On one or more occasions, we may make statements in this report regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements, other than statements of historical facts, included herein relating to management's current expectations of future performance, financial condition, 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 and Section 21E of the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act, and are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.

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

For additional factors that could affect the achievement of our forward-looking statements, you should read "Risk Factors" beginning on page 15. In light of these and other risks, uncertainties and assumptions, actual events or results may be very different from those expressed or implied in the forward-looking statements in this report, or may not occur. The information in this report is subject to change without notice, and we have no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Readers should review future reports filed by us with the SEC.

Industry and market data used throughout this report were obtained through internal company research, surveys and studies conducted by third parties and industry and general publications. Neither we nor the initial purchasers have independently verified, or make any representations or warranties about the accuracy of, market and industry data from third-party sources. While we believe internal company estimates are reliable and market definitions are appropriate, they have not been verified by any independent sources, and neither we nor the initial purchasers make any representations or warranties about the accuracy of such estimates.

This summary highlights some of the information contained in this report. This summary may not contain all the information that is important to you. Therefore, you should read this summary together with the more detailed information appearing elsewhere in this report. We encourage you to read this report and the documents we have referred you to herein in their entirety. In this report, all references to "NorthWestern," "we," "our," "ours" and "us" refer to NorthWestern Corporation and its subsidiaries. You should consider the issues discussed in the "Risk Factors" section beginning on page 15 in evaluating an investment in our security.

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 608,000 customers in Montana, South Dakota and Nebraska as of June 30, 2004. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923. In addition, on February 15, 2002, we acquired electricity and natural gas transmission and distribution assets and natural gas storage assets in Montana. We had consolidated operating income from continuing operations of $78.7 million for the year ended December 31, 2003 compared with consolidated operating income from continuing operations of $75.0 million for the year ended December 31, 2002. Our consolidated revenues and gross margin for the twelve months ended June 30, 2004 were $1,077.4 million and $474.7 million, respectively.

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

Our Montana electric utility business consists of an extensive electric transmission and distribution network. Our Montana service territory covers approximately 107,600 square miles, representing approximately 73% of Montana's land area, as of December 31, 2003, and includes approximately 786,000 people according to the 2000 census. As of December 31, 2003, we delivered electricity to approximately 305,000 customers in 191 communities and their surrounding rural areas in Montana, including Yellowstone National Park. By category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 28%, 36%, 12%, and 24% of our Montana electric revenue, respectively, for the year ended December 31, 2003. We also transmit electricity for non-regulated entities owning generation facilities, other utilities and power marketers serving the Montana electricity market. We do not currently face material competition in the transmission and distribution of electricity within our Montana service territory.

Under Montana law, we are obligated to provide default supply electric service in Montana to customers who have not chosen or are not allowed to choose an alternative electricity supplier. We own no material generation assets in Montana. Accordingly, we purchase substantially all of our Montana capacity and energy requirements for default supply from third parties. Those purchases are recovered through a monthly electricity cost tracking process which is reviewed and adjusted by the MPSC.

For the twelve months ended June 30, 2004, our Montana electric utility business accounted for 53.3% and 60.0% of our total revenues and gross margin, respectively.

Our South Dakota electric utility business operates as a regulated vertically integrated generation, transmission and distribution utility. We have the exclusive right to serve an assigned service area in South Dakota comprised of 25 counties with a combined population of approximately 99,500 people according to the 2000 census. We provided retail electricity to more than 57,600 customers in 108 communities in South Dakota as of December 31, 2003. By category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 38%, 50%, 9% and 3% of our South Dakota electric utility revenue, respectively, for the year ended December 31, 2003. Currently, we serve these customers principally from generation capacity obtained through our undivided interests in three generation plants and other peaking facilities that provide us with 312 megawatts of demonstrated capacity. Direct competition does not presently exist within our South Dakota service territory for the supply and delivery of electricity.

For the twelve months ended June 30, 2004, our South Dakota electric utility business accounted for 9.2% and 14.9% of our total revenues and gross margin, respectively.

Our Montana natural gas business distributed natural gas to nearly 163,000 customers located in 109 Montana communities as of December 31, 2003. We also served several smaller distribution companies that provided service to approximately 28,000 customers as of December 31, 2003. At that date, our natural gas distribution system consisted of approximately 3,500 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. In the year ended December 31, 2003, we transported natural gas volumes of approximately 55 billion cubic feet, with peak capacity in Montana of approximately 300 million cubic feet per day. As of December 31, 2003, the natural gas transmission system consisted of more than 2,000 miles of pipeline and served more than 130 city gate stations. We currently own and operate three working natural gas storage fields in Montana with aggregate storage capacity of approximately 16.2 billion cubic feet, of which 9 billion cubic feet is reserved for our regulated utility business, and maximum aggregate working gas capacity of approximately 185 million cubic feet per day.

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

For the twelve months ended June 30, 2004, our Montana natural gas business accounted for 21.6% and 18.3% of our total revenues and gross margin, respectively.

Our South Dakota and Nebraska natural gas business provided natural gas to approximately 82,000 customers in 59 South Dakota communities and four Nebraska communities as of December 31, 2003.

At that date, we had approximately 2,100 miles of distribution gas mains in South Dakota and Nebraska. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska, and in South Dakota we provide natural gas sales to a number of large volume customers delivered through the distribution system of an unaffiliated natural gas utility company.

For the twelve months ended June 30, 2004, our South Dakota and Nebraska natural gas business accounted for 15.0% and 5.3% of our total revenues and operating income, respectively.

We are focused on creating value for our investors, customers and the communities we serve by becoming the premier regulated energy delivery company in the northwest quadrant of the U.S. To achieve this, we intend to focus on the following strategies:

We believe that we are well-positioned to strengthen our business, improve our balance sheet and credit ratings, and increase our profitability because of the following:

We made substantial investments in non-regulated businesses between 1997 and 2002, particularly in our telecommunications venture and our HVAC operations. These investments required significant capital and incurred substantial losses. After an out of court attempt to restructure our debt could not be implemented, we filed for Chapter 11 bankruptcy protection on September 14, 2003. Pursuant to our Chapter 11 proceeding, we retained control of our assets and were authorized to operate our business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. Included in our consolidated financial statements are subsidiaries that are not debtors in the Chapter 11 case. The assets and liabilities of such subsidiaries are not considered to be material to our consolidated financial statements included herein or are included in discontinued operations therein. In addition, in order to wind-down its affairs in an orderly manner, our subsidiary, Netexit, Inc., also filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code on May 4, 2004.

The Bankruptcy Court approved our first amended disclosure statement for our proposed plan of reorganization on May 26, 2004. Under the terms of our plan of reorganization, we would greatly reduce our debt burden through a debt-for-equity exchange. Holders of claims were required to submit their ballots accepting or rejecting our plan of reorganization by August 2, 2004. The result of the solicitation was overwhelming acceptance by our senior unsecured debtholders, general unsecured claimants and certain litigation claimants. The Bankruptcy Code defines acceptance of a plan of reorganization by a class of claims as acceptance by holders of at least two-thirds in dollar amount and more than one-half in number of the allowed claims of that class that have actually voted. Our plan of reorganization was rejected by the class of our creditors comprised of the holders of our junior subordinated trust preferred securities, which includes holders of our trust preferred securities, or TOPrS, and holders of our quarterly income preferred securities, or QUIPs, because the holders in that class that voted to reject our plan of reorganization held more than one-third in dollar amount of the total amount held by the creditors in that class that voted on our plan of reorganization.

and to confirm our plan of reorganization. As a result of the hearing, we revised the second amended and restated plan of reorganization and second amended and restated disclosure statement and filed revised versions with the Bankruptcy Court on August 31, 2004. An order was entered approving our second amended and restated disclosure statement on September 1, 2004. The second amended and restated plan of reorganization provided that:

Upon consummation of our plan of reorganization, we expect to have an enterprise value of approximately $1.5 billion and equity value of approximately $710 million.

Upon entry of the order approving the second amended and restated disclosure statement, we began resoliciting acceptances and or rejections to the second amended and restated plan of reorganization from holders of our senior unsecured notes and trade vendor claims in excess of $20,000 and holders of TOPrS and QUIPs. A final hearing to consider confirmation of our second amended and restated plan of reorganization was held on October 6, 2004. On October 8, 2004, we received verbal confirmation of our plan of reorganization by the Bankruptcy Court and we anticipate that the Bankruptcy Court will enter a written order confirming our plan of reorganization in the immediate future.

The consummation of this offering is conditional upon the effectiveness of our plan of reorganization. Our plan of reorganization provides that it will become effective upon the satisfaction or waiver of the following conditions:

Parties who object to confirmation of our plan of reorganization have until ten days following the date of entry of our written confirmation order by the Bankruptcy Court to file a notice of appeal from the order confirming our plan of reorganization. Under applicable law, once our plan of reorganization has been "substantially consummated", any pending appeals from the confirmation order may be mooted.

If a notice of appeal from the confirmation order is filed, then there is a risk that the Bankruptcy Court or the federal District Court which would rule on any such appeal could stay the confirmation order and prevent the effective date from occurring. See "Risk Factors—Bankruptcy-Related Risks—Parties objecting to the confirmation of our plan of reorganization may appeal from the order confirming our plan of reorganization."

On July 8, 2004, we announced that we had reached a settlement agreement with the MPSC and the Montana Consumer Counsel, or MCC, resolving outstanding issues involving our plan of reorganization. The Bankruptcy Court approved the settlement agreement on July 15, 2004. As part of the agreement, the MPSC and MCC agreed not to object to confirmation of our plan. In addition, the MCC agreed with us to a consent order by the MPSC to resolve its pending financial investigation. The consent order approving the settlement agreement was issued by the MPSC on August 24, 2004. In return, we agreed to a number of important concessions including, but not limited to, the following:

Criterion		Aggregate Investment Cap
Upon the effective date of the plan of reorganization		$60 million
At least BBB-/Baa3		$75 million
At least BBB/Baa2		$90 million
At least BBB+/Baa1 but in no event earlier than 42 months after the effective date		None;

On July 14, 2004, we announced that we had reached a tentative agreement to settle the McGreevey class action lawsuit filed on behalf of former shareholders of The Montana Power Company. We were named as a defendant due to the fact that we purchased The Montana Power, L.L.C., which the plaintiffs allege is a successor to The Montana Power Company. Under the terms of the settlement agreement, a total of $67 million will be paid by the insurance carriers covering the former Montana Power Company, Clark Fork, Touch America Holdings, Inc., their respective officers and directors, and us. The agreement provides for a release of all claims against the insured companies and their insured officers and directors. Further, the plaintiffs agreed to dismiss with prejudice the claims against the

third party purchasers of the other utility assets of The Montana Power Company. The settlement has been approved by the bankruptcy court adjudicating the Touch America bankruptcy case, which we refer to as the Touch America Bankruptcy Court, but is subject to the approval of our Bankruptcy Court, where a hearing has been set for November 3, 2004, and the United States District Court in Montana. See "Risk Factors—Risks Relating to Our Business—We are one of several defendants in the McGreevey litigation, a class action lawsuit brought in connection with the sale of generating and energy-related assets by The Montana Power Company. If we do not successfully resolve this lawsuit, the insurance coverage does not pay for any damages we are found liable for, or our indemnification claims against TouchAmerica Holdings, Inc. cannot be enforced and reimbursed, then our business will be harmed and there will be a material adverse impact on our financial condition."

Clark Fork, our wholly owned subsidiary, owns and operates the 3-megawatt Milltown Dam hydroelectric facility. On June 21, 2004, the Bankruptcy Court issued an order approving the funding by us of our negotiated share of the remediation and restoration costs with respect to the Milltown Reservoir Superfund site. The reservoir is located behind the Milltown Dam hydroelectric facility. Under the terms of the settlement framework approved in the order, we and Clark Fork, collectively, will pay a total of $11.4 million toward cleanup of the superfund site at Milltown Reservoir. The agreement incorporated into the order provides that we will pay $7.5 million to the Atlantic Richfield Company, or ARCO, the other alleged potentially responsible party at the Milltown Reservoir Superfund site, and $2.5 million to the State of Montana. We have established two escrow accounts, one for the benefit of the State of Montana and one for the benefit of ARCO, and are funding the accounts, on an alternating basis, with monthly payments of $500,000 until the total agreed amount is funded. The remaining $1.4 million amount due the State of Montana will be funded through the sale of certain assets held by Clark Fork. The settlement will be incorporated into and is expressly conditioned upon entry of a final, nonappealable consent decree among the EPA, the State of Montana, us and ARCO, which we expect will be entered in 2005. The monies held in the escrow accounts will not be released until the consent decree is final.

On February 7, 2004, all parties to the consolidated securities class actions and consolidated derivative litigation captioned In re NorthWestern Corporation Securities Litigation and Derivative Litigation, along with other interested parties, reached settlement of the two consolidated lawsuits. Prior to Bankruptcy Court approval, the federal court in Sioux Falls indicated that it intended to grant preliminary approval of the settlement agreement pending Bankruptcy Court approval. Among the terms of the proposed settlement, Expanets, Blue Dot, we and other parties and persons will be released from all claims to these cases. In addition, a settlement fund in the amount of $41 million, of which approximately $37 million would be contributed by our directors and officers liability insurance carriers and $4 million would be contributed from other persons and parties, will be established. The plaintiffs also would have a $20 million liquidated securities claim against Netexit. On September 15, 2004, the bankruptcy court in the Netexit bankruptcy case approved the terms of the settlement. The Bankruptcy Court entered an order approving the settlement on October 7, 2004 and the federal District Court hearing the litigation scheduled a hearing for December 13, 2004 to approve the settlement agreement.

For more information on these and other litigation matters, see "Business—Legal Proceedings."

Concurrently with the consummation of our plan of reorganization, we will establish a new credit facility, which will include revolving and term tranches. Borrowings under the term portion of the new credit facility, together with the net proceeds of our recently announced debt offering and available cash, will be used for the repayment of our current term loan credit facility that is agented by an affiliate of Credit Suisse First Boston, which we refer to as the CSFB Facility. In addition, we expect to issue approximately $15 million of letters of credit under the revolving portion of the new credit facility to replace letters of credit initially issued under the DIP facility in order to terminate the DIP facility. In this report, we refer to these transactions collectively as "the Transactions." Consummation of our recently announced debt offering is conditional on, among other things, consummation of our plan of reorganization and our entry into the new credit facility.

Concurrently with the consummation of our plan of reorganization and our recently announced debt offering, we will enter into a new $250 million credit facility consisting of a five-year revolving tranche and a seven-year term tranche. The $125 million revolving tranche will be available to us for general corporate purposes and for the issuance of letters of credit. On the closing date, we will borrow $125 million under the term tranche.

We will use the proceeds from our recently announced debt offering, cash on hand and borrowing under the new credit facility to repay all amounts owed by us to the lenders under the CSFB Facility, which had an original principal amount outstanding of $390 million. In addition, we expect to use approximately $15 million of the availability under the revolving tranche of the new credit facility to issue letters of credit to replace other outstanding letters of credit initially issued under the DIP facility in order to terminate the DIP facility.

The following table sets forth our summary financial data for the periods indicated. The summary financial data for the years ended December 31, 2001, 2002 and 2003 were derived from the audited financial statements that are included in our 10-K filed with the SEC and the six months ended June 30, 2003 and 2004 were derived from the unaudited financial statements that are included in our 10-Q filed with the SEC. The summary financial data for the twelve months ended June 30, 2004 were derived from our accounting records. This summary is qualified in its entirety by the more detailed information and financial statements, including the notes to that information and those financial statements, included elsewhere herein.

You should read the following information in conjunction with the sections entitled "Capitalization," "Selected Historical Financial Information", "Unaudited Pro Forma Financial Information" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the related notes thereto. Results for the six month periods ended June 30, 2003 and 2004 and for the twelve month period ended June 30, 2004 are not necessarily indicative of results that may be expected for the entire year. Because of our Chapter 11 case, our actual results after consummation of our plan of reorganization may be materially different from our historical results set forth in this report.

Investing in our securities involves risks. You should carefully consider the risks described below as well as all the information contained in this report before investing in our securities. The risks and uncertainties described below are not the only ones facing our company. Additional risks and uncertainties not presently known or that we currently believe to be less significant may also adversely affect us.

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

Parties who objected to confirmation of our plan of reorganization may file a notice of appeal from the confirmation order within the ten-day period following the entry of such written order. In order to preserve all of its rights with respect to the appeal, an appellant may seek a stay of the confirmation order from the Bankruptcy Court. Even if the Bankruptcy Court denies the request for a stay, or upon a showing that such relief would not have been available from the Bankruptcy Court, an appellant may also request a stay from the United States District Court having jurisdiction over the appeal. While appellants seeking a stay often are required to post a bond or other appropriate security to protect the rights of the other parties to the proceeding, it is not always required. A stay would prevent consummation of our plan of reorganization until the appeal is adjudicated or the stay is lifted, which could be a lengthy period of time. Under the Bankruptcy Code, parties should not be able to file a notice of appeal from the confirmation order after such ten-day period, although no assurance can be given that a court will not entertain such a filing, even if it is made after such ten day period.

Generally, consummation of a plan of reorganization equitably moots an appeal. However, in certain rare circumstances, district or appellate courts have refused to dismiss an appeal from an order confirming a plan (even if no stay was obtained) if the courts are able to fashion a remedy for the appellant or the issue on appeal is not integral to the reorganization. Accordingly, if a party appealing from the confirmation order is successful on appeal, our reorganized business could be adversely impacted.

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

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

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

We have incurred and will continue to incur significant costs associated with the Chapter 11 proceedings. The amount of these costs, which are being expensed as incurred, are expected to have a significant adverse effect on our results of operations and cash flows. If our plan of reorganization is successfully consummated and we emerge from bankruptcy, we expect to continue to incur significant costs in connection with the consummation of our plan of reorganization. These expenses are also expected to have an adverse effect on our results of operations and cash flows.

Our ability to raise capital may be adversely affected if the shares of common stock to be issued under our plan of reorganization are not listed on the NASDAQ or another major exchange or if a liquid trading market for our new common stock does not develop.

Under our plan of reorganization, our existing common stock will be cancelled and we will issue new common stock to certain of our creditors upon our emergence from Chapter 11 in full or partial satisfaction of creditor claims. On September 14, 2004, in connection with the contemplated issuance of the new common stock, we filed an application with the NASDAQ requesting that our common stock be listed on the NASDAQ. We received a request for supplemental information from the NASDAQ on October 6, 2004, to which we intend to respond in the near future, after the confirmation order is entered by the Bankruptcy Court. There can be no assurance that any of our new common stock issued under our plan of reorganization will be listed on the NASDAQ or any other major exchange or that a trading market will develop for our new common stock. Reduced liquidity of our new common stock also may reduce our ability to access the capital markets in the future.

We will be subject to claims made after the date that we filed for bankruptcy and other claims that are not discharged in the bankruptcy proceeding, which could have a material adverse effect on our results of operations and profitability.

Although most claims made against us prior to the date of the bankruptcy filing will be satisfied and discharged in accordance with the terms of our plan of reorganization or in connection with settlement agreements that were approved by the Bankruptcy Court prior to consummation of our plan of reorganization, certain claims that will not be discharged or settled may have a material adverse effect on our results of operations and profitability. In addition, claims arising after the date of our bankruptcy filing which are not otherwise discharged pursuant to Section 1141 of the Bankruptcy Code may not be discharged in the bankruptcy proceeding.

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

In addition, although we expect a written order to be entered in the immediate future confirming our plan of reorganization, upon consummation of our plan of reorganization, we will establish a reserve of approximately 4.6 million shares of common stock from the shares allocated to holders of our trade vendor claims in excess of $20,000 and holders of senior unsecured notes. The shares held in this reserve may be used to resolve various outstanding litigation, such as the QUIPs Litigation, certain litigation with PPL Montana and other unliquidated litigation claims, as these claims will not be discharged upon consummation of our plan of reorganization. If we are not able to settle these pending litigations and the plaintiffs in such cases receive a judgment in their favor, then such plaintiffs would receive the consideration to which they would have been entitled if their claim had been an allowed unsecured claim under our plan of reorganization. See the "Business—Legal Proceedings" section of this report for a description of the significant legal proceedings and investigations in which we are presently involved.

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

Under our plan of reorganization, holders of certain claims will receive distributions of shares of our common stock. AG Capital Recovery Partners III, L.P., which we refer to as AG Capital, manages funds which, based on the most recent information made available to us, collectively are expected to receive at least 20% of our new common stock and Harbert Management Corporation, which we refer to as Harbert Management, is affiliated with funds which, based on the most recent information made available to us, collectively are expected to receive at least 5% of our new common stock. AG Capital and Harbert Management could acquire additional claims or shares, or they could divest claims or shares in the future. Our prepetition senior unsecured noteholders, trade vendors with claims in excess

of $20,000 and holders of the TOPrS and QUIPs will receive, collectively, 100% of our new common stock. Other than AG Capital and Harbert Management, however, we are not aware of any other entity that will own or control 5% or more of our common stock to be distributed pursuant to our plan of reorganization.

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

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

We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al., now pending in federal court in Montana. The lawsuit, which was filed by the former shareholders of The Montana Power Company (many of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of The Montana Power Company), claims that the disposition of various generating and energy-related assets by The Montana Power Company was void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern is named as a defendant due to the fact that we purchased Montana Power LLC, which the plaintiffs claim is a successor to The Montana Power Company. On November 6, 2003, the Bankruptcy Court approved a stipulation between NorthWestern and the plaintiffs in McGreevey, et al. v. The Montana Power Company, et al. The stipulation provides that litigation, as against NorthWestern, our wholly owned subsidiary Clark Fork, The Montana Power Company, The Montana Power L.L.C. and Jack Haffey, was temporarily stayed for 180 days from the date of the stipulation. Pursuant to the stipulation and after providing notice to NorthWestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. On July 10, 2004, we and the other insureds under the applicable directors and officers liability insurance policies along with the plaintiffs in the McGreevey case, plaintiffs in the In Re Touch America Holdings, Inc. Securities Litigation and the Touch America Creditors Committee reached a tentative settlement as a result of mediation. Among the terms of the tentative settlement, we, Clark Fork 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. If the proposed settlement is not consummated, then we intend to vigorously defend against this lawsuit. The Bankruptcy Court has entered an order permitting the plaintiffs in McGreevey to file a fraudulent conveyance action against us if we are not able to consummate the settlement. The Bankruptcy Court has scheduled a hearing on November 3, 2004 to approve the settlement. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition.

