility. The Human Resources Committee of our Board of Directors administers the 2005 LTIP. Under the 2005 LTIP, 700,000 shares of our common stock are available for issuance. As of December 31, 2005 there were 581,415 shares of common stock remaining available for grants under this plan.

We account for our service-based restricted stock awards using the fixed accounting method, whereby we amortize the value of the market price of the underlying stock on the date of grant to compensation expense over the service period. We reverse any expense associated with restricted stock that is canceled or forfeited during the performance or service period. Compensation expense recognized for restricted stock awards was $4.7 million for the year ended December 31, 2005, $0.2 million for the two months ended December 31, 2004, and $2.3 million for the 10-months ended October 31, 2004.

Summarized share information for our restricted stock awards, including the Special Recognition Grants and the broad-based employee and Board of Directors grant under the 2005 LTIP is as follows:

	Year Ended December 31, 2005		November 1 - December 31, 2004
Beginning unvested grants	114,151		114,151
Granted	97,651		—
Vested	175,558		—
Canceled	1,080		—
Remaining unvested grants	35,164		114,151
Weighted average fair value restricted stock granted	$	31.02	$	20.00

Director’s Deferred Compensation

Nonemployee directors may elect to defer up to 100% of any qualified compensation that would be otherwise payable to him or her, subject to compliance with our 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Code. The deferred compensation may be invested in NorthWestern stock or in designated investment funds. Compensation deferred in a particular month is recorded as a deferred stock unit (DSU) on the first of the following month based on the closing price of NorthWestern stock or the designated investment fund. A DSU entitles the grantee to receive one share of common stock for each DSU at the end of the deferral period. The value of these DSUs are marked-to-market on a quarterly basis with an adjustment to directors compensation expense. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall be paid a distribution either in a lump sum or in approximately equal installments over a designated number years (not to exceed 10 years). During 2005, DSUs issued to members of our Board of Directors totaled 20,934. Total compensation expense attributable to the DSUs during 2005 was approximately $0.7 million.

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.

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, 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. Compensation expense recognized was $0.4 million for the 10-months ended October 31, 2004 and $0.3 million for the year ended December 31, 2003. The Predecessor Company’s Employee Stock Ownership

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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 2 to the Financial Statements. Pursuant to this pronouncement, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to the customers. Regulatory assets and liabilities are recorded based on management’s assessment that it is probable that a cost will be recovered or that an obligation has been incurred. 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. Of these regulatory assets and liabilities, energy supply costs are the only items earning a rate of return. The remaining regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods. Because these costs are recovered as paid, they do not earn a return. We have specific orders to cover approximately 89% of our regulatory assets and approximately 96% of our regulatory liabilities.

		Remaining	Successor Company
	Note Ref.	Amortization Period	December 31, 2005		December 31, 2004
Pension	16	Undetermined	$	123,326	$	135,358
SFAS No. 106	16	Undetermined	33,096		35,567
Competitive transition charges		8 Years	32,707		36,148
Supply costs		1-4 Years	25,731		9,557
Income taxes	13	Plant Lives	9,184		7,642
State & local taxes & fees		1 Year	5,697		—
Other		Various	13,365		13,072
Total regulatory assets			$	243,106	$	237,344
Removal cost		Various	$	155,453	$	145,257
Gas storage sales		34 Years	14,195		14,615
Supply costs		1 Year	8,738		17,968
Other		Various	2,361		2,252
Total regulatory liabilities			$	180,747	$	180,092

Pension and SFAS No. 106

Through fresh-start reporting in 2004 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. In 2005, the MPSC authorized the recognition of pension costs based on an average of the funding to be made over a 5-year period for the calendar years 2005 through 2009.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

Natural gas transition bonds were issued in 1998 to recover stranded costs of production assets and related regulatory assets and provide a lower cost to utility customers, as the cost of debt was less than the cost of capital. The MPSC authorized the securitization of these assets and approved the recovery of the competitive transition charges in rates over a 15-year period. The regulatory asset relating to competitive transition charges amortizes proportionately with the principal payments on the natural gas transition bonds.

