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

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

Our Annual Report on Form 10-K, recent and forthcoming Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K and other SEC filings discuss some of the important risk factors that may affect our business, results of operations and financial condition.

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

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. Although we believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable, any or all of the forward-looking statements in this

Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions which turn out to be inaccurate or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of a forward-looking statement in this Quarterly Report on Form 10-Q or other public communications that we might make as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

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

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

		September 30, 2006			December 31, 2005
ASSETS
Current Assets:
Cash and cash equivalents	$	1,685		$	2,691
Restricted cash		15,792			25,238
Accounts receivable, net of allowance		89,212			160,856
Inventories		75,265			40,925
Regulatory assets		29,875			38,640
Prepaid energy supply		3,438			1,754
Other current assets		8,610			4,397
Assets held for sale		—			20,000
Deferred income taxes		24,640			10,520
Current assets of discontinued operations		—			8,472
Total current assets		248,517			313,493
Property, Plant, and Equipment, Net		1,482,210			1,409,205
Goodwill		435,076			435,076
Other:
Investments		1,182			1,297
Regulatory assets		190,833			204,466
Other		39,013			36,866
Total assets	$	2,396,831		$	2,400,403
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt and capital leases	$	7,809		$	156,455
Accounts payable		55,576			99,419
Accrued expenses		167,683			157,587
Regulatory liabilities		14,227			10,003
Current liabilities of discontinued operations		—			1,195
Total current liabilities		245,295			424,659
Long-term Capital Leases		40,910			2,725
Long-term Debt		694,030			583,790
Noncurrent Regulatory Liabilities		179,205			170,744
Deferred Income Taxes		132,199			100,192
Other Noncurrent Liabilities		363,604			380,798
Total liabilities		1,655,243			1,662,908
Commitments and Contingencies (Note 12)
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 35,847,109 and 35,522,644, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		358			358
Treasury stock at cost		(9,681	)		(5,573	)
Paid-in capital		725,214			721,240
Unearned restricted stock		(2,137	)		(383	)
Retained earnings		13,823			16,889
Accumulated other comprehensive income		14,011			4,964
Total shareholders’ equity		741,588			737,495
Total liabilities and shareholders’ equity	$	2,396,831		$	2,400,403

		Three Months Ended September 30,					Nine Months Ended September 30,

		2006			2005			2006				2005
OPERATING REVENUES	$	234,637		$	239,123		$	828,305		$	823,603
COST OF SALES		110,914			117,823			448,312			439,388
GROSS MARGIN		123,723			121,300			379,993			384,215
OPERATING EXPENSES
Operating, general and administrative		52,412			59,311			182,384			172,778
Property and other taxes		18,968			18,395			57,146			54,022
Depreciation		18,853			18,424			56,433			55,988
Reorganization items		—			2,901			—			7,021
TOTAL OPERATING EXPENSES		90,233			99,031			295,963			289,809
OPERATING INCOME		33,490			22,269			84,030			94,406
Interest Expense		(13,777	)		(14,924	)		(42,835	)		(47,024		)
Loss on Debt Extinguishment		—			—			—			(548		)
Other Income (Expense)		(397	)		5,365			8,020			7,562
Income From Continuing Operations Before Income Taxes		19,316			12,710			49,215			54,396
Income Tax Expense		(7,918	)		(3,411	)		(19,656	)		(20,330		)
Income From Continuing Operations		11,398			9,299			29,559			34,066
Discontinued Operations, Net of Taxes		—			(463	)		418			(10,243		)
Net Income	$	11,398		$	8,836		$	29,977		$	23,823
Average Common Shares Outstanding		35,510			35,643			35,535			35,620
Basic Earnings per Average Common Share
Continuing operations	$	0.32		$	0.26		$	0.83		$	0.96
Discontinued operations		0.00			(0.01	)		0.01			(0.29		)
Basic	$	0.32		$	0.25		$	0.84		$	0.67
Diluted Earnings per Average Common Share
Continuing operations	$	0.31		$	0.25		$	0.80		$	0.95
Discontinued operations		0.00			(0.01	)		0.01			(0.29		)
Diluted	$	0.31		$	0.24		$	0.81		$	0.66
Dividends Declared per Average Common Share	$	0.31		$	0.25		$	0.93		$	0.69

The accompanying notes to consolidated financial statements are an integral part of these statements.

	Nine Months Ended September 30,
		2006			2005
OPERATING ACTIVITIES:
Net Income	$	29,977		$	23,823
Items not affecting cash:
Depreciation		56,433			55,988
Amortization of debt issue costs, discount and deferred hedge gain		1,772			1,725
Amortization of restricted stock		1,880			4,768
Gain on qualifying facility contract amendment		—			(4,888	)
(Income) Loss from discontinued operations, net of taxes		(418	)		10,243
Gain on sale of assets		(2,292	)		(5,293	)
Gain on hedging activities		(4,772	)		—
Loss on debt extinguishment		—			548
Loss on reorganization items		—			2,600
Deferred income taxes		20,931			20,035
Proceeds from hedging activities		14,547			—
Changes in current assets and liabilities:
Restricted cash		(554	)		(2,462	)
Accounts receivable		70,777			47,222
Inventories		(34,340	)		(10,878	)
Prepaid energy supply costs		(1,684	)		27,198
Other current assets		(874	)		2,473
Accounts payable		(44,221	)		(19,726	)
Accrued expenses		20,347			40,971
Regulatory assets		12,732			(13,545	)
Regulatory liabilities		1,235			(3,950	)
Other noncurrent assets		9,510			(2,829	)
Other noncurrent liabilities		(15,499	)		(20,962	)
Cash provided by continuing operating activities		135,487			153,061
INVESTING ACTIVITIES:
Property, plant, and equipment additions		(75,399	)		(53,593	)
Proceeds from sale of assets		23,317			4,971
Proceeds from hedging activities		5,355			—
Purchases of investments		—			(118,800	)
Proceeds from sale of investments		—			123,478
Cash used in continuing investing activities		(46,727	)		(43,944	)
FINANCING ACTIVITIES:
Deferred gas storage		(11,718	)		2,154
Proceeds from exercise of warrants		340			91
Dividends on common stock		(33,043	)		(24,593	)
Repayment of long-term debt		(326,263	)		(174,782	)
Line of credit borrowings (repayments), net		(36,000	)		75,000
Treasury stock activity		(4,108	)		(2,585	)
Issuance of long term debt		320,205			—
Financing costs		(6,874	)		(2,143	)
Equity registration fees		—			(140	)
Cash used in continuing financing activities		(97,461	)		(126,998	)
DISCONTINUED OPERATIONS:
Operating cash flows of discontinued operations, net		(3,432	)		(10,977	)
Investing cash flows of discontinued operations, net		2,872			399
Financing cash flows of discontinued operations, net		—			—
(Increase) decrease in restricted cash held by discontinued operations		8,255			31,669
Increase (Decrease) in Cash and Cash Equivalents		(1,006	)		3,210
Cash and Cash Equivalents, beginning of period		2,691			17,058
Cash and Cash Equivalents, end of period	$	1,685		$	20,268

The accompanying notes to consolidated financial statements are an integral part of these statements.

We are one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 628,500 customers in Montana, South Dakota and Nebraska under the trade name “NorthWestern Energy.” We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have distributed electricity and natural gas in Montana since 2002.

The consolidated financial statements for the periods included herein have been prepared by NorthWestern Corporation (NorthWestern, we or us), pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. The unaudited consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Although management believes that the condensed disclosures provided are adequate to make the information presented not misleading, management recommends that these unaudited consolidated financial statements be read in conjunction with audited consolidated financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2005.

On April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with Babcock & Brown Infrastructure Limited (BBI), an infrastructure investment company listed on the Australian Stock Exchange, under which BBI will acquire NorthWestern Corporation in an all-cash transaction at $37 per share. Based upon the number of shares outstanding at April 25, 2006, the transaction is valued at approximately $2.2 billion, including the assumption of outstanding debt. The Merger Agreement has been unanimously approved by both companies’ Boards of Directors. Our shareholders approved the Merger Agreement at our August 2, 2006 annual meeting.

The Merger Agreement contains certain covenants whereby NorthWestern is required to continue to operate in the ordinary course of business and must obtain BBI’s consent prior to making certain new investments or divestitures, issuing new debt or common stock or making dividend changes, among other provisions.

The transaction is conditioned upon a number of federal and state regulatory approvals or reviews, and satisfaction of other customary closing conditions. We have received approvals or clearances from the following:

settlement agreement with the SDPUC and they will not oppose the transaction at the federal level if the terms of the agreement are satisfied. The SDPUC expects to make a decision on whether or not it has jurisdiction to approve the sale in December 2006. We anticipate receiving the MPSC’s decision during the first half of 2007. In addition, we must obtain the Federal Communication Commission’s approval, which we expect to occur during the first quarter of 2007.

The transaction is expected to be completed in 2007. Upon closing, NorthWestern’s common stock will cease to be publicly traded.

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 is an interpretation of FASB Statement No. 109, Accounting for Income Taxes, and it seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes by prescribing a recognition threshold and measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance on the derecognition, classification, accounting in interim periods and expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for us as of January 1, 2007. We are currently evaluating the impact that FIN 48 will have on our financial statements.

In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (SAB 108), to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires that we quantify misstatements based on their impact on each of our financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. We are currently evaluating the impact, if any, adopting SAB 108 will have on our financial statements.

In September 2006, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 157 Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The provisions of SFAS 157 are effective as of the beginning of our 2008 fiscal year. We are currently evaluating the impact, if any, adopting SFAS 157 will have on our financial statements.

In September 2006, the FASB issued SFAS No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R). SFAS 158 requires that we recognize the overfunded or underfunded status of our defined benefit and retiree medical plans (our Plans) as an asset or liability in our 2006 year-end balance sheet. Upon our emergence from bankruptcy in November 2004, we recognized a liability for the underfunded status of our Plans, therefore we do not expect the impact of adopting SFAS 158 to be significant. In addition, as we are able to recover these costs from customers, any change in our liability resulting from this standard will be reflected as a change in regulatory assets.

In December 2003, the FASB issued Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, or FIN 46R. FIN 46R was issued to replace FIN 46 and clarify the accounting for interests in variable interest entities. FIN 46R requires the consolidation of entities which are determined to be variable interest entities (VIEs) when the reporting company determines that it will absorb a majority of the VIE’s expected losses, receive a majority of the VIE’s residual returns, or both. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility, and while we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We will

continue to make appropriate efforts to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. We continue to account for this qualifying facility contract as an executory contract. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $550.5 million through 2025, and are included in Contractual Obligations and Other Commitments of Management’s Discussion and Analysis.

We have an electric default supply capacity and energy sale agreement with the owners of a natural gas fired peaking plant that began operating during the third quarter of 2006. In accordance with the agreement, we provide the natural gas necessary to meet demand, and purchase all of the net electrical capacity and output. In our assessment of this contract, we determined that it fits the criteria of a capital lease as set forth in Emerging Issues Task Force 01-8, Determining Whether an Arrangement Contains a Lease. Accordingly, during the third quarter of 2006 we recorded an increase to property, plant and equipment and a capital lease obligation of approximately $40.2 million, which represents the present value of future cash payments for the base capacity and facility charges under the contract.