We are a defendant in the QUIPs Litigation, which is related to the transfer of certain assets to NorthWestern from our subsidiary, Clark Fork, and which could result in assets being removed from the property of the Chapter 11 case. Certain current and former officers of Clark Fork are defendants in a lawsuit related to the same transfer of assets. Our business could be harmed and there could be a material adverse impact on our financial condition if we do not successfully resolve the lawsuit.

Certain creditors and parties-in-interest have initiated legal action against us related to the transfer of the assets and liabilities comprising our Montana utility operations from Clark Fork to NorthWestern, and seek the removal of such assets from our estate or the imposition of a constructive trust for the benefit of such creditors. This litigation may continue after the consummation of our plan of reorganization, which could adversely affect our business, results of operations and financial condition and our ability to continue normal operations. For further information regarding this proceeding, see "Business—Legal Proceedings."

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 from the SEC requesting documents and testimony from employees regarding these matters. The SEC investigation will continue and any claims alleging violations of federal securities laws made by the SEC will not be extinguished pursuant to our plan of reorganization.

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

We are cooperating with the SEC's investigation and intend to cooperate with the FBI if we are contacted in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, for which we can provide no assurance, we may face sanctions, including, but not limited to, monetary penalties and injunctive relief and any monetary liability incurred by us may be material to our financial position or results of operations.

If the MPSC disallows the recovery of the costs incurred in entering into default supply portfolio contracts while we are required to act as the "default supplier," then we may not be able to fully recover the costs incurred in procuring default supply contracts, which could adversely affect our net income and financial condition.

Our electric and natural gas default supply costs are being recovered through an annual cost tracking process pursuant to which rates are based on estimated electricity and natural gas loads and supply costs for the upcoming tracking period and are annually reviewed and adjusted by the MPSC for any differences in the previous tracking year's estimates to actual information. The MPSC could, in any particular year, disallow the recovery of a portion of the electricity or natural gas default supply costs if it makes a determination that we acted imprudently with respect to the open market purchase

strategies or that the approved supply contracts were not prudently administered. A failure to recover such costs could adversely affect our net income and financial condition.

We are subject to extensive governmental regulations, with existing and changed regulations and possible deregulation having the potential to impose significant costs, increase competition and change rates.

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

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

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

Proposals have been introduced in Congress to repeal the Public Utility Holding Company Act of 1935, or PUHCA. To the extent regulatory barriers to entry are eliminated, competitive pressures increase, or the pricing and sale of transmission or distribution services or electricity or fuel assume more characteristics of a commodity business, we could face increased competition adverse to our business. There is no assurance that the introduction of new laws or other future regulatory developments will not have a material adverse effect on our business, results of operations or financial condition. If we cannot comply with all applicable regulations, our business, results of operations, and financial condition could be adversely affected.

If, upon consummation of our plan of reorganization, AG Capital, Harbert Management or any other entity owns 10% or more of our voting securities, such entity would be deemed to be a holding company under PUHCA and we would be deemed a subsidiary of a holding company. If that occurs, unless a 10% holder were able to qualify for an exemption from registration, such 10% holder and we and our subsidiaries would become subject to a comprehensive regulatory scheme imposed by the SEC in order to protect customers, investors and the public interest. Although the SEC does not regulate rates and charges under PUHCA, it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. In order to obtain financing, acquire additional public utility assets or stock, or engage in other significant transactions, we would generally be required to obtain approval from the SEC under PUHCA.

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

Montana law required the MPSC to determine the value of net unmitigable transition costs associated with the transformation of the former utility business of The Montana Power Company from a vertically integrated electric service company to a utility providing only default supply and transmission and distribution services. The MPSC was also obligated to set a competitive transition charge, or CTC, to be included in distribution rates to collect those net transition costs. The majority of these transition costs relate to out-of-market power purchase contracts, which run through 2032, that the former owner of our Montana transmission and distribution business was required to enter into with certain "qualifying facilities" (QF) as established under the Public Utility Regulatory Policies Act of 1978. Based on results of an MPSC order and a FERC determination, we will not be able to fully recover all of the transition costs. As of June 30, 2004, we estimated that we will undercollect approximately $143.0 million on a net present value basis over the remaining terms of the QF power supply contracts. While the CTC is designed to adjust and compensate for future changes in sales volumes or other factors affecting actual cost recoveries, the CTC runs through the year 2029, and therefore, we cannot predict with certainty the actual recovery of transition costs. Changes in the recovery of transition costs could adversely affect our net income and financial condition by increasing the current under collection amount.

We may not be able to continue as a going concern unless we can achieve profitability following consummation of our plan.

Our financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of the bankruptcy filing and related events, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be liquidated or settled for the amounts recorded. In addition, as noted in the unaudited pro forma financial statements included herein, the implementation of our plan of reorganization could change the amounts reported in the financial statements. Our liquidity generally depends on cash provided by operating activities and access to the new credit facility. Our ability to continue as a going concern and the continued appropriateness of using the going concern basis for our financial statements are dependent upon, among other things, (i) our ability to comply with the covenants of the instruments governing our indebtedness, (ii) our ability to maintain adequate cash on hand, (iii) our ability to continue to generate cash from operations, (iv) our ability to attract, retain and compensate key executives and associates and to retain employees generally, and (v) our ability to achieve profitability following such consummation.

Our actual fresh-start reporting adjustments may vary significantly from the fresh-start reporting adjustments used to calculate the pro forma financial data that is included in this report.

We will adopt fresh-start reporting upon the consummation of our plan of reorganization. Under fresh-start reporting, our confirmed enterprise value will be allocated to our assets based on their respective fair values in conformity with the purchase method of accounting for business combinations. Any portion not attributed to specific tangible or identified intangible assets will be an indefinite-lived intangible asset referred to as "reorganization value in excess of value of identifiable assets" and reported as goodwill. Any excess of fair value of assets and liabilities over confirmed enterprise value will be allocated as a pro rata reduction of the amounts that otherwise would have been assigned to all of the assets except financial assets other than investments accounted for by the equity method, assets to be disposed of by sale, deferred tax assets, prepaid assets relating to pension or other postretirement benefit plans and any other current assets.

We have prepared unaudited pro forma consolidated financial data which give effect to fresh-start reporting adjustments, as reflected in "Unaudited Pro Forma Financial Information." These statements have been prepared by us based on the assumptions described in the footnotes to the pro forma financial information contained in this report. However, we will obtain actuarial valuations and reduce

certain tax attributes based on our cancellation of indebtedness income as of the date we emerge from bankruptcy. As a result, we expect there may be adjustments in carrying values of certain assets and liabilities and such adjustments may be material.

We are subject to risks associated with a changing economic environment that could adversely affect our access to funding for our operations.

Events such as the bankruptcy of several large energy and telecommunications companies have adversely affected the availability and cost of capital for our business. Such economic environment, if sustained, could constrain the capital available to our industry and would adversely affect our access to funding for our operations.

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.

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

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

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

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

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

Changes in commodity prices and availability of supply may increase our cost of producing and distributing electricity and distributing natural gas or decrease the amount we receive from selling electricity and natural gas, adversely affecting our financial performance and condition.

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

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

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

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

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

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be predicted. Our range of exposure for environmental remediation obligations is estimated to be $45.3 million to $84.1 million. We had an environmental reserve of $45.3 million at June 30, 2004. This reserve was established in anticipation of future remediation activities at our various environmental

sites and does not factor in any exposure to us arising from private tort actions or government claims for damages allegedly associated with specific environmental conditions. These environmental liabilities will continue and any claims with respect to environmental liabilities will not be extinguished pursuant to our plan of reorganization. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies, our results of operations and financial condition could be adversely affected.

We have experienced increased interest costs and other adverse consequences as a result of our loss of investment grade credit ratings and expect that our non-investment grade status will continue to adversely affect our cash flows.

Our credit ratings have been downgraded to non-investment grade and could be downgraded further. Our current non-investment grade ratings have increased our borrowing costs, both by increasing the actual interest rates we will be required to pay under the new credit facility and any debt in the capital markets that we are able to issue and by requiring us to either prepay or post significant amounts of collateral in the form of cash and letters of credit to support our asset-based businesses and our remaining customer risk management business. In addition, our stated intention to resume the payment of quarterly dividends on our common stock upon demonstrating the financial ability to do so may delay our ability to achieve an investment grade rating for our debt securities. While we are working to resolve many of the concerns cited by the credit rating agencies, we cannot assure you that our credit ratings will improve in the foreseeable future.

We reported a net loss of $113.7 million for the fiscal year ended December 31, 2003, and have incurred losses in prior periods. Our results of operations will continue to be affected by events and conditions both within and beyond our control, including competition, economic, financial, business and other conditions. Therefore, we cannot assure you that we will not incur net losses in the future.

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

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

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

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

Our subsidiary, Netexit, sold substantially all of its assets to Avaya, Inc. In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. Pending the resolution of open claims to Netexit creditors, the proceeds from the sale remain at Netexit and distributions to NorthWestern will be delayed until the bankruptcy proceedings are

resolved. If we encounter unexpected claims or costs relating to its wind-down of operations, our ability to receive any distributions from Netexit and our liquidity could be adversely affected.

As of June 30, 2004, our subsidiary Blue Dot had four remaining businesses. As of August 27, 2004, two of those businesses had been sold and Blue Dot had entered into a letter of intent to sell one of the remaining two businesses. Cash proceeds from business sales remain at Blue Dot. Our ability to realize such proceeds depends upon, among other things, satisfactory resolutions to remaining stock obligations and potential or pending litigation and the amount of insurance and bonding reserves. If we encounter unexpected liabilities or costs relating to the wind-down of operations of Blue Dot, our ability to realize any proceeds from the sale of Blue Dot's assets and our liquidity could be adversely affected.

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

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

Our actual financial results may vary significantly from the projections filed with the Bankruptcy Court.

In connection with our plan of reorganization, we were required to prepare projected financial information to demonstrate to the Bankruptcy Court the feasibility of our plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. That financial information will not be updated on an ongoing basis. These projections were based on financial information available to us as of May 17, 2004. The projections were initially filed with the Bankruptcy Court on May 17, 2004. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to uncertainties and to a wide variety of significant business, economic and competitive risks. Our actual results will vary from those contemplated by the projections and the variations may be material. As a result, we caution you not to rely upon the projections.

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

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

We have and, after completing the Transactions, will continue to have a significant amount of indebtedness. On June 30, 2004, after giving pro forma effect to the Transactions, we would have had total indebtedness of $853.2 million, of which approximately $777.1 million would have been secured by first mortgage bonds, including $200.0 million of debt to be issued in our recently announced debt offering and $125.0 million outstanding under the term portion of the new credit facility and the balance would have consisted of other debt.

Despite current indebtedness levels, we and certain of our subsidiaries may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial leverage.

We may be able to incur additional indebtedness in the future. Our new credit facility would permit us to incur debt in certain circumstances. If new indebtedness is added to our current debt levels, the related risks that we now face could intensify. Notwithstanding the flexibility in the new credit facility with respect to the incurrence of additional debt, as part of our July 8, 2004 settlement with the MPSC and the MCC, we agreed to certain restrictions and obligations with respect to the incurrence of additional indebtedness and our use of the proceeds therefrom. See "Summary—Recent Developments—MPSC Consent Order" for a more detailed discussion of the July 8, 2004 settlement.

The following table sets forth our capitalization as of June 30, 2004 on an actual basis, on a pro forma basis to reflect the consummation of our plan of reorganization ("Reorganization") and as adjusted to reflect the Reorganization and the Transactions as if they had occurred on June 30, 2004. This table should be read in conjunction with our consolidated financial statements and the related notes thereto and the sections entitled "Selected Historical Financial Information," "Unaudited Pro Forma Financial Information" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this report.

The following unaudited pro forma consolidated financial data have been prepared by applying adjustments to our consolidated financial statements included elsewhere in this report. Pursuant to American Institute of Certified Public Accountants, or "AICPA," Statement of Position 90-7 "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," or "SOP 90-7," the accounting for the effects of the reorganization will occur once a plan of reorganization is confirmed by the bankruptcy court and there are no material conditions to completing the implementation of our plan of reorganization. The following unaudited pro forma consolidated financial information at June 30, 2004, for the year ended December 31, 2003 and for the six months ended June 30, 2004 gives effect to the Reorganization and the Transactions, as if the same had occurred on June 30, 2004 (in the case of balance sheet data) and as of the beginning of the periods presented (in the case of the statements of income (loss)). The pro forma financial information should be read in conjunction with our consolidated financial statements, the notes thereto and other financial information contained in this report, including the "Management's Discussion and Analysis of Financial Condition and Results of Operations." The unaudited pro forma consolidated financial data do not purport to represent what our results of operations or financial condition would actually have been if the Reorganization and the Transactions had occurred on the dates indicated, nor are they indicative of results for any future periods.

On August 25, 2004, the Bankruptcy Court held a hearing to approve our second amended and restated disclosure statement and to confirm our plan of reorganization. As a result of the hearing, we revised the second amended and restated plan of reorganization and second amended and restated disclosure statement and filed revised versions with the Bankruptcy Court on August 31, 2004. An order was entered approving our second amended and restated disclosure statement on September 1, 2004 and our plan of reorganization will become effective upon the satisfaction of certain conditions discussed under "The Bankruptcy Restructuring—Effectiveness of Our Plan of Reorganization."

In accordance with SOP 90-7, certain companies are required to adopt fresh start reporting in connection with their emergence from bankruptcy. Fresh start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation will receive less than 50 percent of the voting shares of the emerging entity. We meet these requirements and, upon consummation of our plan of reorganization, will adopt fresh start reporting. The fresh start reporting principles provide, among other things, for us to determine the value to be assigned to the assets of reorganized NorthWestern as of the confirmation date, assuming no material conditions precedent to emergence. Under fresh start reporting, our reorganization value will be allocated to our assets based on their respective fair values in conformity with the purchase method of accounting for business combinations; any portion not attributed to specific tangible or identified intangible assets will be treated as an indefinite-lived intangible asset referred to as "reorganization value in excess of value of identifiable assets" and reported as goodwill. Any excess of fair value of assets and liabilities over confirmed enterprise value will be allocated as a pro rata reduction of the amounts that otherwise would have been assigned to all of the assets except financial assets other than investments accounted for by the equity method, assets to be disposed of by sale, deferred tax assets, prepaid assets relating to pension or other postretirement benefit plans and any other current assets. Based on certain regulatory considerations, the value of our property, plant and equipment should be kept at historical book value less adjustments which reduce these assets to the amount included in our utility rate base; therefore, management will apply the entire excess reorganization value adjustment to goodwill. The pro forma balance sheet contains estimated deferred tax balances, which are primarily dependent upon our ability to utilize net operating losses, attribute reductions related to cancellation of indebtedness income and the tax basis of our fixed assets. The adjustments reflected in the pro forma financial information below are preliminary and subject to further revisions and adjustments, pending an update based on the actuarial valuations and applicable economic conditions as of the effective date of fresh start reporting. Our actual fresh-start reporting adjustments may vary significantly from the fresh-start reporting adjustments used to calculate the pro forma financial information that is set forth below.

NORTHWESTERN CORPORATION
UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF INCOME (LOSS)

The accompanying notes are an integral part of these
unaudited pro forma consolidated financial statements.

NORTHWESTERN CORPORATION
UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF INCOME (LOSS)

The accompanying notes are an integral part of these
unaudited pro forma consolidated financial statements.

NORTHWESTERN CORPORATION
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF INCOME (LOSS)

The accompanying notes are an integral part of these
unaudited pro forma consolidated financial statements.

NORTHWESTERN CORPORATION
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

(1) Reflects the discharge of debt and liabilities in accordance with our plan of reorganization, and the impact of fresh-start reporting.

(3) Reflects the anticipated uses of cash pursuant to our plan of reorganization, including the use of $25 million to satisfy administrative priority claims, unsecured priority claims and convenience class claims.

(4) Reflects the excess reorganization value pursuant to the valuation under our plan of reorganization and in accordance with "fresh start" accounting. Based on certain regulatory considerations, our property, plant and equipment should be kept at historical book value less adjustments which reduce these assets to the amount included in utility rate base, therefore management has applied the entire excess reorganization value adjustment to goodwill.

(5) Increase in regulatory assets of $38.1 million in connection with the valuation adjustment for our pension plans, based on actuarial valuations as of December 31, 2003.

(6) Reflects the write-off of $24.3 million of unamortized deferred financing costs related to extinguished unsecured notes.

(7) Adjusts for the estimated net deferred tax position for NorthWestern upon consummation of our plan of reorganization.

(8) Represents an adjustment of $27.9 million to reflect the fair value of NorthWestern's pension liability, based on actuarial valuations as of December 31, 2003.

(9) Reflects the conversion into equity or extinguishment of unsecured debt and company obligated mandatorily redeemable preferred securities of subsidiary trusts pursuant to our plan of reorganization.

(10) Reflects $12.0 million in cash paid out to settle convenience class claims and other payables, the recognition of a $13.2 million deferred gain on a previously terminated fair value hedge resulting from the extinguishment of related unsecured notes, and the extinguishment of $46.9 million of accrued interest and dividends resulting from the extinguishment of related unsecured notes pursuant to our plan of reorganization.

(11) Represents elimination of historical retained deficit of $935.1 million and issuance of $710.0 million of new stock.

(12) Reflects the reclassification of secured debt and other trade claims, which pursuant to our plan of reorganization will be unimpaired and reinstated.

(13) Reflects the use of net proceeds from our recently announced debt offering, together with $125.0 million to be drawn under the term tranche of the new credit facility concurrently with the closing of our recently announced debt offering, and $71.2 million in available cash to repay amounts due under the CSFB Facility, including prepayment penalties, and the fees and expenses relating to the Transactions.

The following table sets forth our selected financial information for the fiscal years ended December 31, 2001, 2002 and 2003, for the six months ended June 30, 2003 and 2004 and for the twelve months ended June 30, 2004. The selected financial information for the fiscal years was derived from the audited financial statements that are included in our 10-K filed with the SEC and the selected financial information for the six month periods was derived from the unaudited financial statements that are included in our 10-Q filed with the SEC. The selected financial information for the twelve months ended June 30, 2004 were derived from our accounting records. The following selected financial information is qualified in its entirety by the more detailed information and financial statements, including the notes to that information and those financial statements, included elsewhere herein.

You should read the following information in conjunction with the sections entitled "Capitalization," "Unaudited Pro Forma Financial Information" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the related notes thereto included elsewhere herein. Results for the six month periods ended June 30, 2003 and 2004 and for the twelve month period ended June 30, 2004 are not necessarily indicative of results that may be expected for the entire year. Because of our Chapter 11 case, our actual results after consummation of our plan of reorganization may be materially different from our historical results set forth in this report.

The following table sets forth our historical and pro forma adjusted ratios of earnings to fixed charges for the periods indicated. The ratios of historical earnings are prepared on a consolidated basis in accordance with accounting principles generally accepted in the United States and, therefore, reflect all consolidated earnings, which consist of losses, including restructuring charges, before allocation to minority interests, and fixed charges, which consist of fixed charges associated with non-recourse obligations of our consolidated subsidiaries. The ratios of pro forma adjusted earnings to fixed charges reflect the Reorganization and the Transactions, all as of the dates indicated and as more fully described in "Unaudited Pro Forma Combined Financial Information."

For the purpose of calculating such ratios, "earnings" consist of income from continuing operations before income taxes before allocation of net losses to minority interests, and "fixed charges" consist of interest on all indebtedness, including trust preferred securities distribution requirements, amortization of debt expense and the percentage of rental expense on operating leases deemed representative of the interest factor.

The deficiency of one-to-one coverage was $9.5 million for the actual year ended December 31, 2001; $77.8 million for the actual year ended December 31, 2002; $86.6 million for the actual year ended December 31, 2003; $50.6 million for the actual six months ended June 30, 2003; $2.6 million for the actual six months ended June 30, 2004 and $38.5 million for the actual twelve months ended June 30, 2004.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations covers periods prior to the Reorganization and the Transactions. Accordingly, the discussion and analysis of historical periods do not reflect the significant impact that the Reorganization and the Transactions will have on us. In addition, the statements relating to our expectations regarding the performance of our business and the other non-historical statements in the discussion and analysis are intended as forward-looking statements. These forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described in the "Forward-Looking Statements" and "Risk Factors" sections of this report. Our actual results may differ materially from those contained in or implied by any forward-looking statements. You should read the following discussion together with the sections entitled "Forward-Looking Statements," "Risk Factors," "Selected Historical Financial Information" included elsewhere herein and our consolidated financial statements and the related notes filed with the SEC.

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

On September 14, 2003, which we refer to as the Petition Date, we filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code in the Bankruptcy Court under case number 03-12872 (CGC). Pursuant to Chapter 11, we retain control of our assets and are authorized to operate our business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. All vendors are being paid for all goods furnished and services provided after the Petition Date under the supervision of the Bankruptcy Court. As a debtor-in-possession, we are authorized to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the approval of the Bankruptcy Court, after notice and an opportunity for a hearing. Included in the consolidated financial statements are subsidiaries that are not party to our Chapter 11 case. The assets and liabilities of such subsidiaries are not considered to be material to the consolidated financial statements or are included in discontinued operations. In addition, in order to wind-down its affairs in an orderly manner, our subsidiary, Netexit, Inc. 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 on May 4, 2004.

class that voted to reject our plan of reorganization held more than one-third in dollar amount of the total amount held by the creditors in that class that voted on our plan of reorganization.

On August 18, 2004, we and the committee of our unsecured creditors entered into an agreement with the holders of the TOPrS and we filed our second amended and restated plan of reorganization and second amended and restated disclosure statement on August 18, 2004. On August 25, 2004, the Bankruptcy Court held a hearing to approve our second amended and restated disclosure statement and to confirm our plan of reorganization. As a result of the hearing, we revised the second amended and restated plan of reorganization and second amended and restated disclosure statement and filed revised versions with the Bankruptcy Court on August 31, 2004. An order was entered approving our second amended and restated disclosure statement on September 1, 2004. The second amended and restated plan of reorganization provided that:

Upon consummation of our plan of reorganization, we expect to have an enterprise value of approximately $1.5 billion and equity value of approximately $710 million.