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Supply Costs

The MPSC has authorized the use of electric and natural gas supply cost trackers, which enable us to track actual supply costs and either recover the undercollection or refund the overcollection to our customers. Accordingly, a regulatory asset and liability has been recorded to reflect the future recovery of undercollections and refunding of overcollections through the ratemaking process. We earn interest on the electric and natural gas supply costs of 8.46% and 8.82%, respectively, in Montana; 10.61% and 8.53%, respectively, in South Dakota; and 8.32% for natural gas in Nebraska. These same rates are paid to our customers in the event of a refund.

Income Taxes

Tax assetsprimarily 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.

State & Local Taxes & Fees

Under Montana law, utilities are allowed to reflect changes in state and local taxes and fees, and to track these changes such that the actual level of taxes and fees are recovered. In 2005, the MPSC authorized recovery of approximately 60% of the estimated increase in our local taxes and fees (primarily property taxes) in 2005 as compared to the amount of these taxes from our last general rate case in 1999. On December 2, 2005, we filed with the MPSC for an automatic rate adjustment, which reflected 100% of the under recovery of 2005 actual state and local taxes and fees and estimated state and local taxes and fees for 2006. In February 2006, the MPSC issued an order allowing recovery of approximately 60% of the 2005 actual increase and approximately 25% of the 2006 estimated increase. While we have recorded a regulatory asset consistent with the MPSC’s authorization, we are disputing the reduction by the MPSC and have filed a Petition for Judicial Review in Montana District Court regarding the 2005 order. We anticipate resolving this issue in 2006, however we cannot currently predict an outcome.

Removal Cost

A regulatory liability has been recognized to reflect payments our customers have prepaid for future plant removal costs. See Note 6, Asset Retirement Obligations for further information regarding this item.

Gas Storage Sales

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. This regulatory liability is a reduction of rate base.

(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.

Electric

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

On January 23, 2003, we filed our first biennial Electric Default Supply Resource Procurement Plan with the MPSC, which fulfills the requirements established by law and describes the planning we are doing on behalf of our electric default supply customers to provide adequate, reliable and efficient annual and long-term electricity supply services at the lowest long-term cost. We have a substantial portion of the portfolio covered by the existing PPL Montana base-load contracts and the QF contracts. In December 2005, we filed our second biennial Electric Default Supply Resource Procurement Plan. This Plan focuses on the resource options and strategies to replace approximately 55 percent of the supply contracts that are expiring on June 30, 2007.

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Natural Gas

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

Regulatory Matters

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

A bankruptcy stipulation and agreement between the MPSC, MCC and us requires us to file a Montana electric and natural gas informational rate filing by September 30, 2006.

Electric Rates

On September 30, 2005, we filed our annual electric supply cost tracker request with the MPSC for the 12-month period ended June 30, 2005, and for projected costs for the 12-month period ended June 30, 2006. On October 14, 2005, an interim order was approved by the 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 December 16, 2005 a final order was issued by the MPSC for the 24-month electric supply costs ending June 30, 2004.

Natural Gas Rates

On August 23, 2005, we filed an annual gas cost tracker request with the MPSC for any unrecovered actual gas costs for the 12-month period ended June 30, 2005, and for the projected gas costs for the 12-month period ending June 30, 2006. On September 2, 2005, the MPSC issued an interim order, approving recovery of our projected gas costs.

Rates for our Montana natural gas supply are set by the MPSC. 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, then it can disallow such costs. On July 3, 2003, the MPSC issued orders disallowing the recovery of certain gas supply costs totaling $10.8 million for the July 2002 — June 2004 tracker years. The MPSC also rejected a motion for reconsideration filed by us on July 14, 2003. We filed suit in Montana District court on July 28, 2003, seeking to overturn the MSPC’s decision to disallow recovery of these costs. The MPSC has approved a stipulation between us and the Montana Consumer Counsel regarding the recovery of natural gas costs for the 2003 and 2004 tracking years. With this stipulation as a foundation, we have settled with the MPSC and have been allowed recovery of previously disallowed gas costs of $4.6 million. As a result of the settlement, we recorded gas supply revenue of $4.6 million in the second quarter of 2005.

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

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conditions for service consistent with those formerly filed with the municipalities, were filed with and accepted by the NPSC.

