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.

		June 30, 2007		December 31, 2006
ASSETS
Current Assets:
Cash and cash equivalents	$	—		$	1,930
Restricted cash		16,660			15,836
Accounts receivable, net of allowance		102,814			149,793
Inventories		57,417			60,543
Regulatory assets		21,092			31,125
Prepaid energy supply		2,941			2,394
Deferred income taxes		16,690			19
Other		9,290			6,834
Total current assets		226,904			268,474
Property, plant, and equipment, net		1,586,929			1,491,855
Goodwill		355,128			435,076
Regulatory assets		149,347			159,715
Other noncurrent assets		35,633			40,817
Total assets	$	2,353,941		$	2,395,937
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	11,818		$	5,614
Current maturities of capital leases		2,769			2,079
Accounts payable		61,369			78,739
Accrued expenses		179,760			180,278
Regulatory liabilities		41,071			12,226
Total current liabilities		296,787			278,936
Long-term capital leases		38,657			40,383
Long-term debt		679,960			699,041
Deferred income taxes		65,284			113,355
Noncurrent regulatory liabilities		189,917			182,103
Other noncurrent liabilities		326,857			339,348
Total liabilities		1,597,462			1,653,166
Commitments and Contingencies (Note 12)
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 36,411,815 and 36,081,433, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		364			360
Treasury stock at cost		(9,891	)		(9,885	)
Paid-in capital		742,182			727,327
Retained earnings		9,977			10,698
Accumulated other comprehensive income		13,847			14,271
Total shareholders’ equity		756,479			742,771
Total liabilities and shareholders’ equity	$	2,353,941		$	2,395,937

		Three Months Ended June 30,					Six Months Ended June 30,

		2007			2006			2007			2006
OPERATING REVENUES	$	259,608		$	232,186		$	626,173		$		593,668
COST OF SALES		141,255			117,726			360,534				337,398
GROSS MARGIN		118,353			114,460			265,639				256,270
OPERATING EXPENSES
Operating, general and administrative		58,677			68,645			121,125				129,972
Property and other taxes		20,660			18,713			41,252				38,178
Depreciation		20,793			18,751			40,687				37,580
TOTAL OPERATING EXPENSES		100,130			106,109			203,064				205,730
OPERATING INCOME		18,223			8,351			62,575				50,540
Interest Expense		(14,527	)		(14,622	)		(27,747	)			(29,058	)
Other Income		359			3,147			737				8,417
Income (Loss) From Continuing Operations Before Income Taxes		4,055			(3,124	)		35,565				29,899
Income Tax Benefit (Expense)		(1,621	)		310			(13,989	)			(11,738	)
Income (Loss) From Continuing Operations		2,434			(2,814	)		21,576				18,161
Discontinued Operations, Net of Taxes		—			368			—				418
Net Income (Loss)	$	2,434		$	(2,446	)	$	21,576		$		18,579
Average Common Shares Outstanding		35,988			35,511			35,855				35,547
Basic Earnings per Average Common Share
Continuing operations	$	0.07		$	(0.08	)	$	0.60		$		0.51
Discontinued operations		0.00			0.01			0.00				0.01
Basic	$	0.07		$	(0.07	)	$	0.60		$		0.52
Diluted Earnings per Average Common Share
Continuing operations	$	0.06		$	(0.08	)	$	0.57		$		0.50
Discontinued operations		0.00			0.01			0.00				0.01
Diluted	$	0.06		$	(0.07	)	$	0.57		$		0.51
Dividends Declared per Average Common Share	$	0.31		$	0.31		$	0.62		$		0.62

	Six Months Ended June 30,
		2007			2006
OPERATING ACTIVITIES:
Net Income	$	21,576		$	18,579
Items not affecting cash:
Depreciation		40,687			37,580
Amortization of debt issue costs, discount and deferred hedge gain		805			1,301
Amortization of restricted stock		4,259			329
Equity portion of allowance for funds used during construction		(163	)		—
Income from discontinued operations, net of taxes		—			(418	)
Gain on sale of assets		—			(2,392	)
Gain on derivative instruments		—			(5,203	)
Deferred income taxes		12,712			13,017
Proceeds from hedging activities		—			6,292
Changes in current assets and liabilities:
Restricted cash		(824	)		(2,543	)
Accounts receivable		46,979			70,760
Inventories		3,126			(12,672	)
Prepaid energy supply costs		(547	)		(723	)
Other current assets		(330	)		(3,246	)
Accounts payable		(18,314	)		(44,240	)
Accrued expenses		3,622			(11,107	)
Regulatory assets and liabilities		32,386			18,609
Other noncurrent assets		6,822			4,738
Other noncurrent liabilities		(16,559	)		5,229
Cash provided by continuing operating activities		136,237			93,890
INVESTING ACTIVITIES:
Property, plant, and equipment additions		(52,608	)		(45,335	)
Colstrip Unit 4 acquisition		(40,247	)		—
Proceeds from sale of assets		592			23,304
Proceeds from hedging activities		—			5,355
Cash used in continuing investing activities		(92,263	)		(16,676	)
FINANCING ACTIVITIES:
Deferred gas storage		—			(11,718	)
Proceeds from exercise of warrants		10,600			221
Treasury stock activity		(6	)		(3,730	)
Dividends on common stock		(22,297	)		(22,033	)
Repayment of long-term debt		(3,920	)		(173,795	)
Line of credit repayments, net		(30,000	)		(38,000	)
Issuance of long term debt		—			170,205
Financing costs		(281	)		(5,746	)
Cash used in continuing financing activities		(45,904	)		(84,596	)
DISCONTINUED OPERATIONS:
Operating cash flows of discontinued operations, net		—			(3,431	)
Investing cash flows of discontinued operations, net		—			2,872
Financing cash flows of discontinued operations, net		—			—
Decrease in restricted cash held by discontinued operations		—			8,255
Increase (Decrease) in Cash and Cash Equivalents		(1,930	)		314
Cash and Cash Equivalents, beginning of period		1,930			2,691
Cash and Cash Equivalents, end of period	$	—		$	3,005
Supplemental Cash Flow Information:
Cash paid during the period for:
Income Taxes		1,274			112
Interest		18,993			22,662
Significant noncash transactions:
Assumption of debt related to Colstrip Unit 4 acquisition		20,438			—

We are one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 640,000 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, 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, 2006.

(2) Termination of Merger Agreement with Babcock & Brown Infrastructure Limited

On April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with BBI, an infrastructure investment company listed on the Australian Stock Exchange, under which BBI would acquire NorthWestern Corporation in an all-cash transaction at $37 per share. We had received all approvals necessary for the transaction, except from the Montana Public Service Commission (MPSC). On May 22, 2007 the MPSC unanimously directed its staff to draft an order denying the transaction. On June 25, 2007, we and BBI filed a formal joint request asking the MPSC to consider a revised proposal. In connection with our joint request to the MPSC, we and BBI agreed that if the MPSC denied the revised application, then either party in their sole discretion could terminate the Merger Agreement. On July 24, 2007, the MPSC denied the joint request and BBI terminated the Merger Agreement. The MPSC issued a final written order on July 31, 2007.

We incurred transaction related costs of approximately $1.3 million during the six months ended June 30, 2007. Our total transaction related costs since inception were $15.3 million, which have been expensed as incurred.

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

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115 (SFAS No. 159), which permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, with unrealized gains and losses related to these financial instruments reported in earnings at each subsequent reporting date. This Statement is effective as of the beginning of our 2008 fiscal year. We are currently

evaluating the impact, if any, adopting SFAS No. 159 will have on our financial statements.

In July 2006, the FASB issued 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 (SFAS No. 109), 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. We adopted FIN 48 as of January 1, 2007. See Note 5, Income Taxes for further discussion of the impact to our financial statements.

FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, or FIN 46R requires the consolidation of entities which are determined to be variable interest entities (VIEs) when we are the primary beneficiary of a VIE, which means we have a controlling financial interest. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility and, while we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We continue to account for this qualifying facility contract as an executory contract as we have been unable 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. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $532.0 million through 2025, and are included in Contractual Obligations and Other Commitments of Management’s Discussion and Analysis.