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

Our regulated utility operations have, however, previously recognized removal costs of transmission and distribution assets as a component of depreciation in accordance with regulatory treatment. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities pursuant to Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulations. These amounts do not represent SFAS No. 143 legal retirement obligations. As of September 30, 2006 and December 31, 2005, we have recognized accrued removal costs of $151.1 million and $142.6 million, respectively. In addition, for our generation properties, we have accrued decommissioning costs since the generating units were first put into service in the amount of $13.2 million and $12.8 million as of September 30, 2006 and December 31, 2005, respectively.

In connection with the adoption of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), we have recorded a conditional asset retirement obligation of $3.5 million and $3.2 million, as of September 30, 2006 and December 31, 2005, respectively, which increases our property, plant and equipment and other noncurrent liabilities. This is primarily related to Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments. The initial recording of the obligation had no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the ARO is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. The change in our conditional ARO during the nine months ended September 30, 2006, is as follows (in thousands):

There were no changes in our goodwill during the three and nine months ended September 30, 2006. Goodwill by segment as of September 30, 2006 and December 31, 2005 is as follows (in thousands):

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006			2005
Net income	$	11,398		$	8,836	$	29,977		$	23,823
Other comprehensive income, net of tax:
Reclassification of net (gains) losses on hedging instruments from OCI to net income		266			—		(3,619	)		—
Unrealized gain (loss) on derivative instruments qualifying as hedges, net of tax		(150	)		5,392		12,587			3,882
Foreign currency translation		—			93		79			65
Comprehensive income	$	11,514		$	14,321	$	39,024		$	27,770

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

During the first quarter of 2006, based on a review of our capital structure and cash flow, and approval by our Board of Directors, we decided not to refinance $60 million included in the interest rate swap that was being carried on our revolver. As the refinancing transaction and associated interest payments will not occur, the market value included in AOCI of $3.8 million was recognized in Other Income. This forward starting interest rate swap was settled during the second quarter of 2006, and we received an aggregate payment of approximately $3.9 million, which is reflected in investing activities on the statement of cash flows.

In association with the refinancing transactions completed during the second and third quarters of 2006, we settled $170.2 million and $150 million of forward starting interest rate swap agreements, and received aggregate settlement payments of approximately $6.3 million and $8.3 million, respectively. These amounts are being amortized as a reduction to interest expense over the term of the underlying debt, which is 17 years and 10 years, respectively. The cash proceeds related to these hedges are reflected in operating activities on the statement of cash flows. As of September 30, 2006 we have no further interest rate swaps outstanding.

During the second quarter of 2005, we implemented a risk management strategy of utilizing put options in conjunction with our forward fixed price sales to manage our commodity price risk exposure associated with our lease of a 30% share of the Colstrip Unit 4 generation facility. These transactions were designated as cash-flow hedges of forecasted electric sales of approximately 120,000 MWh in each of the third and fourth quarters of 2006 under the provisions of SFAS No. 133, with unrealized gains and losses being recorded in AOCI in our Consolidated Balance Sheets. Due to changes in forward prices for electricity during the fourth quarter of 2005, we utilized unit-contingent forward sales to lock in the remaining output during the third and fourth quarters of 2006, and as a result we undesignated the put options as a hedge of the cash flow variability. During the first quarter of 2006 the put options were sold and we recognized a $1.3 million reduction to cost of sales, reflecting the change in market value since the loss of hedge effectiveness. These cash proceeds are reflected in investing activities on the statement of cash flows. During the third quarter of 2006, we reclassified unrealized losses of approximately $0.4 million into earnings related to the change in market value prior to the loss of hedge effectiveness. The amount remaining in AOCI at September 30, 2006, a net unrealized loss of $0.5 million, will be reclassified into earnings during the fourth quarter of 2006.

We currently operate our business in five reporting segments: (i) regulated electric operations, (ii) regulated natural gas operations, (iii) unregulated electric, (iv) unregulated natural gas, and (v) all other, which primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments. We evaluate the performance of these segments based on gross margin. Items below operating income are not allocated between our electric and natural gas segments. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments, excluding discontinued operations, are as follows (in thousands):

Three months ended		Regulated							Unregulated
September 30, 2006			Electric			Gas				Electric			Gas			Other				Eliminations				Total
Operating revenues	$	173,199		$	34,833			$	22,706		$	11,725		$	101			$	(7,927		)	$	234,637
Cost of sales		86,758			16,677				5,658			9,388			78				(7,645		)		110,914
Gross margin		86,441			18,156				17,048			2,337			23				(282		)		123,723
Operating, general and administrative		30,257			12,305				10,830			758			(1,439		)		(299		)		52,412
Property and other taxes		13,439			4,765				738			21			5				—				18,968
Depreciation		14,501			3,644				443			100			165				—				18,853
Total operating expenses		58,197			20,714				12,011			879			(1,269		)		(299		)		90,233
Operating income (loss)		28,244			(2,558		)		5,037			1,458			1,292				17				33,490
Total assets	$	1,545,714		$	727,499			$	52,495		$	46,828		$	24,295			$	—			$	2,396,831
Capital expenditures	$	18,814		$	9,562			$	1,596		$	92		$	—			$	—			$	30,064

Three months ended		Regulated					Unregulated
September 30, 2005		Electric		Gas			Electric		Gas		Other			Eliminations			Total
Operating revenues	$	165,288	$	33,302		$	26,764	$	30,172	$	115		$	(16,518	)	$	239,123
Cost of sales		82,297		15,960			8,878		26,860		52			(16,224	)		117,823
Gross margin		82,991		17,342			17,886		3,312		63			(294	)		121,300
Operating, general and administrative		32,467		14,557			9,762		1,058		1,761			(294	)		59,311
Property and other taxes		13,189		4,155			1,033		17		1			—			18,395
Depreciation		14,259		3,567			260		101		237			—			18,424
Reorganization items		—		—			—		—		2,901			—			2,901
Total operating expenses		59,915		22,279			11,055		1,176		4,900			(294	)		99,031
Operating income (loss)		23,076		(4,937	)		6,831		2,136		(4,837	)		—			22,269
Total assets	$	1,478,197	$	695,722		$	44,457	$	57,880	$	46,718		$	—		$	2,322,974
Capital expenditures	$	16,834	$	4,367		$	757	$	18	$	—		$	—		$	21,976

Nine Months ended		Regulated				Unregulated
September 30, 2006		Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	492,307	$	250,935	$	61,216	$	63,962	$	267		$	(40,382	)	$	828,305
Cost of sales		247,384		171,420		12,078		56,444		169			(39,183	)		448,312
Gross margin		244,923		79,515		49,138		7,518		98			(1,199	)		379,993
Operating, general and administrative		96,300		44,321		31,286		2,119		9,574			(1,216	)		182,384
Property and other taxes		40,171		14,351		2,538		66		20			—			57,146
Depreciation		43,464		10,946		1,148		301		574			—			56,433
Total operating expenses		179,935		69,618		34,972		2,486		10,168			(1,216	)		295,963
Operating income (loss)		64,988		9,897		14,166		5,032		(10,070	)		17			84,030
Total assets	$	1,545,714	$	727,499	$	52,495	$	46,828	$	24,295		$	—		$	2,396,831
Capital expenditures	$	52,845	$	18,197	$	4,259	$	98	$	—		$	—		$	75,399

Nine months ended		Regulated				Unregulated
September 30, 2005		Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	464,405	$	237,367	$	72,730	$	113,357	$	466		$	(64,722	)	$	823,603
Cost of sales		223,100		152,866		21,934		104,827		293			(63,632	)		439,388
Gross margin		241,305		84,501		50,796		8,530		173			(1,090	)		384,215
Operating, general and administrative		94,982		44,720		28,929		2,256		2,981			(1,090	)		172,778
Property and other taxes		38,043		13,240		2,662		72		5			—			54,022
Depreciation		42,906		11,206		782		303		791			—			55,988
Reorganization items		—		—		—		—		7,021			—			7,021
Total operating expenses		175,931		69,166		32,373		2,631		10,798			(1,090	)		289,809
Operating income (loss)		65,374		15,335		18,423		5,899		(10,625	)		—			94,406
Total assets	$	1,478,197	$	695,722	$	44,457	$	57,880	$	46,718		$	—		$	2,322,974
Capital expenditures	$	42,620	$	9,129	$	1,826	$	18	$	—		$	—		$	53,593

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

There were 4,603,071 warrants outstanding as of September 30, 2006, which are dilutive for the three and nine months ended September 30, 2006 and have been included in the earnings per share calculations. As of September 30, 2006 each warrant had an exercise price of $26.55 and could be exchanged for 1.07 shares of common stock. As of September 30, 2005, there were 4,617,076 warrants outstanding, which were dilutive for the three and nine months ended September 30, 2005 and included in the earnings per share calculation. Under the terms of the warrant agreement, the exercise price of the warrants is subject to adjustment from time to time, based on certain events. These events include additional share issuances and dividend payments. An adjustment is made in the case of a cash dividend if the amount of the cash dividend increases or decreases the exercise price by at least 1%, otherwise such amount is carried forward and taken into account with any subsequent cash dividend. Adjustments in the exercise price also require an adjustment in the number of shares covered by the warrants. A total of 12,849 warrants were exercised during the nine months ended September 30, 2006.

Net periodic benefit cost for our pension and other postretirement plans consists of the following for the three and nine months ended September 30, 2006 and 2005 (in thousands):

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
	2006			2005			2006			2005
Components of Net Periodic Benefit Cost
Service cost	$	2,262		$	2,133		$	185		$	172
Interest cost		5,198			5,044			693			713
Expected return on plan assets		(5,364	)		(5,087	)		(207	)		(140	)
Amortization of prior service cost		60			—			—			—
Net Periodic Benefit Cost	$	2,156		$	2,090		$	671		$	745

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
	2006			2005			2006			2005
Components of Net Periodic Benefit Cost
Service cost	$	6,787		$	6,399		$	555		$	516
Interest cost		15,593			15,132			2,081			2,139
Expected return on plan assets		(16,093	)		(15,261	)		(622	)		(420	)
Amortization of prior service cost		181			—			—			—
Net Periodic Benefit Cost	$	6,468		$	6,270		$	2,014		$	2,235

During the third quarter of 2006 we contributed approximately $18.0 million to our pension plans. We expect to contribute approximately $22.0 million to our pension plans during 2007.

In February 2005, the Board of Directors established an equity-based incentive plan with 700,000 shares, the NorthWestern Corporation 2005 Long-Term Incentive Plan (2005 LTIP), which provides for grants of stock options, share appreciation rights, restricted and unrestricted share awards, deferred share units and performance awards. The Human Resources Committee of our Board of Directors administers the 2005 LTIP.

In August 2006, the Board of Directors approved granting the remaining shares available under the 2005 LTIP. We expect to grant approximately 400,000 restricted shares in November with vesting schedules over the next five years, however these shares will vest immediately upon closing of the transaction with BBI.

We account for our service-based restricted stock awards using the fixed accounting method, whereby we amortize the value of the market price of the underlying stock on the date of grant to compensation expense over the service period. We reverse any expense associated with restricted stock that is canceled or forfeited during the performance or service period. Compensation expense recognized for restricted stock awards was $1.6 million and $1.9 million for the three and nine months ended September 30, 2006, respectively, as compared to $3.1 million and $4.8 million for the three and nine months ended September 30, 2005, respectively.