(20)         Earnings (Loss) Per Share

Basic earnings per share is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all warrants were exercised and all unvested restricted shares were to vest. Common stock equivalent shares are calculated using the treasury stock method. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted shares and warrants. Average shares used in computing the basic and diluted earnings per share for the year ended December 31, 2005 and the two-months ended December 31, 2004 are as follows:

	Successor Company
	December 31, 2005	December 31, 2004
Basic computation	35,630,038	35,614,164
Dilutive effect of
Restricted shares	35,164	114,151
Stock warrants	431,993	—
Diluted computation	36,097,195	35,728,315

Warrants to purchase 4,615,633 shares of common stock as of December 31, 2005 are dilutive and have been included in the earnings per share calculations. These warrants have an exercise price of $27.48. As of December 31, 2004 there were 4,620,333 of these warrants to purchase shares of common stock, which were antidilutive and excluded from the earnings per share calculations. The exercise price of these warrants at December 31, 2004 was $28.48. Under the terms of the warrant agreement, the exercise price of the warrants is subject to adjustment from time to time, based on certain events. These events include additional share issuances and dividend payments. An adjustment is made in the case of a cash dividend if the amount of the cash dividend increases or decreases the exercise price by at least 1%, otherwise such amount is carried forward and taken into account with any subsequent cash dividend. Adjustments in the exercise price also require an adjustment in the number of shares covered by the warrants. As of December 31, 2005 each warrant could be exchanged for 1.04 shares of common stock. A total of 4,700 warrants were exercised during the year ended December 31, 2005.

(21)         Guarantees, Commitments and Contingencies

Qualifying Facilities Liability

In Montana we have certain contracts with Qualifying Facilities, or QFs. The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our gross contractual obligation related to the QFs is approximately $1.6 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $1.3 billion through 2029. Upon adoption of fresh-start reporting, we computed the fair value of the remaining liability of approximately $367.9 million 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. The following table summarizes the change in the QF liability for the year ended December 31, 2005, and two-month period ended December 31, 2004 (in thousands):

	December 31, 2005			December 31, 2004
Beginning QF liability	$	143,381		$	143,826
Unrecovered amount	(8,626		)	(2,258		)
Interest expense	10,600			1,813
Contract amendment	(4,888		)	—
Ending QF liability	$	140,467		$	143,381

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

	Gross Obligation		Recoverable Amounts			Net
2006	$	56,398	$	(52,061	)	$	4,337
2007	58,420		(52,567		)	5,853
2008	60,574		(53,060		)	7,514
2009	62,598		(53,583		)	9,015
2010	64,580		(54,086		)	10,494
Thereafter	1,329,039		(1,016,926		)	312,113
Total	$	1,631,609	$	(1,282,283	)	$	349,326

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 $433.9 million for the year ended December 31, 2005, $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, 2005 our commitments under these contracts are $626 million in 2006, $293 million in 2007, $194 million in 2008, $179 million in 2009, $171 million in 2010 and $395 million thereafter. These commitments are not reflected in our Consolidated Financial Statements.

Environmental Liabilities

We are subject to numerous state and federal environmental laws and regulations. Because these laws and regulations are continually developing and subject to amendment, reinterpretation and varying degrees of enforcement, we may be subject to, but cannot predict with certainty, the nature and amount of future environmental liabilities. The Clean Air Act Amendments of 1990 (the Act) and subsequent amendments stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We comply with these existing emission requirements through purchase of sub-bituminous coal and we believe that we are in compliance with all presently applicable environmental protection requirements and regulations with respect to these plants. Recent legislation has been proposed, which may require further limitations on emissions of these pollutants along with limitations on carbon dioxide, particulate matter, and mercury emissions. The recent regulatory and legislative proposals are subject to normal administrative processes, however, and thus we cannot make any prediction as to whether the proposals will pass or on the impact of those actions.

The range of exposure for environmental remediation obligations at present is estimated to range between $29.5 million to $66.2 million. Our environmental reserve accrual is $44.6 million as of December 31, 2005. 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.

Manufactured Gas Plants

Approximately $27.6 million of our environmental reserve accrual is related to manufactured gas plants. 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 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 be necessary at the Aberdeen site, commencing in 2006. Our current reserve for

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remediation costs at the Aberdeen site is approximately $14.4 million, and we estimate that approximately $13.1 million of this amount will be incurred during the next five years. At present, we cannot estimate with a reasonable degree of certainty the timing of remediation cleanup at the other South Dakota sites.