We also consolidate the Owner Trust associated with our Owner Participant interest in the electric generation unit known as Colstrip Unit 4 in accordance with FIN 46R. See Note 13, Colstrip Unit 4 Acquisition, for further details.

We adopted the provisions of FIN 48 on January 1, 2007. FIN 48 provides that a tax position that meets the more-likely-than-not threshold shall initially and subsequently be measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As a result of the implementation of FIN 48, we increased our deferred tax assets by $77.5 million and decreased other noncurrent liabilities by $2.4 million, with a corresponding decrease to goodwill. The decrease to goodwill is consistent with the guidance in SFAS No. 109 and the requirements of fresh-start reporting, as our uncertain tax positions relate to periods prior to our emergence from bankruptcy. We have unrecognized tax benefits of approximately $102.5 million as of June 30, 2007.

If any of our unrecognized tax benefits were recognized, they would have no impact on our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statute of limitations prior to June 30, 2008.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 2007, we have not recognized expense for interest or penalties, and do not have any amounts accrued at June 30, 2007 and December 31, 2006, respectively, for the payment of interest and penalties.

Our federal tax returns from 2000 forward remain subject to examination by the Internal Revenue Service.

Our goodwill was decreased by approximately $79.9 million during the six months ended June 30, 2007 to record the impact of the adoption of FIN 48 as discussed in Note 5, Income Taxes. Goodwill by segment 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 June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Net income (loss)	$	2,434		$	(2,446	)	$	21,576		$	18,579
Other comprehensive income (loss), net of tax:
Reclassification of net gains on hedging instruments from OCI to net income (loss), net of tax of $711 in 2006		(297	)		(61	)		(594	)		(3,885	)
Unrealized gain on derivative instruments qualifying as hedges, net of tax of $1,359 and $4,633 in the three and six months ended June 30, 2006, respectively		—			4,819			—			12,738
Foreign currency translation		151			81			170			79
Comprehensive income	$	2,288		$	2,393		$	21,152		$	27,511

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 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 (AOCI) in our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from AOCI 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. 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.

During the second and third quarters of 2006, we issued $170.2 million of Montana Pollution Control Obligations and $150 million of Montana First Mortgage Bonds. In association with these refinancing transactions, 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. AOCI includes unrealized pre-tax gains related to these transactions of $13.4 million and $14.0 million at June 30, 2007 and December 31, 2006, respectively. We expect to reclassify approximately $1.2 million of pre-tax gains on these cash-flow hedges from AOCI into interest expense during the next twelve months. The cash proceeds related to these hedges are reflected in operating activities on the statement of cash flows. 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. The remaining unrealized losses included in AOCI due to changes in market value prior to the hedges being undesignated of approximately $0.9 million were reclassified into earnings during the third and fourth quarters of 2006.

We currently operate our business in five reporting segments: (i) regulated electric, (ii) regulated natural gas, (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 are evaluating our plans with regard to our unregulated natural gas segment, and expect to either sell the remaining business or transfer the remaining customers and contracts into our regulated gas segment during 2007.

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, are as follows (in thousands):

Three months ended		Regulated							Unregulated
June 30, 2007			Electric			Gas				Electric			Gas			Other				Eliminations				Total
Operating revenues	$	170,579		$	62,032			$	14,601		$	16,715		$	—			$	(4,319		)	$	259,608
Cost of sales		87,890			36,924				4,205			16,180			—				(3,944		)		141,255
Gross margin		82,689			25,108				10,396			535			—				(375		)		118,353
Operating, general and administrative		30,831			16,063				7,536			356			4,266				(375		)		58,677
Property and other taxes		14,453			5,345				856			2			4				—				20,660
Depreciation		15,280			4,107				954			12			440				—				20,793
Operating income (loss)		22,125			(407		)		1,050			165			(4,710		)		—				18,223
Total assets	$	1,483,660		$	731,352			$	118,604		$	5,058		$	15,267			$	—			$	2,353,941
Capital expenditures	$	16,156		$	14,681			$	1,301		$	—		$	—			$	—			$	32,138

Three months ended		Regulated					Unregulated
June 30, 2006		Electric		Gas			Electric			Gas		Other			Eliminations			Total
Operating revenues	$	151,007	$	58,209		$	13,707		$	17,001	$	78		$	(7,816	)	$	232,186
Cost of sales		71,478		35,565			3,049			15,055		38			(7,459	)		117,726
Gross margin		79,529		22,644			10,658			1,946		40			(357	)		114,460
Operating, general and administrative		33,381		15,300			10,533			437		9,351			(357	)		68,645
Property and other taxes		13,245		4,558			878			21		11			—			18,713
Depreciation		14,440		3,630			383			100		198			—			18,751
Operating income (loss)		18,463		(844	)		(1,136	)		1,388		(9,520	)		—			8,351
Total assets	$	1,490,922	$	739,430		$	46,991		$	12,602	$	39,902		$	—		$	2,329,847
Capital expenditures	$	16,360	$	6,054		$	1,742		$	5	$	—		$	—		$	24,161

Six months ended		Regulated				Unregulated
June 30, 2007		Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	349,073	$	220,221	$	36,879	$	32,786	$	—		$	(12,786	)	$	626,173
Cost of sales		180,679		152,134		8,441		31,173		—			(11,893	)		360,534
Gross margin		168,394		68,087		28,438		1,613		—			(893	)		265,639
Operating, general and administrative		65,339		34,148		15,904		713		5,914			(893	)		121,125
Property and other taxes		28,644		10,940		1,635		26		7			—			41,252
Depreciation		30,658		8,057		1,370		86		516			—			40,687
Operating income (loss)		43,753		14,942		9,529		788		(6,437	)		—			62,575
Total assets	$	1,483,660	$	731,352	$	118,604	$	5,058	$	15,267		$	—		$	2,353,941
Capital expenditures	$	28,552	$	22,115	$	1,941	$	—	$	—		$	—		$	52,608

Six months ended		Regulated				Unregulated
June 30, 2006		Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	319,108	$	217,710	$	38,510	$	50,629	$	166		$	(32,455	)	$	593,668
Cost of sales		160,626		154,743		6,420		47,056		91			(31,538	)		337,398
Gross margin		158,482		62,967		32,090		3,573		75			(917	)		256,270
Operating, general and administrative		66,043		32,555		20,456		822		11,013			(917	)		129,972
Property and other taxes		26,732		9,586		1,800		45		15			—			38,178
Depreciation		28,963		7,302		705		201		409			—			37,580
Operating income (loss)		36,744		13,524		9,129		2,505		(11,362	)		—			50,540
Total assets	$	1,490,922	$	739,430	$	46,991	$	12,602	$	39,902		$	—		$	2,329,847
Capital expenditures	$	34,031	$	8,636	$	2,663	$	5	$	—		$	—		$	45,335

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:

Warrants outstanding as of June 30, 2007 and 2006 of 4,100,006 and 4,607,570, respectively, are dilutive and have been included in the diluted earnings per share calculations. These warrants are exercisable through November 1, 2007. Each warrant could be exchanged for 1.10 and 1.06 shares of common stock and have an exercise price of $25.62 and $26.86 as of June 30, 2007 and 2006, respectively. 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 406,519 warrants were exercised during the six months ended June 30, 2007.

Net periodic benefit cost for our pension and other postretirement plans consists of the following for the three and six months ended June 30, 2007 and 2006 (in thousands):

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
	2007			2006			2007			2006
Components of Net Periodic Benefit Cost
Service cost	$	2,185		$	2,392		$	102		$	198
Interest cost		5,501			5,351			519			675
Expected return on plan assets		(6,388	)		(5,642	)		(310	)		(274	)
Amortization of prior service cost		61			61			—			—
Net Periodic Benefit Cost	$	1,359		$	2,162		$	311		$	599

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
	2007			2006			2007			2006
Components of Net Periodic Benefit Cost
Service cost	$	4,474		$	4,525		$	290		$	370
Interest cost		10,900			10,395			1,221			1,388
Expected return on plan assets		(12,211	)		(10,729	)		(535	)		(415	)
Amortization of prior service cost		121			121			(180	)		—
Net Periodic Benefit Cost	$	3,284		$	4,312		$	796		$	1,343

In April 2007, we contributed approximately $21.1 million to our pension plans. We expect to contribute an additional $1.5 million to our pension plans during the remainder of 2007.