Summarized restricted stock activity, including the Special Recognition Grants issued upon emergence from bankruptcy, and annual broad based employee and Board of Director grants under the 2005 LTIP for the nine months ended September 30, 2006 is as follows:

On September 29, 2006 we submitted an informational filing to the MPSC outlining our cost of providing electric and natural gas delivery service in Montana. The informational filing is based on actual costs in 2005, adjusted for known and measurable cost changes that occurred in 2006 and is a result of a 2004 stipulation and settlement agreement between NorthWestern, the MPSC and the Montana Consumer Counsel. The filing demonstrates a revenue deficiency of approximately $29.1 million in electric rates and $12.3 million in natural gas rates: however, we did not seek a rate adjustment, as we would like the MPSC to give priority to its approval of the transaction with BBI.

On October 17, 2006, we filed an application with the FERC requesting an increase in transmission rates in Montana under the open access transmission tariff. While the request presents a net increase of $28.8 million in overall transmission costs, the rate adjustment pertains only to wholesale transmission and retail choice customers. Therefore, the portion of the requested cost increase pertaining to the remaining Montana retail customer loads, which represents approximately 70% of this increase, is subject to MPSC jurisdictional rates, and will not result in increased revenues. Since the last transmission rate adjustment, which was filed in March 1998, our cost of service has increased and the type of transmission service that we provide has changed as partial retail access has developed in Montana. The overall net effect of this filing for affected customers is expected to be an average increase of between 6 – 18%, depending on the type of customer.

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

In this regard, with respect to our leasehold interest in the Colstrip Unit 4 generation facility, on October 16, 2006, the Montana Board of Environmental Review gave final approval to the Montana rules placing limitations on mercury emissions from existing and new coal-fired electric generation facilities. These rules, which were published in the Montana Register on October 26, 2006 and became final as of October 27, 2006, will require material capital investment on the part of the Colstrip owners in order to bring the facility into compliance with the mercury limits set

forth in the rules. We are continuing to work with the other Colstrip owners to determine the ultimate financial impact of these new rules.

The range of exposure for environmental remediation obligations at present is estimated to range between $19.5 million to $56.1 million. Our environmental reserve accrual is $34.3 million as of September 30, 2006. We anticipate that as environmental costs become fixed and determinable we will seek insurance coverage and/or authorization to recover these costs in rates, therefore we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

Approximately $27.4 million of our environmental reserve accrual is related to manufactured gas plants. Two formerly operated manufactured gas plants located in Aberdeen and Mitchell, South Dakota, have been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS), list as contaminated with coal tar residue. At this time, we know that no material remediation is necessary at the Mitchell location and we are currently implementing a limited task list approved by the South Dakota Department of Environment and Natural Resources (SD DENR) in order to attain a No Further Action status for this location. We are currently investigating and characterizing the Aberdeen site pursuant to work plans approved by the SD DENR and some remedial activities commenced at the Aberdeen site in 2006. Our current reserve for remediation costs at the Aberdeen site is approximately $14.2 million, and we estimate that approximately $13.1 million of this amount will be incurred during the next five years.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. In August 2002, the Nebraska Department of Environmental Quality (NDEQ) conducted site-screening investigations at the Kearney and Grand Island locations for alleged soil and groundwater contamination. During 2004, the NDEQ conducted Phase I Environmental Site Assessments of the Kearney and Grand Island locations. During 2005, the NDEQ conducted Phase II investigations of soil and groundwater at these two locations. On March 30, 2006 and May 17, 2006, the NDEQ released to us the Phase II Limited Subsurface Assessment performed by the NDEQ’s environmental consulting firm for Kearney and Grand Island, respectively, and we are evaluating the results of these reports. We plan to conduct additional site investigation and assessment work at these locations in 2007. At present, we cannot determine with a reasonable degree of certainty the timing of any remediation cleanup at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require entry into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena sites, however, were placed into the MDEQ’s voluntary remediation program for cleanup due to the existence of exceedences of regulated pollutants in the groundwater. We conducted additional groundwater monitoring during 2005 at the Butte and Missoula sites and have analyzed the data and presented it to the MDEQ. At this time, we believe that natural attenuation should address the problems at these sites. However, additional groundwater monitoring will be necessary. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may be necessary to prevent certain contaminants from migrating offsite. We have evaluated the results of a pilot program meant to promote aerobic degradation of certain targeted contaminants. However, further data collection is necessary to complete the evaluation and assess other remediation technologies to determine the optimal remedial technology for this site. Monitoring of groundwater at this site will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the timing of additional remediation at the Helena site.

Based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and the potential to recoup some portion of prudently incurred remediation costs in rates, we do not expect remediation costs at these locations to be materially different from the established reserve.

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three megawatt generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. In April 2003, the Environmental Protection Agency (EPA) announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed partial removal of the contaminated sediments located within the Milltown Reservoir, together with the removal of the Milltown Dam and powerhouse (this remedy was incorporated into the EPA’s formal Record of Decision issued on December 20, 2004). In light of this pre-Record of Decision announcement, we entered into a stipulation (Stipulation) with Atlantic Richfield, the EPA, the Department of the Interior, the State of Montana and the Confederated Salish and Kootenai Tribes (collectively the Government Parties), which capped NorthWestern’s and CFB’s collective liability to Atlantic Richfield and the Government Parties at $11.4 million. In April 2006, we released escrowed amounts of $2.5 million and $7.5 million to the State of Montana and Atlantic Richfield, respectively, in accordance with the terms of the consent decree described below.

On July 18, 2005, CFB and we executed the Milltown Reservoir superfund site consent decree, which incorporated the terms set forth in the Stipulation. The consent decree was approved by the Federal District Court for the District of Montana on February 8, 2006 and became effective on April 10, 2006. In light of the material environmental risks associated with the catastrophic failure of the Milltown Dam, we secured a 10-year, $100 million environmental insurance policy, effective May 31, 2002, to mitigate the risk of future environmental liabilities arising from the structural failure of the Milltown Dam caused by an act of God. We are obligated under the settlement to continue to maintain the environmental insurance policy until the Milltown Dam is removed during implementation of the remedy.

We continue to manage polychlorinated biphenyl (PCB)-containing oil and equipment in accordance with the EPA’s Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

On April 16, 2004, Magten Asset Management Corporation (Magten) and Law Debenture Trust Company (Law Debenture) initiated an adversary proceeding, which we refer to as the QUIPS Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets and liabilities of CFB to us. In essence, Magten and Law Debenture are asserting that the transfer of the transmission and distribution assets acquired from the Montana Power Company was a fraudulent conveyance because such transfer left CFB insolvent and unable to pay certain claims. The plaintiffs also assert that they are creditors of CFB as a result of Magten owning a portion of the Series A 8.5% Quarterly Income Preferred Securities for which Law Debenture serves as the Indenture Trustee. Plaintiffs seek, among other things, the avoidance of the transfer of assets, declaration that the assets were fraudulently transferred and are not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets and the return of such assets to CFB. On September 29, 2006, the Delaware District Court, which has jurisdiction over this lawsuit, denied NorthWestern’s Motion for a Protective Order to limit the scope of discovery sought by plaintiffs, and thus discovery has commenced. We intend to vigorously defend against the QUIPS litigation.

On April 19, 2004, Magten also filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for alleged breaches of fiduciary duties by such officers in connection with the same transaction described above which is at issue in the QUIPS Litigation, namely the transfer of the transmission and distribution assets acquired from the Montana Power Company to NorthWestern. Those officers have requested CFB to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. That lawsuit was transferred to the Federal District Court in Delaware in July 2005 and is consolidated with the QUIPS Litigation for purposes of discovery and

On October 19, 2004, the Bankruptcy Court entered a written order confirming our Plan of Reorganization. On October 25, 2004, Magten filed a notice of appeal of such order seeking, among other things, a reversal of the Confirmation Order. In connection with this appeal, Magten’s efforts to obtain a stay of the enforcement of the Confirmation Order to prevent our Plan from becoming effective were denied by the Bankruptcy Court on October 25, 2004 and by the United States District Court for the District of Delaware on October 29, 2004. With no stay imposed, our Plan became effective November 1, 2004. On October 26, 2004, Magten filed a notice of appeal of the Bankruptcy Court’s approval of the memorandum of understanding (MOU), which memorialized the settlement of the consolidated securities class actions and consolidated derivative litigation against NorthWestern and others. In March 2005, we moved to dismiss Magten’s appeal of the Confirmation Order on equitable mootness grounds. Magten’s appeals of the Confirmation Order and the order approving the MOU were consolidated before the Delaware District Court. On September 29, 2006, the District Court granted NorthWestern's motion to dismiss Magten’s appeal of the Confirmation Order and affirmed the Bankruptcy Court’s order approving the MOU.

On February 9, 2005, we negotiated the terms of a proposed settlement with Magten and Law Debenture which would release and terminate all claims, pending actions and appeals, including the QUIPS Litigation, in exchange for which Magten and Law Debenture would receive a distribution of new common stock and warrants from Class 8(b) in the same amounts as if they had voted to accept the Plan and a distribution of the reserve of new common stock which had been set aside for them in the Class 9 Disputed Claims Reserve pursuant to NorthWestern’s Plan, in the amount of approximately $17.4 million at “Plan Value.” Prior to seeking approval from the Bankruptcy Court, certain major shareholders and the Plan Committee objected to the settlement on both its economic terms and on the basis that the structure of the settlement violated the Plan. After reviewing the objections and undertaking our own analysis of the potential Plan violation, we informed Magten and Law Debenture as well as the Plan Committee and the objecting major shareholders that we would not proceed with the settlement. Magten and Law Debenture therefore filed a motion with the Bankruptcy Court seeking approval of the settlement, which motion was denied by the Bankruptcy Court. On March 10, 2005, Magten and Law Debenture appealed the Bankruptcy Court's order to the District Court. The District Court affirmed the Bankruptcy Court’s order on September 29, 2006.

On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern Corporation, Gary Drook, Michael Hanson, Brian Bird, Thomas Knapp and Roger Schrum seeking to revoke the Confirmation Order on the grounds that it was procured by fraud as a result of the alleged failure to adequately fund the Class 9 Disputed Claims Reserve with enough shares of New Common Stock to satisfy a potential full recovery on all pending claims against NorthWestern’s bankruptcy estate which were outstanding at the time the Plan became Effective on November 1, 2004. The plaintiffs also alleged breach of fiduciary duty on the part of certain former and current officers in connection with the alleged under-funding of the Disputed Claims Reserve. NorthWestern filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of the Confirmation Order appeal. NorthWestern intends to seek dismissal of this action and to the extent such action is not dismissed, NorthWestern intends to vigorously defend this action.

Twice during 2005, Magten, Law Debenture, the Plan Committee and NorthWestern unsuccessfully engaged in mediation to resolve the pending appeals and other pending litigation described above. At this time, we cannot predict the impact or resolution of any of these actions or reasonably estimate a range of possible loss, which could be material. We intend to vigorously defend against the adversary proceedings, lawsuits, appeals and any subsequently filed similar litigation. While we cannot currently predict the impact or resolution of this litigation, the plaintiffs’ claims with respect to the QUIPs Litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the Class 9 Disputed Claims Reserve established under the Plan.

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

defendant due to the fact that we purchased The Montana Power L.L.C., which plaintiffs claim is a successor to the Montana Power Company.

In June 2006, we and the McGreevey plaintiffs entered into an agreement to settle the claims brought by the McGreevey plaintiffs in all of the actions stated above through a covenant not to execute by McGreevey plaintiffs against us and by us quit claiming any interest we had in any claims we may or may not have under any applicable directors and officers liability insurance policy, against any insurers for contractual or extracontractual damages, and against certain defendants in the McGreevey lawsuits. This agreement was preliminarily approved by the Bankruptcy Court in September 2006 and is subject to final hearing on the reasonableness of the settlement in November 2006. Once the Bankruptcy Court provides final approval, the settlement is still subject to approval by the Federal District Court. In the event such agreement is approved, the claims against us in the McGreevey lawsuits will be dismissed.