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 (TBA) Program. During 2005, the NDEQ conducted Phase 2 investigations of soil and groundwater at these two locations using funding provided by the TBA Program. At present, we do not have Phase 2 investigation reports from NDEQ for either location and therefore cannot determine with a reasonable degree of certainty the timing of any remediation cleanup at our Nebraska locations.

In addition, we own sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An 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 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 conducted additional groundwater monitoring during 2005 at the Butte and Missoula sites and, at this time, we believe that natural attenuation should address the problems at these sites. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may be necessary to prevent certain contaminants from migrating offsite. We are currently evaluating the results of a pilot program meant to promote aerobic degradation of certain targeted contaminants. During 2006, we will complete our evaluation of the pilot program and also evaluate other alternatives including monitored natural attenuation. In light of these activities, 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 the timing of additional remediation at the Helena site.

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 remediation costs at these locations to be materially different from the established reserve.

Milltown Mining Waste

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three 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 pre-Record of Decision 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. 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 resolved both our liability with Atlantic Richfield in general accordance with the previously negotiated settlement agreement and established 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

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Richfield, until the total agreed amount is funded. As of December 31, 2005, we have fully funded the State of Montana escrow account in the amount of $2.5 million and have funded the Atlantic Richfield account in the amount of $6.0 million.

On July 18, 2005, CFB and we executed the Milltown Reservoir superfund site consent decree. After completion of the public comment period and formulation of EPA responses to the filed public concerns, the Department of Justice, on behalf of the EPA, filed a motion to enter the consent decree with the United States District Court for the District of Montana, on January 4, 2006. The consent decree was approved by the court on February 8, 2006 and becomes effective in 60 days if no appeals are filed. In light of the material environmental risks associated with the catastrophic failure of the Milltown Dam, 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. We are obligated under the settlement to continue to maintain the environmental insurance policy until the Milltown Dam is removed during implementation of the remedy.

Other

We continue to manage polychlorinated biphenyl (PCB)-containing oil and equipment in accordance with the EPA’s Toxic Substance Control Act 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.

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Legal Proceedings

Magten/Law Debenture/QUIPS Litigation

On April 16, 2004, Magten Asset Management Corporation (Magten) and Law Debenture Trust Company (Law Debenture) initiated an adversary proceeding, which we refer to as the QUIPs Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets and liabilities 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. As a result of filing the appeal of the confirmation order, the Bankruptcy Court has stayed the prosecution of this case until the appeal is finally decided. On September 22, 2005, the Delaware District Court withdrew the reference of this action to the Bankruptcy Court and will now hear this lawsuit. The parties will now prepare for trial of this lawsuit.

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. That lawsuit has now been transferred to the Federal District Court in Delaware. The parties will now prepare for trial of this lawsuit.

On October 19, 2004, the Bankruptcy Court entered a written order confirming our Plan. On October 25, 2004, 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’s efforts to obtain a stay of the enforcement of the confirmation order to prevent our Plan from becoming effective were denied by the Bankruptcy Court on October 25, 2004 and by the United States District Court for the District of Delaware on October 29, 2004. With no stay imposed, our Plan became effective November 1, 2004. On October 26, 2004, Magten filed a notice of appeal of the Bankruptcy Court’s approval of the memorandum of understanding (MOU), which memorialized the settlement of the consolidated securities class actions and consolidated derivative litigation against NorthWestern and others. In March 2005, we moved to dismiss Magten’s appeal of the confirmation order on equitable mootness grounds. Magten’s appeals of the confirmation order and the order approving the MOU have been consolidated before the Delaware District Court. While we cannot currently predict the impact or resolution of Magten’s appeal of the confirmation order or the MOU, we intend to vigorously defend against the appeals.

On February 9, 2005, we agreed to settlement terms with Magten and Law Debenture to release all claims, including Magten’s and Law Debenture’s fraudulent conveyance action pending against NorthWestern 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. On March 10, 2005, the Bankruptcy Court entered an order denying the motion filed by Magten and Law Debenture. Magten and Law Debenture have appealed that order. This appeal has been docketed with the District Court, briefing has been completed, and we are awaiting a decision of the District Court. On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern Corporation, Gary

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Drook, Michael Hanson, Brian Bird, Thomas Knapp and Roger Schrum alleging that NorthWestern and the former and current officers committed fraud by failing to include a sufficient amount of shares in the Class 9 reserve set aside for payment of unsecured claims and thus the confirmation order should be revoked and set aside. We filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of the confirmation order appeal. The Federal District Court withdrew the reference, will now hear the lawsuit, and we intend to vigorously defend against the lawsuit.