Upon entry of the order approving the second amended and restated disclosure statement, we began resoliciting acceptances and or rejections to the second amended and restated plan of reorganization from holders of senior unsecured notes and trade vendor claims in excess of $20,000 and holders of TOPrS and QUIPs. A final hearing to consider confirmation of our second amended and restated plan of reorganization was held on October 6, 2004. On October 8, 2004, we received verbal confirmation of our plan of reorganization by the Bankruptcy Court and we anticipate that the Bankruptcy Court will enter a written order confirming our plan of reorganization in the immediate future.

Upon consummation of our plan of reorganization, we will establish a reserve of approximately 4.6 million shares of common stock from the shares allocated to holders of our trade vendor claims in excess of $20,000 and holders of senior unsecured notes. The shares held in this reserve may be used to resolve various outstanding litigation, such as the QUIPs Litigation, certain litigation with PPL Montana and other unliquidated litigation claims.

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

These challenges are in addition to those operational, regulatory and other challenges that we face in connection with our business as a regional utility. In addition, we have incurred and will continue to incur, significant expenses and costs associated with the Reorganization, even for several months after we emerge from bankruptcy.

The following paragraphs provide brief summaries of the status of our non-core asset sale efforts.

In order to wind-down its affairs in an orderly manner, our subsidiary Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. On June 30, 2004, Netexit filed schedules and statements of financial affairs with the Bankruptcy Court, setting forth, among other things, the assets and liabilities of Netexit. The schedules, which were prepared by NorthWestern management and are unaudited, list total assets of approximately $67.6 million (primarily cash and short-term investments) and total liabilities of approximately $237.9 million as of May 4, 2004, of which approximately $237.7 million (including contractual interest of $13.7 million) of the total liabilities represents intercompany obligations by Netexit to NorthWestern. We anticipate receiving cash proceeds in excess of $40 million upon the ultimate liquidation of Netexit. However, the amount of the claims to be filed against Netexit by creditors could be significantly different than the amount of the liabilities that have been recorded. Netexit will incur significant additional expenses related to the bankruptcy filing and may incur losses related to the resolution of open claims. Netexit has not yet proposed a plan of reorganization but anticipates doing so during the fourth quarter of 2004. Pending the resolution of open claims to Netexit creditors, the proceeds from the sale remain at Netexit and distributions to NorthWestern will be delayed until the Netexit bankruptcy proceedings are resolved. Our ability to emerge from Chapter 11 protection is not linked to resolution of the Netexit bankruptcy proceedings.

Effective November 1, 2002, we relinquished our direct and indirect equity interests in CornerStone Propane, L.P. and CornerStone Propane Partners, L.P. (collectively, CornerStone). CornerStone has filed proofs of claims against us aggregating approximately $310 million asserting that we owe them for capital account contribution obligations and obligations related to requirements to transfer title of certain real property. We filed an objection disputing these claims on July 13, 2004, as we do not believe they are valid. On June 3, 2004, CornerStone filed petitions for relief under Chapter 11 of the Bankruptcy Code. We have filed a proof of claim against CornerStone for a $29.5 million secured claim, which arose due to our August 2002 purchase of a lenders' interest in CornerStone's credit facility. We have also filed additional proofs of claim against CornerStone totaling $23.2 million related to previous intercompany obligations and payments on letters of credit on behalf of CornerStone. In previous years, we took impairment charges to reduce our note receivable and other advances to an estimated recoverable amount. As of June 30, 2004, the net book value of our receivables from CornerStone was $11 million. We and CornerStone reached settlement of these claims and filed a motion with the Bankruptcy Court in our Chapter 11 proceeding on October 4, 2004, which is pending. The settlement also will have to be approved by the bankruptcy court in the CornerStone proceeding. Under the terms of this settlement agreement, we will receive a $15 million allowed

secured claim in CornerStone's bankruptcy proceedings and we will allow CornerStone a $19.5 million general unsecured, or Class 9, claim under our plan of reorganization. On October 4, 2004, we filed a motion seeking Bankruptcy Court approval of this settlement. If no objections are filed, then this settlement will be deemed approved on October 14, 2004.

We are also attempting to sell our interest in Montana Megawatts I, LLC, or MMI, our indirect wholly-owned subsidiary that owns the Montana First Megawatts generation project. In an effort to facilitate the sale of the Montana First Megawatts project and its ultimate development at its current location in Great Falls, Montana, we filed the power sales agreement with the FERC on August 18, 2003, requesting that the FERC accept for filing the cost-based power sales agreement between MMI and its affiliate, NorthWestern Energy. A late motion to intervene and protest was filed by the MPSC and the MCC. On October 17, 2003, the FERC issued an order conditionally accepting the power sales agreement, subject to suspension for a designated period, to permit resolution of certain concerns voiced by the MPSC and MCC in their filing. On July 20, 2004 we entered into a Settlement Term Sheet with the MCC and MMI, modifying certain economic terms contained in the cost-based power sales agreement conditionally approved by the FERC on October 17, 2003. Under the terms of the settlement we expect to file the MCC Settlement Term Sheet with the FERC and the MPSC for their review and consideration. A revised power sales agreement may be filed with the MPSC, subject to meeting necessary preconditions imposed by Montana law and MPSC rules. Also, the MPSC may be requested to provide expedited approval of this agreement for inclusion in the Montana default supply portfolio. This filing is subject to certain necessary preconditions imposed by MPSC rules.

On July 18, 2004, we entered into a nonbinding letter of intent to sell MMI to a nonaffiliated third party. For various reasons, the parties agreed to terminate the letter of intent. We continue to discuss the sale of the project with various interested parties.

We cannot guarantee approval by the MPSC of a revised power sales agreement, that the project at the Great Falls location will ever be completed, or that the project will be sold to a buyer in the foreseeable future.

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

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

We believe that the accounting estimate related to determining the fair value of goodwill, and thus any impairment, is a "critical accounting estimate" because: (i) it is highly susceptible to change from period to period since it requires company management to make cash flow assumptions about future revenues, operating costs and discount rates over an indefinite life; and (ii) recognizing an impairment has had a significant impact on the assets reported on our balance sheet and our operating results.

Management's assumptions about future sales margins and volumes require significant judgment because actual margins and volumes have fluctuated in the past and are expected to continue to do so. In estimating future margins, we use our internal budgets.

According to the guidance set forth in Statement of Financial Accounting Standards (SFAS) No. 142, we are required to evaluate our goodwill and indefinite-lived intangible assets for impairment at least annually (October 1) and more frequently when indications of impairment exist. Accounting standards require that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, we compare the implied fair value of the reporting unit's goodwill with its carrying value.

Certain Qualifying Facilities (QFs) located in Montana require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. As of June 30, 2004, our gross undiscounted contractual obligation related to the QFs is approximately $1.8 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable though rates authorized by the MPSC, totaling approximately $1.4 billion though 2029. In computing the liability, we have had to make various estimates in relation to contract costs, capacity utilization, discount rates and recoverable amounts. Actual utilization and regulatory changes may significantly impact our results of operations. In light of the executory nature of the QF power sales agreements and certain out-of-market pricing and escalation terms, we are continuing to evaluate our options with respect to continued purchases under these contracts. We anticipate additional adjustments to our QF liability may arise during the fourth quarter of 2004, if certain negotiated contract modifications become effective.

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

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

Our regulated operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulations. Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and default electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through

the ratemaking process. If any part of our operations become no longer subject to the provisions of SFAS No. 71, then the probable future recovery of or reduction in revenue with respect to the related regulatory assets and liabilities would need to be evaluated. In addition, we would need to determine if there was any impairment to the carrying costs of deregulated plant and inventory assets.

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

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

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

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

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

Our proposed plan of reorganization contemplates a significant reduction of our outstanding indebtedness and, as a result, we expect to realize approximately $560 million of cancellation of indebtedness, or COD, income. For tax purposes, we are not required to include any COD income in our taxable income when we emerge, however we will be required to reduce certain tax attributes up to the amount of COD income. As a general rule, tax attributes are reduced in the following order: (a) net operating losses (NOLs), (b) most tax credits, (c) capital loss carryovers, (d) tax basis in assets, and (e) foreign tax credits. Under a certain tax code election, we anticipate reducing a combination of attributes, consisting of tax basis in depreciable assets and NOLs. While we have made assumptions in our plan of reorganization related to the reduction of these attributes, the ultimate amounts of each reduction will not be determined until after we emerge from bankruptcy. Changes in our assumptions related to these attribute reductions could materially impact the tax basis of our depreciable assets and the amount of NOLs available to utilize against future income. Additionally, under our proposed plan of reorganization, there will be an "ownership change" as defined under Internal Revenue Code Section 382 in connection with our emergence from bankruptcy, which provides an annual limit on the ability to utilize our NOLs. Based on this limitation and our current assumptions, we expect to be able to fully utilize these NOLs.

Three-Month and Six-Month Periods Ended June 30, 2004, Compared to the Three-Month and Six-Month Periods Ended June 30, 2003.

The following is a summary of our consolidated results of operations for the three-month and six-month periods ended June 30, 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.

Consolidated revenues in the second quarter of 2004 were $233.0 million, as compared to $234.7 million in the second quarter of 2003. Consolidated revenues for the six months ended June 30, 2004 were $572.6 million, an increase of $50.0 million, or 9.6%, over the same period in 2003. This increase was primarily due to increased sales of surplus gas of $19.7 million, increased market prices for gas of $15.9 million and an increase in nonregulated gas revenues of $13.4 million.

Consolidated cost of sales was $129.6 million in the second quarter of 2004, as compared to $129.3 million in the second quarter of 2003. Consolidated cost of sales for the six months ended June 30, 2004 was $336.5 million, an increase of $52.1 million, or 18.3%, over the same period in 2003. This increase was primarily due to increased sales of surplus gas of $19.7 million, increased market prices for gas of $15.9 million and an increase in nonregulated gas cost of sales of $15.8 million.

Consolidated gross margin in the second quarter of 2004 was $103.3 million, as compared to $105.4 million in the second quarter of 2003. For the six months ended June 30, 2004, consolidated gross margin was $236.0, as compared to $238.2 million for the same period in 2003.

Consolidated operating expenses in the second quarter of 2004 were $96.3 million as compared to $104.1 million in the second quarter of 2003. Included in 2003 results was a $12.4 million impairment charge related to our investment in the Montana First Megawatts project. Aside from the 2003 impairment charge, increased expenses in the second quarter of 2004 primarily consisted of higher insurance costs (mainly directors and officers) of $2.5 million, higher property taxes of $1.4 million, and contractor costs related to strike contingency planning in 2004 of $1.1 million. Depreciation was $18.2 million, as compared to $17.4 million in the second quarter of 2003. Since filing for bankruptcy, we present reorganization professional fees and expenses separately from operating, general and administrative expenses on the income statement. While we incurred $7.8 million of reorganization expenses during the second quarter of 2004, there were similar amounts for legal and other professional fees included in operating, general and administrative expenses in the second quarter of 2003 due to our efforts to restructure the company prior to filing for bankruptcy. For the six months ended June 30, 2004 consolidated operating expenses were $196.0 million, as compared to $193.8 million in 2003. As noted above, 2003 results included a $12.4 million impairment charge. Aside from the 2003 impairment charge, the increase in expenses in 2004 is primarily due to higher insurance costs (mainly directors and officers) of $5.4 million, higher property taxes of $3.9 million, and contractor costs related to strike contingency planning in 2004 of $1.1 million. Depreciation was $36.4 million for the six months ended June 30, 2004, as compared to $34.9 million for the same period in 2003. Reorganization professional fees and expenses for the six months ended June 30, 2004 were $14.6 million.

Consolidated operating income in the second quarter of 2004 was $7.0 million, an increase of $5.7 million. This increase is due to the inclusion in our 2003 results of the impairment charge offset by higher operating, general and administrative expenses in 2004. For the six months ended June 30, 2004 consolidated operating income was $40.0 million, a decrease of $4.4 million, or 9.8%, from the same period in 2003. This decrease is due to lower margins and higher operating expenses as discussed above.

Consolidated interest expense in the second quarter of 2004 was $22.1 million, a decrease of $17.5 million, or 44.1%. For the six months ended June 30, 2004 interest expense was $43.9 million, a decrease of $37.3 million, or 45.9%, from the same period in 2003. These decreases are attributable to our cessation of recording of interest expense on our unsecured debt due to our bankruptcy filing.

Consolidated losses on common stock in the second quarter of 2004 were $4.8 million, as compared to $57.8 million in the second quarter of 2003. Due to our bankruptcy filing, we ceased recording interest expense on our unsecured debt and preferred securities, which accounted for a $17.5 million decrease in interest expense, and a $7.5 million decrease in our minority interests on preferred securities of subsidiary trusts. In addition, results from discontinued operations improved by $22.6 million, primarily related to a Netexit gain of $11.5 million attributable to a settlement with Avaya. Consolidated earnings on common stock were $12.2 million for the six months ended June 30, 2004, a $60.1 million increase from the first six months of 2003. Due to our bankruptcy filing, we ceased recording interest expense on our unsecured debt and preferred securities, which accounted for a $37.3 million decrease in interest expense, and a $14.9 million decrease in our minority interests on preferred securities of subsidiary trusts. In addition, results from discontinued operations improved by $11.3 million, primarily attributable to the gain discussed above.

Revenues in the second quarter of 2004 were $152.6 million, a decrease of $9.2 million, or 5.7%, from results in the second quarter of 2003. Our regulated rate revenues are affected by three primary components; average market rates, sales volume and sales of excess purchased power to the secondary market. The decrease in revenues during the second quarter of 2004 as compared to 2003 was primarily due to a $16.9 million decrease in sales of excess purchased power to the secondary market primarily offset by an $8.4 million increase in sales volumes to our core customers. As the purchased power costs and sales to the secondary market are also reflected in cost of sales, there is no gross margin impact. Revenues for the six months ended June 30, 2004 were $329.6 million as compared to $329.5 million for the same period in 2003. Retail revenues from our core customers increased approximately $15.5 million due to increased volumes. The increase was offset by a $13.1 million decrease in sales of excess purchased power to the secondary market and approximately $1.2 million due to decreases in average market rates.

Cost of sales in the second quarter of 2004 was $70.3 million, a decrease of $5.9 million, or 7.7%, from results in the second quarter of 2003. Purchased power supply costs, which are recovered in rates, decreased $8.8 million. This decrease was partially offset by a $2.1 million loss related to a dispute settlement with a wholesale power supply vendor and a $1.0 million increase in transmission and wheeling costs associated with energy load scheduling. For the six months ended June 30, 2004, costs of sales were $158.0 million, an increase of $4.7 million, or 3.1%, from 2003. This increase was primarily due to a $2.0 million increase in transmission and wheeling costs associated with energy load scheduling and the $2.1 million loss discussed above.

Gross margin in the second quarter of 2004 was $82.3 million, a decrease of $3.4 million, or 3.9% from gross margin in the second quarter of 2003. This decrease was primarily attributable to the loss on the wholesale power supply contract and increased transmission and wheeling costs. Margins as a percentage of revenues increased to 53.9% for 2004, from 52.9% for 2003. Gross margin as a percentage of revenue is impacted by the fluctuations that occur in power supply costs, which are collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they have no actual impact on gross margin amounts. For the six months ended June 30, 2004, margins of $171.6 million were $4.6 million lower, or 2.6%, from results in the first six months of 2003. This decrease was primarily attributable to higher transmission and wheeling costs and the loss related to the dispute settlement discussed above. Margins as a percentage of revenues decreased to 52.1% for 2004, from 53.5% in 2003.

Operating, general and administrative expenses for the second quarter of 2004 were $52.3 million, an increase of $5.0 million, or 10.6%, over results in the second quarter of 2003. This increase was primarily due to a $1.6 million increase in insurance (primarily directors and officers liability) costs, $0.9 million in higher property taxes, $0.7 million in higher contractor costs due to strike contingency

planning and an increased allocation of corporate expenses from the all other segment to electric operating expenses. Depreciation was $14.2 million for the second quarter of 2004, an increase of $0.7 million over 2003. Operating, general and administrative expenses for the six months ended June 30, 2004 were $104.2 million, an increase of $11.5 million, or 12.5%, over results in the first six months of 2003. This increase was primarily due to a $3.4 million increase in insurance (primarily directors and officers liability) costs, $2.7 million in higher property taxes, $0.7 million in higher contractor costs due to strike contingency planning and an increased allocation of corporate expenses from the all other segment to electric operating expenses. Depreciation was $28.3 million for 2004, an increase of $1.2 million over 2003.

Operating income in the second quarter of 2004 was $15.9 million, a decrease of $9.0 million, or 36.3%, from the second quarter of 2003. This decrease was primarily due to increased operating, general and administrative expenses, the $2.1 million loss related to a dispute settlement with a wholesale power supply vendor and increased transmission and wheeling costs. For the six months ended June 30, 2004, operating income was $39.0 million, a decrease of $17.4 million, or 30.8%, from the same period in 2003. This decrease was primarily due to increased operating, general and administrative expenses, the $2.1 million loss discussed above, and higher transmission and wheeling costs.

Interest expense in the second quarter of 2004 for the electric and gas segments combined was $20.5 million, a decrease of $3.5 million or 14.6% from the second quarter of 2003. Interest expense for the six months ended June 30, 2004 for the electric and gas segments combined was $40.6 million, a decrease of $9.5 million or 19.0% from the first six months of 2003. These decreases were attributable to our cessation of recording interest expense on unsecured debt due to our bankruptcy filing.

Revenues in the second quarter of 2004 were $78.2 million, an increase of $7.5 million, or 10.6%, from results in the second quarter of 2003. Gas supply costs increased $5.2 million, or 32.6%, as a result of higher average market prices. These costs are also reflected in cost of sales, thereby having no impact on gross margin. Additionally, nonregulated revenues increased approximately $4.3 million, primarily from the addition of ethanol plant customers. This was partially offset by a $2.7 million decrease in retail revenues resulting from a 3.7% volume decline. Revenues for the six months ended June 30, 2004 of $238.3 million were $49.9 million higher, or 26.5%, from results in the same period of 2003. Gas supply costs increased $15.9 million, or 25.4%, as a result of higher average market prices. These costs are also reflected in cost of sales, thereby having no impact on gross margin. Retail revenues increased $19.7 million due to an increase in sales of surplus gas. As the revenue from sales of surplus gas benefits our general business customers, these sales are also included in cost of sales, thereby having no impact on gross margin. Nonregulated revenues increased approximately $13.4 million primarily due to the addition of ethanol plant customers.

Cost of sales in the second quarter of 2004 was $58.9 million, an increase of $6.4 million, or 12.2%, from results in the second quarter of 2003. Gas supply costs increased $5.2 million, nonregulated costs increased $4.4 million primarily due to the addition of ethanol plant customers discussed above and retail costs increased $1.1 million primarily due to increased market prices. Offsetting these increases, was a decrease of $4.3 million in the amount of gas costs written off due to the MPSC's disallowance of certain gas supply costs. During the second quarter of 2004, we wrote off $1.9 million resulting from the MPSC's disallowance of certain gas supply costs, as compared to $6.2 million during the second quarter of 2003. We are currently contesting the MPSC's order disallowing these gas costs in district court in Montana. For the six months ended June 30, 2004, costs of $177.3 million were $47.6 million higher, or 36.7%, from results in the first six months of 2003. Gas supply costs increased $15.9 million, while the write-off due to the MPSC's disallowance of certain gas supply costs decreased $3.3 million. Remaining retail costs increased $19.7 million due to the higher

sales of surplus gas discussed above and nonregulated costs increased $15.8 million primarily due to the addition of ethanol plant customers discussed above.

Gross margin in the second quarter of 2004 was $19.4 million, an increase of $1.1 million, or 6.1%, over 2003. Lower retail margins were more than offset by the decrease in the write-off of gas supply costs discussed above. Margins as a percentage of revenues decreased to 24.8% for 2004 from 25.8% for 2003. Gross margin as a percentage of revenue is impacted by the fluctuations that occur in retail costs, which are collected from customers through rates. For the six months ended June 30, 2004, margins of $61.0 million were $2.3 million higher, or 3.9%, over 2003. This increase was mainly due to decrease in the write-off of gas supply costs discussed above. Margins as a percentage of revenues decreased to 25.6% for 2004 from 31.1% for 2003. Gross margin as a percentage of revenue is impacted by the fluctuations that occur in retail costs, which are collected from customers through rates. Additionally, as nonregulated revenues increase gross margin as a percentage of revenues will generally decrease.

Operating, general and administrative expenses for the second quarter of 2004 were $16.9 million, an increase of $3.1 million, or 22.1%, over 2003 results. This increase was primarily due to a $0.9 million increase in insurance (primarily directors and officers liability) costs, $0.5 million in higher property taxes, $0.4 million in higher contractor costs due to strike contingency planning and an increased allocation of corporate costs from the all other segment to natural gas operating expenses. Depreciation was $3.7 million for 2004, an increase of $0.2 million over 2003. Operating, general and administrative expenses for the six months ended June 30, 2004 were $35.4 million, an increase of $5.8 million, or 19.8%, over 2003 results. This increase was primarily due to a $2.0 million increase in liability insurance (primarily directors and officers liability) costs, $1.2 million in higher property taxes, $0.4 million in higher contractor costs due to strike contingency planning, and an increased allocation of corporate expenses from the all other segment to natural gas operating expenses. Depreciation was $7.3 million for 2004, an increase of $0.4 million over 2003.

Operating losses in the second quarter of 2004 were $1.2 million, a change of $2.1 million, from operating income in 2003. This change primarily resulted from higher operating, general and administrative expenses. For the six months ended June 30, 2004, operating income was $18.3 million, a decrease of $3.9 million, or 17.6%, from 2003. This decrease primarily resulted from the higher operating, general and administrative expenses partially offset by the decrease in write-off of gas supply costs discussed above.

All other operations primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments, and any eliminating amounts. The miscellaneous service activities principally include unregulated businesses offering a portfolio of services to residential and business customers, including product sales and maintenance contracts in areas such as home monitoring devices and appliances.