Environmental laws and regulations are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. The range of exposure for environmental remediation obligations at present is estimated to range between $20.4 million to $56.1 million. As of June 30, 2007, we have a reserve of approximately $33.9 million. We anticipate that as environmental costs become fixed and reliably determinable, we will seek insurance reimbursement and/or authorization to recover these 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.

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. In November 2006, The Sierra Club sent a Notice of Intent to File a Suit to the owners, including us, of Big Stone I, asserting that it would file a lawsuit in 60 days alleging that the plant failed to obtain permits for certain projects undertaken in 1995, 2001 and 2005 and otherwise failed to comply with the Clean Air Act. The owners intend to vigorously defend against any lawsuit filed by The Sierra Club.

We have a 222 megawatt interest in Colstrip Unit 4, a coal-fired power plant located in southeastern Montana. In addition, we are also joint owners in three coal-fired plants used to serve our South Dakota customer supply demands, Citing its authority under the Clean Air Act, the EPA has finalized Clean Air Mercury Regulations (CAMR) that affect coal-fired plants. These regulations establish a cap-and-trade program to take effect in two phases, with a first phase to begin in January 2010, and a second phase with more stringent caps to begin in January 2018. Under CAMR, each state is allocated a mercury emissions cap and is required to develop regulations to implement the requirements, which can follow the federal requirements or be more restrictive.

Montana has finalized its own rules that would require every coal-fired generating plant in the state to achieve by 2010 reduction levels more stringent than CAMR’s 2018 cap. Because enhanced chemical injection technologies may not be sufficiently developed to meet these levels of reduction by 2010, there is a risk that adsorption/absorption technology with fabric filters at the Colstrip Unit 4 generation facility would be required, which could represent a material cost. We expect the Montana mercury rules to be challenged. If those rules are overturned and we are instead required to comply with CAMR, achievement of the 2010 and 2018 requirements may be possible with more refined

chemical injection technology combined with adjustments to boiler/fireball dynamics at a minimal cost. We are continuing to work with the other Colstrip owners to determine the ultimate financial impact of these new rules.

Approximately $28.6 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Energy and Natural Resources. Our current reserve for remediation costs at this site is approximately $15.4 million, and we estimate that approximately $13 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. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. 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 nature and timing of any risk-based remedial action 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 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 and 2006 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. Recent monitoring of groundwater and aquifer characterization work at the Helena manufactured gas plant site suggests that groundwater remediation may not 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 and it appears that this has limited impact on the overall contaminant levels in the aquifer. Further data collection is ongoing 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 nature and timing of risk-based remedial action at the Helena site.

Based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and the potential to recover 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, we and CFB 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.

Pursuant to the terms of the consent decree, the parties expect that the remaining financial obligation of $1.4 million to the State of Montana will be covered through a combination of any refund of premium upon cancellation of the catastrophic release policy, and the sale or transfer of land and water rights associated with the Milltown Dam operations.

We, along with eight other potentially responsible parties, have signed an Administrative Settlement Agreement and Order on Consent to conduct a Remedial Investigation/Feasibility Study at the Harbor Oil Superfund Site, an oil recycling facility in Oregon to which waste oil had been transported by The Montana Power Company and others. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

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

We routinely engage the services of a third-party environmental consulting firm to perform a comprehensive evaluation of our environmental reserve. Based upon information available to our consultants at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:

Magten and Law Debenture v. NorthWestern Corporation - 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 allegedly 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 (QUIPS) 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. On July 18, 2007, the Delaware District Court extended the discovery schedule and set the trial for March 2008. We intend to vigorously defend against the QUIPS litigation.

Magten v. Certain Current and Former Officers - 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 pre-trial matters. The Federal District Court has denied Magten's motions without prejudice to refile and denied the request for leave to file a dispositive motion before the deadline previously established by the Federal District Court. We anticipate that dispositive motions will be filed pursuant to the Federal District Court's schedule for filing such motions at the close of discovery. On July 18, 2007 the Delaware District Court extended the discovery schedule and set the trial for March 2008.

Magten v. Bank of New York - In July 2006, Magten served a complaint against The Bank of New York (BNY) in an action filed in New York State court, seeking damages for alleged breach of contract, breach of fiduciary duty and negligence in connection with the same transaction described above which is at issue in the QUIPS Litigation. Specifically, Magten alleges that BNY, as the Indenture Trustee at the time of the 2002 transfer of assets from Montana Power Company to NorthWestern, should have taken steps to protect the QUIPS holders’ interests by seeking to set aside the transfer and imposing a constructive trust on the assets. The New York State court dismissed Magten’s complaint in May 2007 and Magten has filed a notice of appeal. BNY has asserted a right to indemnification by NorthWestern for legal fees and costs incurred in defending against Magten’s claims pursuant to the terms of the Indenture governing the QUIPS under which BNY served as Trustee. It is our position that any such recovery should be payable from the Class 9 Disputed Claim Reserve set aside under NorthWestern’s Chapter 11 Plan of Reorganization (the “Plan”), although the Plan Committee, acting on behalf of certain creditors of NorthWestern’s bankruptcy estate, has objected to this position.

Magten and Law Debenture v. NorthWestern Corporation and Certain Individuals - On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern Corporation and certain former and current officers and directors seeking to revoke the Confirmation Order of our Plan of Reorganization 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 Magten’s appeal of the Order confirming our Plan of Reorganization. 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 and during the second quarter of 2007, Magten, Law Debenture, the Plan Committee and NorthWestern unsuccessfully engaged in mediation to resolve the pending appeals and other pending litigation described above. We continue to have settlement discussions with the parties, and are currently engaged in further mediation efforts in the Third Circuit. 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 Reserv e 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.

We are one of the defendants in a second class action lawsuit brought by the McGreevey plaintiffs, also entitled McGreevey, et al. v. The Montana Power Company, et al., and pending in U.S. District Court in Montana. This lawsuit, like the Magten litigation described above, seeks, among other things, the avoidance of the transfer of assets from CFB to us, declaration that the assets were fraudulently transferred and are not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets, and the return of such assets to CFB. In response to this litigation, we filed an adversary proceeding in the Delaware Bankruptcy Court and obtained an order in October 2005 enjoining the McGreevey plaintiffs from prosecuting their lawsuit against us.

In June 2006, we and the McGreevey plaintiffs entered into an agreement to settle all claims brought by the McGreevey plaintiffs in all of the actions described above, wherein the McGreevey plaintiffs executed a covenant not to execute against us, and we quit claimed 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. In November 2006, this agreement was approved by the Delaware Bankruptcy Court and the claims were discharged. The plaintiffs’ attorneys and we filed a joint motion to dismiss the claims against us in the McGreevey lawsuits and no objections were filed. On March 16, 2007, the federal court in Montana denied the motions to dismiss us from the McGreevey lawsuits, questioning the benefits of the settlement to be received by the class members in the settlement and the authority of the plaintiffs’ counsel to have negotiated the settlement without a class having been certified by the federal court. We believe that the settlement agreement, which was approved by the Delaware Bankruptcy Court in our bankruptcy case, is valid. The Bankruptcy Court in the Touch America case currently has under advisement a decision on whether or not the claims raised by the McGreevey plaintiffs are part of the bankruptcy estate of Touch America. This decision may determine if we need to file any further motions with the Montana federal court.

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 entered into a settlement agreement which provided that NorthWestern would 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. Under the proposed agreement, the Board could 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. In December 2006 the federal court indicated it would not approve the settlement because it did not provide any benefit to the class members. Based on the federal court’s order, the plaintiffs agreed to dismiss the lawsuit with prejudice on the condition that the federal court would retain jurisdiction over any award of attorneys’ fees. The plaintiffs’ motion seeking discovery in advance of its motion for an award of attorneys’ fees was denied. Plaintiffs have filed a motion for attorneys’ fees and costs seeking $9.9 million on the grounds that the Board’s acceptance of the BBI offer was attributable to their efforts. We have

responded arguing that plaintiffs opposed all of the Board’s efforts leading to the BBI transaction and that its lawyers are thus entitled to no fees. The plaintiffs filed a reply in May 2007. On May 24, 2007, we notified the federal court of the MPSC unanimous direction to its staff to draft an order rejecting the proposed BBI transaction, noting that unless the BBI transaction was approved, the plaintiffs’ argument for benefit to the estate would be moot and suggested that the federal court delay any ruling until the MPSC reaches a final decision on the BBI transaction. On July 25, 2007, we advised the federal court that the Merger Agreement was terminated based on the action by the MPSC denying consideration of the revised proposal and denying approval of the transaction. We are awaiting a decision by the federal court and we believe that any award of attorneys' fees would be reimbursed by insurance proceeds.