In November 2005, we and our directors were named as defendants in a shareholder class action and derivative action entitled City of Livonia Employee Retirement System v. Draper, et al., pending in the U.S. District Court for the District of South Dakota. The plaintiff claims, among other things, that the directors breached their fiduciary duties by not sufficiently negotiating with Montana Public Power Inc. and Black Hills Corporation, two entities that had made public, unsolicited offers to purchase NorthWestern. On April 26, 2006, Livonia amended its complaint to add allegations that our directors had erred in choosing the BBI offer because it was not the most attractive offer they had received for the company. The parties have entered into a settlement agreement which provides that NorthWestern will redeem the existing shareholder rights plan either following shareholder approval of the Merger Agreement with BBI or upon termination of the Merger Agreement with BBI – whichever occurs first. The Board may adopt a new shareholder rights plan if the shareholders approve adoption of such a plan in advance or, in the event that circumstances require timely implementation of such a plan, the Board seeks and receives approval from shareholders within 12 months after adoption. After limited confirmatory discovery, the settlement agreement has been filed and awaiting the federal court’s preliminary and final approval. Once the federal court provides preliminary approval, notice will be sent to all class members informing them of the terms of the settlement, their right to object and notice of the final hearing to approve the settlement. The plaintiffs’ lawyers will also have the right to seek an award of attorneys’ fees from the federal court. Once approved, the lawsuit filed by the City of Livonia Employees’ Retirement System would be dismissed. The settlement does not confer a financial award to either party and NorthWestern will contest any request for reimbursement of legal fees or other expenses related to this case.

In April 2005, a group of former employees of the Montana Power Company filed a lawsuit in the state court of Montana against us and certain officers styled Ammondson, et al. v. NorthWestern Corporation, et al., Case No. DV-05-97. The former employees have alleged that by moving to terminate their supplemental retirement contracts in our bankruptcy proceeding without having listed them as claimants or giving them notice of the disclosure statement and Plan, that we breached those contracts, and breached a covenant of good faith and fair dealing under Montana law and by virtue of filing a complaint in our Bankruptcy Case against those employees from seeking to prosecute their state court action against NorthWestern, we had engaged in malicious prosecution and should be subject to punitive damages. On May 4, 2005, the Bankruptcy Court found that it did not have jurisdiction over these contracts, dismissed our action against these former employees, and transferred our motion to terminate the contracts to Montana state court where the former employees’ lawsuit is pending. We unsuccessfully engaged in mediation of this dispute in November 2005 and September 2006. We recorded a loss of $2.6 million in the third quarter of 2005 to reestablish a liability for the present value of amounts due to these former employees under their supplemental retirement contracts and we have reestablished monthly payments to these former employees under the terms of their contracts. The former employees have also amended their complaint to add claims against our bankruptcy lawyers. We are engaged in discovery and anticipate a trial sometime in the first half of 2007. We intend to vigorously defend against this lawsuit; however we cannot currently predict the ultimate impact of this litigation.

In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern, NorthWestern Communications Solutions, Expanets and Blue Dot. Since December 2003, we have periodically received and continue to receive subpoenas and informal requests from the SEC requesting documents and testimony from former and current employees as well as third parties regarding these matters. In January 2006, the SEC issued Wells Notices to several former officers, a current

officer and a current employee, associated with NorthWestern and NorthWestern Communications Solutions. In July 2006, additional Wells Notices were issued to former officers and directors of NorthWestern and Expanets. A Wells Notice is an indication that the SEC staff has made a preliminary decision to recommend enforcement action that provides recipients with an opportunity to respond to the SEC staff before a formal recommendation is finalized. There have been no findings or adjudication of the underlying allegations in the Wells Notices, and the SEC’s investigation is ongoing and it could issue additional Wells Notices. In addition, certain of our former directors and several former and current employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the FBI and IRS concerning certain of the allegations made in the now resolved class action securities and derivative litigation as well as other matters. We have not been advised that NorthWestern is the subject of any FBI or IRS investigation. We are not aware of any other governmental inquiry or investigation related to these matters. We are fully cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are requested to do so in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome but we continue to work toward a resolution of the investigation. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, as a result of a ruling by the Bankruptcy Court, the SEC may not be able to pursue civil sanctions, including, but not limited to, monetary penalties against NorthWestern. The SEC did not appeal such order within the allowed appeal period. The SEC could, however, pursue other remedies and penalties against NorthWestern.

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

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

During the second quarter of 2006 we issued $170.2 million of Montana Pollution Control Obligations (PCOs) at a fixed interest rate of 4.65%, and used the proceeds to redeem our 6.125%, $90.2 million and 5.90%, $80.0 million Montana pollution control obligations due in 2023. Consistent with our historical regulatory treatment, the remaining deferred financing costs of approximately $3.8 million were recorded as a regulatory asset and will be amortized over the remaining life of the debt. The new PCOs will mature on August 1, 2023, and are secured by our Montana electric and natural gas assets. This transaction will reduce our annual interest expense by approximately $2.4 million.

During the third quarter of 2006 we issued $150 million of Montana First Mortgage Bonds at a fixed interest rate of 6.04% and used the proceeds to redeem our 7.30%, $150 million Montana first mortgage bonds due December 1, 2006. Consistent with our historical regulatory treatment, the remaining deferred financing costs and prepayment penalty of $0.8 million were recorded as a regulatory asset and will be amortized over the remaining life of the debt. The new first mortgage bonds will mature September 1, 2016, and are secured by our Montana electric and natural gas assets. This transaction will reduce our annual interest expense by approximately $1.9 million.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

NorthWestern Corporation, doing business as Northwestern Energy, is one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 628,500 customers in Montana, South Dakota and Nebraska. For an in-depth discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended December 31, 2005.

As discussed in Note 1 to the Consolidated Financial Statements, on April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with Babcock & Brown Infrastructure Limited (BBI) to acquire NorthWestern Corporation in an all-cash transaction at $37 per share. Based upon the number of shares outstanding at April 25, 2006, the transaction is valued at approximately $2.2 billion, including the assumption of outstanding debt. The Merger Agreement has been unanimously approved by both companies’ Boards of Directors. Our shareholders approved the Merger Agreement at our August 2, 2006 annual meeting.

We must still obtain approvals of the Montana Public Service Commission (MPSC) and the South Dakota Public Utilities Commission (SDPUC). We have submitted filings to each of these Commissions and they are currently reviewing the transaction. Due to existing statutory language in South Dakota, our filing requests the SDPUC to determine if it has jurisdiction over the sale and, if so, for transaction approval. In July, the SDPUC filed a notice with FERC that it intended to intervene and file a protest in the federal proceedings. In October, we reached a settlement agreement with the SDPUC and they will not oppose the transaction at the federal level if the terms of the agreement are satisfied. The SDPUC expects to make a decision on whether or not it has jurisdiction to approve the sale in December 2006. We anticipate receiving the MPSC’s decision during the first half of 2007. In addition, we must obtain the Federal Communication Commission’s approval, which we expect to occur during the first quarter of 2007.

The transaction is expected to be completed in 2007. Upon closing, NorthWestern’s common stock will cease to be publicly traded. Although we believe that the expectation as to timing for the closing of the merger is reasonable, no assurances can be given as to the timing of the receipt of any required regulatory approvals or that all regulatory approvals will be received.

We have incurred and expect to continue to incur advisor and professional fees associated with the transaction. Our operating results for the three and nine months ended September 30, 2006 were significantly affected by these transaction costs. This includes a $4.3 million initial payment to our strategic advisor for services related to the transaction with BBI, and an additional $4.3 million payment after our shareholders approved the proposed transaction. Under the terms of the agreement with our strategic advisor we will be required to pay an additional $8.6 million upon consummation of the proposed transaction.

In addition, in August 2006, the Board of Directors approved granting the remaining shares available under our 2005 Long-Term Incentive Plan. We expect to grant approximately 400,000 shares in November 2006 with vesting terms over the next five years, however all unvested shares will vest immediately upon closing of the transaction with BBI. If the transaction is completed in 2007 as anticipated, our 2007 stock-based compensation expense will be approximately $16 million.

Other operational and financial highlights for the three months ended September 30, 2006 include:

The following is a summary of our results of operations for the three month and nine month periods ended September 30, 2006 and 2005. 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.

Three Months Ended September 30, 2006 Compared to the Three Months Ended September 30, 2005

	Three Months Ended September 30,
			2006				2005				Change			% Change
	(in millions)
Operating Revenues
Regulated Electric		$		173.2		$		165.3		$		7.9			4.8		%
Regulated Natural Gas				34.9				33.3				1.6			4.8
Unregulated Electric				22.7				23.5				(0.8	)		(3.4	)
Unregulated Natural Gas				11.7				30.2				(18.5	)		(61.3	)
Other				—				—				—			—
Eliminations				(7.9	)			(13.2	)			5.3			40.2
		$		234.6		$		239.1		$		(4.5	)		(1.9	)	%

		Three Months Ended September 30,
				2006				2005				Change			% Change
		(in millions)
	Cost of Sales
Regulated Electric			$		86.8		$		82.3		$		4.5			5.5		%
Regulated Natural Gas					16.7				16.0				0.7			4.4
Unregulated Electric					5.7				5.6				0.1			1.8
Unregulated Natural Gas					9.4				26.9				(17.5	)		(65.1	)
Other					—				—				—			—
Eliminations					(7.7	)			(13.0	)			5.3			40.8
			$		110.9		$		117.8		$		(6.9	)		(5.9	)	%

		Three Months Ended September 30,
				2006						2005						Change					% Change
		(in millions)
Gross Margin
Regulated Electric			$			86.4			$			83.0			$			3.4				4.1			%
Regulated Natural Gas						18.2						17.3						0.9				5.2
Unregulated Electric						17.0						17.9						(0.9		)		(5.0		)
Unregulated Natural Gas						2.3						3.3						(1.0		)		(30.3		)
Other						—						—						—				—			%
	Eliminations						(0.2	)					(0.2	)					—				—
					$		123.7				$		121.3				$		2.4				2.0			%

Consolidated gross margin for the three months ended September 30, 2006 was $123.7 million, an increase of $2.4 million, or 2.0%, over gross margin of $121.3 million in 2005. Margin in our regulated electric segment increased $3.4 million primarily due to higher transmission revenue and increased retail volumes. The $0.9 million increase in regulated natural gas margin is primarily due to higher transportation, distribution, and storage revenue. Unregulated electric margin decreased $0.9 million primarily due to lower volumes resulting from unplanned outages. Unregulated natural gas gross margin decreased $1.0 million due to a combination of factors, including the amendment of a gas supply and management services contract, lower volumes and a $0.3 million refund of transportation charges during the three months ended September 30, 2005.