Losses from continuing operations were $12.2 million in the second quarter of 2004, an improvement of $26.7 million or 68.6%, from the second quarter of 2003. Effective with our bankruptcy filing, we ceased recording interest expense on unsecured debt, which contributed $14.0 million to this decrease along with a $4.2 million decrease in operating, general and administrative expenses due to a change in allocation of corporate costs from the all other segment to the electric and gas segments, and a $12.4 million decrease due to an impairment charge on our Montana First Megawatts generation project in the second quarter of 2003. These decreases in costs were partially offset by a $3.3 million increase to the tax provision. For the six months ended June 30, 2004 losses from continuing operations were $14.2 million, an improvement of $37.2 million, or 72.4%, from results in 2003. Effective with our bankruptcy filing, we ceased recording interest expense on unsecured debt, which contributed

$27.7 million to this decrease along with a $4.3 million decrease in operating, general and administrative expenses due to a change in allocation of corporate costs from the all other segment to the electric and gas segments, and a $12.4 million decrease due to an impairment charge in the second quarter of 2003. These decreases in costs were partially offset by a $6.9 million reduction to the benefit for income taxes.

As previously discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, we sold substantially all the assets and business of Expanets, Inc. to Avaya and retained certain specified liabilities. Thereafter, Expanets, Inc. was renamed Netexit. On February 24, 2004, Avaya submitted its proposed final calculation of the postclosing working capital adjustment required under the sale agreements claiming that Avaya should retain $44.6 million in held-back proceeds plus an additional $4.2 million. Netexit disputed this calculation. As a result of negotiations between Netexit and Avaya, the parties entered into a settlement on April 27, 2004 resulting in additional cash proceeds of $17.5 million paid by Avaya to Netexit. We recorded a gain related to this settlement of $11.5 million in the second quarter of 2004.

In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. On June 30, 2004, Netexit filed schedules and statements of financial affairs with the Bankruptcy Court, setting forth, among other things, the assets and liabilities of Netexit. The schedules, which were prepared by NorthWestern management and are unaudited, list total assets of approximately $67.6 million (primarily cash and short-term investments) and total liabilities of approximately $237.9 million as of May 4, 2004, of which approximately $237.7 million (contractual interest of $13.7 million) of the total liabilities represents intercompany obligations by Netexit to NorthWestern. However, the amount of the claims to be filed against Netexit by creditors could be significantly different than the amount of the liabilities that have been recorded. Netexit will incur significant additional expenses related to the bankruptcy filing and may incur losses related to the resolution of open claims. Netexit has not yet proposed a plan of reorganization, but anticipates doing so during the second quarter of 2005. Pending the resolution of open claims to Netexit creditors, the proceeds from the sale remain at Netexit and distributions to NorthWestern will be delayed until the Netexit bankruptcy proceedings are resolved. Our ability to emerge from Chapter 11 protection is not linked to resolution of the Netexit bankruptcy proceedings.

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

	Three Months Ended June 30,
	2004			2003
Revenues	$	—		$	162,061

Loss before income taxes	$	(1,191	)	$	(6,765	)
Gain on disposal		11,500			—
Income tax provision		—			(113	)

Income (Loss) from discontinued operations, net of income taxes	$	10,309		$	(6,878	)

	Six Months Ended June 30,
	2004		2003
Revenues	$	—	$	328,667

Income before income taxes	$	475	$	14,355
Gain on disposal		11,500		—
Income tax provision		—		(253	)

Income from discontinued operations, net of income taxes	$	11,975	$	14,102

Netexit's income before income taxes for the three months ended June 30, 2003, includes a gain on debt extinguishment of $27.3 million.

As of June 30, 2004 our subsidiary Blue Dot had four remaining businesses. As of August 27, 2004 two of those businesses had been sold and Blue Dot had entered into a letter of intent to sell one of the remaining two businesses. Cash proceeds from business sales remain at Blue Dot. Although we anticipate receiving in excess of $12 million in cash from Blue Dot on or before the liquidation of the operations, our ability to realize such proceeds depends upon, among other things, satisfactory resolutions to remaining stock obligations and potential or pending litigation and the amount of insurance and bonding reserves. If we encounter unexpected liabilities or costs relating to the wind-down of operations of Blue Dot, our ability to realize any proceeds from the sale of Blue Dot's assets and our liquidity could be adversely affected.

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

	Three Months Ended June 30,
	2004			2003
Revenues	$	6,072		$	115,046

Income before income taxes and minority interests	$	602		$	2,882
Loss on disposal		(1,365	)		—
Income tax provision		—			(296	)

Income (Loss) from discontinued operations, net of income taxes	$	(763	)	$	2,586

	Six Months Ended June 30,
	2004			2003
Revenues	$	22,665		$	226,241

Loss before income taxes and minority interests	$	(3,691	)	$	(1,366	)
Gain on disposal		6,184			—
Income tax provision		—			(591	)

Income (Loss) from discontinued operations, net of income taxes	$	2,493		$	(1,957	)

Year Ended December 31, 2003, Compared to the Year Ended December 31, 2002, Compared to the Year Ended December 31, 2001.

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

Consolidated losses on common stock in 2002 were $892.9 million compared to earnings on common stock of $37.5 million in 2001. The loss is primarily due to impairment and other charges of

$878.5 million and increased interest expense of $70.3 million, offset by an approximately $29.3 million increase in earnings related to the addition of our Montana operations.

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

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

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

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

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

Revenues in 2002 were $533.9 million, an increase of $426.9 million, or 399.0%, from 2001 results. This increase was almost exclusively attributable to the addition of our Montana operations, effective February 1, 2002, which contributed $441.4 million of revenues for the year. The volume of wholesale and retail megawatt hours sold in 2002 for our Montana operations were 1.4 million and 6.7 million, respectively. In addition, our South Dakota operations contributed revenues of $92.5 million for 2002, which was a decrease of $14.5 million, or 13.5%, from 2001. This decrease in revenues was principally

the result of a decrease of $16.1 million in wholesale electric revenues within the South Dakota operations due to market price declines. The volume of wholesale megawatt hours sold in 2002 for our South Dakota operations decreased by 6.2%, however, the volume of retail megawatt hours sold increased by 0.3%.

Cost of sales in 2002 was $205.6 million, an increase of $182.6 million, or 791.9%, from 2001 results. This increase was nearly all due to the addition of our Montana operations, which increased costs by $182.0 million. In addition, our South Dakota operations experienced a $0.6 million increase in costs related to the increase in sales volume.

Gross margin in 2002 was $328.3 million, an increase of $244.4 million, or 291.1%, over the 2001 gross margin of $83.9 million. This increase was primarily due to the contribution of $259.4 million in gross margin from our Montana operations. Partially offsetting this increase was a decrease in gross margin by our South Dakota operations of $15.0 million, or 17.9%, as a result of a substantial decrease in market prices for wholesale electricity as compared to the unusually high market prices in 2001. Overall gross margin as a percentage of revenues in 2002 was 61.5%, as compared to 78.5% in 2001. This decrease was the result of the substantial decline in wholesale electric margins from market price fluctuations and the influence of lower margin Montana operations as compared to our South Dakota operations.

Operating, general and administrative expenses were $169.7 million in 2002, an increase of $142.0 million, or 512.0%, over the 2001 results. This increase was nearly all due to the addition of our Montana operations. Depreciation for 2002 was $48.9 million, an increase of $35.7 million primarily due to the addition of our Montana operations.

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

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

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

Gross margins for 2003 were $109.7 million, or $3.1 million higher as compared to 2002. The January 2003 results of our Montana operations contributed approximately $10.9 million of this

increase. Margins for February through December 2003, as compared to the same period in 2002, decreased $7.8 million primarily due to the MPSC's disallowance of $6.2 million in gas supply costs. Margins as a percentage of revenues decreased to 31.8% for 2003 from 44.5% for 2002. Gross margin as a percentage of revenue is impacted by the fluctuations that occur in retail costs, which are collected from customers through rates.

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

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

Revenues in 2002 were $239.8 million, an increase of $95.6 million, or 66.3%, from 2001 results. Revenues for the period reflect the inclusion of our Montana operations, which contributed $119.6 million in revenues. In addition, our South Dakota operations contributed revenues of $120.2 million for 2002, which was a decrease of $24.0 million, or 16.7%, from 2001. This decrease was principally the result of a drop in commodity prices reflected within the South Dakota operations during 2002 compared to 2001, and a decrease in volumes as a result of warmer weather in the Nebraska and South Dakota service territories in 2002 than in 2001.

Cost of sales in 2002 was $133.1 million, an increase of $14.1 million, or 11.8%, from the 2001 results. Cost of sales for the period reflect the inclusion of our Montana operations, which contributed $38.9 million in cost of sales, and a decrease in cost of sales from our South Dakota business of $24.9 million, or 20.9%. This decrease occurred primarily as a result of lower commodity prices and reduced retail volumes from warmer weather in 2002 than in 2001.

Gross margin in 2002 was $106.7 million, an increase of $81.5 million, or 324.1%, over the 2001 gross margin of $25.2 million. This increase was nearly all due to the contribution of $80.7 million in gross margin by our Montana operations. In addition, our South Dakota operations experienced a $0.8 million increase in margins due to increased volumes in the nonregulated gas segment. Overall gross margin as a percentage of revenues in 2002 was 44.5%, as compared to 17.4% in 2001, resulting primarily from the higher margin impact from the Montana operations. The higher margins from the Montana operations are principally due to NorthWestern owning the natural gas transmission system in Montana on which we collect tariff revenues and margins, as compared to South Dakota and Nebraska operations where third parties own the transmission systems and NorthWestern pays these costs which are then passed on to ratepayers as a component of the natural gas costs.

Operating, general and administrative expenses in 2002 were $60.2 million, an increase of $45.7 million, or 314.0%, over 2001 results primarily due to the addition of our Montana operations. Depreciation expense was $12.6 million in 2002, an increase of $9.3 million over 2001. This increase was also primarily due to the addition of our Montana operations.

Operating income in 2002 was $33.9 million, an increase of $27.7 million, or 446.7%, from 2001, primarily due to the addition of our Montana operations, which contributed $30 million in operating income, while operating income from the South Dakota operations declined by $2.3 million.

All Other primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments, and any eliminating amounts. The miscellaneous service activities principally include unregulated businesses offering a portfolio of services to residential and business customers, including product sales and maintenance contracts in areas such as home monitoring devices and appliances.

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

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

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

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

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

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

In October 2003, we were authorized to complete the sale of Expanets' assets. On November 25, 2003, Expanets closed on an Asset Purchase and Sale Agreement to sell substantially all the assets and business of Expanets to Avaya, Inc. (Avaya) and retained certain specified liabilities. Thereafter, Expanets was renamed Netexit, Inc. (Netexit), which will continue as a non-operating company until its affairs can be wound down in accordance with its lending agreements, its corporate charter and provisions of Delaware law. Under the terms of the agreement, a $4 million "break-up fee" was paid to a third party originally involved in the transaction and Avaya paid Netexit cash of approximately $50.8 million and assumed debt of approximately $38.1 million.

$48.8 million at closing, and claiming that Avaya should retain the entire holdback amount plus an additional $4.2 million. Netexit disputed this calculation. As a result of negotiations between Netexit and Avaya, the parties entered into a settlement on April 27, 2004 resulting in additional cash proceeds of $17.5 million paid by Avaya to Netexit. We recorded a gain related to this settlement of $11.5 million in the second quarter of 2004.

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

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

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

In July 2004, we reduced the commitment under our DIP Facility to $50 million. As of June 30, 2004 the only outstanding amounts under our DIP Facility were letters of credit of $15.4 million. We anticipate that our total cash and cash equivalents, together with access to our DIP Facility, will be sufficient to fund our operations during our bankruptcy proceedings.

In July 2004, we filed applications with the MPSC and the FERC seeking approval to enter proposed exit financing facilities, which we refer to as the Exit Financing, as follows:

The only component of the Exit Financing needed for us to emerge from bankruptcy is the $100 million revolving credit facility. The Exit Financing will be secured by mortgage bonds and will be

used to repay and refinance our existing DIP Facility, the CSFB Facility, which had an outstanding balance of $384.2 million as of June 30, 2004, and potentially $150 million of Montana First Mortgage Bonds. In the applications with the FERC and the MPSC, we specifically requested permission to vary the size of the components of the Exit Financing based on advantageous pricing levels. Refinancing these obligations at this time with longer term maturities and at lower interest rates will lower our borrowing cost and improve our cash flow. The additional components of the Exit Financing are being contemplated to lower our borrowing costs and extend existing maturities.

We have also requested MPSC and FERC approval to issue up to 35.5 million shares of new common stock. Under the terms of our plan of reorganization, our existing common stock will be cancelled and the debt owed to our unsecured creditors and holders of our mandatorily redeemable preferred securities of subsidiary trusts will be exchanged for 35.5 million shares of common stock. On August 3, 2004, the MPSC conditionally approved the proposed exit financing and issuance of new common stock, subject to confirmation of our plan of reorganization. On August 20, 2004, the FERC conditionally approved the proposed exit financing and issuance of new common stock, subject to certain requirements. On August 25, 2004, we filed an application with the MPSC to approve the issuance of warrants for up to 5.305 million share of common stock to be issued to certain creditors in connection with the consummation of our plan of reorganization and to issue up to 7.571 million shares of new common stock. On September 2, 2004, we filed an application with the FERC to approve the issuance of warrants for up to 5.305 million share of common stock to be issued to certain creditors in connection with the consummation of our plan of reorganization and to issue up to 7.571 million shares of new common stock. On September 29, 2004, the MPSC conditionally approved the issuance of the warrants and additional common stock, subject to certain requirements. On October 1, 2004, the FERC conditionally approved the issuance of the warrants and additional stock, subject to certain requirements.

Funding of Our Operations Upon and Following Our Emergence from Bankruptcy Proceedings

If our current plan or reorganization is approved by our creditors and other parties-in-interest and confirmed by the Bankruptcy Court, we anticipate emerging from bankruptcy and completing the Transactions on or about November 1, 2004.

Based upon our current plans, level of operations and business conditions, we anticipate that our current cash and cash equivalents, together with cash provided by continuing operations and funds available under our Exit Financing, will be sufficient to meet our capital requirements and working capital needs following our emergence from bankruptcy through the end of 2006. However, there can be no assurance that our operations will not be negatively effected by weather or other conditions beyond our control, that we will be able to obtain the required approvals of our plan of reorganization or that we will be able to consummate the Exit Financing or any other financing necessary to emerge from bankruptcy or that any such financing, if required, will be available on terms satisfactory to us.

As of June 30, 2004, cash and cash equivalents were $101.6 million, compared to $15.2 million at December 31, 2003.

Cash provided by continuing operations during the six months ended June 30, 2004 totaled $123.1 million compared to cash used in continuing operations of $86.3 million during the six months ended June 30, 2003. This increase was substantially due to improvements in net income, improved vendor credit terms and the suspension of interest payments on our unsecured debt during our reorganization. During 2004, cash provided by operations was composed primarily of net income of

$12.2 million adjusted for non-cash items of $27.4 million, changes in operating assets and liabilities of $59.4 million and changes in regulatory assets and liabilities of $25.1 million. This compares to a cash use in 2003 consistent primarily of a net loss of $32.9 million adjusted for non-cash items of $52.0 million offset by cash used due to changes in operating assets and liabilities of $59.3 million and changes in regulatory assets and liabilities of $22.5 million.

Cash used in investing activities totaled $30.4 million during the six months ended June 30, 2004 compared to cash provided by investing activities of $27.6 million during the six months ended June 30, 2003. Cash used during 2004 was almost entirely due to property, plant and equipment additions. Cash provided during 2003 was primarily due to proceeds from investment sales offset by property, plant and equipment additions and investment purchases.

Cash used in financing activities totaled $6.4 million during the six months ended June 30, 2004 compared to cash provided by financing activities of $86.2 million during the six months ended June 30, 2003. Cash used during 2004 was to make scheduled principal payments on secured long-term debt. During the first quarter of 2003, we received $390.0 million under a senior secured term loan, net of $24.9 million in financing costs, which was used to repay $255.0 million on our line of credit facility.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

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

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

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

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

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

As part of our July 8, 2004 settlement with the MPSC and the MCC, we agreed to engage Liberty Consulting Group, or Liberty Consulting, to perform an audit and to make recommendations regarding the condition of our utility transmission and distribution infrastructure and to provide the findings of such audit to the MPSC. We also agreed to coordinate and cooperate with the MPSC and MCC to implement appropriate recommendations set forth in the audit report. Although the capital expenditure estimates set forth above may include components relating to the expected recommendations from Liberty Consulting, such estimates were prepared prior to the completion of the Liberty Consulting audit. We are in the process of evaluating the contents of the audit report.

We have a variety of contractual obligations and other commercial commitments that represent prospective requirements in addition to expense. The following table shows our contractual cash obligations and commercial commitments as of June 30, 2004, without regard to the reclassification of long-term debt to current. You should read the following table in conjunction with "The Bankruptcy Restructuring" because the debt subject to compromise and our mandatorily redeemable preferred securities of subsidiary trusts will be exchanged for our equity.

There have not been any material changes outside the ordinary course of our business to the contractual obligations and other commitments listed above since June 30, 2004.

The following table shows our contractual cash obligations and commercial commitments as of December 31, 2003, without regard to the reclassification of long-term debt to current. See our Annual Report on Form 10-K for the year ended December 31, 2003 for additional discussion. You also should read the following table in conjunction with "The Bankruptcy Restructuring" because the debt subject to compromise and our mandatorily redeemable preferred securities of subsidiary trusts will be exchanged for our equity.

We have various letter of credit requirements and other collateral obligations of approximately $15.4 million and $16.4 million as of June 30, 2004 and December 31, 2003, respectively.

Blue Dot and Netexit had previously obtained various license, bid and performance bonds to secure the performance of contracts and the adequate provision of services. The total amount of these outstanding surety bonds is approximately $49.1 million and $59.5 million as of June 30, 2004 and December 31, 2003. Due to the completion of work and as a result of the sale of these subsidiaries' businesses, we estimate the amount of the underlying obligations that such bonds secure is $3.5 million and $3.5 million as of June 30, 2004 and December 31, 2003, respectively.

The surety bonds obtained by Blue Dot and Netexit are supported by indemnity agreements that we entered into for the benefit of these subsidiaries and are secured by various letters of credit obtained by Blue Dot, Netexit, or us. Approximately $5.5 million and $10 million of these letters of credit and other collateral obligations as of June 30, 2004 and December 31, 2003, respectively, serve to support performance bonds primarily related to Blue Dot and Netexit. In addition, included in other assets at June 30, 2004 are $9.1 million of deposits that support performance bonds related to Blue Dot and Netexit.

With the acquisition of our Montana operations, our pension and other postretirement benefit obligations significantly increased. Our reported costs of providing pension and other postretirement benefits, as described in Note 15 of "Notes to the Consolidated Financial Statements" contained elsewhere herein, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

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

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

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

for fiscal 2003 was the result of the acquisition of our Montana operations and the excess of our accumulated benefit obligations over plan assets.

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

In February 2003, we closed and received funds from a $390.0 million senior secured term loan. The net proceeds of $366.0 million, after payment of financing costs and fees, were used to repay $259.6 million outstanding under the existing $280.0 million bank credit facility and existing outstanding letters-of-credit. The remaining proceeds of the term loan were used to fund working capital and other general corporate purposes.

On October 8, 2002, we completed a 10 million share common stock offering. The offering raised $81.0 million of net proceeds, after expenses and commissions. The net proceeds were used for general corporate purposes, including reducing amounts drawn under our credit facility.

On March 13, 2002, we issued $250 million of our 7.875% senior notes due March 15, 2007, and $470 million of our 8.75% senior notes due March 15, 2012, which resulted in net proceeds to us of $713.9 million. We applied these net proceeds together with available cash to fully repay and terminate the $720 million term loan portion of our credit facility. On March 28, 2002, we entered into two fair value hedge agreements, each of $125.0 million, to effectively swap the fixed interest rate on our $250 million five-year senior notes to floating interest rates at the three month London Interbank Offered Rate plus spreads of 2.32% and 2.52%, effective as of April 3, 2002. These fair value hedge agreements were settled on September 17, 2002, resulting in $17.0 million of proceeds and an unrecognized gain to us. The unrecognized gain is recorded in Other Noncurrent Liabilities and will be recognized as a reduction of interest expense over the remaining life of the notes. On the nine remaining coupon payments on the five-year notes, the amortization of the gain equates to a $1.9 million interest savings per coupon payment, effectively lowering the annual interest rate on the five-year notes to 6.3%.

On February 15, 2002, in connection with the completed acquisition of The Montana Power Company's energy distribution and transmission business, we assumed $511.1 million of debt and preferred stock net of cash received from The Montana Power Company, and we entered into a $720.0 million term loan and drew down a $19.0 million swing line commitment under our $280.0 million revolving credit facility to fund our acquisition costs and repay borrowings of $132.0 million outstanding under our existing recourse bank credit facility. The $511.1 million of assumed debt and preferred stock includes various series of mortgage bonds, pollution control bonds and notes that bear interest rates between 5.90% and 8.95%. These include both secured and unsecured obligations with maturities that range from 2003 to 2026.

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

We are exposed to the impact of market fluctuations associated with commodity prices and interest rates. We have policies and procedures to assist in controlling these market risks, and we may utilize derivatives to manage a portion of our risk. Our policy allows the use of derivative instruments as part of an overall energy price and interest rate risk management program to efficiently manage and

minimize commodity price interest rate risk. We do not enter into financial instruments for speculative or trading purposes.

We use fixed and variable rate long-term debt to partially finance capital expenditures and mandatory debt retirements. These debt agreements expose us to market risk related to changes in interest rates. We manage this risk by taking advantage of market conditions when timing the placement of long-term or permanent financing. We have historically used interest rate swap agreements to manage a portion of our interest rate risk and may take advantage of such agreements in the future to minimize such risk. All of our term debt has fixed interest rates, with the exception of the CSFB Facility which bears interest at a variable rate, which as of September 30, 2004 was approximately 7.34% and was tied to the Eurodollar rate. A 1% increase in the Eurodollar rate would increase annual interest expense by approximately $3.8 million. Our DIP Facility also bears interest at a variable rate tied to the Eurodollar rate, however, we have no outstanding borrowings as of September 30, 2004.

The fair value of fixed-price commodity contracts is estimated based on market prices of commodities covered by the contracts. We have a fixed price forward sales contract through October 1, 2004 for natural gas outstanding with commodity price risk. Settlement of this contract resulted in a loss of $2.8 million.

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 608,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923. We had consolidated operating income from continuing operations of $78.7 million for the year ended December 31, 2003 compared with consolidated operating income from continuing operations of $75.0 million for the year ended December 31, 2002. Our consolidated revenues and gross margin for the twelve months ended June 30, 2004 were $1,077.4 million and $474.7 million, respectively.