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. We unsuccessfully engaged in mediation of this dispute in November 2005 and September 2006. We recorded a loss of $2.6 million in November 2005 to reestablish a liability for the present value of amounts due to these former employees under their supplemental retirement contracts, paid all past due amounts plus interest and reestablished monthly payments to these former employees under the terms of their contracts. In February 2007, a jury verdict was rendered against us in Montana state court, which ordered us to pay $17.4 million in compensatory and $4.0 million in punitive damages in a case called Ammondson, et al. v. NorthWestern Corporation, et al. Due to the verdict, we recognized a loss of $19.0 million in our 2006 results of operations to increase our recorded liability related to this claim. The Montana state court reviewed the amount of the punitive damages under state law and did not alter the amount. We have appealed the judgment and posted a $25.8 million bond. We intend to vigorously pursue the appeal; however, there can be no assurance that we will prevail in our efforts. We expect to incur additional legal and court costs related to these proceedings.

During the second quarter of 2007 we voluntarily informed the Federal Energy Regulatory Commission (FERC) of several potential regulatory compliance issues related to our natural gas business. The FERC has initiated a nonpublic, informal investigation. We cannot currently predict the outcome of the FERC’s investigation.

In December 2006, the MPSC issued an order finalizing certain qualifying facility rates for the periods July 1, 2003 through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a qualifying facility with which we have a power purchase agreement through 2025. CELP filed a complaint against NorthWestern and the MPSC in Montana district court on July 6, 2007. Under the terms of the power purchase agreement with CELP, energy and capacity rates were fixed through June 30, 2004 and beginning July 1, 2004 through the end of the contract energy and capacity rates are to be determined each year pursuant to a formula. If the MPSC’s order is upheld in its current form, we anticipate reducing our QF liability by approximately $25 million as our estimate of energy and capacity rates for the remainder of the contract period would be reduced. CELP is disputing the methodology, used by us and approved by the MPSC, to calculate energy and capacity payments for the contract years 2004 and 2005. CELP is claiming that NorthWestern breached the power purchase agreement causing damages, which CELP asserts are not presently known but believed to be approximately $22 million for contract years 2004 and 2005. We believe CELP has no basis for their complaint and we are currently evaluating our next course of action.

Relative to our leasehold interest in Colstrip Unit 4, the Mineral Management Service of the United States Department of Interior (MMS) issued two orders to Western Energy Company (WECO) in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 and 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 and 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31,

2001. On April 28, 2005, the appeals division of the MMS issued an order that reduced the amount claimed due to the application of statute of limitations. The state of Montana issued a demand to WECO in May 2005 consistent with the MMS position outlined above on these transportation revenues. Further, on September 28, 2006, the MMS issued an order to pay additional royalties on the basis of an audit of WECO’s royalty payments during the three years 2002 to 2004. WECO has appealed these orders and we are monitoring the process. The Colstrip Units 3 and 4 owners and WECO currently dispute the responsibility of the expenses if the MMS position prevails. We believe that the Colstrip Units 3 and 4 owners have reasonable defenses in this matter. However, if the MMS position prevails and WECO prevails in passing the expense responsibility to the owners, our share of the alleged additional royalties would be 15 percent, or approximately $1.2 million, and ongoing royalty expenses related to coal transportation.

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.

On March 13, 2007 we completed the purchase from Mellon Leasing Corporation (Mellon) of Mellon’s Owner Participant interest in the 740 megawatt (MW) demonstrated-capacity coal-fired steam electric generation unit known as Colstrip Unit 4 for an aggregate purchase price of approximately $40.2 million, which includes applicable closing costs. The transaction involved a transfer by Mellon to us of its Owner Participant interest in the Owner Trust that holds title to Mellon’s beneficial interest. The Owner Participant interest acquired represents approximately 79 MWs of our 222 MW interest. We remain the lessee of that interest under the lease from the Owner Trustee. The transaction does not result in any change in control over, or operation of, Colstrip Unit 4.

In accordance with FIN 46R, we have consolidated the Owner Trust, which was determined to be a VIE. As a result of this consolidation, approximately $20.4 million of electric generation property, plant and equipment and non-recourse long-term debt (which is secured by the generation assets) are included on our consolidated balance sheet as of June 30, 2007. The debt was incurred by the Owner Trust to finance the initial purchase of the undivided interest in Colstrip Unit 4.

South Dakota Natural Gas Rate Case – In June 2007, we filed a request with the South Dakota Public Utilities Commission for a natural gas distribution revenue increase of $3.7 million. We are currently awaiting the establishment of a procedural schedule.

Nebraska Natural Gas Rate Case– In June 2007, we filed a request with the Nebraska Public Service Commission for a natural gas distribution revenue increase of $2.8 million. We will negotiate the rate case directly with the cities we serve in Nebraska.

FERC Transmission Rate Case – In October 2006, we filed a request with the FERC for an electric transmission revenue increase. Our requested increase pertains only to FERC jurisdictional wholesale transmission and retail choice customers representing approximately $8.6 million in revenue. In May 2007, we implemented interim rates, which are subject to refund plus interest pending final resolution. We are currently involved in settlement discussions with intervenors.

Montana Electric and Natural Gas Rate Case – In July 2007, we filed a request with the MPSC for a electric transmission and distribution revenue increase of $31.4 million, and a natural gas transmission, storage and distribution revenue increase of $10.5 million. We are currently awaiting the establishment of a procedural schedule.

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 640,000 customers in Montana, South Dakota and Nebraska. For a 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, 2006.

On April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with BBI, an infrastructure investment company listed on the Australian Stock Exchange, under which BBI would acquire NorthWestern Corporation in an all-cash transaction at $37 per share. We had received all approvals necessary for the transaction, except from the Montana Public Service Commission (MPSC).On May 22, 2007 the MPSC unanimously directed its staff to draft an order denying the transaction. On June 25, 2007, we and BBI filed a formal joint request asking the MPSC to consider a revised proposal. In connection with our joint request to the MPSC, we and BBI agreed that if the MPSC denied the revised application, then either party in their sole discretion could terminate the Merger Agreement. On July 24, 2007, the MPSC denied the joint request and BBI terminated the Merger Agreement. The MPSC issued a final written order on July 31, 2007.

The following is a summary of our results of operations for the three and six months ended June 30, 2007 and 2006. 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 June 30, 2007 Compared with the Three Months Ended June 30, 2006

	Three Months Ended June 30,
		2007			2006			Change		% Change
		(in millions)
Operating Revenues
Regulated Electric	$	170.6		$	151.0		$	19.6		13.0		%
Regulated Natural Gas		62.0			58.2			3.8		6.5
Unregulated Electric		14.6			13.7			0.9		6.6
Unregulated Natural Gas		16.7			17.0			(0.3	)	(1.8	)
Other		—			0.1			(0.1	)	(100.0	)
Eliminations		(4.3	)		(7.8	)		3.5		(44.9	)
	$	259.6		$	232.2		$	27.4		11.8		%

	Three Months Ended June 30,
		2007			2006			Change	% Change
		(in millions)
Cost of Sales
Regulated Electric	$	87.9		$	71.5		$	16.4	22.9		%
Regulated Natural Gas		36.9			35.6			1.3	3.7
Unregulated Electric		4.2			3.0			1.2	40.0
Unregulated Natural Gas		16.2			15.1			1.1	7.3
Other		—			—			—	—
Eliminations		(4.0	)		(7.5	)		3.5	(46.7	)
	$	141.2		$	117.7		$	23.5	20.0		%

	Three Months Ended June 30,
		2007			2006			Change		% Change
		(in millions)
Gross Margin
Regulated Electric	$	82.7		$	79.5		$	3.2		4.0		%
Regulated Natural Gas		25.1			22.6			2.5		11.1
Unregulated Electric		10.4			10.7			(0.3	)	(2.8	)
Unregulated Natural Gas		0.5			1.9			(1.4	)	(73.7	)
Other		—			0.1			(0.1	)	(100.0	)
Eliminations		(0.3	)		(0.3	)		—		—
	$	118.4		$	114.5		$	3.9		3.4		%

Consolidated gross margin for the three months ended June 30, 2007 was $118.4 million, an increase of $3.9 million, or 3.4%, as compared with gross margin of $114.5 million in the second quarter of 2006. Margins in our regulated electric segment increased $3.2 million primarily due to customer growth. Margin in our regulated natural gas segment increased $2.5 million primarily due to higher volumes from colder weather in our Montana service territory. Offsetting these increases was a decrease of $1.4 million in unregulated natural gas margin primarily due to a renegotiated gas supply and management services contract and lower volumes.