Margin as a percentage of revenues increased to 52.7% for 2006, from 50.7% for 2005. Gross margin as a percentage of revenue is primarily impacted by the fluctuations that occur in regulated electric and natural gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Consolidated operating, general and administrative expenses were $52.4 million for the three months ended September 30, 2006 as compared to $59.3 million in 2005. This decrease was primarily due to an insurance settlement

of $9.3 million received during the third quarter of 2006. The settlement related to an insurance coverage dispute over a settlement that occurred in 2002. Partly offsetting this decrease was approximately $5.8 million in transaction related costs pursuant to the proposed BBI acquisition. While an acquiring entity typically capitalizes its acquisition related costs, the transaction costs incurred by an acquiree are expensed as incurred. These costs during the third quarter of 2006 included payment of a $4.3 million transaction fee to our strategic advisor after our shareholders approved the proposed transaction. Under the terms of our agreement with our strategic advisor we will be required to pay an additional $8.6 million upon consummation of the proposed transaction. Since this additional payment is contingent on consummation of the transaction, it will be expensed in the period the transaction occurs. Other items impacting operating, general and administrative expense were increased pension expense of $2.3 million, offset by a $2.4 million decrease in stock-based compensation and short-term incentive expense, as well as a $2.6 million reduction in legal and professional fees.

The increase to pension expense is based on new funding projections over the next five years. In Montana, we have a regulatory order that authorizes us to recognize pension costs based on an average of the funding to be made over a five-year period for the calendar years 2005 through 2009. Based on our new funding projections, our 2006 annual pension expense will be higher than 2005 pension expense by approximately $3.1 million.

Property and other taxes were $19.0 million for the three months ended September 30, 2006 as compared to $18.4 million in 2005. This increase was primarily due to a higher valuation assessment in our Montana service territory. Property tax expense has been estimated based on the latest valuation assessment and our estimate of mill levy increases. We expect to receive our 2006 Montana property tax statements in November and we will adjust our estimated expense to actual during the fourth quarter of 2006. We have seen significant increases in our Montana property taxes since 2003 due primarily to increasing valuation assessments of our property by the Montana Department of Revenue. We have paid a portion of our 2005 property taxes under protest and are currently appealing our 2005 valuation before the State Tax Appeal Board in Montana. We recognized our 2005 property tax expense based on the total amount paid (including the payment under protest), so if we are successful with our appeal, we will recognize a reduction of property tax expense in the period the appeal is resolved.

Under Montana law, utilities are allowed to reflect changes in state and local taxes and fees, and to track these changes such that the actual level of taxes and fees are recovered. This should mitigate our exposure to the increases in property taxes discussed above; however, the MPSC has only authorized recovery of approximately 60% of the increase in our local taxes for both 2005 and 2006, as compared to the amount of these taxes included in our last general rate case in 1999. We have filed a Petition for Judicial Review in Montana District Court seeking to recover 100% of the increase in these taxes, however we cannot currently predict an outcome.

Depreciation expense was $18.8 million for the three months ended September 30, 2006 as compared to $18.4 million in 2005.

Reorganization items in 2005 of $2.9 million consisted of bankruptcy related professional fees and expenses. While we continued to incur professional fees during 2006 associated with various legal proceedings that must be resolved before our bankruptcy case can be closed, these costs are included in operating, general and administrative expenses. The reorganization expenses for the three months ended September 30, 2005 included a $2.6 million loss associated with the reestablishment of a liability that was removed from our balance sheet upon emergence from bankruptcy for contracts of former Montana Power Company employees.

Consolidated operating income for the three months ended September 30, 2006 was $33.5 million, as compared to $22.3 million in 2005. This $11.2 million increase was primarily due to changes in operating expenses discussed above and increased gross margin of $2.4 million.

Consolidated interest expense for the three months ended September 30, 2006 was $13.8 million, a decrease of $1.1 million, or 7.4%, from 2005. This decrease was primarily attributable to a $94 million decrease in debt in 2005. We anticipate additional reductions in interest expense during the remainder of 2006 due to our debt reduction efforts and lower rates as a result of refinancing transactions. See “Liquidity and Capital Resources” for additional information regarding our refinancing activities.

Consolidated other expense for the three months ended September 30, 2006 was $0.4 million, as compared to other income of $5.4 million in 2005. This decrease was primarily due to a $4.7 million gain from the sale of sulfur dioxide (SO2) emission allowances in 2005.

Consolidated provision for income taxes for the three months ended September 30, 2006 was $7.9 million as compared to $3.4 million in 2005. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

Consolidated net income for the three months ended September 30, 2006 was $11.4 million, an increase of $2.6 million, or 29.5%, over $8.8 million in 2005. This improvement was primarily due to an $8.8 million decline in operating expenses due largely to the receipt of a $9.3 million insurance settlement, a $2.4 million improvement in gross margin, and a $1.2 million decrease in interest expense. These improvements were offset by a $5.8 million decline in other income due primarily to a $4.7 million gain on the sale of SO2 emission allowances in the third quarter of 2005 and an increase in tax expense of $4.5 million due to increase in pre-tax income for the quarter ended Sept. 30, 2006.

Nine Months Ended September 30, 2006 Compared to the Nine Months Ended September 30, 2005

		Nine Months Ended September 30,
				2006				2005				Change			% Change
		(in millions)
Operating Revenues
	Regulated Electric		$		492.3		$		464.4		$		27.9			6.0		%
	Regulated Natural Gas				250.9				237.4				13.5			5.7
	Unregulated Electric				61.2				64.2				(3.0	)		(4.7	)
	Unregulated Natural Gas				63.9				113.3				(49.4	)		(43.6	)
	Other				0.3				0.5				(0.2	)		(40.0	)
	Eliminations				(40.3	)			(56.2	)			15.9			28.3
			$		828.3		$		823.6		$		4.7			0.6		%

	Nine Months Ended September 30,
			2006			2005				Change			% Change
			(in millions)
Cost of Sales
Regulated Electric		$		247.4		$	223.1		$		24.3			10.9		%
Regulated Natural Gas				171.4			152.9				18.5			12.1
Unregulated Electric				12.1			13.4				(1.3	)		(9.7	)
Unregulated Natural Gas				56.4			104.8				(48.4	)		(46.2	)
Other				0.2			0.3				(0.1	)		(33.3	)
Eliminations				(39.2	)		(55.1	)			15.9			28.9
		$		448.3		$	439.4		$		8.9			2.0		%

		Nine Months Ended September 30,
							2006					2005					Change				% Change
				(in millions)
Gross Margin
Regulated Electric			$			244.9			$		241.3			$		3.6				1.5				%
Regulated Natural Gas						79.5					84.5					(5.0		)		(5.9		)
Unregulated Electric						49.1					50.8					(1.7		)		(3.3		)
Unregulated Natural Gas						7.5					8.5					(1.0		)		(11.8		)
Other						0.1					0.2					(0.1		)		(50.0		)
	Eliminations						(1.1	)				(1.1	)				—				—
					$		380.0			$		384.2			$		(4.2		)		(1.1		)		%

Consolidated gross margin for the nine months ended September 30, 2006 was $380.0 million, a decrease of $4.2 million, or 1.1%, from gross margin of $384.2 million in 2005. The decrease in regulated natural gas margin is primarily due to the inclusion of a $4.6 million recovery of supply costs during the second quarter of 2005 that was previously disallowed by the MPSC. The regulated electric gross margin increase in 2006 was primarily due to increased transmission revenues and retail volumes offset by the following items. During March 2006, we signed a stipulation with the Montana Consumer Counsel (MCC) to settle various issues raised relative to our 2005 and 2006 electric tracker filings. As a result of this stipulation we are responsible for replacement costs related to certain forward sales contracts for periods after July 1, 2005. These forward sales extend through 2007. We recognized a loss in cost of sales of $1.4 million during the first quarter of 2006 related to the removal of replacement costs from our electric tracker for these sales contracts between July 1, 2005 and March 31, 2006. Additionally, regulated electric cost of sales includes a $2.9 million loss based on the market value of the remaining forward sales through 2007. Regulated electric results for the nine months ended September 30, 2005 also included a $4.9 million gain related to a QF contract amendment.

Margin as a percentage of revenues decreased to 45.9% for the nine months ended September 30, 2006, as compared to 46.7% for 2005. Gross margin as a percentage of revenue is primarily impacted by the fluctuations that occur in regulated electric and natural gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Consolidated operating, general and administrative expenses were $182.4 million for the nine months ended September 30, 2006 as compared to $172.8 million in 2005. The $9.6 million increase was primarily due to $13.3 million in transaction related costs pursuant to the proposed BBI acquisition and $2.6 million in higher legal and professional fees associated with assessing our strategic alternatives and addressing outstanding litigation. In addition, we incurred approximately $2.5 million in increased operating costs primarily due to increased line clearance, maintenance and fuel costs. Our pension expense increased $2.3 million and we increased our bad debt expense by $1.6 million due to increases in past due customer balances. The receipt of $9.3 million from an insurance settlement and a $4.3 million reduction in stock-based compensation and short-term incentive expense partially offset these increases.

Property and other taxes were $57.2 million for the nine months ended September 30, 2006 as compared to $54.0 million in 2005. This increase was primarily due to a higher valuation assessment in our Montana service territory, as discussed in more detail in the quarterly results above.

Depreciation expense was $56.4 million for the nine months ended September 30, 2006 as compared to $56.0 million in 2005.

Reorganization items in 2005 of $7.0 million consisted of bankruptcy related professional fees and expenses. While we continue to incur professional fees during 2006 associated with various legal proceedings that must be resolved before our bankruptcy case can be closed, these costs are included in operating, general and administrative expenses. As discussed above, the expenses for the nine months ended September 30, 2005 includes a $2.6 million loss for the reestablishment of a liability that was removed from our balance sheet upon emergence from bankruptcy.

Consolidated operating income for the nine months ended September 30, 2006 was $84.0 million, as compared to $94.4 million in 2005. This $10.4 million decrease was primarily due to lower margins and increased expenses discussed above.

Consolidated interest expense for the nine months ended September 30, 2006 was $42.8 million, a decrease of $4.2 million, or 8.9%, from 2005. This decrease was primarily attributable to a $94 million decrease in debt in 2005. We anticipate additional reductions in interest expense during the remainder of 2006 due to our debt reduction efforts and lower rates as a result of refinancing transactions. See “Liquidity and Capital Resources” for additional information regarding our refinancing activities.

Consolidated loss on extinguishment of debt of $0.5 million for the nine months ended September 30, 2005 resulted from an early principal payment of $25.0 million on our senior secured term loan B on April 22, 2005.

Consolidated other income for the nine months ended September 30, 2006 was $8.0 million, an increase of $0.4 million from 2005. This increase was primarily due to a $3.9 million gain related to an interest rate swap and a $2.3 million gain on the sale of a partnership interest in oil and gas properties in May 2006. We have no further significant interests in oil and gas properties. Partially offsetting this increase was a $4.7 million gain from the sale of excess SO2 emission allowances in 2005.

Consolidated income tax provision for the nine months ended September 30, 2006 was $19.7 million as compared to $20.3 million in 2005. Our effective tax rate for 2006 was 39.2% as compared to 37.3% for 2005. Portions of our acquisition related fees are non-deductible for taxes, which will increase our effective tax rate in 2006. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

Income from discontinued operations for the nine months ended September 30, 2006 was $0.4 million compared to a loss of $10.2 million for the same period in 2005. The income in 2006 related to the final liquidation of Netexit, while the 2005 loss primarily related to a settlement reached with securities class action claimants in Netexit’s bankruptcy proceedings.

Consolidated net income for the nine months ended September 30, 2006 was $30.0 million compared to $23.8 million for the same period in 2005. This improvement was primarily related to the change in discontinued operations, higher other income and a decrease in interest expense and income taxes. Increased operating expenses and decreased margins partially offset this improvement.