Twice during 2005, Magten, Law Debenture, the Plan Committee and NorthWestern unsuccessfully engaged in mediation to resolve the pending appeals and other pending litigation described above. At this time, we cannot predict the impact or resolution of any of these lawsuits, appeals or reasonably estimate a range of possible loss, which could be material. We intend to vigorously defend against the adversary proceedings, lawsuits, appeals 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 Class 9 disputed claims reserve established under the Plan. We cannot currently predict the impact or resolution of this litigation.

McGreevey Litigation

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 The Montana Power L.L.C., 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. that temporarily stayed the litigation, as against NorthWestern, CFB, The Montana Power Company, The Montana Power L.L.C. and Jack Haffey. As a result of the confirmation of our Plan, the stay has been made permanent. On July 10, 2004, we and the other insured parties 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. There are various issues preventing a consensus on a global settlement and the Federal District Court has now stayed the case pending resolution of bankruptcy issues in the Touch America and NorthWestern bankruptcy cases. In the event the parties do not reach a global settlement agreement, a settlement is not approved or it does not take effect for any other reason, we intend to vigorously defend against this lawsuit. If we are unsuccessful in defending against this class action lawsuit, the plaintiffs’ litigation claims are channeled to the Directors & Officers Trust established under our Plan, or alternatively would be treated as securities, or Class 14, claims and would be entitled to no recovery 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 are not material to our operations or financial position.

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On August 9, 2005, McGreevey plaintiffs filed an action in Montana state court claiming that our transfer of certain assets to CFB was a fraudulent transfer. (The plaintiffs received approval in our bankruptcy case to initiate a similar fraudulent conveyance action as an adversary proceeding in our bankruptcy case, which they did not do. Under the terms of the settlement with the plaintiffs in the McGreevey case discussed above, they would not file such proceeding.) We have removed the action to the federal court in Montana and filed a motion to transfer the action to the Bankruptcy Court in Delaware. We also filed an adversary action in our Bankruptcy Case seeking injunctive relief against the McGreevey plaintiffs to stop them from pursuing their fraudulent conveyance action outside our bankruptcy case. McGreevey plaintiffs answered the adversary complaint and asserted counterclaims against us alleging the same fraudulent conveyance claims. McGreevey plaintiffs also filed a motion to remand the fraudulent conveyance action to state court in Montana and the same motion to certify certain issues to the Montana Supreme Court. On October 25, 2005 the Bankruptcy Court preliminarily enjoined the plaintiffs from further prosecuting their claim. The McGreevey plaintiffs have asked for leave to appeal this order and we have asked the Bankruptcy Court to deny the request. We cannot currently predict the impact or resolution of this litigation.

Other Litigation

In April 2005, a group of former employees of the Montana Power Company filed a lawsuit in the state court of Montana against us and certain officers styled Ammondson, et al. v. NorthWestern Corporation, et al., Case No. DV-05-97. The former employees have alleged that by moving to terminate their supplemental retirement contracts in our bankruptcy proceeding without having listed them as claimants or giving them notice of the disclosure statement and Plan, that we breached those contracts, and breached a covenant of good faith and fair dealing under Montana law and by virtue of filing a complaint in our Bankruptcy Case against those employees from seeking to prosecute their state court action against NorthWestern, we had engaged in malicious prosecution and should be subject to punitive damages. On May 4, 2005, the Bankruptcy Court found that it did not have jurisdiction over these contracts, dismissed our action against these former employees, and transferred our motion to terminate the contracts to Montana state court where the former employees’ lawsuit is pending. We unsuccessfully engaged in mediation of this dispute in November 2005. We recorded a loss of $2.6 million in the third quarter of 2005 to reestablish a liability for the present value of amounts due to these former employees under their supplemental retirement contracts and we have reestablished monthly payments to these former employees under the terms of their contracts. We intend to vigorously defend against this lawsuit, however we cannot currently predict the ultimate impact of this litigation.