Consolidated operating, general and administrative expenses were $58.7 million for the three months ended June 30, 2007 as compared with $68.6 million in the second quarter of 2006. Transaction related costs pursuant to the proposed BBI acquisition accounted for approximately $7.0 million of the decrease. In addition, lease expense decreased by $3.1 million mainly due to our purchase of the Owner Participant interest in a portion of the Colstrip Unit 4 generating facility in March 2007. With this purchase, our annual lease expense (a component of operating, general and administrative expenses) will decrease by approximately $7.8 million. These decreases were partially offset by increased expense related to restricted stock awards granted in 2006 of $2.0 million.

Property and other taxes were $20.6 million for the three months ended June 30, 2007 as compared with $18.7 million in 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 protested approximately $11.6 million and $16.3 million of our 2005 and 2006 property taxes, respectively, and are currently appealing our 2005 valuation before the State Tax Appeal Board in Montana. We have recognized our property tax expense based on the total amount billed (including amounts protested), 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, we are allowed to track the changes in the actual level of state and local taxes and fees and recover these amounts in rates; however the MPSC has only authorized recovery of approximately 60% of this increase for the last three years.

Depreciation expense was $20.8 million for the three months ended June 30, 2007 as compared with $18.8 million in the second quarter of 2006.

Consolidated operating income for the three months ended June 30, 2007 was $18.2 million, as compared with $8.4 million in the second quarter of 2006. This $9.8 million improvement was primarily due to higher margins and lower operating expenses as discussed above.

Consolidated other income for the three months ended June 30, 2007 was $0.4 million, a decrease of $2.7 million from the second quarter of 2006. This decrease was primarily due to the inclusion in 2006 results of a $2.3 million gain on the sale of a partnership interest in oil and gas properties.

Consolidated provision for income taxes for the three months ended June 30, 2007 was $1.6 million as compared to a benefit of $0.3 million in the second quarter of 2006.

Consolidated net income for the three months ended June 30, 2007 was $2.4 million, an improvement of $4.8 million as compared to a consolidated net loss of $2.4 million in the second quarter of 2006. This improvement was primarily related to higher margins and lower operating expenses. Lower other income and higher income taxes partially offset this increase.

Six Months Ended June 30, 2007 Compared to the Six Months Ended June 30, 2006

	Six Months Ended June 30,
		2007			2006			Change		% Change
		(in millions)
Operating Revenues
Regulated Electric	$	349.1		$	319.1		$	30.0		9.4		%
Regulated Natural Gas		220.2			217.7			2.5		1.1
Unregulated Electric		36.8			38.5			(1.7	)	(4.4	)
Unregulated Natural Gas		32.8			50.6			(17.8	)	(35.2	)
Other		—			0.2			(0.2	)	(100.0	)
Eliminations		(12.8	)		(32.4	)		19.6		60.5
	$	626.1		$	593.7		$	32.4		5.5		%

	Six Months Ended June 30,
		2007			2006			Change		% Change
		(in millions)
Cost of Sales
Regulated Electric	$	180.7		$	160.6		$	20.1		12.5		%
Regulated Natural Gas		152.1			154.7			(2.6	)	(1.7	)
Unregulated Electric		8.4			6.4			2.0		31.3
Unregulated Natural Gas		31.2			47.0			(15.8	)	(33.6	)
Other		—			0.1			(0.1	)	(100.0	)
Eliminations		(11.9	)		(31.4	)		19.5		62.1
	$	360.5		$	337.4		$	23.1		6.8		%

	Six Months Ended June 30,
		2007			2006			Change		% Change
		(in millions)
Gross Margin
Regulated Electric	$	168.4		$	158.5		$	9.9		6.2		%
Regulated Natural Gas		68.1			63.0			5.1		8.1
Unregulated Electric		28.4			32.1			(3.7	)	(11.5	)
Unregulated Natural Gas		1.6			3.6			(2.0	)	(55.6	)
Other		—			0.1			(0.1	)	(100.0	)
Eliminations		(0.9	)		(1.0	)		0.1		10.0
	$	265.6		$	256.3		$	9.3		3.6		%

Consolidated gross margin for the six months ended June 30, 2007 was $265.6 million, an increase of $9.3 million, or 3.6%, over gross margin of $256.3 million in 2006. Margins in our regulated electric segment increased $9.9 million due to increased volumes driven by customer growth, and higher cost of sales in 2006 due to a $4.1 million loss recorded as a result of a stipulation with the Montana Consumer Counsel. Margin in our regulated natural gas segment increased $5.1 million primarily due to colder weather and 1.9% customer growth. Offsetting these increases was a decrease of $3.7 million in unregulated electric margin primarily due to lower average prices, higher fuel supply costs, and the inclusion in 2006 results of a $1.3 million reduction to cost of sales related to the settlement of put options. An increase in volumes resulting from higher demand partly offset these decreases. Margins in our unregulated natural gas segment decreased $2.0 million primarily due to a renegotiated gas supply and management services contract and lower volumes.

Consolidated operating, general and administrative expenses were $121.1 million for the six months ended June 30, 2007 as compared with $130.0 million in same period of 2006. This decrease was primarily due to lower transaction related costs pursuant to the proposed BBI acquisition as discussed above, and reduced lease expense of $4.1 million for our Colstrip Unit 4 generating facility, offset by increased expense related to restricted stock awards granted in 2006 of $3.9 million.

Property and other taxes were $41.3 million for the six months ended June 30, 2007 as compared with $38.2 million in 2006. This increase was primarily due to a higher valuation assessment in our Montana service territory as discussed above.

Depreciation expense was $40.7 million for the six months ended June 30, 2007 as compared with $37.6 million in 2006 primarily due to higher plant and property in service.

Consolidated operating income for the six months ended June 30, 2007 was $62.6 million, as compared with $50.5 million in 2006. This $12.1 million increase was primarily due to higher margins and lower operating expenses as discussed above.

Consolidated interest expense for the six months ended June 30, 2007 was $27.7 million as compared with $29.1 million in 2006. This decrease was primarily attributable to refinancing transactions completed in 2006. Partially offsetting this decrease was interest on debt assumed related to the purchase of Owner Participant interest in a portion of the Colstrip Unit 4 generating facility in March 2007. We expect annual interest expense to increase by approximately $2.6 million as a result of this purchase.

Consolidated other income for the six months ended June 30, 2007 was $0.7 million, a decrease of $7.7 million from 2006. This decrease was primarily due to the inclusion in 2006 results of gains of $3.8 million related to an interest rate swap and $2.3 million on the sale of a partnership interest in oil and gas properties.

Consolidated provision for income taxes for the six months ended June 30, 2007 was $14.0 million as compared with $11.7 million in 2006. Our effective tax rate for 2007 was 39.3% as compared to 39.1% for 2006. Portions of our BBI transaction related costs were considered non-deductible for taxes in 2006 and 2007; however, with the termination of the agreement these costs may be become deductible. If we determine some or all of these costs to be deductible, our income tax expense may be reduced by approximately $1.5 million during the third or fourth quarter of 2007.