Three Months Ended September 30, 2006 Compared to the Three Months Ended September 30, 2005

			Results
			2006				2005				Change			% Change
			(in millions)
	Electric supply revenue	$		83.0		$		76.1		$		6.9			9.1		%
	Transmission & distribution revenue			75.0				74.3				0.7			0.9
	Rate schedule revenue			158.0				150.4				7.6			5.1
	Transmission			10.8				10.3				0.5			4.9
	Wholesale			2.4				2.8				(0.4	)		(14.3	)
	Miscellaneous			2.0				1.8				0.2			11.1
	Total Revenues			173.2				165.3				7.9			4.8		%
	Supply costs			82.8				75.6				7.2			9.5
	Wholesale			0.9				0.8				0.1			12.5
	Other cost of sales			3.1				5.9				(2.8	)		(47.5	)
	Total Cost of Sales			86.8				82.3				4.5			5.5		%
	Gross Margin	$		86.4		$		83.0		$		3.4			4.1		%
% GM/Rev			49.9		%		50.2		%

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

Electric rate schedule revenue for the three months ended September 30, 2006 increased $7.6 million, or 5.1% over results in 2005, primarily due to $3.4 million, or 6.1%, higher average prices and a $3.3 million, or 2.4%, increase in volumes due to customer growth and warmer weather. This increase in volumes was also the primary cause of the transmission and distribution revenue increase.

Transmission revenue consists of revenue earned for transmitting energy across our lines for customers who select other suppliers and for off-system, or open access, customers. Transmission revenues in Montana can fluctuate substantially from year to year based on market conditions in surrounding states. For example, if energy costs are substantially higher in California than in states to our east, suppliers may realize more profit by transmitting electricity across our lines into the California market than by buying electricity within California. We refer to these differences as price differentials. These price differentials caused the $0.5 million, or 4.9%, increase in transmission revenue.

Wholesale revenue is derived from our joint ownership in generation facilities. Excess power not used by our South Dakota customers is sold in the wholesale market. These revenues decreased $0.4 million, or 14.3%, primarily due to a $0.6 million, or 22.9%, decrease in average prices partially offset by $0.2 million, or 10.3% higher volumes sold in the secondary markets.

Gross margin for the three months ended September 30, 2006 increased $3.4 million, or 4.1% as compared to the second quarter 2005 primarily due to higher transmission revenue and increased retail volumes.

Margin as a percentage of revenues decreased to 49.9% for 2006, from 50.2% for 2005 due to the items discussed above. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Regulated retail electric volumes for the three months ended September 30, 2006 totaled 2,592,823 MWHs, which increased 2.4% as compared with 2,532,070 MWHs in the same period in 2005 due to a combination of customer growth and warmer weather. Regulated wholesale electric volumes in the third quarter of 2006 were 64,194 MWHs, an increase from 57,579 MWHs in the same period in 2005 primarily due to higher generation plant availability with less down time for maintenance.

Nine Months Ended September 30, 2006 Compared to the nine Months Ended September 30, 2005

			Results
			2006				2005					Change			% Change
			(in millions)
	Electric supply revenue	$			231.4		$		212.4		$		19.0			8.9		%
	Transmission & distribution revenue				213.3				210.9				2.4			1.1
	Rate schedule revenue				444.7				423.3				21.4			5.1
	Transmission				34.6				28.8				5.8			20.1
	Wholesale				6.8				6.9				(0.1	)		(1.4	)
	Miscellaneous				6.2				5.4				0.8			14.8
	Total Revenues				492.3				464.4				27.9			6.0		%
	Supply costs				234.0				205.8				28.2			13.7
	Wholesale				2.4				2.2				0.2			9.1
	Other cost of sales				11.0				15.1				(4.1	)		(27.2	)
	Total Cost of Sales				247.4				223.1				24.3			10.9		%
	Gross Margin	$			244.9		$		241.3		$		3.6			1.5		%
% GM/Rev				49.7		%		52.0		%

Electric rate schedule revenue for the nine months ended September 30, 2006 increased $21.4 million, or 5.1% over results in 2005. Electric supply revenue, which consists of supply costs that are collected in rates from customers, increased $19.0 million due to $15.4 million, or 6.8%, higher average prices and a $3.6 million, or 2.1%, increase in volumes. This increase in volumes was also the primary cause of the transmission and distribution revenue increase.

As discussed above, transmission revenues in Montana can fluctuate substantially from year to year based on market conditions in surrounding states. During the second quarter of 2006 the Pacific Northwest experienced strong hydro generation, which resulted in increased electric supply at significantly lower prices than states to our south. Since Pacific Northwest energy prices were substantially lower than in these states, suppliers realized more profit by transmitting electricity across our lines. These market conditions created significant price differentials and a $5.8 million, or 20.1%, increase in transmission revenue as compared to the nine months ended September 30, 2005.

Gross margin for the nine months ended September 30, 2006 increased $3.6 million, or 1.5% as compared to the same period in 2005. The gross margin increase in 2006 was primarily due to higher transmission revenue and increased retail volumes offset by the items discussed below. During March 2006 we signed a stipulation with the Montana Consumer Counsel to settle various issues they raised relative to our 2005 and 2006 electric tracker filings. As a result of this stipulation we are responsible for replacement costs related to certain forward sales contracts for periods after July 1, 2005. These forward sales extend through 2007. We recognized a loss in cost of sales of $1.4 million during the first quarter of 2006 related to the removal of replacement costs from our electric tracker for these sales contracts between July 1, 2005 and March 31, 2006. Additionally, cost of sales includes a $2.9 million loss based on the market value of the remaining forward sales through 2007. Results for the nine months ended September 30, 2005 also included a $4.9 million gain related to a QF contract amendment.

Margin as a percentage of revenues decreased to 49.7% for 2006, from 52.0% for 2005 due to the items discussed above. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power

supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Regulated retail electric volumes for the nine months ended September 30, 2006 totaled 7,338,574 MWHs, which increased 2.1% as compared with 7,191,337 MWHs in the same period in 2005 due primarily to a 1.8% increase in customer growth and warmer weather. Regulated wholesale electric volumes for the nine months ended September 30, 2006 were 176,492 MWHs, an increase over 170,992 MWHs in the same period in 2005 due primarily to higher generation plant availability with less down time for maintenance.

Three Months Ended September 30, 2006 Compared to the Three Months Ended September 30, 2005

			Results
			2006			2005			Change			% Change
			(in millions)
Gas supply revenue	$	14.2			15.7			(1.5		)	(9.6		)	%
Transportation, distribution & storage revenue		13.0			12.5			0.5			4.0
Rate schedule revenue		27.2			28.2			(1.0		)	(3.5		)
Transportation & storage		4.8			4.5			0.3			6.7
Wholesale revenue		2.1			—			2.1			100.0
Miscellaneous		0.8			0.6			0.2			33.3
Total Revenues		34.9			33.3			1.6			4.8			%
Supply costs		14.2			15.7			(1.5		)	(9.5		)
Wholesale supply costs		2.1			—			2.1			100.0
Other cost of sales		0.4			0.3			0.1			33.3
Total Cost of Sales		16.7			16.0			0.7			4.4			%
Gross Margin	$	18.2			17.3			0.9			5.2			%
% GM/Rev		52.1		%	52.0		%

Rate schedule revenue consists of revenue for supply, transportation, distribution, and storage of natural gas. This includes fully bundled rates for supplying, transporting, and distributing natural gas to customers who utilize us as their commodity supplier. Customers that have chosen other commodity suppliers are billed for moving their natural gas through our pipelines and their distribution revenues are reflected as rate schedule revenue, while their transportation revenues are reflected as transportation revenue.

Gas rate schedule revenue for the three months ended September 30, 2006 decreased $1.0 million, or 3.5% over results in 2005. Gas supply revenues, which consist of supply costs that are collected in rates from customers, decreased $1.5 million due to an 8.6% decrease in average prices. Transmission, distribution and storage revenues increased $0.5 million, primarily due to higher storage returns, as we have more natural gas in storage than in 2005.

Transportation revenue consists of revenue earned for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. Transportation and storage revenue increased $0.3 million for the three months ended September 30, 2006 as compared to 2005. Transportation and storage revenue can fluctuate significantly from year to year based on the anticipated spread and volatility between summer and winter gas prices. For example, producers may elect to store summer gas production for later delivery during the traditionally higher priced winter heating season. Likewise, choice customers may utilize storage to secure lower priced summer gas production for use during the winter season.

Wholesale revenue increased $2.2 million due to an increase in sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.

Gross margin for the three months ended September 30, 2006 increased $0.9 million, or 5.2% over the third quarter 2005, primarily due to the higher transportation, distribution, and storage revenue.

Margin as a percentage of revenue of 52.1% for 2006 remained flat over 2005. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are generally collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Regulated retail natural gas volumes were 2,227,857 MMbtu (million British Thermal Units) during the three months ended September 30, 2006, a slight decrease from 2,251,246 MMbtu for the same period in 2005.

Nine Months Ended September 30, 2006 Compared to the Nine Months Ended September 30, 2005

			Results
			2006				2005				Change			% Change
			(in millions)
	Gas supply revenue	$		161.3		$		138.7		$		22.6			16.3		%
	Transportation, distribution & storage revenue			63.9				65.9				(2.0	)		(3.0	)
	Rate schedule revenue			225.2				204.6				20.6			10.1
	Transportation & storage			13.8				13.1				0.7			5.3
	Wholesale revenue			8.0				16.8				(8.8	)		(52.4	)
	Miscellaneous			3.9				2.9				1.0			34.5
	Total Revenues			250.9				237.4				13.5			5.7		%
	Supply costs			161.3				134.1				27.2			20.3
	Wholesale supply costs			8.0				16.8				(8.8	)		(52.4	)
	Other cost of sales			2.1				2.0				0.1			5.0
	Total Cost of Sales			171.4				152.9				18.5			12.1		%
	Gross Margin	$		79.5		$		84.5		$		(5.0	)		(5.9	)	%
% GM/Rev			31.7		%		35.6		%

Gas rate schedule revenue for the nine months ended September 30, 2006 increased $20.6 million, or 10.1% over results in 2005. Gas supply revenues, which consist of supply costs that are collected in rates from customers, increased $22.6 million due to 25.1% higher average prices, partially offset by a $12.2 million, or 7.0% weather related decrease in volumes. The volume decrease also caused the $2.0 million decrease in transportation, distribution and storage revenue. In addition, 2005 revenues included the recovery of $4.6 million of supply costs previously disallowed by the MPSC.

Transportation and storage revenue increased $0.7 million for the nine months ended September 30, 2006 as compared to the same period 2005.

Wholesale revenue decreased $8.8 million, or 52.4%, due to a decrease in sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.

Gross margin for the nine months ended September 30, 2006 decreased $5.0 million, or 5.9% over the same period in 2005 primarily due to warmer weather and the recovery of $4.6 million of supply costs reflected in the 2005 margin, which were previously disallowed by the MPSC.

Margin as a percentage of revenue decreased to 31.7% for 2006, from 35.6% for 2005. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are generally collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Regulated retail natural gas volumes were 18,616,509 MMbtu (million British Thermal Units) during the nine months ended September 30, 2006, a 7.0 % decline from 20,021,412 MMbtu for the same period in 2005. This decline was due primarily to warmer weather in all regulated markets.

Three Months Ended September 30, 2006 Compared to the Three Months Ended September 30, 2005

Our unregulated electric segment primarily consists of our lease of a 30% share of the Colstrip Unit 4 generation facility. We sell our Colstrip Unit 4 generation, representing approximately 222 megawatts at full load, principally to two unrelated third parties under agreements through December, 2010. We also have a separate agreement to repurchase 111 megawatts through December 2010. These 111 megawatts are available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 megawatts have been offered to supply a portion of the Montana default supply load (included in our regulated electric segment) for a term of 11.5 years at an average nominal price of $35.80 per megawatt hour.