In February 2002, we completed the acquisition of the electric and natural gas storage, transmission and distribution business of The Montana Power Company. As a result of the acquisition, from February 15, 2002, the closing date of the acquisition, through November 15, 2002, we distributed electricity and natural gas in Montana through our wholly owned subsidiary, NorthWestern Energy, L.L.C. Effective November 15, 2002, we transferred all of the energy and natural gas transmission and distribution operations of NorthWestern Energy, L.L.C. to NorthWestern Corporation, and since that date, we have operated that business as part of our NorthWestern Energy division. We are operating our utility business under the common name "NorthWestern Energy" in all our service territories. Our utility operations are regulated primarily by the MPSC, the NPSC, the SDPUC and the FERC.

On September 14, 2003, which we refer to as the Petition Date, we filed a voluntary petition for relief under the provisions of the Federal Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware, referred to as the Bankruptcy Court, under case number 03-12872 (CGC). Pursuant to Chapter 11, we retained control of our assets and were authorized to operate our business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. Included in our consolidated financial statements are subsidiaries that are not party to the Chapter 11 case and are not debtors. In addition, in order to wind down its affairs in an orderly manner, our subsidiary Netexit filed a voluntary petition for relief under the Bankruptcy Code in the Bankruptcy Court on May 4, 2004. See additional discussion related to our bankruptcy filing under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "The Bankruptcy Restructuring."

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

We operate a regulated electric utility business in Montana through our NorthWestern Energy division. Our Montana electric utility business consists of an extensive electric transmission and distribution network. Our Montana service territory covers approximately 107,600 square miles, representing approximately 73% of Montana's land area, as of December 31, 2003, and includes approximately 786,000 people according to the 2000 census. We also transmit electricity for nonregulated entities owning generation facilities, other utilities and power marketers doing business in the Montana electricity market. In 2003, by category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 28%, 36%, 12%, and 24% of our Montana electric revenue, respectively.

Our Montana electric transmission system consists of approximately 7,000 miles of transmission lines, ranging from 50 to 500 kilovolts, 260 circuit segments and 125,000 transmission poles with associated transformation and terminal facilities as of December 31, 2003, and extends throughout the western two-thirds of Montana from Colstrip in the east to Thompson Falls in the west. Our 230 kilovolt and 161 kilovolt facilities form the backbone of our Montana transmission system. Lower voltage systems, which range from 50 kilovolts to 115 kilovolts, provide for local area service needs. We also jointly own a 500 kilovolt transmission system that is part of the Colstrip Transmission System, which transfers Colstrip generation to markets within the state and west of Montana. The system has interconnections with five major nonaffiliated transmission systems located in the Western Electricity Coordinating Council area, as well as one interconnection to a system that connects with the Mid-Continent Area Power Pool region. With these interconnections, we transmit power to and from diverse interstate transmission systems, including those operated by Avista Corporation; Idaho Power Company, a division of Idacorp, Inc.; PacifiCorp; the Bonneville Power Administration; and the Western Area Power Administration.

As of December 31, 2003, we delivered electricity to approximately 305,000 customers in 191 communities and their surrounding rural areas in Montana, including Yellowstone National Park. We also delivered electricity to rural electric cooperatives in Montana that served approximately 76,000 customers as of December 31, 2003. Our Montana electric distribution system consisted of approximately 19,700 miles of overhead and underground distribution lines and approximately 334 transmission and distribution substations as of December 31, 2003.

We operate our regulated electric utility business in South Dakota through our NorthWestern Energy division as a vertically integrated generation, transmission and distribution utility. We have the exclusive right to serve an assigned service area in South Dakota comprised of 25 counties with a combined population of approximately 99,500 people according to the 2000 census. We provided retail electricity to more than 57,600 customers in 108 communities in South Dakota as of December 31, 2003. In 2003, by category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 38%, 50%, 9% and 3% of our South Dakota electric utility revenue, respectively.

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

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

Our transmission and distribution network in South Dakota consists of approximately 3,100 miles of overhead and underground transmission and distribution lines across South Dakota as well as 120 substations as of December 31, 2003. We have interconnection and pooling arrangements with the transmission facilities of Otter Tail Power Company, a division of Otter Tail Corporation; Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.; Xcel Energy Inc.; and the Western Area Power Administration. We have emergency interconnections with the transmission facilities of East River Electric Cooperative, Inc. and West Central Electric Cooperative. These interconnection and pooling arrangements enable us to arrange purchases or sales of substantial quantities of electric power and energy with other pool members and to participate in the benefits of pool arrangements.

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

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

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

In our Montana service territory, the total control area peak demand was approximately 1,442 megawatts, the average daily load was approximately 972 megawatts, and more than 8,355,978 megawatt hours were supplied to choice and default supply customers during the year ended December 31, 2003. In our South Dakota service territory, peak demand was approximately 272 megawatts, the average daily load was approximately 136 megawatts, and more than 1,192,772 megawatt hours were supplied during the year ended December 31, 2003.

Pursuant to Montana Law, we are obligated to provide default supply electric service to those customers who have not chosen or are not allowed to choose an alternative electricity supplier. In this

role, we purchase substantially all of the capacity and 5.9 million megawatt hours of energy requirements for the default supply from third parties. We have power-purchase agreements with PPL Montana for 300 megawatts of firm base-load and 150 megawatts of unit-contingent on peak energy. We also purchase power from 13 "qualifying facilities" under contracts that The Montana Power Company was required to enter into under the Public Utility Regulatory Policies Act of 1978, which provide a total of 101 megawatts of winter peak capacity. We have secured additional contracts from Thompson River Co-gen, LLC for up to 14 megawatts of base-load power from coal/waste-coal and Tiber Montana for 5 megawatts of seasonal base-load hydro supply. We have submitted an Electric Default Supply Resource Procurement Plan, which fully details the resource requirements, analysis and proposed resources to meet the default supply load requirements. Certain contracted and proposed projects are sufficient to meet the default supply load requirements through June 30, 2007, with minimal price volatility. For more information about our obligations as a result of deregulation in Montana during the statutory transition period, see "—Utility Regulations—Electric Operations—Montana."

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

On March 27, 2001, we announced our plan to construct Montana First Megawatts, a 260 megawatt, natural gas-fired, combined-cycle electric generation facility. We commenced construction of the facility, located in Great Falls, Montana, in early November 2001. In light of the uncertainties regarding regulatory review of the Montana First Megawatts' power sales contract with NorthWestern Energy, and resulting difficulties in funding the project due to such uncertainties, we suspended construction on the project in June 2002. Shortly thereafter, we wrote down our investment in this project to an estimated salvage value of $30 million. The facility is fully permitted, and we estimate that a buyer of such facility could complete the project in approximately 12 to 15 months following the recommencement of construction activities. We estimate total construction, development and related costs will be approximately $180 million inclusive of our existing investment. As part of our restructuring, we are attempting to sell this project. In an effort to facilitate the timely sale of the Montana First Megawatts project, we filed the power sales agreement with the FERC on August 18, 2003, requesting that the FERC accept for filing the cost-based power sales agreement between MMI and its affiliate, NorthWestern Energy. A late motion to intervene and protest was filed by the MPSC and the MCC. On October 17, 2003, the FERC issued an order conditionally accepting the power sales agreement, subject to suspension for a designated period, to permit resolution of certain concerns voiced by the MPSC and MCC in their filing. On July 20, 2004, we entered into a Settlement Term Sheet with the MCC and MMI, modifying certain economic terms contained in the cost-based power sales agreement conditionally approved by the FERC on October 17, 2003. Under the terms of the settlement, we expect to file the MCC Settlement Term Sheet with the FERC and the MPSC for their review and consideration. A revised power sales agreement may be filed with the MPSC, subject to meeting necessary preconditions imposed by Montana law and MPSC rules. Also, the MPSC may be requested to provide expedited approval of this agreement for inclusion in the Montana default supply portfolio. This filing is subject to certain necessary preconditions imposed by MPSC rules.

On June 19, 2002, our power marketing affiliate entered into two five-year power supply contracts to supply a total of approximately 20 megawatts of electricity to customers located in Montana. These supply obligations commenced on July 1, 2002, and continue through June 30, 2007. Due to our financial condition, our affiliate was unable to secure a source of power to cover its contractual obligation subsequent to June 30, 2003. Based on the uncertainty of supply, as of July 1, 2003, the two customers elected to secure their power supply needs from the Montana default supply. Shortly thereafter, the customers notified our affiliate that they would seek damages to compensate them for their increased power supply costs. Our affiliate reached a settlement with its two customers on October 27, 2003, and subsequently paid $1.5 million in full settlement of its remaining contractual obligations.

We lease a 30% share of Colstrip Unit 4, a 750 megawatt gross-capacity coal-fired power plant located in southeastern Montana through our unregulated Colstrip Unit 4 Lease Management Division. A long-term coal supply contract with Western Energy Company provides the coal necessary to run the plant. We sell our leased share of Colstrip Unit 4 generation, representing approximately 222 megawatts at full load, principally to Duke Energy Trading and Marketing and to Puget Sound Energy under agreements expiring December 20, 2010. On January 23, 2004, we entered into Amendment #2 to the Duke Energy Power Purchase Agreement, which modified the economic terms of the power sales arrangement to our benefit. This amendment was approved by the Bankruptcy Court on February 23, 2004.

Most of the electricity that we supply to customers in South Dakota is generated by power plants that we own jointly with other regional utilities. In addition, we have several wholly owned peaking/standby generating units that are installed at nine locations throughout our service territory. Details of our generating facilities are described further in the chart below. Each of the jointly owned plants is subject to a joint management structure. Except as otherwise noted, we are entitled to a proportionate share of the electricity generated in our jointly owned plants and are responsible for a proportionate share of the operating expenses, based upon our ownership interest. Most of the power allocated to us from these facilities is distributed to our South Dakota customers, although in 2003, approximately 19% of the power was sold in the wholesale market. Our facilities had a total net summer peaking capacity in 2003 of approximately 312 megawatts.

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

The 2003 peak demand in our South Dakota service areas was approximately 272 megawatts, and the average daily load in South Dakota during 2003 was approximately 136 megawatts. The 2003 Midcontinent Area Power Pool accredited capacity including the required 15% reserve margins was approximately 293 megawatts. We believe we have adequate supplies through our share of generation from jointly owned plants, existing supply contracts, Midcontinent Area Power Pool power swap availability, and capacity for sale in the current market to meet our power supply needs during the next few years.

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

Coal was used to generate approximately 95% of the electricity utilized for South Dakota operations for the year ended December 31, 2003. Our natural gas and fuel oil peaking units provided the balance of generating capacity. We have no interests in nuclear generating plants. The fuel for our jointly owned base-load generating plants is provided through supply contracts of various lengths with several coal companies. There remains upward pressure on coal prices, which may result in modest increases in costs to our customers due to fuel adjustments in our rates. The average cost by type of fuel burned is shown below for the periods indicated:

	Cost per Million BTU for the Year Ended December 31,						Percent of 2003 Megawatt Hours Generated
Fuel Type	Cost per Million BTU for the Year Ended December 31,						Percent of 2003 Megawatt Hours Generated
Fuel Type	2003		2002		2001
Sub-bituminous-Big Stone	$	1.34	$	1.24	$	1.07	54.40	%
Lignite-Coyote*		.79		.66		.75	18.23	%
Sub-bituminous-Neal		.77		.80		.71	27.22	%
Natural Gas		6.68		6.68		4.26	0.075	%
Oil		2.04		2.04		5.16	0.075	%

During the year ended December 31, 2003, the average delivered cost per ton of fuel for our base-load plants was $25.77 at Big Stone, $14.76 at Coyote and $13.22 at Neal. Changes in our fuel costs are passed on to customers through the operation of the fuel adjustment clause in our South Dakota tariffs. For a discussion of federal regulations regarding the use of coal to produce electricity, see "Utility Regulation—Environmental." Also see "Risk Factors—Risks Relating to Our Business—Changes in commodity prices and availability of supply may increase our cost of producing and distributing electricity and distributing natural gas or decrease the amount we receive from selling

electricity and natural gas, adversely affecting our financial performance and condition" included elsewhere herein.

The Big Stone facility currently burns Wyoming sub-bituminous coal from the Powder River Basin supplied under contracts that continue through the end of 2004. The Coyote facility has a contract for the delivery of lignite coal that expires in 2016 and provides for an adequate fuel supply for Coyote's estimated economic life. Neal receives Wyoming sub-bituminous coal under multiple firm and spot contracts with terms of up to several years in duration.

The South Dakota Department of Environment and Natural Resources has given approval for Big Stone to burn a variety of alternative fuels, including tire-derived fuel and refuse-derived fuel. In 2003, approximately 3.0% of the fuel consumption at Big Stone was derived from alternative fuels.

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

We must pay fees to third parties to transmit the power generated at our Big Stone and Neal plants to our South Dakota transmission system. In 2001, we entered into a new 10-year agreement with the Western Area Power Administration for transmission services, including transmission of electricity from Big Stone and Neal to our South Dakota service areas through seven points of interconnection on the Western Area Power Administration's system. Transmission services under this agreement, and our costs for such services, are variable and depend upon a number of factors, including the respective parties' system peak demand and the amount of our transmission assets that are integrated into the Western Area Power Authority's system. In 2003, our costs for services under this contract totaled approximately $3.62 million. Our tariffs in South Dakota generally allow us to pass costs with respect to power purchased, including transmission costs from other suppliers, to our customers.

Our regulated natural gas utility operations purchase, transport, distribute and store natural gas for approximately 245,000 commercial and residential customers in Montana, South Dakota and Nebraska as of December 31, 2003. Natural gas service generally includes fully bundled services consisting of natural gas supply and interstate pipeline transmission services and distribution services to our customers, although certain large commercial and industrial customers, as well as wholesale customers, may buy the natural gas commodity from another provider and utilize our utility's transportation and distribution service.

We distribute natural gas to nearly 163,000 customers located in 109 Montana communities as of December 31, 2003. The MPSC does not assign service territories in Montana. However, we have nonexclusive municipal franchises to purchase, transport, distribute and store natural gas in the Montana communities we serve. The terms of the franchises vary by community, but most are for 30 to 50 years. During the next four years, one of our municipal franchises, which accounts for approximately 4,000 customers, is scheduled to expire. We also serve several smaller distribution companies that provided service to approximately 28,000 customers as of December 31, 2003. Our natural gas distribution system consisted of approximately 3,500 miles of underground distribution pipelines as of December 31, 2003.

We also transmit natural gas in Montana from production receipt points and storage facilities to distribution points and other nonaffiliated transmission systems. We transported natural gas volumes of

approximately 55 billion cubic feet in the year ended December 31, 2003. NorthWestern Energy's Montana peak capacity was approximately 300 million cubic feet per day during the year ended December 31, 2003. Our Montana natural gas transmission system consisted of more than 2,000 miles of pipeline, which vary in diameter from two inches to 20 inches, and served more than 130 city gate stations as of December 31, 2003. NorthWestern Energy has connections in Montana with five major, nonaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, Encana and Havre Pipeline. Seven compressor sites provide more than 42,000 horsepower, capable of moving approximately 300 million cubic feet per day during the year ended December 31, 2003. In addition, we own and operate a pipeline border crossing through our wholly owned subsidiary, Canadian-Montana Pipe Line Corporation.

We own and operate three working natural gas storage fields in Montana with aggregate storage capacity of approximately 16.2 billion cubic feet, of which 9 billion cubic feet is reserved for our regulated utility business, and maximum aggregate working gas capacity of approximately 185 million cubic feet per day. We own a fourth storage field that is being depleted at approximately 0.03 million cubic feet per day with approximately 71 million cubic feet of remaining reserves as of December 31, 2003.

We provided natural gas to approximately 82,000 customers in 59 South Dakota communities and four Nebraska communities as of December 31, 2003. The state regulatory agencies in South Dakota and Nebraska do not assign service territories. We have nonexclusive municipal franchises to purchase, transport, distribute and store natural gas in the South Dakota and Nebraska communities we serve. The maximum term permitted under Nebraska law for these franchises is 25 years while the maximum term permitted under South Dakota law is 20 years. Our policy is to seek renewal of a franchise in the last year of its term. During the next five years, five of our South Dakota and Nebraska municipal franchises, which account for approximately 36,000 customers, are scheduled to expire. We have never been denied the renewal of any of these franchises. Included in the five franchises mentioned above is the City of Kearney, Nebraska. Our franchise with Kearney was scheduled to expire in the fall of 2003 but was extended indefinitely, and we are negotiating a new franchise with the City. We had approximately 2,100 miles of distribution gas mains in South Dakota and Nebraska as of December 31, 2003. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska, and in South Dakota provide natural gas sales to a number of large volume customers delivered through the distribution system of an unaffiliated natural gas utility company.

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

In South Dakota and Nebraska, we are subject to competition for natural gas supply. In addition, competition currently exists for commodity sales to large volume customers and for delivery in the form of system bypass, alternative fuel sources such as propane and fuel oil, and, in some cases, duplicate providers. We do not face material competition from alternative natural gas supply companies in the communities in which we serve in South Dakota and Nebraska. We are currently the largest provider of natural gas in our South Dakota service territory based on MMBTU sold. In South Dakota, we also transport natural gas for two gas-marketing firms currently serving 160 customers through our

distribution systems. In Nebraska, we transport natural gas for one customer, whose supply is contracted from another gas company. We delivered approximately 6.7 million MMBTU of third-party transportation volume on our South Dakota distribution system and approximately 0.93 million MMBTU of third-party transportation volume on our Nebraska distribution system.

Competition in the natural gas industry may result in the further unbundling of natural gas services. Separate markets may emerge for the natural gas commodity, transmission, distribution, meter reading, billing and other services currently provided by utilities. At present, it is unclear when or to what extent further unbundling of utility services will occur. To remain competitive in the future, we must provide top-quality services at reasonable prices. To prepare for the future, we must ensure that all aspects of our natural gas business are efficient, reliable, economical and customer-focused.

Natural gas is used primarily for residential and commercial heating. As a result, the demand for natural gas depends upon weather conditions. Natural gas is a commodity that is subject to market price fluctuations. Purchase adjustment clauses contained in South Dakota and Nebraska tariffs allow us to reflect increases or decreases in gas supply and interstate transportation costs on a timely basis, so we are generally allowed to pass these higher natural gas prices through to our customers.

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

In Montana, our natural gas supply requirements for the year ended December 31, 2003, were approximately 21.3 million MMBTU. We have contracted with more than seven major producers and marketers with varying contract durations for natural gas supply in Montana.

Our South Dakota natural gas supply requirements for the year ended December 31, 2003, were approximately 5.4 million MMBTU. We have contracted with Tenaska Marketing Ventures, Inc. in South Dakota to manage transportation, storage and procurement of supply in order to minimize cost and price volatility to our customers.

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

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

As of December 31, 2003, we had 1,269 employees in our energy division, NorthWestern Energy. Of these, our Montana operations had 960 employees in its electric and gas utilities business, 374 of whom were covered by collective bargaining agreements involving six unions. In addition, our South

Dakota and Nebraska operations had 309 employees in its electric gas and utilities business, 179 of whom were covered by the System Council U-26 of the IBEW.

On June 30, 2004, members of the International Brotherhood of Electrical Workers ratified a new four-year collective bargaining agreement with us. The union represents approximately 310 of our electric and natural gas workers in Montana. On July 28, 2004, we reached a tentative agreement on a new four-year collective bargaining agreement with the United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry Locals 41 and 459, which represents 64 natural gas workers whose contract expired May 31, 2004. Though the tentative agreement was not ratified by the membership, as of October 2004, negotiations continued with Locals 41 and 459 to obtain a ratified agreement. PACE International Union, Local 8-0493 ratified a new collective bargaining agreement on August 26, 2004. We have three remaining union agreements that expired in August 2004, with Montana unions representing 24 other NorthWestern workers. We are continuing to negotiate with these unions.

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.

We are a "public utility" within the meaning of the Federal Power Act. Accordingly, we are subject to the jurisdiction of, and regulation by, the FERC with respect to the issuance of securities, the transmission of electric energy in interstate commerce and the setting of wholesale electric rates. As such, we are required to submit annual filings of certain financial information on the FERC Form No. 1 Annual Report of Major Electric Utilities, Licensees and Others. In addition, on December 23, 2003, FERC issued Order 2001-E, requiring quarterly filings of certain financial information on the FERC Form No. 3-Q, Quarterly Financial Report of Electric Companies, Licensees, and Natural Gas Companies, effective beginning with the first quarter 2004 filing.

In April 1996, the FERC issued Order No. 888 and Order No. 889 requiring utilities to allow open use of their transmission systems by other utilities and power marketers. We and other jurisdictional utilities filed open access transmission tariffs, or OATTs, with the FERC in compliance with Order No. 888. NorthWestern Public Service and The Montana Power Company included OATTs in their filings which conform to the "Pro Forma" tariff in Order No. 888 in which eligible transmission service customers can choose to purchase transmission services from a variety of options ranging from full use of the transmission network on a firm long-term basis to a fully interruptible service available on an hourly basis. These tariffs also include a full range of ancillary services necessary to support the transmission of energy while maintaining reliable operations of our transmission system. NorthWestern Energy LLC, and subsequently, NorthWestern, succeeded to The Montana Power Company's OATTs.

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

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

On December 20, 1999, the FERC issued Order No. 2000, its most recent order regarding Regional Transmission Organizations, or RTOs. An RTO is an organization that places operational control of transmission facilities owned by utilities in the hands of an entity that is "independent" of any seller or other market participant in order to assure non-discriminatory access by third parties to the transmission system in keeping with the goals of Order No. 888. Pursuant to Order No. 2000, utilities that own, operate or control interstate transmission facilities were required to file a proposal with the FERC by October 15, 2000, describing the utilities' efforts to participate in an RTO expected to be operational by December 15, 2001.