Consolidated net income for the six months ended June 30, 2007 was $21.6 million, an increase of $3.0 million, or 16.1%, over $18.6 million in 2006. This improvement was primarily related to higher margins, lower operating expenses, and lower interest expense. A decrease in other income and higher income taxes partially offset this increase.

Three Months Ended June 30, 2007 Compared with the Three Months Ended June 30, 2006

			Results
			2007				2006				Change			% Change
			(in millions)
	Electric supply revenue	$		85.5		$		68.3		$		17.2			25.2		%
	Transmission & distribution revenue			68.3				65.7				2.6			4.0
	Rate schedule revenue			153.8				134.0				19.8			14.8
	Transmission			13.3				13.6				(0.3	)		(2.2	)
	Wholesale			1.1				1.4				(0.3	)		(21.4	)
	Miscellaneous			2.4				2.0				0.4			20.0
	Total Revenues			170.6				151.0				19.6			13.0		%
	Supply costs			84.2				67.6				16.6			24.6
	Wholesale			0.4				0.6				(0.2	)		(33.3	)
	Other cost of sales			3.3				3.3				—			—
	Total Cost of Sales			87.9				71.5				16.4			22.9		%
	Gross Margin	$		82.7		$		79.5		$		3.2			4.0		%
% GM/Rev			48.5		%		52.6		%

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 June 30, 2007 increased $19.8 million, or 14.8% over results in the second quarter of 2006. Electric supply revenue, which consists of supply costs that are collected in rates from customers, increased $17.2 million primarily due to higher average prices. In addition, transmission and distribution revenue increased $2.6 million due to customer growth.

Gross margin for the three months ended June 30, 2007 increased $3.2 million, or 4.0% as compared with the second quarter of 2006. This increase was due to increased volumes from customer growth.

Regulated retail electric volumes for the three months ended June 30, 2007 totaled 2,302,165 MWHs, which increased slightly as compared with 2,284,545 MWHs in the same period in 2006 due primarily to a 1.7% increase in customer growth. Although the weather was warmer in our service territories in 2007 as compared with 2006, our customer usage during the second quarter is not driven by these changes. Regulated wholesale electric volumes in the second quarter of 2007 were 33,446 MWHs, a decrease from 42,426 MWHs in the same period in 2006 resulting from plant down time due to maintenance.

Six Months Ended June 30, 2007 Compared to the Six Months Ended June 30, 2006

			Results
			2007				2006					Change			% Change
			(in millions)
	Electric supply revenue	$			176.3		$		150.5		$		25.8			17.1		%
	Transmission & distribution revenue				141.7				136.4				5.3			3.9
	Rate schedule revenue				318.0				286.9				31.1			10.8
	Transmission				23.8				23.8				—			—
	Wholesale				2.3				4.4				(2.1	)		(47.7	)
	Miscellaneous				5.0				4.0				1.0			25.0
	Total Revenues				349.1				319.1				30.0			9.4		%
	Supply costs				173.7				153.1				20.6			13.5
	Wholesale				0.9				1.6				(0.7	)		(43.8	)
	Other cost of sales				6.1				5.9				0.2			3.4
	Total Cost of Sales				180.7				160.6				20.1			12.5		%
	Gross Margin	$			168.4		$		158.5		$		9.9			6.2		%
% GM/Rev				48.2		%		49.7		%

Electric rate schedule revenue for the six months ended June 30, 2007 increased $31.1 million, or 10.8% over results in 2006. Electric supply revenue, which consists of supply costs that are collected in rates from customers, increased $25.8 million due to $22.0 million, or 2.2%, higher average prices and a $3.8 million, or 1.9%, increase in volumes due to customer growth. This customer growth was also the primary cause of the $5.3 million increase in transmission and distribution revenue.

Wholesale revenues are derived from our joint ownership in generation facilities. Excess power not used by our South Dakota customers is sold in the wholesale market. These revenues for the six months ended June 30, 2007 decreased $2.1 million, or 47.7%, as compared with the same period in 2006, primarily due to a $1.7 million, or 42.0% decrease in volumes sold in the secondary markets and $0.4 million, or 8.4%, lower average prices. We had less wholesale energy available to sell due to decreased plant availability resulting from maintenance.

Gross margin for the six months ended June 30, 2007 increased $9.9 million, or 6.2% as compared with the same period in 2006. This improvement was due to increased volumes driven by customer growth, and higher cost of sales in 2006 due to a $4.1 million loss recorded as a result of a stipulation with the Montana Consumer Counsel. This increase was partly offset by lower wholesale sales in the secondary market.

Regulated retail electric volumes for the six months ended June 30, 2007 totaled 4,834,776 MWHs, which increased 1.9% as compared with 4,745,751 MWHs in the same period in 2006 due primarily to customer growth. Regulated wholesale electric volumes in 2007 were 65,008 MWHs, a decrease from 112,298 MWHs in the same period in 2006 resulting from increased plant down time due to maintenance. We expect lower volumes through mid-October due to scheduled maintenance.

Three Months Ended June 30, 2007 Compared with the Three Months Ended June 30, 2006

			Results
			2007				2006				Change			% Change
			(in millions)
Gas supply revenue	$	33.8			$	34.7			$	(0.9		)	(2.6		)	%
Transportation, distribution & storage revenue		18.5				16.9				1.6			9.5
Rate schedule revenue		52.3				51.6				0.7			1.4
Transportation & storage		6.0				4.9				1.1			22.4
Wholesale revenue		2.5				0.3				2.2			733.3
Miscellaneous		1.2				1.4				(0.2		)	(14.3		)
Total Revenues		62.0				58.2				3.8			6.5			%
Supply costs		33.8				34.8				(1.0		)	(2.9		)
Wholesale supply costs		2.5				0.3				2.2			733.3
Other cost of sales		0.6				0.5				0.1			20.0
Total Cost of Sales		36.9				35.6				1.3			3.7			%
Gross Margin	$	25.1			$	22.6			$	2.5			11.1			%
% GM/Rev		40.5		%		38.8		%

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 June 30, 2007 increased $0.7 million, or 1.4% from results in the second quarter of 2006. Gas supply revenues, which consist of supply costs that are collected in rates from customers, decreased $0.9 million, or 2.6%, due to $2.4 million, or 6.8% lower average rates partly offset by an increase of $1.5 million due to a 4.7% increase in volumes resulting from colder weather in our Montana service territory and 1.9% customer growth. This volume increase also caused the $1.6 million increase in transportation, distribution and storage revenue.

Transportation revenue consists of revenue earned for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. Transportation and storage revenue increased $1.1 million in the second quarter of 2007 as compared with the second quarter of 2006. Transportation and storage revenues 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, customers that have chosen other commodity suppliers 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 June 30, 2007 increased $2.5 million, or 11.1% over the second quarter of 2006 primarily due to colder weather in our Montana service territory, and increased transportation and storage revenue.

Regulated retail natural gas volumes were 4,774,541 dekatherms during the three months ended June 30, 2007, compared with 4,559,407 dekatherms, an increase of 4.7% over the same period in 2006. This increase was due primarily to colder weather in our Montana service territory and customer growth.

Six Months Ended June 30, 2007 Compared to the Six Months Ended June 30, 2006

			Results
			2007				2006				Change			% Change
			(in millions)
	Gas supply revenue	$		133.8		$		147.1		$		(13.3	)		(9.0	)	%
	Transportation, distribution & storage revenue			55.1				50.8				4.3			8.5
	Rate schedule revenue			188.9				197.9				(9.0	)		(4.5	)
	Transportation & storage			11.5				9.9				1.6			16.2
	Wholesale revenue			16.5				5.9				10.6			179.7
	Miscellaneous			3.3				4.0				(0.7	)		(17.5	)
	Total Revenues			220.2				217.7				2.5			1.1		%
	Supply costs			133.8				147.1				(13.3	)		(9.0	)
	Wholesale supply costs			16.5				5.9				10.6			179.7
	Other cost of sales			1.8				1.7				0.1			5.9
	Total Cost of Sales			152.1				154.7				(2.6	)		(1.7	)	%
	Gross Margin	$		68.1		$		63.0		$		5.1			8.1		%
% GM/Rev			30.9		%		28.9		%

Gas rate schedule revenue for the six months ended June 30, 2007 decreased $9.0 million, or 4.5% from results in 2006. Gas supply revenues, which consist of supply costs that are collected in rates from customers, decreased $13.3 million, or 9.0%, due to $24.0 million, or 16.3% lower average rates partly offset by an increase of $10.7 million due to an 8.7% increase in volumes resulting from colder weather and customer growth. This volume increase also caused the $4.3 million increase in transportation, distribution and storage revenue.