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 and informal requests from the SEC requesting documents and testimony from former and current employees as well as third parties regarding these matters. In January 2006, the SEC issued several Wells notices to individuals formerly associated with a now-defunct subsidiary. There have been no findings or adjudication of the underlying allegations in the Wells notices, and the SEC’s investigation is ongoing and it could issue additional Wells notices. In addition, certain of our former directors and several former and current employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the FBI and IRS concerning certain of the allegations made in the now resolved class action securities and derivative litigation as well as other matters. We have not been advised that NorthWestern is the subject of any FBI or IRS investigation. We are not aware of any other governmental inquiry or investigation related to these matters. We are fully cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are requested to do so 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, as a result of a ruling by the Bankruptcy Court, the

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SEC may not be able to pursue civil sanctions, including, but not limited to, monetary penalties against NorthWestern. The SEC has not appealed such order. The SEC could, however, pursue other remedies and penalties against NorthWestern.

In November 2005, we and our directors were named as defendants in a shareholder class action and derivative action entitled City of Livonia Employee Retirement System v. Draper, et al., pending in the U.S. District Court for the District of South Dakota. The plaintiff claims, among other things, that the directors breached their fiduciary duties by not sufficiently negotiating with Montana Public Power Inc. and Black Hills Corporation, two entities that had made public, unsolicited offers to purchase NorthWestern. After the Board of Directors adopted our shareholders’ rights plan on December 5, 2005, this plaintiff also sought a temporary restraining order and preliminary injunction to prevent the implementation of the rights plan or any other defensive measures. On December 16, 2005, the Federal District Court denied the plaintiff’s application. The Federal District Court has scheduled a trial on plaintiffs’ request for a permanent injunction against the rights plan and other measures, which will commence on March 21, 2006.. We intend to vigorously defend against the plainitffs’ claims; however, we cannot currently predict the ultimate impact of this litigation.

In February 2006, we and our directors were named as defendants in an action entitled Harbinger Capital Partners Master Fund I, LTD v. Hanson, et al., pending in the Delaware Court of Chancery for Newcastle County. The plaintiffs sought a preliminary and permanent injunction finding that the application of the beneficial ownership provisions of the shareholders’ rights plan may not prevent plaintiff from seeking to build a coalition slate with other shareholders or circulate a referendum to shareholders. On February 22, 2006, the Delaware Court of Chancery denied plaintiff’s request for expedited proceedings on their preliminary injunction motion, ruling that it would await rulings on the issue by the federal court in South Dakota. The court has not set a schedule in this action. We intend to vigorously defend against the plaintiff’s claims; however, we cannot currently predict the ultimate outcome of this litigation.

Relative to Colstrip Unit 4’s long-term coal supply contract with Western Energy Company (WECO), Mineral Management Service of the United States Department of Interior issued orders to 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 this matter is currently pending before the Interior Board of Land Appeals of the Department of Interior. In addition, the Montana Department of Revenue has asserted various tax and royalty demands, which are being appealed. We are monitoring the progression of these matters. 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 these matters nor the associated costs can be predicted at this time.

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.

Disputed Claims Reserve

Upon consummation of our Plan, 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. 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.

F-44

(22)         Capital Stock

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 granted for Special Recognition Grants (see Note 17).

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 through November 1, 2007 at a current adjusted strike price of $27.48 (see Note 20). We recognized $3.8 million of expense associated with these warrants as a reduction of cancellation of indebtedness income.

Repurchase of Common Stock

On November 8, 2005, our Board of Directors authorized a common stock repurchase program that allows us to repurchase up to $75 million of common stock. Purchases under the stock repurchase program may be made in the general open market in accordance with Rule 10b-18 under the Securities Exchange Act of 1934. We are also authorized to make privately negotiated repurchases in appropriate circumstances. The purchases are based on a number of factors, including price, volume and timing. From the program’s inception through December 31, 2005 we have repurchased in open market transactions 96,442 shares of common stock for approximately $2.8 million.

We also retired 95,799 shares of common stock during 2005, which were tendered by employees to us to satisfy the employees’ tax withholding obligations in connection with the vesting of restricted stock awards. These shares were retired based on their fair market value on the vesting date.