The Montana Power Company was a co-sponsor of a filing at the FERC that proposed to form RTO West. RTO West would be a nonprofit organization with an independent board that would act as the independent system operator for the aggregated transmission systems of participating transmission owners. If RTO West is implemented and we participate, then we would execute a transmission operating agreement with RTO West prior to startup of the RTO West operation. We do not anticipate that the transmission operating agreement would include any of our transmission assets other than those used in NorthWestern Energy's Montana operations. RTO West would not be permitted to own transmission assets pursuant to its charter, so the transmission operating agreement would not convey ownership of the assets to RTO West but would grant RTO West the right to operate the assets consistent with the obligation to provide services pursuant to applicable tariffs. NorthWestern Energy and other participating transmission owners would likely retain the right and obligation to maintain the facilities that RTO West has authority to operate pursuant to the transmission operating agreements. Participation in RTO West would create a new commercial arrangement for the transmission of the energy we distribute in Montana, but we do not anticipate any material change in the size or timing of the transmission-related revenue stream as a result of participation in RTO West. In early 2004, the stakeholders in RTO West stepped back once again to determine what a Regional Transmission Organization should look like in the West. The effort refocused on the issues most important to the region and has since been renamed GridWest. We cannot predict with certainty the impact that GridWest will have on our earnings, revenues or prices. We do know that the effort to form a Regional Transmission Organization in the West has gone through multiple phases and it could be some time before the ultimate outcome is known. At this time, it is uncertain when or if GridWest will begin operations.

With respect to our South Dakota transmission operations, we filed in October 2000 our Order No. 2000 Compliance Filing with the FERC detailing options we are pursuing concerning participating in an RTO, including participation in the investigation of the formation of a regional transmission entity as well as the pursuit of various options associated with joining the Midwest Independent System Operator, or MISO. We have decided not to join MISO at this time and, on July 28, 2004, in its Findings of Fact, the FERC determined that our transmission facility agreements related to the Big Stone Plant and the Coyote I Station were not MISO transactions, and we would not have responsibility for MISO transmission expenses related to such agreements. In its September 6, 2004 Order, the FERC determined that the Big Stone Plant transmission agreement should be excluded from further MISO cost assignment proceedings, and that we, the other transmission agreement participants and MISO should submit information to the FERC for the FERC to determine whether the Coyote I Station transmission agreement also should be excluded.

On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, or the SMD NOPR. In April 2003, FERC issued a white paper

related to the SMD NOPR, which paper reflected some of the comments made to FERC in the NOPR process. This paper proposed certain changes, but did not materially alter the proposed rules. The proposed rules set forth in the SMD NOPR would require, among other things, that:

We cannot predict whether or when the FERC will issue final rules on SMD NOPR, or what form they will take. We do know that the SMD NOPR was very unpopular across substantial portions of the country. The SMD NOPR has generated significant opposition, including from interested parties in the Northwest, where we operate, the Southeast and their respective Congressional delegations. In the near term, it does not appear that SMD will become a Final FERC order in the West. We cannot predict with certainty the impact the future SMD-related proceedings will have on the Company's earnings, revenues or prices.

On July 24, 2003, FERC issued Order 2003 on Standardization of Generation Interconnection Procedures and Agreements. The final rule, which was effective January 20, 2004, requires public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to have on file standard procedures and a standard agreement for interconnecting generators larger than 20 MW. FERC believes that Order 2003 will prevent undue discrimination, preserve reliability, increase energy supply, and lower prices for customers by increasing the number and variety of new generators that will compete in the wholesale electricity market. For utilities that are not part of an RTO, Order 2003 requires that new generators fund the cost of transmission provider interconnection facilities needed to interconnect their new generation to the transmission system. In addition, the order requires that the generator advance any funds that are required for network upgrades associated with the generation interconnection. The generator then receives a refund of the network upgrade costs based upon the transmission usage for the energy produced by the new generation facility over time. This ultimately may result in our requesting that the network system upgrades be added to the utility ratebase. It is reasonable to assume that regulators will allow recovery of such investment from customers, but that is not certain. The impact this order will have on the Company's earnings, revenues or prices will depend on the number of new generators that interconnect to the Company's system in the future, the extent of the transmission upgrades required by those generators, and ultimate regulatory treatment of those investments.

On November 25, 2003, the FERC issued Order 2004 on Standards of Conduct. Orders 2004A and 2004B, which essentially have clarified order 2004, have also been issued. In Order 2004, FERC adopted standards of conduct that apply uniformly to interstate gas pipelines and public utilities (jointly referred to as Transmission Providers) that are currently subject to the gas and electric standards of conduct in Part 161 and Part 37 of FERC's regulations, respectively. The new standards of conduct govern the relationship between a regulated Transmission Provider and any Energy Affiliate that such Transmission Provider may have. Because of the Company's electric transmission operations, it is a Transmission Provider under Order 2004. On April 9, 2004, the Company filed with the FERC an Informational Filing and Motions i) requesting continued exemption of the Standards of Conduct for its South Dakota operations on the basis, among other reasons, that such operations continue to meet the definition of a small public utility (for which the Company received a waiver from the FERC as to FERC Order 889 requirements), and ii) a second motion requesting clarification, or alternatively a limited waiver of Order 2004 for the Company's Montana operations. The Company very recently received an Order from FERC on its April filing. The Order granted the request for exemption of the

requirements of FERC Order 2004 with respect to the South Dakota operations and requested additional information on the Montana operations to be filed by October 20, 2004. The Company has taken steps to implement the training requirements of the standards of conduct.

If, ultimately the Motion with regard to our Montana operations is not granted, compliance with Order 2004 may require some level of reorganization of certain of the Company's operations. Although we cannot predict with certainty the impact Order 2004 may have on the our earnings, revenues or prices, management believes that in the aggregate, our earnings and revenues would not be materially affected.

The Montana Power Company provided wholesale power to two electric cooperatives, but the two cooperatives have chosen to obtain their power supply from another source, and we provide only transmission services to the Montana cooperatives. In order to recover the transition costs associated with power that would have been supplied to these two cooperatives, The Montana Power Company made a filing with the FERC in April 2000, seeking recovery of approximately $13.9 million in transition costs associated with serving both of the wholesale electric cooperatives. On November 1, 2002, the FERC granted the electric cooperatives' motion for summary judgment and determined that The Montana Power Company had failed to meet its burden of showing that it was entitled to recover the transition costs at issue. We, as successor to The Montana Power Company, appealed but a FERC decision issued on January 28, 2004, affirmed the original decision. No further appeal was taken.

The limited liability company that formerly held our Montana transmission and distribution assets has been renamed "Clark Fork and Blackfoot, L.L.C." This entity owns and operates the Milltown Dam, a three-megawatt hydroelectric dam at the confluence of the Clark Fork and Blackfoot Rivers, under a license granted by the FERC. The current license for operation of the dam would have expired but for extensions received from the FERC. The Montana Power Company received an extension of its FERC license to operate the dam until 2008, and we are currently seeking to extend that license until 2009. Generally, under FERC rules, notice of intent to renew a license must be filed five years prior to its expiration. Accordingly, Clark Fork and Blackfoot, L.L.C. gave the FERC its notice to seek renewal of the license in 2003. In the event the FERC license was terminated, the FERC may require that the dam be removed. If Clark Fork and Blackfoot, LLC does not receive the license extension, then it might be required to relinquish the license, cease operating the dam and remove the structures as early as 2008. Based on estimates received from our environmental consultants, management believes that the cost of such removal would be approximately $10 million. The licensing strategy described above is being applied to facilitate implementation of the Milltown Dam Reservoir Superfund Site remedy. See "—Environmental" for discussion of the Milltown Dam superfund matter.

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

If we make sales in the wholesale market in interstate commerce at market-based rates, we will need to make a filing at the FERC that satisfies certain new indicative market power screens. If we cannot meet these tests, the filing may be set for hearing, all payments for market-based rates may be subject to refund beginning as early as 60 days after the order is set for hearing and ultimately, the FERC may withdraw approval for us to sell at market-based rates and may order us to refund certain payments.

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

In August 2000, The Montana Power Company filed a combined request for increased natural gas and electric rates with the MPSC. The Montana Power Company requested increased annual electric revenues of approximately $38.5 million, with a proposed interim annual increase of approximately $24.9 million. On November 28, 2000, the MPSC granted the former owner an interim electric rate increase of $14.5 million. On May 8, 2001, The Montana Power Company received a final order from the MPSC resulting in an annual electric service revenue increase of $16.0 million.

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

On January 31, 2002, the MPSC approved a stipulation among The Montana Power Company, us and a number of other parties, which, among other things, conclusively established the pretax net present value of the retail transition costs relating to out-of-market power purchase contracts recoverable in retail rates to be approximately $244.7 million, approximately $60 million less than the QF costs in The Montana Power Company's filing with the MPSC. In addition, the stipulation set a fixed annual recovery for the retail transition costs beginning at $14.9 million in the first year after implementation and increasing up to $25.6 million through 2029. On June 12, 2003, the MPSC approved the next annual tracking period amount of $17.4 million to be effective July 1, 2003. Because the recovery stream as finalized by the stipulation is less than the total payments due under the out-of-market power purchase contracts, the difference must be mitigated or covered from other revenue sources. The QF contracts require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our gross contractual obligation related to the QFs is approximately $1.8 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.4 billion through 2029. Upon completion of the purchase price allocation related to our acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company, we established a liability of $134.3 million, based on the net present value of the difference between our obligations under the QF supply contracts and the related amount recoverable. Although we believe that we have opportunities to mitigate the impact of these differences through improved management of our obligations under these contracts and by negotiating buyouts of certain of these contracts, we cannot assure you that our actions will be successful.

The stipulation also required The Montana Power Company and us to contribute $30 million to an account which funded credits to Montana electric distribution customers. The account was applied on a per kilowatt hour basis which began on July 1, 2002, with a term of one year. On June 12, 2003, the MPSC approved the elimination of the Electric Sale Credit effective July 1, 2003.

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

On October 29, 2001, The Montana Power Company filed with the MPSC its initial default supply portfolio, containing a mix of long and short-term contracts from new and existing power suppliers and generators. On April 25, 2002, the MPSC approved NorthWestern Energy LLC's proposed "cost recovery mechanism" in the form filed. On June 21, 2002, the MPSC issued a final order approving contracts meeting approximately 60% of the default supply winter peak load and approximately 73% of the annual energy requirements, principally covered by PPL Montana and QF supply contracts. On January 23, 2004, NorthWestern filed with the MPSC its first biannual Electric Default Supply Resource Procurement Plan, which fulfills the requirements established by law and describes the planning we are performing on behalf of its electric default supply customers to acquire a balanced, cost-effective resource portfolio. The immediate needs are for resources that address the variable portion of the load. We plan to present several contracts to the MPSC for approval in 2004, which meet these variable requirements. For further discussion of this risk, see "Risk Factors—Risks Relating to Our Business—We will not be able to fully recover transition costs, which could adversely affect our net income and financial condition" and "Risk Factors—Risks Relating to Our Business—If the MPSC disallows the recovery of the costs incurred in entering into default supply portfolio contracts while we are required to act as the "default supplier," then we may not be able to fully recover the costs incurred in procuring default supply contracts, which could adversely affect our net income and financial condition" included elsewhere herein.

On June 16, 2003, we filed an annual electric supply cost tracker request with the MPSC for actual electric supply costs for the 12-month period ended June 30, 2003, and for projected costs for the 12-month period ended June 30, 2004. On July 15, 2003, an interim order was approved by the MPSC for the projected electric supply cost. This case was subsequently suspended upon our bankruptcy filing and is now being processed in conjunction with the 2004 electric supply cost tracker.

On June 4, 2004, we filed the 2004 annual electric supply cost tracker request for actual costs for the 12-month period ended June 30, 2004, and projected costs for the 12-month period ended June 30, 2005. The MPSC approved an interim order on July 28, 2004 for historical actual costs for the 24-month period ended June 30, 2004 and for the requested projected costs.

pending financial investigation. The consent order approving the settlement agreement was issued by the MPSC on August 24, 2004. In return, we agreed to a number of important concessions including, but not limited to, the following:

Criterion		Aggregate Investment Cap
Upon the effective date of the plan of reorganization		$60 million
At least BBB-/Baa3		$75 million
At least BBB/Baa2		$90 million
At least BBB+/Baa1 but in no event earlier than 42 months after the effective date		None;

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

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

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

FERC Order 636 requires that all companies with interstate natural gas pipelines separate natural gas supply and production services from interstate transportation service and underground storage services. The effect of the order was that natural gas distribution companies, such as NorthWestern, and individual customers purchase natural gas directly from producers, third parties and various gas-marketing entities and transport it through interstate pipelines. We have established transportation rates on our transmission and distribution systems to allow customers to have supply choices. Our transportation tariffs have been designed to make us economically indifferent as to whether we sell and transport natural gas or merely deliver it for the customer.

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

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 may be subject to MPSC jurisdiction when we issue, assume or guarantee securities, or when we create liens on our Montana properties.

Rates for our Montana natural gas supply are set by the MPSC. We use a monthly gas tracking mechanism in Montana for the recovery of gas supply costs, which we prepare and file monthly with the MPSC. The filing sets gas cost rates based on estimated gas loads and gas costs for the upcoming tracking period and adjusts for any differences in the rolling 12-month period's estimates to actual cost information.

We filed an annual gas cost tracker request in Montana in December 2001 for actual gas costs for the 12-month period ended October 31, 2001, and for projected costs for the 12-month period ended October 31, 2002. Our December 2001 request was finalized by order of the MPSC on October 10, 2002. On November 1, 2002, we filed an annual gas cost tracker request for actual gas costs for the 12-month period ended October 31, 2002, and for projected costs for the eight-month period ended June 30, 2003. In our 2002 filing, we proposed to change the tracking year to July 1 through June 30 and therefore estimated our gas costs from November 1, 2002 through June 30, 2003. That request was finalized by order of the MPSC on July 3, 2003, with the exception of disallowing $6.2 million of our purchased gas costs as having been imprudently incurred. We filed a motion for reconsideration regarding the disallowance of purchased gas cost with the MPSC on July 14, 2003, which was denied. We filed suit in Montana state court on July 28, 2003, seeking to overturn the MPSC's decision to disallow recovery of these costs.

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

result in the Company undercollecting approximately $4.5 million for the period July 1, 2003 through June 30, 2004. This case was subsequently suspended upon our bankruptcy filing and is now being processed in conjunction with the 2004 gas cost tracker. Negotiations continue between us and the MPSC regarding our recovery of these costs.

On May 28, 2004, we filed the 2004 annual gas supply cost tracker request for actual costs for the 12-month period ended June 30, 2004, and projected costs for the 12-month period ended June 30, 2005. The MPSC approved an interim order on July 8, 2004 that approved the requested projected costs and continued to reflect a disallowance of historical gas costs as described above, with the actual undercollection totaling $4.6 million.

In January 2001, The Montana Power Company submitted to the MPSC an annual gas cost tracker requesting an increase of approximately $51.0 million. At that time, the former owner also submitted a compliance filing for a credit of approximately $32.5 million associated with a sharing of the proceeds from the sale of gathering and production properties previously included in the natural gas utility's rate base. As a result, effective February 1, 2001, The Montana Power Company began collecting a net amount of $18.5 million in revenues over a one-year period. In September 2001, after all testimony addressing the amount of sharing had been filed with the MPSC, The Montana Power Company reached an agreement with intervening parties to increase the amount of the credit to $56.3 million. This $23.8 million increase, along with $4.0 million in interest from the date of sale, was credited to customers' bills over approximately a two-year period, which began February 1, 2002. This customer credit was fully refunded by December 2003.

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

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

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

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

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

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

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

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

The Clean Air Act Amendments of 1990, which prescribe limitations on, among other pollutants, 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. On January 30, 2004, the EPA proposed the Utility Mercury Reductions Rule for controlling mercury emissions from power plants, which proposal was supplemented on February 23, 2004. The comment period for the rule closed on June 29, 2004, and the EPA is reviewing comments and preparing to issue a final rule in March 2005. Because of the uncertain nature of the final Utility Mercury Reductions Rule and the potential for development of more stringent emission standards in general, we cannot reasonably determine the additional costs we may incur under the Clean Air Act. In addition to the proposed Utility Mercury Reductions Rule, legislation has been introduced in the Congress to amend the Clean Air Act, including legislation that implements President Bush's "Clear Skies" proposal, or would otherwise affect the regulatory programs applicable to emissions of sulfur oxide, nitrogen oxide, mercury, and possibly carbon dioxide. These proposals are all subject to the normal legislative process, and we cannot make any prediction about whether the proposals will pass, or the final terms of the legislation if it were to pass. Any such legislation, if passed, would likely require the adoption of administrative regulations. We cannot reasonably determine whether any proposals would impose additional costs, or if so, the timing or magnitude of those costs.

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

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

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

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

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

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

Toxic heavy metals in the silts resting in Milltown Reservoir, which sits behind Milltown Dam, caused the EPA to identify Milltown Reservoir on its Superfund National Priority List. ARCO, as successor to the Anaconda Company, was named as the party with responsibility for completing the remedial investigation and feasibility studies and conducting site cleanup, under the EPA's direction. The Montana Power Company did not undertake any direct responsibility in that regard, in light of a statutory exemption from liability under CERCLA provided to the holder of the Milltown Dam FERC operating license. By virtue of its acquisition of The Montana Power Company's electric and natural gas transmission and distribution business and the Milltown Dam, Clark Fork and Blackfoot, LLC succeeded to similar protection under this statutory exemption. ARCO, however, has argued that the owner of the Milltown Dam should be considered a potentially responsible party and threatened to challenge Clark Fork's exempt status. ARCO and The Montana Power Company entered into a confidential settlement agreement to limit The Montana Power Company's and now Clark Fork's potential liability under such a challenge and limit costs and ongoing operating expenditures, provided that the EPA selects a remedy that leaves the dam and sediments in place in its final Record of Decision. In April 2003, the EPA announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed the removal of the Milltown Dam and powerhouse, together with partial removal of the contaminated sediments residing near the Milltown Reservoir. In light of this announcement, we commenced negotiations with ARCO. On September 10, 2003, we executed a confidential settlement agreement with ARCO, which, among other things, capped our maximum contribution towards remediation of the Milltown Reservoir superfund

site. A motion to approve the settlement agreement with ARCO was filed with the Bankruptcy Court on October 17, 2003. On April 7, 2004 we entered into a stipulation with ARCO, the EPA, the Department of the Interior, the State of Montana and the Confederated Salish and Kootenai Tribes, which collectively, we refer to as the Government Parties, which is intended to resolve both our liability with ARCO in general accordance with the previously negotiated settlement agreement and establish a framework to resolve our liability with the Government Parties for their claims, including natural resource restoration claims, against NorthWestern as they relate to remediation of the Milltown Site. The stipulation caps NorthWestern's and Clark Fork's collective liability to ARCO and the Government Parties at $11.4 million. On June 22, 2004 the Bankruptcy Court approved the stipulation and the funding of the ARCO settlement, as modified by the stipulation. The amount of the stipulated liability has been fully accrued in the accompanying financial statements. Pursuant to the stipulation, commencing in August 2004 and each month thereafter, we will pay $500,000 alternately into two escrow accounts, one for the State of Montana and one for ARCO, until the total agreed amount is funded. No interest will accrue on the unpaid balance due, and the escrow accounts will remain funded until a final, nonappealable consent decree is entered by the United States District Court. If, however, a consent decree (i) is not executed by the relevant parties, (ii) is not approved by the United States District Court, or (iii) does not become fully effective, then all funds in the escrow accounts will continue to be held in trust pending further court order. The stipulation incorporates appropriate releases and indemnifications from ARCO under the previously negotiated settlement agreement.

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

The Montana Power Company voluntarily cleaned up two sites in Butte and Helena, Montana where it formerly operated manufactured gas plants and had investigated a third in Missoula, Montana at the time of our acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company. Only the Butte and Helena, Montana sites were placed into the MDEQ's voluntary remediation program for cleanup due to the existence of minor exceedences in groundwater of regulated pollutants. We believe that natural attenuation should address the problems at these sites. The investigation conducted at the Missoula site did not require entry into the MDEQ voluntary remediation program, but required preparation of a groundwater monitoring plan. Monitoring of groundwater continues at all of the Montana manufactured gas plant sites. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may become necessary in the future to prevent contamination from migrating offsite. Therefore, continued monitoring of groundwater at this site is necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty what the costs of additional cleanup will be for such groundwater remediation at Helena, or whether additional cleanup will be required at the Butte and Missoula sites. However, based upon the information available to date, our current environmental liability reserves and applicable insurance coverage, we do not expect cleanup costs at these sites to be material.

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

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

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. However, we believe that we accrue an appropriate amount of costs and estimate reasonably foreseeable potential costs related to such environmental regulation and cleanup requirements. As of June 30, 2004, we have a reserve of approximately $45.3 million to cover all estimated environmental liabilities. We anticipate that as environmental costs become fixed and determinable we will seek insurance coverage and/or rate recovery, therefore we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

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

Our executive offices are located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104, where we lease approximately 35,300 square feet of office space, pursuant to a lease that expires on June 30, 2005.

NorthWestern Energy's principal corporate office is owned and located at 600 Market Street W., Huron, South Dakota 57350. Substantially all of NorthWestern Energy's South Dakota and Nebraska facilities are owned. NorthWestern Energy's Montana executive offices, which we own, are located at 40

East Broadway Street, Butte, Montana 59701. NorthWestern Energy leases other offices throughout the state of Montana, including a 20,000 square foot facility in Butte, Montana, where we provide call center customer support services and conduct customer billing and other functions.

As a result of our bankruptcy filing, attempts to collect, secure or enforce remedies with respect to most prepetition claims against us are subject to the automatic stay provisions of Section 362(a) of the Bankruptcy Code.

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

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

On February 7, 2004, the parties to the above consolidated securities class actions and consolidated derivative litigation, together with certain other affected persons and parties, reached a tentative settlement of the litigation. On April 19, 2004, the parties and other affected persons signed a memorandum of understanding (MOU) which memorialized the tentative settlement. On June 16, 2004, the parties and other affected persons signed a settlement agreement memorializing the tentative settlement and addressing various issues necessary for federal court approval. We obtained approval of the MOU in the NorthWestern and Netexit bankruptcy cases on October 7, 2004 and September 15, 2004, respectively. Prior to those approvals, the federal court in Sioux Falls indicated that it intended to grant preliminary approval of the settlement agreement pending the Bankruptcy Court approval, and has set a date for final approval on December 13, 2004. Among the terms of the proposed settlement, we, Expanets, Blue Dot and other parties and persons will be released from all claims to these cases, a settlement fund in the amount of $41 million (of which approximately $37 million would be contributed by our directors and officers liability insurance carriers, and $4 million would be contributed from other persons and parties) will be established, and the plaintiffs will have a $20 million liquidated securities claim against Netexit. If for any reason the settlement is not approved, then we intend to vigorously defend against these lawsuits. If we are unsuccessful in defending against these lawsuits, the plaintiffs' securities litigation and derivative litigation claims would be subordinated to our other debt under our plan of reorganization, and such claims would be treated as securities, or Class 14, claims under our plan of reorganization, and would be entitled to no recovery under our plan of reorganization. Claims by our current and former officers and directors for indemnification for these proceedings would be channeled into the Directors and Officers Trust. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition.