Transportation revenue consists of revenue earned for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. Transportation and storage revenue increased $1.6 million in the six months ended June 30, 2007 as compared with the same period in 2006. Transportation and storage revenues 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, customers that have chosen other commodity suppliers may utilize storage to secure lower priced summer gas production for use during the winter season.

Wholesale revenue increased $10.6 million, or 179.7%, 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 six months ended June 30, 2007 increased $5.1 million, or 8.1% over the same period in 2006 primarily due to colder weather and customer growth.

Regulated retail natural gas volumes were 17,811,258 dekatherms during the six months ended June 30, 2007, compared with 16,388,652 dekatherms, an increase of 8.7% over the same period in 2006. This increase was due primarily to colder weather and customer growth.

Three Months Ended June 30, 2007 Compared with the Three Months Ended June 30, 2006

Our unregulated electric segment primarily consists of our lease and ownership 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 of base-load energy from Colstrip Unit 4 will be supplied to 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 increased $0.9 million, or 6.6%, for the three months ended June 30, 2007 primarily due to 27.4% higher volumes, partially offset by lower average contracted prices. During the second quarter of 2006 strong hydro generation in the Pacific Northwest provided increased supply in the wholesale electricity market, resulting in reduced demand for our Colstrip power.

Gross margin decreased slightly with higher volumes offset by an increase in fuel supply costs.

Unregulated electric volumes were 307,027 MWHs in the second quarter of 2007, an increase over 241,113 MWHs in the same period in 2006. The 2007 increase was primarily due to increased demand as compared to the same period in 2006. Strong hydro generation during the second quarter of 2006 provided increased supply in the wholesale electricity market, resulting in reduced demand for our Colstrip power.

Six Months Ended June 30, 2007 Compared to the Six Months Ended June 30, 2006

		Results
				2007				2006				Change			% Change
		(in millions)
	Total Revenues		$		36.8		$		38.5		$		(1.7	)		(4.4	)	%
	Supply costs				6.9				4.8				2.1			43.8
	Wheeling costs				1.5				1.6				(0.1	)		(6.3	)
	Total Cost of Sales		$		8.4		$		6.4		$		2.0			31.3		%
	Gross Margin		$		28.4		$		32.1		$		(3.7	)		(11.5	)	%
% GM/Rev				77.2		%		83.4		%

Unregulated electric revenue decreased $1.7 million, or 4.4%, for the six months ended June 30, 2007 primarily due to lower average contracted prices partially offset by higher volumes. The higher volumes in 2007 were primarily due to reduced demand in 2006 as discussed above along with decreased plant availability.

Gross margin decreased $3.7 million, or 11.5%, due primarily to lower average contracted prices, higher fuel supply costs, and the inclusion in 2006 results of a $1.3 million reduction to cost of sales related to the settlement of put options. An increase in volumes resulting from higher demand partly offset these decreases.

Unregulated electric volumes were 735,342 MWHs for the six months ended June 30, 2007, an increase over 662,318 MWHs in 2006. This increase was primarily due to increased demand in 2007 as discussed above.

Three Months Ended June 30, 2007 Compared with the Three Months Ended June 30, 2006

Our unregulated natural gas segment reflects the operations of our subsidiary, NorthWestern Services, LLC (NSC), which provides natural gas supply and management services. In addition, this segment also reflects the results of our unregulated Montana retail propane operations. During the first quarter of 2007, we merged NSC’s subsidiary, Nekota Resources LLC (Nekota), into NorthWestern Corporation. We also transferred certain customers to our regulated natural gas segment. We are currently evaluating our unregulated natural gas business and we expect to sell the remaining unregulated natural gas business or move the remaining customers and contracts to our regulated natural gas segment during 2007.

Unregulated natural gas revenue decreased $0.3 million, or 1.8%, due primarily to a renegotiated gas supply and management services contract and the transfer of Nekota and certain customers to our regulated natural gas segment. We expect revenues and supply costs to continue to decline during 2007.

Gross margin decreased $1.4 million, or 73.7%, for the three months ended June 30, 2007 as compared with the same period in 2006 primarily due to a renegotiated gas supply and management services contract and the transfer of Nekota and certain customers to our regulated natural gas segment.

Unregulated wholesale natural gas volumes delivered totaled 2,277,524 dekatherms in 2007, compared with 4,122,328 dekatherms in 2006. This decrease was due primarily to the transfer of Nekota and certain customers to our regulated natural gas segment.

Six Months Ended June 30, 2007 Compared to the Six Months Ended June 30, 2006

Unregulated natural gas revenue decreased $17.8 million, or 35.2%, due primarily to a renegotiated gas supply and management services contract and the transfer of Nekota and certain customers to our regulated natural gas segment. We expect revenues and supply costs to continue to decline during 2007.

Gross margin decreased $2.0 million, or 55.6%, for the six months ended June 30, 2007 as compared with the same period in 2006 primarily due to a renegotiated gas supply and management services contract and the transfer of Nekota and certain customers to our regulated natural gas segment.

Unregulated wholesale natural gas volumes delivered totaled 6,185,529 dekatherms in 2007, compared with 9,661,502 dekatherms in 2006. This decrease was due primarily to the transfer of Nekota and certain customers to our regulated natural gas segment.

We utilize our revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to reduce borrowings. As a result, as of June 30, 2007, we had no cash and cash equivalents, and revolver availability of $143.8 million. During the six months ended June 30, 2007, we used existing cash to repay $33.9 million of debt, including repayments of $30.0 million on our revolver. In addition to these repayments, we paid dividends on common stock of $22.3 million, property tax payments of approximately $38 million, our semi-annual Colstrip Unit 4 operating lease payment of approximately $16.1 million, completed the purchase of the owner participant interest in a portion of the Colstrip Unit 4 generating facility for approximately $40.2 million, and contributed $21.1 million to our pension plans.

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 revolving 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. As of June 30, 2007, we are over collected on our current Montana natural gas and electric trackers by approximately $20.7 million, as compared with $0.5 million as of June 30, 2006. This overcollection is primarily due to increases phased into our electric supply rates during 2007 in anticipation of contract changes leading to higher supply prices. This phase in of increases will distribute the impact of supply cost increases over the next annual tracking period.

		Six Months Ended June 30,
		2007			2006
Continuing Operating Activities
Net income	$	21.6		$	18.6
Non-cash adjustments to net income		58.3			44.2
Proceeds from hedging activities		—			6.3
Changes in working capital		66.0			14.8
Other		(9.7	)		10.0
		136.2			93.9
Continuing Investing Activities
Property, plant and equipment additions		(52.6	)		(45.3	)
Sale of assets		0.6			23.3
Proceeds from hedging activities		—			5.3
Colstrip Unit 4 acquisition		(40.2	)		—
		(92.2	)		(16.7	)
Continuing Financing Activities
Net repayment of debt		(33.9	)		(41.6	)
Dividends on common stock		(22.3	)		(22.0	)
Deferred gas storage		—			(11.7	)
Other		10.3			(9.3	)
		(45.9	)		(84.6	)
Discontinued Operations		—			7.7
Net Increase in Cash and Cash Equivalents	$	(1.9	)	$	0.3
Cash and Cash Equivalents, beginning of period	$	1.9		$	2.7
Cash and Cash Equivalents, end of period	$	—		$	3.0

As of June 30, 2007, we had no cash and cash equivalents, as compared with $1.9 million at December 31, 2006 and $3.0 million at June 30, 2006. Cash provided by continuing operating activities totaled $136.2 million for the six months ended June 30, 2007 as compared with $93.9 million during the six months ended June 30, 2006. This increase in operating cash flows was primarily related to an overcollection in our electric tracker which is discussed above in the “Factors Impacting Our Liquidity” section, and decreased purchases of storage gas and higher net income, offset by the change in timing of the funding of our pension plans to the second quarter of 2007 as compared with the third quarter of 2006.