Unregulated electric revenue decreased $0.8 million, or 3.4%, for the three months ended September 30, 2006 primarily due to $1.1 million, or 5.3% lower volumes partially offset by $0.3 million, or 55.2%, higher average prices. We had less energy available to sell due to unplanned plant outages in 2006 related to plant maintenance.

Unregulated electric volumes were 413,974 MWHs in the third quarter of 2006, compared with 436,931 MWHs in the same period in 2005. This decrease was primarily due to unplanned plant outages in 2006.

Nine Months Ended September 30, 2006 Compared to the Nine Months Ended September 30, 2005

Unregulated electric revenue decreased $3.0 million, or 4.7%, for the nine months ended September 30, 2006 primarily due to $11.1 million, or 19.6% lower volumes partially offset by $8.1 million, or 16.8%, higher average prices. Strong hydro generation in the Pacific Northwest during the second quarter of 2006 provided increased supply in the wholesale electricity market, resulting in reduced demand for our Colstrip power. In addition, we had less energy available to sell due to decreased plant availability in 2006 due to planned and unplanned outages for plant maintenance.

Gross margin decreased $1.7 million, or 3.3%, primarily due to lower volumes partially offset by higher average prices and a $1.3 million reduction to cost of sales related to the settlement of put options.

Unregulated electric volumes were 1,076,292 MWHs for the nine months ended September 30, 2006, compared with 1,338,174 MWHs in the same period in 2005. The lower volumes in 2006 were due to reduced demand and less plant availability due to planned and unplanned outages as discussed above.

Three Months Ended September 30, 2006 Compared to the Three Months Ended September 30, 2005

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

Unregulated natural gas revenue decreased $18.5 million, or 61.3%, due primarily to certain customers contracting directly with other providers for their commodity supply needs. We have continued to encourage certain customers to choose other commodity suppliers as we receive little to no margin on commodity costs.

Gross margin decreased $1.0 million, or 30.3%, due to a combination of factors, including the amendment of a gas supply and management services contract, lower volumes and a $0.3 million refund of transportation charges during the three months ended September 30, 2005.

Unregulated wholesale natural gas volumes delivered totaled 3,664,562 MMbtu in 2006, compared with 4,250,406 MMbtu in 2005. This decrease was due primarily to the transfer of certain customers to our regulated gas segment.

Nine Months Ended September 30, 2006 Compared to the Nine Months Ended September 30, 2005

Unregulated natural gas revenue decreased $49.4 million, or 43.6%, due primarily to certain customers contracting directly with other providers for their commodity supply needs. We have continued to encourage certain customers to choose other commodity suppliers as we receive little to no margin on commodity costs.

Unregulated wholesale natural gas volumes delivered totaled 13,362,064 MMbtu in 2006, compared with 15,569,366 MMbtu in 2005. This decrease was due primarily to unplanned outages at various ethanol facilities in South Dakota and the transfer of certain customers to our regulated gas segment.

As of September 30, 2006, we had cash and cash equivalents of $1.7 million, and revolver availability of $136.2 million. During the nine months ended September 30, 2006, we used existing cash to repay $42.1 million of debt, including repayments of $36.0 million on our revolver. In addition to these repayments we paid dividends on common stock of $33.0 million, property tax payments of approximately $35.0 million, our semi-annual Colstrip Unit 4 operating lease payment of approximately $16.1 million, and contributed $18.0 million to our pension plans. We have also increased our natural gas in storage by approximately $23.5 million, rather than utilizing deferred storage arrangements. During the nine months ended September 30, 2006, we received net proceeds of $17.2 million from the sale of our Montana First Megawatts generation assets, $7.7 million related to our allowed claim in Netexit’s bankruptcy, and $9.4 million from a settlement with an insurance provider.

Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas sales and transportation services typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing line of credit, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.

The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above, therefore we usually under collect in the fall and winter and over collect in the spring.

		Nine Months Ended September 30,
		2006			2005
Continuing Operating Activities
Net income	$	30.0		$	23.8
Non-cash adjustments to net income		73.5			85.7
Proceeds from hedging activities		14.5			—
Changes in working capital		23.5			67.3
Other		(6.0	)		(23.7	)
		135.5			153.1
Continuing Investing Activities
Property, plant and equipment additions		(75.3	)		(53.6	)
Sale of assets		23.3			5.0
Proceeds from hedging activities		5.3			—
Net proceeds from sales of investments		—			4.7
		(46.7	)		(43.9	)
Continuing Financing Activities
Net repayment of debt		(42.1	)		(99.8	)
Dividends on common stock		(33.0	)		(24.6	)
Deferred gas storage		(11.7	)		2.2
Other		(10.7	)		(4.8	)
		(97.5	)		(127.0	)
Discontinued Operations		7.7			21.0
Net Increase in Cash and Cash Equivalents	$	(1.0	)	$	3.2
Cash and Cash Equivalents, beginning of period	$	2.7		$	17.1
Cash and Cash Equivalents, end of period	$	1.7		$	20.3

As of September 30, 2006, cash and cash equivalents were $1.7 million, compared with $2.7 million at December 31, 2005, and $20.3 million at September 30, 2005. Cash provided by continuing operating activities totaled $135.5 million during the nine months ended September 30, 2006, compared to $153.1 million during the nine months ended September 30, 2005. This decrease in operating cash flows is primarily related to increases in natural gas held in storage, and higher energy payables due to higher market prices during the heating season, offset by significant collections of supply costs from customers in 2006 through the trackers discussed above, proceeds received from hedging activities in 2006, and decreases in pension funding in 2006 versus 2005. In addition, operating cash flows in the nine months ended September 30, 2005 were positively impacted due to improved credit terms reflected in the reduction of prepaid energy supply.

Cash used in investing activities of continuing operations totaled $46.7 million during the nine months ended September 30, 2006 compared to $43.9 million during the nine months ended September 30, 2005. During the nine months ended September 30, 2006, we received cash proceeds of $23.3 million from the sale of assets and $5.3 million from the settlement of hedge positions, offset by cash used of approximately $75.3 million for property, plant and equipment additions. During the nine months ended September 30, 2005, we used approximately $53.6 million for property, plant and equipment additions.

Cash used in financing activities of continuing operations totaled $97.5 million during the nine months ended September 30, 2006 compared to $127.0 million during the nine months ended September 30, 2005. During the nine

months ended September 30, 2006, we have made debt repayments of $42.1 million, paid dividends on common stock of $33.0 million, and paid $11.7 million for deferred storage transactions. Cash used to repurchase shares during the nine months ended September 30, 2006 was approximately $4.1 million. In addition, in association with our debt refinancing transactions completed during 2006, we incurred financing costs of $6.9 million. During the nine months ended September 30, 2005, we made debt repayments of $99.8 million and paid dividends on common stock of $24.6 million.

The decrease in restricted cash held by discontinued operations during the nine months ended September 30, 2006 and 2005 was due to Netexit’s $7.7 million and $20.0 million distribution to us, respectively.

We believe that our cash on hand, operating cash flows, and borrowing capacity, taken as a whole, provide sufficient resources to fund our ongoing operating requirements, debt maturities, anticipated dividends and estimated future capital expenditures during the next twelve months. As of September 30, 2006, our revolver availability was approximately $136.2 million.

Our Board of Directors has approved the purchase of approximately 79 megawatts of our undivided interest in the Colstrip Unit 4 generation facility from Mellon Leasing for approximately $59 million. We expect to complete this purchase during January 2007.

During the second quarter of 2006, we issued $170.2 million of Montana Pollution Control Obligations (PCOs) at a fixed interest rate of 4.65%, and used the proceeds to redeem our 6.125%, $90.2 million and 5.90%, $80.0 million Montana pollution control obligations due in 2023. Consistent with our historical regulatory treatment, the remaining deferred financing costs of approximately $3.8 million were recorded as a regulatory asset and will be amortized over the remaining life of the debt. The new PCOs will mature on August 1, 2023, and are secured by our Montana electric and natural gas assets. This transaction will reduce our annual interest expense by approximately $2.4 million.

During the third quarter of 2006, we issued $150 million of Montana First Mortgage Bonds at a fixed interest rate of 6.04% and used the proceeds to redeem our 7.30%, $150 million Montana first mortgage bonds due December 1, 2006. Consistent with our historical regulatory treatment, the remaining deferred financing costs and prepayment penalty of $0.8 million were recorded as a regulatory asset and will be amortized over the remaining life of the debt. The new first mortgage bonds will mature September 1, 2016, and are secured by our Montana electric and natural gas assets. This transaction will reduce our annual interest expense by approximately $1.9 million.

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of September 30, 2006. See our Annual Report on Form 10-K for the year ended December 31, 2005 for additional discussion.

		Total		2006		2007		2008		2009		2010			Thereafter
	(in thousands)
Long-term Debt	$	699,643	$	—	$	5,613	$	5,391	$	50,862	$		6,123	$	631,654
Capital Leases(1)	43,106		626		2,085		1,677		1,274		1,174			36,270
Future Minimum Operating Lease Payments(2)	264,313		16,656		34,080		33,026		32,429		32,294			115,828
Estimated Pension and Other Postretirement Obligations(3)	105,500		1,500		28,000		28,000		24,000		24,000			N/A
Qualifying Facilities(4)	1,590,188		14,100		58,420		60,574		62,598		64,580			1,329,916
Supply and Capacity Contracts(5)	1,994,919		165,271		440,590		279,081		267,558		255,687			586,732
Contractual Interest Payments on Debt	440,402		8,008		40,340		39,998		39,169		36,366			276,521
Total Commitments	$	5,138,071	$	206,161	$	609,128	$	447,747	$	477,890	$		420,224	$	2,976,921

Fitch Investors Service (Fitch), Moody’s Investors Service (Moody’s) and Standard and Poor’s Rating Group (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of September 30, 2006, our ratings with these agencies are as follows:

Management’s discussion and analysis of financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.

As of September 30, 2006, there have been no significant changes with regard to the critical accounting policies disclosed in Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended December 31, 2005. The policies disclosed included the accounting for the following: goodwill and long-lived assets, qualifying facilities liability, revenue recognition, regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.

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

We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. All of our debt has fixed interest rates, with the exception of our revolver, which bears interest at a variable rate (currently approximately 6.5%) tied to the London Interbank Offered Rate (LIBOR). Based upon amounts outstanding as of September 30, 2006, a 1% increase in the LIBOR would increase annual interest expense on this line of credit by approximately $0.5 million.

During the second quarter of 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions of approximately $380 million. These swaps were designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income in our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive income into interest expense in our Consolidated Statements of Income during the periods in which the interest payments being hedged occur. During the first quarter of 2006, based on a review of our capital structure and cash flow, and approval by our Board of Directors, we decided not to refinance $60 million included in the interest rate swap that was being carried on our revolver. This forward starting interest rate swap was settled during the second quarter of 2006, and we received an aggregate payment of approximately $3.9 million.

In association with the refinancing transactions completed during the second and third quarters of 2006, we settled $170.2 million and $150.0 million of forward starting interest rate swap agreements, and received aggregate settlement payments of approximately $6.3 million and $8.3 million, respectively. These amounts are being amortized as a reduction to interest expense over the term of the underlying debt, which is 17 years and 10 years, respectively. The cash proceeds related to these hedges are reflected in operating activities on the statement of cash flows. As of September 30, 2006 we have no interest rate swaps outstanding.