(FBI) concerning certain of the allegations made in the class action securities and derivative litigation matters. We have not been advised that NorthWestern is the subject of any FBI investigation. We understand that the FBI and the Internal Revenue Service (IRS) have contacted former employees of ours or our subsidiaries. As of the date hereof, we are not aware of any other governmental inquiry or investigation related to these matters. We are cooperating with the SEC's investigation and intend to cooperate with the FBI if we are contacted in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, for which we can provide no assurance, we may face sanctions, including, but not limited to, monetary penalties and injunctive relief and any monetary liability incurred by us may be material to our financial position or results of operations.

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

On April 16, 2004 Magten Asset Management Corporation (Magten) and Law Debenture Trust Company of New York (Law Debenture) initiated an adversary proceeding, the QUIPs Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets of Clark Fork 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 Clark Fork insolvent and unable to pay certain claims. The plaintiffs also assert that they are creditors of Clark Fork 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 Clark Fork. (In addition to the adversary proceeding filed by Magten and Law Debenture, the plaintiffs in the class action lawsuit entitled McGreevey, et al v. Montana Power Company, et al received approval in our bankruptcy case to initiate similar adversary proceedings. Under the terms of the settlement with the plaintiffs in the McGreevey case discussed below, they would not file such proceeding.) On April 19, 2004 Magten also filed a complaint against certain former and current officers of Clark Fork in U.S. District Court in Montana, seeking compensatory and punitive damages for breaches of fiduciary duties by such officers. Those officers have requested Clark Fork to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. At this time, we cannot predict the impact or resolution of any of these lawsuits or reasonably estimate a range of possible loss, which could be material. The resolution of these lawsuits could harm our business and have a material adverse impact on our financial condition. We intend to vigorously defend against the adversary proceeding and any subsequently filed similar litigation. The plaintiffs' claims with respect to

this litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the share reserve that we will establish with respect to the Class 9 disputed claims reserve under the plan of reorganization. See "Risk Factors—Bankruptcy-Related Risks—We will be subject to claims made after the date that we filed for bankruptcy and other claims that are not discharged in the bankruptcy proceeding, which could have a material adverse effect on our results of operations and profitability."

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

On November 6, 2003, the Bankruptcy Court approved a stipulation between NorthWestern and the plaintiffs in McGreevey, et al. v. The Montana Power Company, et al. The stipulation provides that litigation, as against NorthWestern, Clark Fork, the Montana Power Company, Montana Power LLC and Jack Haffey, shall be temporarily stayed for 180 days from the date of the stipulation. Pursuant to the stipulation and after providing notice to NorthWestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. On July 10, 2004, we and the other insureds under the applicable directors and officers liability insurance policies along with the plaintiffs in the McGreevey case, plaintiffs in the In Re Touch America Holdings, Inc. Securities Litigation and the Touch America Creditors Committee reached a tentative settlement through mediation. Among the terms of the tentative settlement, we, Clark Fork 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, where a hearing has been set for November 3, 2004, and approval of the proposed settlement by the Federal District Court for the District of Montana, where the class actions are pending. We cannot predict the ultimate outcome of this litigation in the event that the settlement is not approved, or does not take effect for any other reason. If for any reason the settlement is not approved, then we intend to vigorously defend against this lawsuit. If we are unsuccessful in defending against this class action lawsuit, the plaintiffs' litigation claims would be subordinated to our other debt under our plan of reorganization, and such claims would be treated as securities, or Class 14, claims under our plan of reorganization, and would be entitled to no recovery under our plan of reorganization. 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. The plaintiffs could elect to proceed directly against Clark Fork and the assets owned by such entity, which as of June 30, 2004 were not material to our operations or financial position. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition.

In NorthWestern Corporation vs. PPL Montana, LLC vs. NorthWestern Corporation and Clark Fork and Blackfoot, LLC, No. CV-02-94-BU-SHE, (D. MT), we are pursuing claims against PPL Montana, LLC (PPL) due to its refusal to purchase the Colstrip transmission assets which under the

Asset Purchase Agreement (APA) executed by and between the Montana Power Company (MPC) and PP&L Global, Inc. (PPL Global), NorthWestern claims PPL (PPL Global's successor-in-interest under the APA) is required to purchase the Colstrip transmission assets for $97.1 million. PPL has also asserted a number of counterclaims against NorthWestern and Clark Fork based in large part upon PPL's claim that MPC and/or NorthWestern Energy breached two Wholesale Transition Service Agreements and certain indemnification obligations under the APA in the approximate amount of $40 million. PPL also filed a proof of claim against NorthWestern's bankruptcy estate which asserts substantially the same claims as the PPL counterclaim. PPL moved the Bankruptcy Court for relief from the automatic stay to pursue its counterclaims. NorthWestern objected to PPL's motion to lift the automatic stay and has also filed a motion to transfer the venue of the entire litigation to the United States District Court for the District of Delaware. On March 19, 2004 the federal court in Montana denied our motion to transfer the entire case. We intend to vigorously defend against the PPL claims in the Bankruptcy Court and the counterclaims in federal court as well as vigorously prosecute our claims against PPL. We cannot currently predict the impact or resolution of the claims or this litigation or reasonably estimate a range of possible loss on the counterclaims, which could be material. The plaintiffs' claims with respect to this litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the share reserve that we will establish with respect to the Class 9 disputed claims reserve under the plan of reorganization. See "Risk Factors—Bankruptcy-Related Risks—We will be subject to claims made after the date that we filed for bankruptcy and other claims that are not discharged in the bankruptcy proceeding, which could have a material adverse effect on our results of operations and profitability."

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

We, and certain of our former officers and directors, were named as defendants in certain complaints filed against CornerStone Propane Partners, LP and other defendants purporting to be class actions filed in the United States District Court for the Northern District of California by purchasers of units of CornerStone Propane Partners alleging violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. Through November 1, 2002, we held an economic equity interest in a subsidiary that serves as the managing general partner of CornerStone Propane Partners, LP. Certain former officers and directors of NorthWestern who are named as defendants in certain of these actions have also been sued in their capacities as directors of the managing general partner. These complaints allege that defendants sold units of CornerStone Propane Partners based upon false and misleading statements and failed to disclose material information about CornerStone Propane Partners' financial condition and future prospects, including overpayment for acquisitions, overstating earnings and net income, and that it lacked adequate internal controls. All of the lawsuits have now been consolidated and Gilbert H. Lamphere has been named as lead plaintiff. The actions have been stayed as to NorthWestern due to its bankruptcy filing. On October 27, 2003,

the plaintiffs filed an amended consolidated class action complaint. The new complaint does not name NorthWestern as a defendant, although it alleges facts relating to NorthWestern's conduct. Certain of our former officers and directors are named as defendants in the amended consolidated complaint. The plaintiffs seek compensatory damages, prejudgment and postjudgment interest and costs, injunctive relief, and other relief. On March 2, 2004, the plaintiffs filed a corrected consolidated amended complaint against CornerStone and the individual defendants, which also did not name NorthWestern. On November 6, 2003, the Bankruptcy Court entered an order approving a stipulation between NorthWestern and plaintiffs in this litigation. The stipulation provides that litigation as against NorthWestern shall be temporarily stayed for 180 days from the date of the stipulation. Pursuant to the stipulation and after providing notice to NorthWestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. In June 2004, CornerStone Propane Partners, LP along with its subsidiaries and affiliates filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. As a result of that filing this case is now stayed against CornerStone Propane Partners and other named subsidiaries and affiliates. Although we have not been named as a defendant in the consolidated and amended complaint, we cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition. We intend to vigorously defend any claims asserted against us by these lawsuits. The plaintiffs' claims with respect to this litigation, and any indemnification claims from our officers and directors, would be treated as securities, or Class 14, claims and would be entitled to no recovery under the plan of reorganization. Any claims in this litigation would be channeled into the Directors and Officers Trust to the extent that they are indemnification claims. See "Risk Factors—Bankruptcy-Related Risks—We will be subject to claims made after the date that we filed for bankruptcy and other claims that are not discharged in the bankruptcy proceeding, which could have a material adverse effect on our results of operations and profitability."

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

Certain of our present and former officers and directors, and CornerStone Propane Partners, LP, as a nominal defendant, are among other defendants named in two derivative actions commenced in the Superior Court for the State of California, County of Santa Cruz, entitled Adelaide Andrews v. Keith G. Baxter, et al., Case No. CV146662 and Ralph Tyndall v. Keith G. Baxter, et al., Case No. CV146661. These derivative lawsuits allege that the defendants breached various fiduciary duties based

upon the same general set of alleged facts and circumstances as the federal unitholder suits. The plaintiffs seek unspecified compensatory damages, treble damages pursuant to the California Corporations Code, injunctive relief, restitution, disgorgement, costs, and other relief. The case has now been stayed against CornerStone due to its bankruptcy filing. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition. Claims by our current and former officers and directors for indemnification with respect to these proceedings would be channeled into the Directors and Officers Trust.

On April 30, 2003, Mr. Richard Hylland, our former President and Chief Operating Officer, filed a demand for arbitration of contract claims under his employment agreement, as well as tort claims for defamation, infliction of emotional distress and tortious interference and a claim for punitive damages. Mr. Hylland is seeking relief in the amount of $25 million, plus interest, attorney's fees, costs, and punitive damages. Mr. Hylland has also filed claims in our bankruptcy case similar to the claims in his arbitration demand. We dispute Mr. Hylland's claims and intend to vigorously defend the arbitration and object to Mr. Hylland's claims in our bankruptcy case. On May 6, 2003, based on the recommendations of the Special Committee of the NorthWestern Board of Directors formed to evaluate Mr. Hylland's performance and conduct in connection with the management of NorthWestern and its subsidiaries, the Board determined that Mr. Hylland's performance and conduct as President and Chief Operating Officer warranted termination under his employment contract. This arbitration has been stayed due to our bankruptcy filing, and once we consummate our plan of reorganization, we expect that an arbitration timetable will be set. Mr. Hylland's claims with respect to this proceeding would be treated as unsecured general, or Class 9, claims and would be satisfied out of the share reserve that we have established. See "Risk Factors—Bankruptcy-Related Risks—We will be subject to claims made after the date that we filed for bankruptcy and other claims that are not discharged in the bankruptcy proceeding, which could have a material adverse effect on our results of operations and profitability."

On August 12, 2003, the Montana Consumer Counsel (MCC) filed a Petition for Investigation, Adoption of Additional Regulatory Controls and Related Relief with the Montana Public Service Commission (MPSC). On August 22, 2003, the MPSC issued an order initiating an investigation of NorthWestern Energy relating to, among others, finances, corporate structure, capital structure, cash management practices and affiliated transactions. The relief sought includes adoption of new regulatory controls that would specifically apply to NorthWestern, including additional reporting, cost allocation and financing rules and requirements, and examination of affiliate transactions necessary to ensure that we are not operating our energy division, and will not in the future operate, in a manner that would prejudice our ability to furnish reasonably adequate service and facilities at reasonable and just charges as required under Montana law. We have entered into a settlement of this matter with the MPSC and MCC, which was approved by the Bankruptcy Court on July 15, 2004, and this proceeding will be closed except for responding to recommendations related to a recently completed infrastructure audit conducted by a consultant. We are currently reviewing these recommendations and have not yet determined the estimated financial impact they may have on our results of operations. As part of the settlement, we agreed to pay approximately $2.8 million of professional fees incurred by the MPSC, the MCC and the Montana Attorney General in connection with our bankruptcy filing. We have fully accrued these fees as of June 30, 2004.

Expanets and NorthWestern have been named defendants in two complaints filed with the Supreme Court of the State of New York, County of Bronx, alleging violations of New York's prevailing wage laws, breach of contract, unjust enrichment, willful failure to pay wages, race, ethnicity, national origin and/or age discrimination and retaliation. In the complaint entitled Felix Adames et al. v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, Bronx County, Index No. 8664-04, which has not yet been served upon Expanets, 14 former employees of Expanets seek

damages in the amount of $27,750,000, plus interest, penalties, punitive damages, costs, and attorney's fees. In the complaint entitled Wayne Belnavis and David Daniels v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, Bronx County, Index No. 8729-04, two former employees of Expanets seek damages in the amount of $12,500,000, plus interest, penalties, punitive damages, costs, and attorney's fees. We intend to vigorously defend against the allegations made in these complaints. Though the filing of the complaint may violate the automatic stay provisions of the Federal Bankruptcy Code and may be subject to the claims process of the bankruptcy proceeding, we cannot currently predict the impact or resolution of these claims or reasonably estimate a range of possible loss, which could be material, and the resolution of these claims may harm our business and have a material adverse impact on our financial condition. Stipulations were entered by the court on March 29, 2004 dismissing us and Avaya as defendants. Netexit remains a defendant in the litigation and claims against Netexit will be satisfied out of its bankruptcy estate.

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

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

The following information is furnished with respect to the current directors of NorthWestern Corporation:

The following information is furnished with respect to the persons who will comprise the board of directors of NorthWestern Corporation upon consummation of our plan of reorganization:

Upon the effective date of our plan of reorganization, the shares of common stock held by our current stockholders will be cancelled. Currently, there are no persons known to us who own more than 5% of the outstanding shares of common stock other than a group (as defined under Rule 13d-1 of the Exchange Act) comprised of RCG Carpathia Master Fund, Ltd. and SPhinX Distressed (RCG Carpathia), Segregated Portfolio, a segregated account of SPhinX Distressed Fund SPC, a Cayman Islands company, based solely on a Schedule 13G filed with the SEC on March 12, 2004 by Ramius Capital Group, LLC, the manager of the two entities. The Ramius entities stated in their Schedule 13G that collectively, they owned 5.52% of our outstanding shares of common stock.

Our "Named Executive Officers" include (a) our Chief Executive Officer; and (b) our four most highly compensated executive officers, other than the Chief Executive Officer, who were serving as executive officers at the end of fiscal year 2003; provided, however, that no disclosure need be provided

for any executive officer, other than the CEO, whose total annual salary and bonus does not exceed $100,000.

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

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

We have contractual arrangements with one other executive officer, Chief Financial Officer Brian B. Bird.

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

provides for severance if Mr. Austin is involuntarily terminated or otherwise as a result of the bankruptcy proceedings and indemnification by us for claims made in connection with his engagement as Chief Restructuring Officer. On September 4, 2004, Mr. Austin terminated his employment with NorthWestern and entered into a consulting agreement with us. This agreement, which was approved by the Bankruptcy Court, provides for Mr. Austin to be compensated based on an estimated 20 hour workweek, and provides him with a lump sum payment to cover the cost of COBRA coverage, reimbursement of travel and business related expenses and continued participation in his previously approved incentive compensation program.

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

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

Gary G. Drook became our chief executive officer on January 5, 2003. Mr. Drook does not have a written employment agreement with us. Mr. Drook received a cash payment of $600,000 on his date of hire. He will be required to repay 50% of that amount if his employment with us terminates before January 5, 2005. Mr. Drook's base salary in 2004 is $565,000 per year, and his target annual bonus is $423,750, or 75% of his base salary. Mr. Drook's annual bonus for 2003 and 2004 will be paid together in three payments of $282,000 as authorized by the Bankruptcy Court under our incentive compensation and severance plan. Bonus payments beyond 2004 will be determined by the Board. We believe that Mr. Drook's cash compensation in 2004 will be approximately $1,130,000. As part of his compensation arrangements, Mr. Drook is also allowed to use NorthWestern's aircraft for personal use as permitted under our Aircraft Use Policy. The cost to us related to Mr. Drook's use of our aircraft is treated as income to him and will not exceed 10% of Mr. Drook's annual compensation in 2004. Our Aircraft Use Policy also provides Mr. Drook with a tax gross up payment for all income related to personal aircraft usage. Mr. Drook is also eligible to participate in our health, welfare and retirement programs and relocation assistance.

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

On September 15, 2003, in connection with our Chapter 11 filing, the New York Stock Exchange (NYSE) suspended trading and subsequently delisted our common stock and all series of our trust preferred securities. On October 10, 2003, the SEC issued an order granting the application of the NYSE to delist our common stock and trust preferred securities.

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

On September 16, 2003, following first day hearings held on September 15, 2003, the Bankruptcy Court entered orders granting us authority to, among other things, pay prepetition and postpetition employee wages, salaries, benefits and other employee obligations, pay selected vendors and other providers for the postpetition delivery of goods and services, continue bank accounts and existing cash management system, and continue existing forward power contracts and enter into additional similar contracts in the ordinary course of business. On November 7, 2003, the Bankruptcy Court entered a final order to approve access of up to $85 million of the $100 million debtor-in-possession financing facility arranged by the company with Bank One, N.A. (DIP Facility). In December 2003, we reduced the commitment to $85 million under this facility. We further reduced this commitment to $75 million in April 2004 and $50 million in July 2004. The DIP Facility expires on December 31, 2004, and bears interest at a variable rate tied to the Eurodollar rate plus a spread of 3.00% or at the prime rate plus a spread of 1.00%. The DIP Facility will provide a source of liquidity during the course of our bankruptcy, but requires that we maintain certain other financial covenants and restricts liens, indebtedness, capital expenditures, dividend payments and sales of assets. As of June 30, 2004, we had $15.4 million in letters of credit outstanding and no borrowings under the DIP Facility.

We reached an agreement with the lenders holding claims under the CSFB Facility in October 2003 to reduce the interest rate of our $390 million prepetition credit facility. The amended credit facility provides advantages to NorthWestern, including lower interest expense and allowing reinstatement upon NorthWestern's emergence from Chapter 11. At NorthWestern's option, the amended credit facility bears interest at a variable rate tied to the Eurodollar rate, plus a spread of 5.50%, or at an alternate base rate, as defined by the amended credit facility, plus a spread of 3.50%.

There is no longer a minimum floor for the Eurodollar rate or the alternate base rate. As a result of this amendment, we estimate annualized interest expense will be reduced by approximately $6 million to $8 million.

The Chapter 11 filing triggered defaults, or termination events, on substantially all of our debt and lease obligations, and certain contractual obligations. As such, we have classified all of our secured debt as current as of June 30, 2004. Subject to certain exceptions under the Bankruptcy Code, our Chapter 11 filing automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against us or our property to recover on, collect or secure a claim arising prior to the Petition Date. Thus, for example, creditor actions to obtain possession of our property, or to create, perfect or enforce any lien against our property, or to collect on or otherwise exercise rights or remedies with respect to a prepetition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

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

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

The United States Trustee for the Bankruptcy Court appointed an official committee of unsecured creditors (Creditors' Committee). The Creditors' Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court and may take positions on matters that come before the Bankruptcy Court. There can be no assurance that the Creditors' Committee will support our positions or our plan of reorganization, and disagreements between us and the Creditors'

Committee could protract the Chapter 11 case, could negatively impact our ability to operate during the Chapter 11 case and could prevent our emergence from Chapter 11.

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

In addition, Avaya deposited approximately $13.5 million and $1.0 million into escrow accounts to satisfy certain specified liabilities that were not assumed by Avaya, and certain indemnification obligations of Netexit, respectively. Avaya also reduced cash paid at closing by approximately $44.6 million as a working capital adjustment, pending the determination of a final closing balance sheet. On February 24, 2004, Avaya submitted its proposed final calculation of the working capital adjustment asserting that there was a working capital shortfall at Expanets of approximately $48.8 million at closing, and claiming that Avaya should retain the entire holdback amount plus an additional $4.2 million. Netexit disputed this calculation. As a result of negotiations between Netexit and Avaya, the parties entered into a settlement on April 27, 2004 resulting in additional cash proceeds of $17.5 million paid by Avaya to Netexit. We recorded a gain related to this settlement of $11.5 million in the second quarter of 2004.

In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for Chapter 11 bankruptcy protection on May 4, 2004. Pending the resolution of open claims to Netexit creditors, the proceeds from the sale remain at Netexit and distributions to NorthWestern will be delayed until the bankruptcy proceedings are resolved. Although we anticipate receiving cash proceeds in excess of $40 million, if we encounter unexpected claims or costs relating to its wind-down of operations, our ability to receive any distributions from Netexit and our liquidity could be adversely affected.

Blue Dot sold 48 businesses during 2003, repaid its credit facility from sales proceeds and terminated the facility. As of June 30, 2004, Blue Dot had 4 remaining businesses. Blue Dot anticipates selling substantially all of its remaining businesses by December 31, 2004. We hope to receive in excess of $15 million in cash from Blue Dot during the liquidation of the operations; provided however, this assumes satisfactory resolutions to remaining stock obligations, potential or pending litigation, insurance and bonding reserves, and no new material additional claims or litigation. Furthermore, it assumes that the remaining businesses produce their projected cash proceeds and receivables from various sold locations are collectible.

We are also attempting to sell the Montana First Megawatts generation project. In an effort to facilitate the timely sale of the Montana First Megawatts project and its ultimate development at its

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

Upon consummation of our plan of reorganization, we expect to have an enterprise value of approximately $1.5 billion and equity value of approximately $710 million.

Upon entry of the order approving the second amended and restated disclosure statement, we began resoliciting acceptances and or rejections to the second amended and restated plan of reorganization from holders of our senior unsecured notes and trade vendor claims in excess of $20,000 and holders of TOPrS and QUIPs. A final hearing to consider confirmation of the second amended and restated plan was held by the Bankruptcy Court on October 6, 2004. On October 8, 2004, we received verbal confirmation of our plan of reorganization by the Bankruptcy Court and we anticipate that the Bankruptcy Court will enter a written order confirming our plan of reorganization in the immediate future.

Our plan of reorganization provides that it will become effective upon the satisfaction or waiver of the following conditions:

Parties who object to confirmation of our plan of reorganization have until ten days following the date of entry of our confirmation order by the Bankruptcy Court to file a notice of appeal from the written order confirming our plan of reorganization. Under applicable law, once our plan of reorganization has been "substantially consummated", any pending appeals from the confirmation order may be mooted.