Cash used in investing activities of continuing operations totaled $92.3 million during the six months ended June 30, 2007, as compared with $16.7 million during the six months ended June 30, 2006. During the six months ended June 30, 2007 we used $40.2 million to complete the purchase of the Owner Participant interest in a portion of the Colstrip Unit 4 generating facility, and $52.6 million for property, plant and equipment additions. During the six months ended June 30, 2006, we received cash proceeds from the sale of assets of approximately $23.3 million and $5.3 million from the settlement of hedges, offset by cash used of approximately $45.3 million for property, plant and equipment additions.

Cash used in financing activities of continuing operations totaled $45.9 million during the six months ended June 30, 2007, as compared with $84.6 million during the six months ended June 30, 2006. During the six months ended June 30, 2007 we made debt repayments of $33.9 million and paid dividends on common stock of $22.3 million, offset by cash proceeds of $10.6 million received from the exercise of warrants. During the six months ended June 30, 2006 we made debt repayments of $41.6 million, paid dividends on common stock of $22.0 million, and paid $11.7 million for deferred storage transactions. Cash used to repurchase shares during the six months ended June 30, 2006 was approximately $3.7 million. In addition, in association with our pollution control obligation refinancing transaction completed in the second quarter of 2006, we capitalized $5.7 million of financing costs.

We believe that our 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 August 3, 2007, our availability under our revolving line of credit was approximately $148.4 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 June 30, 2007. See our Annual Report on Form 10-K for the year ended December 31, 2006 for additional discussion.

		Total		2007		2008		2009		2010		2011			Thereafter
	(in thousands)
Long-term Debt (1)	$	691,778	$	6,681	$	10,115	$	30,927	$	12,366	$		6,578	$	625,111
Capital Leases	41,426		1,047		1,677		1,259		1,174		1,265			35,004
Future Minimum Operating Lease Payments (1)	231,646		17,306		33,442		32,701		32,346		14,520			101,331
Estimated Pension and Other Postretirement Obligations (2)	97,160		2,120		26,490		22,870		23,340		22,340			N/A
Qualifying Facilities (3)	1,547,889		58,420		60,574		62,598		64,580		66,067			1,235,650
Supply and Capacity Contracts (4)	2,051,444		311,509		431,061		301,224		279,342		142,548			585,760
Contractual Interest Payments on Debt (5)	412,513		19,926		40,207		39,013		36,846		35,830			240,691
Total Commitments	$	5,073,856	$	417,009	$	603,566	$	490,592	$	449,994	$		289,148	$	2,823,547

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. Our current ratings with these agencies are as follows:

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us and impacts our trade credit availability. Our credit ratings have remained consistent during 2007.

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 June 30, 2007, 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, 2006. 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 June 30, 2007, a 1% increase in the LIBOR would increase annual interest expense on this line of credit by approximately $0.2 million.

Commodity price risk is one of 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 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 historically 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 annual 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 the end of the period covered by this report, our disclosure controls and procedures are effective.

There have been no changes in our internal control over financial reporting during the three months ended June 30, 2007 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.

We have incurred, and may continue to incur, significant costs associated with outstanding litigation, 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 laws and regulations that affect our industry and our operations, which could have a material adverse effect on our results of operations and financial condition.

We are subject to regulation by federal and state governmental entities, including the FERC, MPSC, SDPUC and NPSC. Regulations can affect allowed rates of return, recovery of costs and operating requirements. In addition, existing regulations may be revised or reinterpreted, new laws, regulations, and interpretations thereof may be adopted or become applicable to us and future changes in laws and regulations may have a detrimental effect on our business.

Our rates are approved by our respective commissions and are effective until new rates are approved. In addition, supply costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover costs in rates or adjustment clauses could have a material adverse effect on our cash flow and financial position.

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 and liquidity.

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. To the extent our energy 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.

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 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 interest could be impaired if we are unable to obtain adequate terms on 132 megawatts of power that are not under contract after 2010.

Beginning July 1, 2007, 90 megawatts of base-load energy from Colstrip Unit 4 will be supplied to the Montana default supply for a term of 11.5 years, at an average nominal price of $35.80 per megawatt hour. 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 generation assets. If we are unable to sell the 132 megawatts at such a sufficient price, then the value of our Colstrip Unit 4 interest would be materially adversely impacted.

Our jointly owned electric generating facilities and our interest in Colstrip Unit 4 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 I 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 liquidity.

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas 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 in Montana, 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 require 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 private tort allegations or government claims 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 $20.4 million to $56.1 million. We had an environmental reserve of $33.9 million at June 30, 2007. 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.

We must meet certain credit quality standards. If we are unable to maintain an investment grade credit rating, we would be required under certain credit agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect our liquidity and /or access to capital.

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.

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.

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

For the quarterly period ended June 30, 2007

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 — June 30, 2007 and December 31, 2006		5
	Consolidated Statements of Income (Loss) — Three and Six Months Ended June 30, 2007 and 2006		6
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2007 and 2006		7
	Notes to Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		39
Item 4.	Controls and Procedures		40
PART II. OTHER INFORMATION			41
Item 1.	Legal Proceedings		41
Item 1A.	Risk Factors		41
Item 6.	Exhibits		43
SIGNATURES			44

	Six Months Ended June 30, 2007	Six Months Ended June 30, 2006
Basic computation	35,854,902	35,547,310
Dilutive effect of
Restricted shares	530,655	35,164
Stock warrants	1,469,097	1,156,109
Diluted computation	37,854,654	36,738,583

		June 30, 2007		December 31, 2006
Regulated electric	$	241,100	$	295,377
Regulated natural gas		114,028		139,699
Unregulated electric		—		—
Unregulated natural gas		—		—
	$	355,128	$	435,076

	Three Months Ended June 30, 2007	Three Months Ended June 30, 2006
Basic computation	35,988,340	35,510,760
Dilutive effect of
Restricted shares	530,655	—
Stock warrants	1,355,872	—
Diluted computation	37,874,867	35,510,760

	Three Months Ended June 30,
			2007			2006			Change			% Change
	(in millions)
Operating Expenses
Operating, general and administrative		$		58.7	$		68.6	$		(9.9	)		(14.4	)	%
Property and other taxes				20.6			18.7			1.9			10.2
Depreciation				20.8			18.8			2.0			10.6
		$		100.1	$		106.1	$		(6.0	)		(5.7	)	%

	Six Months Ended June 30,
			2007			2006			Change			% Change
			(in millions)
Operating Expenses
Operating, general and administrative		$		121.1	$		130.0	$		(8.9	)		(6.8	)	%
Property and other taxes				41.3			38.2			3.1			8.1
Depreciation				40.7			37.6			3.1			8.2
		$		203.1	$		205.8	$		(2.7	)		(1.3	)	%

	Volumes MWH
	2007		2006		Change			% Change
	(in thousands)
Retail Electric
Residential		564		556		8			1.4		%
Commercial		947		931		16			1.7
Industrial		746		746		—			—
Other		45		52		(7	)		(13.5	)
Total Retail Electric		2,302		2,285		17			0.7		%
Wholesale Electric		33		42		(9	)		(21.4	)	%

Average Customer Counts		2007		2006		Change		% Change
	Montana		325,657		319,744		5,913		1.8	%
	South Dakota		59,403		58,901		502		0.9	%
	Total		385,060		378,645		6,415		1.7	%

	2007 as compared to:
Cooling Degree-Days	2006	Historic Average
Montana	13% warmer	37% warmer
South Dakota	4% warmer	39% warmer

		Volumes Dekatherms
		2007		2006		Change			% Change
		(in thousands)
Retail Gas
	Residential		2,833		2,703		130			4.8		%
	Commercial		1,898		1,815		83			4.6
	Industrial		24		19		5			26.3
	Other		20		22		(2	)		(9.1	)
	Total Retail Gas		4,775		4,559		216			4.7		%

	2007 as compared to:
Heating Degree-Days	2006	Historic Average
Montana	5% colder	11% warmer
South Dakota	4% warmer	17% warmer
Nebraska	12% warmer	23% 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+	Stable

	NORTHWESTERN CORPORATION
Date: August 8, 2007	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.