Shareholder Rights Plan

On December 5, 2005, our Board of Directors adopted a shareholder rights plan, which declared a dividend of one right (Right) for each outstanding share of our common stock at the close of business on December 15, 2005. Each Right entitles the registered holder to purchase from us a unit consisting of 1/1000 of a share (Unit) of Preferred Stock at a purchase price of $100 per Unit, subject to adjustment. The shareholder rights plan is intended to allow the Board of Directors to pursue its review of strategic alternatives in order to maximize value for all shareholders, ensure the fair treatment of all shareholders in the event of a hostile takeover attempt and to encourage a potential acquirer to negotiate with the Board of Directors a fair price for all shareholders before attempting a takeover.

(23)         Segment and Related Information

We currently operate our business in five reporting segments: (i) regulated electric operations, (ii) regulated natural gas 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. We evaluate the performance of these segments based on gross margin. Items below operating income are not allocated between our electric and natural gas segments. 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

F-45

and assumptions. Financial data for the business segments, excluding discontinued operations, are as follows (in thousands):

Successor Company	Regulated				Unregulated
December 31, 2005	Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	631,676	$	365,974	$	86,978	$	157,929	$	595		$	(77,402	)	$	1,165,750
Cost of sales	306,431		246,809		17,407		146,595		402			(75,889		)	641,755
Gross margin	325,245		119,165		69,571		11,334		193			(1,513		)	523,995
Operating, general and administrative	125,053		62,930		32,295		2,718		4,031			(1,513		)	225,514
Property and other taxes	49,297		19,872		2,903		69		(54		)	—			72,087
Depreciation	57,172		14,771		1,043		404		1,023			—			74,413
Reorganization Items	—		—		—		—		7,529			—			7,529
Operating income (loss)	93,723		21,592		33,330		8,143		(12,336		)	—			144,452
Total assets	$	1,516,581	$	713,788	$	48,195	$	55,959	$	57,408		$	—		$	2,391,931
Capital expenditures	$	63,302	$	14,033	2,566		54		$	922		$	—		$	80,877

Successor Company
Two-month period ended	Regulated				Unregulated
December 31, 2004	Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	99,564	$	76,185	$	14,153	$	30,401	$	346		$	(14,697	)	$	205,952
Cost of sales	48,378		51,450		2,566		28,513		265			(14,397		)	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	$	1,503,255	$	707,516	$	29,900	$	76,851	$	60,219		$	—		$	2,377,741
Capital expenditures	$	14,493	$	2,935	$	264	$	28	$	3		$	—		$	17,723
Predecessor Company
10-month period ended	Regulated				Unregulated
October 31, 2004	Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	472,359	$	235,506	$	65,741	$	106,604	$	1,910		$	(49,083	)	$	833,037
Cost of sales	224,243		153,754		15,575		99,734		1,367			(47,619		)	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	$	1,551,971	$	730,445	$	36,735	$	69,716	$	84,217		$	—		$	2,473,084
Capital expenditures	$	40,884	$	17,183	$	4,020	$	288	$	16		$	—		$	62,391

F-46

Predecessor Company	Regulated				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

(24)         Quarterly Financial Data (Unaudited)

The following table sets forth certain unaudited financial data for each of the quarters within fiscal 2005 and 2004. 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 (in thousands):

2005 Successor Company	First		Second			Third			Fourth
Operating revenues,	$	335,093	$	249,387		$	239,123		$	342,147
Gross margin	144,712		118,203			121,300			139,780
Operating income	47,799		24,338			22,269			50,046
Net income (loss)	$	18,918	$	(3,931	)	$	8,836		$	35,644
Average common shares outstanding	35,611		35,607			35,643			35,659
Income (loss) per average common share (basic):
Net income from continuing operations	$	0.52	$	0.18		$	0.26		$	0.77
Discontinued operations	0.01		(0.29		)	(0.01		)	0.23
Net income (loss)	0.53		(0.11		)	0.25			1.00
Income (loss) per average common share (diluted):
Net income from continuing operations	$	0.52	$	0.18		$	0.25		$	0.76
Discontinued operations	0.01		(0.29		)	(0.01		)	0.23
Net income (loss)	0.53		(0.11		)	0.24			0.99
Dividends per share	$	0.22	$	0.22		$	0.25		$	0.31
Stock price:
High	$	28.75	$	31.52		$	31.95		$	31.80
Low	25.73		26.43			30.11			27.88
Quarter-end close	26.37		31.52			30.19			31.07

F-47

	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		June 30			September 30			2004		2004		2004
	(in thousands except per share amounts)
Operating revenues	$	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

F-48

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	Deductions(1)		Balance End of Period
FOR THE YEAR ENDED DECEMBER 31, 2005 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts	$	2,104	2,024	(1,964	)	2,164
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	)	—

(1)           Utilization of previously recorded balances.