										Twelve Months Ended June 30,
	Years Ended December 31,
($ in millions)	Years Ended December 31,
($ in millions)	2001			2002			2003			2004
INCOME STATEMENT DATA
Net income (loss)	$	44.5		$	(863.9	)	$	(113.7	)	$	(68.6	)
Plus (Minus):
Interest expense		27.7			98.0			147.6			110.4
(Gain) loss on debt extinguishment		—			20.7			(3.3	)		(3.3	)
Investment income and other		(7.1	)		5.5			6.0			5.9
Reorganization interest income		—			—			—			(0.2	)
Benefit for income taxes		(6.9	)		(39.8	)		(0.1	)		(0.8	)
Discontinued operations, net of taxes and minority interests		(40.3	)		854.5			42.1			30.9

Operating income	$	17.9		$	75.0		$	78.6		$	74.3
Plus:
Environmental charge		—			—			7.4			9.8
Incremental D&O insurance prior to emergence from bankruptcy		—			—			4.7			8.0
Impairment on assets held for sale		—			35.7			12.4			—
Depreciation and amortization		18.2			63.3			70.2			71.8
Restructuring charge		11.8			—			—			—
Reorganization professional fees & expenses		—			—			8.3			22.9

Adjusted EBITDA(1)	$	47.9		$	174.0		$	181.6		$	186.8

CASH FLOW DATA
Cash provided by (used in) operating activities	$	(125.3	)	$	(69.9	)	$	(93.9	)	$	119.2
Capital expenditures		(80.3	)		(147.8	)		(70.7	)		(69.4	)

			Years Ended December 31,									Six Months Ended June 30,						Twelve Months Ended June 30,
			2001			2002			2003			2003			2004			2004
												(unaudited)			(unaudited)			(unaudited)
			(in thousands)
INCOME STATEMENT DATA
Operating revenues			$	255,151		$	783,744		$	1,027,437		$	522,616		$	572,571		$	1,077,392
Cost of sales				145,568			341,526			550,589			284,457			336,529			602,661
Gross margin				109,583			442,218			476,848			238,159			236,042			474,731
Operating expenses
	Operating, general and administrative			61,730			268,218			307,258			146,537			145,021			305,742
	Impairment on assets held for sale			—			35,729			12,399			12,399			—			—
	Depreciation			17,923			63,240			70,252			34,855			36,418			71,815
	Amortization of goodwill and intangibles			269			19			—			—			—			—
	Restructuring charge			11,771			—			—			—			—			—
	Reorganization professional fees and expenses			—			—			8,280			—			14,605			22,885

		Total operating expenses		91,693			367,206			398,189			193,791			196,044			400,442

Operating income				17,890			75,012			78,659			44,368			39,998			74,289
Interest expense				(27,709	)		(98,010	)		(147,626	)		(81,181	)		(43,904	)		(110,349	)
Gain (loss) on debt extinguishment				—			(20,688	)		3,300			—			—			3,300
Investment income and other				7,134			(5,481	)		(5,977	)		1,155			1,204			(5,928	)
Reorganization interest income				—			—			14			—			144			158

Loss from continuing operations before income taxes				(2,685	)		(49,167	)		(71,630	)		(35,658	)		(2,558	)		(38,530	)
Benefit (provision) for income taxes				6,860			39,811			48			(501	)		271			820

Income (loss) from continuing operations				4,175			(9,356	)		(71,582	)		(36,159	)		(2,287	)		(37,710	)
Discontinued operations, net of taxes and minority interests				40,357			(854,586	)		(42,143	)		3,214			14,468			(30,889	)

Net income (loss)				44,532			(863,942	)		(113,725	)		(32,945	)		12,181			(68,599	)
Minority interests on preferred securities of subsidiary trusts				(6,827	)		(28,610	)		(14,945	)		(14,945	)		—			—
Dividends and redemption premium on preferred stock				(191	)		(391	)		—			—			—			—
Earnings (losses) on common stock				37,514			(892,943	)		(128,670	)		(47,890	)		12,181			(68,599	)

BALANCE SHEET DATA
Total assets		2,641,685		2,785,061		2,444,511		2,624,886		2,422,343		2,422,343
Long-term debt (including current portion)		767,794		1,668,431		919,392		1,787,210		912,384		912,384
Liabilities subject to compromise
	Financing debt	—		—		864,844		—		864,844		864,844
	Trade creditors	—		—		287,803		—		288,613		288,613
	Mandatorily redeemable preferred securities	187,500		370,250		365,550		370,250		365,550		365,550
Total shareholders' equity (deficit)		396,578		(456,076	)	(585,951	)	(503,942	)	(573,611	)	(573,611	)
CASH FLOW DATA
Cash provided by (used in) operating activities		(125,329	)	(69,864	)	(93,860	)	(89,833	)	123,130		119,103
Cash provided by (used in) investing activities		(80,728	)	(641,134	)	4,932		27,555		(30,394	)	(53,017	)
Cash provided by (used in) financing activities		200,193		732,592		77,557		86,213		(6,362	)	(15,018	)
Capital expenditures		(80,295	)	(147,847	)	(70,737	)	(31,826	)	(30,529	)	(69,440	)

			At June 30, 2004
			Actual			Pro Forma for Reorganization		As Adjusted for Reorganization and Transactions
						(in thousands) (unaudited)
Cash and cash equivalents			$	101,557		$	76,557	$	5,315

Debt:
New credit facility—Revolver			$	—		$	—	$	—	⁽¹⁾
New credit facility—Term Loan				—			—		125,000
Recently announced debt offering				—			—		200,000
Other secured debt				912,384			912,384		528,234
Unsecured debt				864,844			—		—
Junior subordinated debt				365,550			—		—

	Total debt		$	2,142,778		$	912,384	$	853,234
	Total stockholders' equity (deficit)			(573,611	)		710,000		695,782

		Total capitalization	$	1,569,167		$	1,622,384	$	1,549,016

			Year Ended December 31, 2003			Reorganization⁽¹⁾			Year Ended December 31, 2003 Pro Forma for Reorganization			Transactions⁽¹⁾			Year Ended December 31, 2003 Pro Forma for Reorganization and the Transactions⁽¹⁾
						(in thousands)
Operating revenues			$	1,027,437		$	—		$	1,027,437		$	—		$	1,027,437
Cost of sales				550,589						550,589						550,589

Gross margin				476,848			—			476,848			—			476,848
Operating expenses:
	Operating, general and administrative expenses			307,258						307,258						307,258
	Impairment on assets held for sale			12,399						12,399						12,399
	Depreciation			70,252						70,252						70,252
	Reorganization professional fees and expenses			8,280			(8,280	)⁽²⁾		—						—

		Total operating expenses		398,189			(8,280	)		389,909						389,909

Operating income				78,659			8,280			86,939						86,939
Interest (expense) income				(147,626	)		57,907	⁽³⁾⁽⁴⁾		(89,719	)		22,755	⁽⁵⁾		(66,964	)
Gain on debt extinguishment				3,300						3,300						3,300
Investment income and other				(5,977	)					(5,977	)					(5,977	)
Reorganization interest income				14			(14	)⁽²⁾		—						—

Income (loss) from continuing operations before income taxes				(71,630	)		66,173			(5,457	)		22,755			17,298
Benefit (provision) for income taxes				48			2,053	⁽⁶⁾		2,101			(8,761	)⁽⁶⁾		(6,660	)

Income (loss) from continuing operations			$	(71,582	)	$	68,226		$	(3,356	)	$	13,994		$	10,638

			Six Months Ended June 30, 2004			Reorganization⁽¹⁾			Six Months Ended June 30, 2004 Pro Forma for Reorganization			Transactions⁽¹⁾			Six Months Ended June 30, 2004 Pro Forma for Reorganization and the Transactions⁽¹⁾
						(in thousands)
Operating revenues			$	572,571		$	—		$	572,571		$	—		$	572,571

Cost of sales				336,529						336,529						336,529
Gross margin				236,042			—			236,042			—			236,042
Operating expenses:
	Operating, general and administrative expenses			145,021						145,021						145,021
	Depreciation			36,418						36,418						36,418
	Reorganization professional fees and expenses			14,605			(14,605	)⁽²⁾		—						—

		Total operating expenses		196,044			(14,605	)		181,439						181,439

Operating income				39,998			14,605			54,603						54,603
Interest (expense) income				(43,904	)					(43,904	)		7,667	⁽⁵⁾		(36,237	)
Investment income and other				1,204						1,204						1,204
Reorganization interest income				144			(144	)⁽²⁾		—						—

Income (loss) from continuing operations before income taxes				(2,558	)		14,461			11,903			7,667			19,570
Benefit (provision) for income taxes				271			(4,854	)⁽⁶⁾		(4,583	)		(2,952	)⁽⁶⁾		(7,535	)

Income (loss) from continuing operations			$	(2,287	)	$	9,607		$	7,320		$	4,715		$	12,035

			June 30, 2004			Reorganization⁽¹⁾			June 30, 2004 Pro Forma for Reorganization		Transactions⁽²⁾			June 30, 2004 Pro Forma for Reorganization and the Transactions
			(in thousands)
Assets
Current Assets:
Cash and cash equivalents			$	101,557		$	(25,000)	⁽³⁾	$	76,557	$	(71,242)	⁽¹³⁾	$	5,315
Restricted cash				21,199						21,199					21,199
Accounts receivable, net				79,632						79,632					79,632
Inventories				27,009						27,009					27,009
Regulatory assets				5,695						5,695					5,695
Prepaid energy supply				30,017						30,017					30,017
Prepaid and other				32,800						32,800					32,800
Assets held for sale				30,000						30,000					30,000
Current assets of discontinued operations				87,168						87,168					87,168

	Total current assets			415,077			(25,000	)		390,077		(71,242	)		318,835
Property, plant and equipment, net				1,364,632						1,364,632					1,364,632
Goodwill				375,798			64,648	⁽⁴⁾		440,446					440,446
Other:
Investments				9,313						9,313					9,313
Regulatory assets				201,664			38,125	⁽⁵⁾		239,789					239,789
Other				55,785			(24,252)	⁽⁶⁾		31,533		(11,026)	⁽¹³⁾		20,507
Noncurrent assets of discontinued operations				74						74					74

	Total Assets		$	2,422,343		$	53,521		$	2,475,864	$	(82,268	)	$	2,393,596

Liabilities and Shareholders' Equity
Current Liabilities:
Current maturities of long-term debt			$	912,384		$	(895,927)	⁽¹²⁾	$	16,457	$	(2,650)	⁽¹³⁾	$	13,807
Accounts payable				58,162						58,162					58,162
Accrued liabilities				108,899			6,431	⁽¹²⁾		115,330					115,330
Regulatory liabilities				1,793						1,793					1,793
Current liabilities of discontinued operations				12,309						12,309					12,309

	Total current liabilities			1,093,547			(889,496	)		204,051		(2,650	)		201,401
Long-term debt				—			895,927	⁽¹²⁾		895,927		(56,500)	⁽¹³⁾		839,427
Deferred income taxes				9,936			44,523	⁽⁷⁾		54,459		(8,900)	⁽⁷⁾		45,559
Noncurrent regulatory liabilities				158,857						158,857					158,857
Other noncurrent liabilities				214,150			237,963	⁽⁸⁾⁽¹²⁾		452,113					452,113
Noncurrent liabilities and minority interests of discontinued operations				457						457					457

	Total liabilities not subject to compromise			1,476,947			288,917			1,765,864		(68,050	)		1,697,814
Liabilities subject to compromise:
Financing debt				864,844			(864,844)	⁽⁹⁾		—					—
Trade creditors				288,613			(288,613)	⁽¹⁰⁾⁽¹²⁾		—					—
Company obligated mandatorily redeemable preferred securities of subsidiary trusts				365,550			(365,550)	⁽⁹⁾		—					—

	Total liabilities subject to compromise			1,519,007			(1,519,007	)		—		—			—
		Total liabilities		2,995,954			(1,230,090	)		1,765,864		(68,050	)		1,697,814
Shareholders' equity				(573,611	)		1,283,611	⁽¹¹⁾		710,000		(14,218)	⁽¹³⁾		695,782

		Total liabilities and shareholders' equity	$	2,422,343		$	53,521		$	2,475,864	$	(82,268	)	$	2,393,596

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

Income (Loss) before income taxes and minority interests	$	1,360		$	(422,802	)	$	(119,198	)
Estimated loss on disposal		(49,250	)		—			—
Minority interests		—			11,152			127,893
Income tax benefit (provision)		—			(22,780	)		32,190

Income (Loss) from discontinued operations, net of income taxes and minority interests	$	(47,890	)	$	(434,430	)	$	40,885

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

Income (Loss) before income taxes and minority interests	$	(3,356	)	$	(311,674	)	$	(17,392	)
Gain on disposal		14,352			—			—
Minority interests		—			3,762			13,555
Income tax benefit (provision)		—			(9,071	)		3,830

Income (Loss) from discontinued operations, net of income taxes and minority interests	$	10,996		$	(316,983	)	$	(7	)

	Total			2004		2005		2006		2007		2008		Thereafter
	(in thousands)
Debt Not Subject to Compromise:
Senior Secured Term Loan	$	384,150		$	1,950	$	3,900	$	378,300	$	—	$	—	$	—
South Dakota Mortgage Bonds, 7.00% and 7.10%		115,000			—		60,000		—		—		—		55,000
South Dakota Pollution Control Obligations, 5.85% and 5.90%		21,350			—		—		—		—		—		21,350
Montana First Mortgage Bonds, 7.00%, 7.30%, 8.25% and 8.95%		157,197			—		5,386		150,000		365		—		1,446
Discount on Montana First Mortgage Bonds		(3,326	)		—		—		—		—		—		(3,326	)
Montana Pollution Control Obligations, 6.125% and 5.90%		170,205			—		—		—		—		—		170,205
Montana Secured Medium Term Notes, 7.25%		13,000			—		—		—		—		13,000		—
Montana Natural Gas Transition Bonds, 6.20%		44,148			1,698		4,744		4,712		5,248		5,391		22,355
Capital leases⁽¹⁾		10,660			1,632		2,146		1,798		1,194		738		3,152

Total Debt Not Subject to Compromise		912,384			5,280		76,176		534,810		6,807		19,129		270,182
Debt Subject to Compromise⁽²⁾:
Senior Unsecured Notes, 7.875% and 8.75%		720,000			—		—		—		250,000		—		470,000
Senior Unsecured Debt, 6.95%		105,000			—		—		—		—		—		105,000
Montana Unsecured Medium Term Notes, 7.07%, 7.96% and 7.875%		40,000			—		—		15,000		—		—		25,000
Discount on Montana Unsecured Medium Term Notes		(156	)		—		—		—		—		—		(156	)

Total Debt Subject to Compromise		864,844			—		—		15,000		250,000		—		599,844
Total Mandatorily Redeemable Preferred Securities of Subsidiary Trusts⁽²⁾		365,550			—		—		—		—		—		365,550
Future Minimum Operating Lease Payments		211,078			16,568		32,894		32,587		32,298		32,279		64,452
Estimated Pension and Other Postretirement Obligations⁽³⁾		116,000			16,000		25,000		25,000		25,000		25,000		N/A
Qualifying Facilities (QFs) ⁽⁴⁾		1,792,128			54,823		56,579		58,468		60,634		62,931		1,498,693
Commodity Purchase Contracts⁽⁵⁾		1,295,857			201,603		275,109		214,973		148,809		95,081		360,282
Interest Payments on Existing Secured Debt		408,607			30,720		58,613		52,557		18,646		17,418		230,653

Total Commitments	$	5,966,448		$	324,994	$	524,371	$	933,395	$	542,194	$	251,838	$	3,389,656

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

Total Debt Not Subject to Compromise		919,392			11,643		76,519		535,031		7,045		19,129		270,025
Debt Subject to Compromise⁽²⁾:
Senior Unsecured Notes, 7.875% and 8.75%		720,000			—		—		—		250,000		—		470,000
Senior Unsecured Debt, 6.95%		105,000			—		—		—		—		—		105,000
Montana Unsecured Medium Term Notes, 7.07%, 7.96% and 7.875%		40,000			—		—		15,000		—		—		25,000
Discount on Montana Unsecured Medium Term Notes		(156	)		—		—		—		—		—		(156	)

Total Debt Subject to Compromise		864,844			—		—		15,000		250,000		—		599,844
Total Mandatorily Redeemable Preferred Securities of Subsidiary Trusts		365,550			—		—		—		—		—		365,550
Future Minimum Operating Lease Payments⁽³⁾		227,562			33,133		32,849		32,572		32,288		32,268		64,452
Estimated Pension and Other Postretirement Obligations⁽⁴⁾		116,000			16,000		25,000		25,000		25,000		25,000		N/A
Qualifying Facilities (QFs) ⁽⁵⁾		1,818,673			54,823		56,579		58,468		60,634		62,931		1,525,238
Commodity Purchase Contracts⁽⁶⁾		1,235,826			250,983		227,693		164,953		98,383		45,333		448,481
Interest Payments on Existing Secured Debt		439,327			61,440		58,613		52,557		18,646		17,418		230,653

Total Commitments	$	5,987,174		$	428,022	$	477,253	$	883,581	$	491,996	$	202,079	$	3,504,243

Name and Location of Plant	Fuel Source	Our Ownership Interest		Our Share of 2003 Peak Summer Demonstrated Capacity	% of Total 2003 Peak Summer Demonstrated Capacity
Big Stone Generating Station, located near Big Stone City in northeastern South Dakota	Sub-bituminous coal	23.4	%	106.58 megawatts	34.2%
Coyote I Electric Generating Plant, located near Beulah, North Dakota	Lignite coal	10.0	%	42.70 megawatts	13.7%
Neal Electric Generating Unit No. 4, located near Sioux City, Iowa	Sub-bituminous coal	8.7	%	55.90 megawatts	17.9%
Miscellaneous combustion turbine units and small diesel units (used only during peak periods)	Combination of fuel oil and natural gas	100.0	%	106.65 megawatts	34.2%

Total Capacity				311.83 megawatts	100.0%

Director Name	Principal Occupation or Employment	Term Expires	Director Since	Age on September 1, 2004
Marilyn R. Seymann	Interim Chairman of the NorthWestern Board of Directors since January 2003; and Chief Executive Officer of M ONE, Inc., a financial services consulting firm, since 1991; Member of the Boards of Directors of Beverly Enterprises, Inc. (NYSE: BEV), a healthcare service provider; and Community First Bankshares, a financial institution.	*2006*	*2000*	61
Lawrence J. Ramaekers	Director since May 2003; Formerly President and Chief Executive Officer (2002–2003) and Chief Restructuring Officer (2001–2002) of ANC Rental Corporation; member of AlixPartners (1982–2000), a turnaround management firm, serving as Chief Executive Officer of United Companies Financial Corporation, Umbro International, Inc., Medical Resources, Inc., Centennial Technologies, Inc., Color Tile, Inc., and Family Restaurants, Inc.	*2006*	*2003*	66
Randy G. Darcy	Senior Vice President, Operations of General Mills, Inc. (NYSE: GIS) a consumer foods company, since 1987.	*2004*	*1998*	53
Gary G. Drook	Chief Executive Officer of NorthWestern since January 2003; formerly President and Chief Executive Officer and Director of AFFINA, The Customer Relationship Company (formerly Ruppman Marketing Technologies, Inc.), a provider of customer services programs, since 1997; formerly President of Network Services (1994–1995) for Ameritech Corporation, a communications services provider.	*2004*	*1998*	59
Bruce I. Smith	Attorney and partner in the law firm of Leininger, Smith, Johnson, Baack, Placzek, Steele & Allen since 1978.	*2004*	*1989*	62

Jerry W. Johnson		Visiting Scholar, Congressional Budget Office, U.S. Congress since June 2002; former Dean Emeritus (2001–2002), Dean and Professor of Economics (1990–2001), School of Business, University of South Dakota; Member of the Boards of Directors of Citibank (S.D.), N.A., Citibank FSB and Citibank USA.		*2005*		*1994*		63
Larry F. Ness		Chairman and Chief Executive Officer of First Dakota Financial Corp., a bank holding company, and of First Dakota National Bank since 1996; formerly Vice Chairman and Chief Executive Officer of that bank (1993–1996).		*2005*		*1991*		59

Director Name	Principal Occupation or Employment	Term Expires	Director Since	Age on September 1, 2004
Stephen P. Adik	Vice Chairman of NiSource Inc. ("NiSource"), a large regulated electric and natural gas production, transmission and distribution company serving 3.7 million customers, from 2000 to 2003. NiSource Senior Executive Vice President, Chief Financial Officer and Treasurer from 1999 to 2000. NiSource Executive Vice President, Chief Financial Officer and Treasurer from 1994 to 1999. NiSource Vice President and General Manager—Corporate Support Group, from 1987 to 1994.	2005*	*2004*	61
E. Linn Draper, Jr.	Former Chairman, President and Chief Executive Officer of American Electric Power Company ("AEP"), one of the nation's largest public utility holding companies, since 1993. AEP President and Chief Operating Officer from 1992 to 1993. Chairman, President and Chief Executive Officer of Gulf States Utilities Company, a regulated utility, from 1987 to 1992. Serves on the Board of Directors for Sprint, Temple-Inland and Borden Chemicals and Plastics, LP.	2005*	*2004*	62

Phillip L. Maslowe		Non-executive Chairman of AMF Bowling Worldwide, Inc, the largest operators of bowling centers and providers of sporting goods, since 2002. Executive Vice President and Chief Financial Officer of The Wackenhut Corporation, a security, staffing and privatized prisons corporation, from 1997 to 2002. Executive Vice President and Chief financial Officer of Kindercare Learning Centers from 1993 to 1997. Serves on the Board of Directors for Mariner Health Inc.		2005*		*2004*		57
Corbin A. McNeill, Jr.		Former Chairman & Co-Chief Executive Officer of Exelon Corporation, one of the nation's largest utility companies (formed in the October 2000 merger of Peco Energy Company and Unicom Corporation), from 2000 to 2002. Chairman, President and Chief Executive Officer of Peco Energy from 1997 to 1999. Director, President and Chief Executive Officer of Peco Energy from 1995 to 1997. Director, President & Chief Operating Officer of Peco Energy from 1990 to 1995. Executive Vice President—Nuclear of Peco Energy from 1988 to 1990. Serves on the Board of Directors for Enron Corporation (having been recruited to the board as part of the company's bankruptcy reorganization in 2002) and Portland General Electric.		2005*		*2004*		65