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

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

In our unregulated electric segment, due to our lease of a 30% share of the Colstrip Unit 4 generation facility, we are exposed to the market price fluctuations of electricity. We have entered into forward contracts for the sale of a significant portion of Colstrip Unit 4’s generation through the first quarter of 2007. To the extent Colstrip Unit 4 experiences unplanned outages and generation is lower than our contracted sales, we would need to secure the quantity deficiency from the wholesale market to fulfill our forward sales contracts. As of September 30, 2006, market prices exceeded our contracted forward sales prices by approximately $5.7 million.

In our unregulated natural gas segment, we currently have a capacity contract through 2013 with a pipeline that gives us basis risk depending on gas prices at two different delivery points. We have sales contracts with certain customers that provide for a selling price based on the index price of gas coming from a delivery point in Ventura, Iowa. The pipeline capacity contract allows us to take delivery of gas from Canada, which has typically been cheaper than gas coming from Ventura, even when including transportation costs. If the Canadian gas plus transportation cost exceeds the index price at Ventura, then we will lose money on these gas sales. The annual capacity payments are approximately $1.8 million, which represents our maximum exposure related to this basis risk.

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

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation our principal executive officer and principal financial officer have concluded that, as of September 30, 2006, our disclosure controls and procedures are effective.

There have been no changes in our internal control over financial reporting during the three months ended September 30, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

See Note 12, Commitments and Contingencies, to the Consolidated Financial Statements for information about legal proceedings.

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our shares or other securities.

The agreement to sell NorthWestern to Babcock & Brown Infrastructure (BBI) will be completed only if certain conditions are met, including various federal and state regulatory approvals. If the sale is not completed, then our shareholders may not be able to obtain the premium for their shares of common stock offered in the proposed transaction.

The agreement to sell NorthWestern to BBI is subject to numerous federal and state regulatory approvals and certain other closing conditions. The inability to obtain these regulatory approvals or fulfill those closing conditions could result in the termination of the agreement. If the BBI transaction does not reach closing, then our shareholders will not receive the agreed upon purchase price per share.

We have incurred, and may continue to incur, significant costs associated with outstanding litigation and the formal investigation being conducted by the SEC relating to the restatement of our 2002 quarterly financial statements and other accounting and financial reporting matters (SEC investigation), which may adversely affect our results of operations and cash flows.

These costs, which are being expensed as incurred, have had, and may continue to have an adverse affect on our results of operations and cash flows. Pending litigation matters are discussed in detail under the Legal Proceedings section in Note 12 to the Consolidated Financial Statements. An adverse result in any of these matters could have an adverse effect on our business.

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

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

We are regulated by commissions in the states we serve. As a result, these commissions review our books and records, including energy supply contracts, which could result in rate changes or other limitations on our ability to recover costs and have a material adverse effect on our results of operations and financial condition.

Competition for various aspects of electric and natural gas services has been introduced throughout the country that will open these markets to new providers of some or all of traditional electric utility and natural gas services. Competition could result in the further unbundling of electric utility and natural gas services as has occurred in Montana for electricity and Montana, South Dakota and Nebraska for natural gas. Separate markets may emerge for generation, transmission, distribution, meter reading, billing and other services currently provided by electric utility

and natural gas providers as a bundled service. As a result, additional competitors could become active in the generation, transmission and distribution segments of our industry.

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

Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rates through our monthly trackers. During the fourth quarter of 2005, the MCC submitted testimony alleging we were imprudent and recommending the MPSC consider disallowing portions of our forecasted electric and natural gas supply costs contained in the 2005 tracker filings. In March 2006, upon signing a stipulation with the MCC, we recognized a loss of approximately $1.4 million related to the removal of replacement costs for certain forward sales transactions from our 2006 electric tracker forecast. The stipulation settles various issues relative to our electric supply costs raised by the MCC and has been approved by the MPSC. In May 2006, the MPSC approved our 2005 annual natural gas tracker as filed. To the extent our energy supply costs are deemed imprudent by the MPSC or other applicable state regulatory commissions, we would under-recover our costs, which could adversely impact our results of operations.

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

Our obligation to supply a minimum annual quantity of power to the Montana default supply could expose us to material commodity price risk if certain qualifying facilities (QFs) under contract with us do not supply during a time of high commodity prices, as we are required to supply any quantity deficiency.

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

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the default supply with a certain minimum amount of power at an agreed upon price per megawatt. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. Furthermore, we will not realize commodity price risk, unless any required replacement energy cost is in excess of the total amount recovered under the QF contracts.

However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to secure the quantity deficiency from other sources. Since we own no material generation in Montana, the anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility.

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

During the course of our bankruptcy reorganization proceedings, we offered to provide 90 megawatts of baseload energy from Colstrip 4 into the Montana default supply for a term of 11.5 years, commencing on July 1, 2007, at an average nominal price of $35.80 per megawatt hour. This offer was below prevailing market prices, and was made as part of a negotiated process with the MPSC and the MCC to settle their intervention in opposition to our request that the Bankruptcy Court approve our contract amendment with Duke, (which was novated to DB Energy Trading LLC in the first quarter of 2006). We expect that the sale of the 132 megawatts of our remaining output, which is not under contract after 2010, will be sufficient to allow us to recover the carrying value of our Colstrip Unit 4 leasehold improvements. If we are unable to sell the 132 megawatts at such a sufficient price, then the value of our Colstrip Unit 4 leasehold improvements would be materially adversely impacted.

Our jointly owned electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

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

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

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

Our utility business is subject to extensive laws and regulations imposed by federal, state and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, solid waste disposal and other environmental considerations. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations. However, possible future developments, including the promulgation of more stringent environmental laws and regulations, such as the new mercury emissions rules approved by the Montana Board of Environmental Review, and the timing of future enforcement proceedings that may be taken by environmental authorities could affect the costs and the manner in which we conduct our business and could cause us to make substantial additional capital expenditures.

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

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be predicted. Our range of exposure for environmental remediation obligations is estimated to be $19.5 million to $56.1 million. We had an environmental reserve of $34.3 million at September 30, 2006. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or claims for damages allegedly associated with specific environmental conditions. To the extent that our

environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.

A downgrade in our credit ratings could negatively affect our ability to operate our business and/or access capital.

S&P has assigned us a negative outlook due to the uncertainty surrounding BBI’s acquisition of NorthWestern. A downgrade of our credit ratings could adversely affect our liquidity, as counter parties could require us to post collateral. In addition, our ability to raise capital on favorable terms could be hindered and our borrowing costs could increase.

On August 2, 2006, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

Exhibit 31.1—Certification of chief executive officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

Exhibit 31.2—Certification of chief financial officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

Exhibit 32.1—Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2—Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,

In connection with the Quarterly Report of NorthWestern Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Hanson, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,

In connection with the Quarterly Report of NorthWestern Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brian B. Bird, Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(Mark One)
x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006

Or

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

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

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

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

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

Large Accelerated Filer x Accelerated Filer o Non-accelerated Filer o

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

	Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest
practicable date:

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION			5
Item 1.	Financial Statements (Unaudited)		5
	Consolidated Balance Sheets — September 30, 2006 and December 31, 2005		5
	Consolidated Statements of Income — Three and Nine Months Ended September 30, 2006 and 2005		6
	Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2006 and 2005		7
	Notes to Consolidated Financial Statements		9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		45
Item 4.	Controls and Procedures		46
PART II. OTHER INFORMATION			47
Item 1.	Legal Proceedings		47
Item 1A.	Risk Factors		47
Item 4.	Submission of Matters to a Vote of Security Holders		50
Item 6.	Exhibits		51
SIGNATURES			52

Supplemental Cash Flow Information
Cash paid (received) during the period for:
Income taxes	$	112	$	(341	)
Interest		31,338		32,248
Supplemental Schedule of Noncash Investing and Financing Activities
Additions to property, plant and equipment and capital lease obligations		40,210		—

Liability at January 1, 2006	$	3,233
Accretion expense		190
Liabilities incurred		—
Liabilities settled		—
Revisions to cash flows		42
Liability at September 30, 2006	$	3,465

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

	Nine Months Ended September 30, 2006	Nine Months Ended September 30, 2005
Basic computation	35,534,894	35,620,389
Dilutive effect of
Restricted shares	101,100	57,271
Stock warrants	1,303,693	298,570
Diluted computation	36,939,687	35,976,230

	Three Months Ended September 30, 2006	Three Months Ended September 30, 2005
Basic computation	35,510,467	35,643,037
Dilutive effect of
Restricted shares	101,100	57,271
Stock warrants	1,417,404	531,851
Diluted computation	37,028,971	36,232,159

Beginning unvested shares granted	35,164
Granted	105,812
Vested	39,425
Canceled	451
Remaining unvested shares granted	101,100

Weighted average fair value restricted stock granted	$	34.53

	Volumes MWH
	2006		2005		Change			% Change
	(in thousands)
Retail Electric
Residential		675		634		41			6.5		%
Commercial		1,068		1,022		46			4.5
Industrial		759		791		(32	)		(4.0	)
Other		91		85		6			7.1
Total Retail Electric		2,593		2,532		61			2.4		%
Wholesale Electric		64		58		6			10.3		%

Average Customer Counts		2006		2005		Change		% Change
	Montana		321,748		315,443		6,305		2.0	%
	South Dakota		59,133		58,678		455		0.8	%
	Total		380,881		374,121		6,760		1.8	%

	2006 as compared to:
Cooling Degree-Days	2005	Historic Average
Montana	45% warmer	49% warmer
South Dakota	4% warmer	35% warmer

		Volumes Mmbtu
		2006		2005		Change			% Change
		(in thousands)
Retail Gas
	Residential		1,194		1,255		(61	)		(4.9	)	%
	Commercial		999		969		30			3.1
	Industrial		4		12		(8	)		(66.7	)
	Other		31		15		16			106.7
	Total Retail Gas		2,228		2,251		(23	)		(1.0	)	%

	2006 as compared to:
Heating Degree-Days	2005	Historic Average
Montana	20% warmer	17% warmer
South Dakota	8% warmer	63% warmer
Nebraska	250% colder	3% warmer

	Senior Secured Rating		Senior Unsecured Rating		Corporate Rating	Outlook
Fitch	BBB		BBB-		BBB-	Stable
Moody’s	Baa3		Ba2		N/A	Stable
S&P	BBB-	*	BB-	*	BB+	Negative	**

	VOTES FOR:		VOTES WITHHELD:
Stephen P. Adik		28,502,162		658,107
E. Linn Draper		28,403,565		756,704
Jon S. Fossel		27,836,477		1,323,792
Michael J. Hanson		28,360,068		800,201
Julia L. Johnson		28,402,852		757,417
Philip L. Maslowe		28,395,261		765,008
D. Louis Peoples		28,408,141		752,128

	FOR:	AGAINST:		ABSTAIN:
Votes	28,713,530		328,143		118,596

	NORTHWESTERN CORPORATION
Date: November 2, 2006	By:	/s/ BRIAN B. BIRD
		Brian B. Bird
		Chief Financial Officer
		Duly Authorized Officer and Principal Financial Officer

Exhibit Number		Description
*31.1		Certification of chief executive officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.
*31.2		Certification of chief financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1		Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Date: November 2, 2006		/s/ MICHAEL J. HANSON
		Michael J. Hanson
		President and Chief Executive Officer