EX-12.1

Exhibit 12.1

NorthWestern Corporation

Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges

	Year Ended December 31,		November 1,- December 31,			January 1 - October 31,		Year Ended December 31,
	2005		2004			2004		2003			2002			2001
								(in thousands, except ratios)
Earnings:
Income (loss) before income taxes	$	100,057	$	(11,450	)	$	547,520	$	(71,630	)	$	(49,167	)	$	(2,685	)
Add: Fixed charges as below	61,295		11,021			72,822		162,571			126,620			34,536
Less: Distributions on preferred securities of subsidiary trust	—		—			—		(14,945		)	(28,610		)	(6,827		)
Total	$	161,352	$	(429	)	$	620,342	$	75,996		$	48,843		$	25,024
Fixed Charges:
Interest charges	$	61,295	$	11,021		$	72,822	$	147,626		$	98,010		$	27,709
Distributions on redeemable preferred securities of subsidiary trust	—		—			—		14,945			28,610			6,827
Total	$	61,295	$	11,021		$	72,822	$	162,571		$	126,620		$	34,536
Ratio of earnings to fixed charges	2.63		—			8.52		—			—			—
Earnings to fixed charges deficit	—		(11,450		)	—		(86,575		)	(77,777		)	(9,512		)

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

Name	State of Jurisdiction of Incorporation or Limited Partnership
NorthWestern Corporation		Delaware
NorthWestern Investments, LLC		South Dakota LLC
Blue Dot Services, LLC		Delaware
Netexit, Inc.		Delaware
Clark Fork and Blackfoot, L.L.C.		Montana LLC
NorthWestern Services Corporation		South Dakota
Nekota Resources, Inc.		South Dakota
NorthWestern Energy Development, LLC		Delaware LLC
NorthWestern Generation I, LLC		Delaware LLC
Montana Megawatts I, LLC		Delaware LLC
NorthWestern Energy Marketing, LLC		Delaware LLC
Canadian-Montana Pipe Line Corporation		Canada
Risk Partners Assurance, Ltd.		Bermuda

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements No. 333-122428 and  333-124624 on Form S-8, and No. 333-123450 on Form S-3, and No. 333-123381 on Form S-4 of our reports dated March 3, 2006, relating to the consolidated financial statements and financial statement schedule of NorthWestern Corporation (a Delaware corporation) and Subsidiaries (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the emergence from bankruptcy and adoption of fresh-start reporting in 2004 described in Notes 1 and 3) and management’s report on the effectiveness of internal control over financial reporting appearing in this Annual Report on Form 10-K of NorthWestern Corporation for the year ended December 31, 2005.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, MN

March 3, 2006

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO
17 CFR 240. 13a-14
PROMULGATED UNDER
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Michael J. Hanson, certify that:

1.I have reviewed this annual report on Form 10-K of NorthWestern Corporation;

2.Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 3, 2006
/s/ MICHAEL J. HANSON
Michael J. Hanson
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO
17 CFR 240. 13a-14
PROMULGATED UNDER
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Brian B. Bird, certify that:

1.I have reviewed this annual report on Form 10-K of NorthWestern Corporation;

2.Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d 15(e) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information ; and

(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: March 3, 2006
/s/ BRIAN B. BIRD
Brian B. Bird
	Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of NorthWestern Corporation (the “Company”) on Form 10-K for the fiscal year ended December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Hanson, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1)The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 3, 2006	/s/ MICHAEL J. HANSON
		Michael J. Hanson
		President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of NorthWestern Corporation (the “Company”) on Form 10-K for the fiscal year ended December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brian B. Bird, Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1)The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 3, 2006	/s/ BRIAN B. BIRD
		Brian B. Bird
		Vice President and Chief Financial Officer