SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2007

Or

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

For the transition period from to

Commission File Number: 1-10499

NORTHWESTERN CORPORATION

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:

Common Stock, Par Value $.01

37,060,658 shares outstanding at October 26, 2007

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION			4
Item 1.	Financial Statements (Unaudited)		5
	Consolidated Balance Sheets — September 30, 2007 and December 31, 2006		5
	Consolidated Statements of Income — Three and Nine Months Ended September 30, 2007 and 2006		6
	Consolidated Statements of Cash Flows – Nine Months Ended September 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		38
Item 4.	Controls and Procedures		39
PART II. OTHER INFORMATION			40
Item 1.	Legal Proceedings		40
Item 1A.	Risk Factors		40
Item 4.	Submission of Matters to a Vote of Security Holders		42
Item 6.	Exhibits		43
SIGNATURES			44

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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 ability to avoid or mitigate adverse rulings or judgments against us in our pending litigation;

•

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

•

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

•

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

•

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

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.

PART 1. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

		September 30,			December 31,
		2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	4,679		$	1,930
Restricted cash		13,574			15,836
Accounts receivable, net of allowance		102,804			149,793
Inventories		79,801			60,543
Regulatory assets		21,946			31,125
Prepaid energy supply		3,343			2,394
Deferred income taxes		20,525			19
Other		5,734			6,834
Total current assets		252,406			268,474
Property, plant, and equipment, net		1,597,404			1,491,855
Goodwill		355,128			435,076
Regulatory assets		143,748			159,715
Other noncurrent assets		37,022			40,817
Total assets	$	2,385,708		$	2,395,937
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	9,938		$	5,614
Current maturities of capital leases		2,561			2,079
Accounts payable		57,844			78,739
Accrued expenses		192,238			180,278
Regulatory liabilities		37,602			12,226
Total current liabilities		300,183			278,936
Long-term capital leases		38,338			40,383
Long-term debt		671,607			699,041
Deferred income taxes		74,425			113,355
Noncurrent regulatory liabilities		191,637			182,103
Other noncurrent liabilities		336,407			339,348
Total liabilities		1,612,597			1,653,166
Commitments and Contingencies (Note 12)
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 37,180,291 and 36,827,691, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		372			360
Treasury stock at cost		(10,485	)		(9,885	)
Paid-in capital		758,533			727,327
Retained earnings		11,025			10,698
Accumulated other comprehensive income		13,666			14,271
Total shareholders’ equity		773,111			742,771
Total liabilities and shareholders’ equity	$	2,385,708		$	2,395,937

See Notes to Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

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

		2007			2006			2007			2006
OPERATING REVENUES	$	265,863		$	234,637		$	892,036		$		828,305
COST OF SALES		139,021			110,914			499,555				448,312
GROSS MARGIN		126,842			123,723			392,481				379,993
OPERATING EXPENSES
Operating, general and administrative		52,486			52,412			173,611				182,384
Property and other taxes		20,393			18,968			61,645				57,146
Depreciation		20,725			18,853			61,412				56,433
TOTAL OPERATING EXPENSES		93,604			90,233			296,668				295,963
OPERATING INCOME		33,238			33,490			95,813				84,030
Interest Expense		(14,633	)		(13,777	)		(42,380	)			(42,835	)
Other Income (Expense)		909			(397	)		1,646				8,020
Income From Continuing Operations Before Income Taxes		19,514			19,316			55,079				49,215
Income Tax Expense		(6,337	)		(7,918	)		(20,326	)			(19,656	)
Income From Continuing Operations		13,177			11,398			34,753				29,559
Discontinued Operations, Net of Taxes		—			—			—				418
Net Income	$	13,177		$	11,398		$	34,753		$		29,977
Average Common Shares Outstanding		36,471			35,510			36,063				35,535
Basic Earnings per Average Common Share
Continuing operations	$	0.36		$	0.32		$	0.96		$		0.83
Discontinued operations		0.00			0.00			0.00				0.01
Basic	$	0.36		$	0.32		$	0.96		$		0.84
Diluted Earnings per Average Common Share
Continuing operations	$	0.35		$	0.31		$	0.93		$		0.80
Discontinued operations		0.00			0.00			0.00				0.01
Diluted	$	0.35		$	0.31		$	0.93		$		0.81
Dividends Declared per Average Common Share	$	0.33		$	0.31		$	0.95		$		0.93

See Notes to Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
		2007			2006
OPERATING ACTIVITIES:
Net Income	$	34,753		$	29,977
Items not affecting cash:
Depreciation		61,412			56,433
Amortization of debt issue costs, discount and deferred hedge gain		1,211			1,772
Amortization of restricted stock		5,889			1,880
Equity portion of allowance for funds used during construction		(349	)		—
Income from discontinued operations, net of taxes		—			(418	)
Gain on sale of assets		(256	)		(2,292	)
Gain on derivative instruments		—			(4,772	)
Deferred income taxes		18,018			20,931
Proceeds from hedging activities		—			14,547
Changes in current assets and liabilities:
Restricted cash		2,262			(554	)
Accounts receivable		46,989			70,777
Inventories		(19,258	)		(34,340	)
Prepaid energy supply costs		(949	)		(1,684	)
Other current assets		874			(874	)
Accounts payable		(21,378	)		(44,221	)
Accrued expenses		14,683			20,347
Regulatory assets and liabilities		31,832			13,967
Other noncurrent assets		12,030			9,510
Other noncurrent liabilities		(13,892	)		(15,499	)
Cash provided by continuing operating activities		173,871			135,487
INVESTING ACTIVITIES:
Property, plant, and equipment additions		(77,905	)		(75,399	)
Colstrip Unit 4 acquisition		(40,247	)		—
Proceeds from sale of assets		1,466			23,317
Proceeds from hedging activities		—			5,355
Cash used in continuing investing activities		(116,686	)		(46,727	)
FINANCING ACTIVITIES:
Deferred gas storage		—			(11,718	)
Proceeds from exercise of warrants		25,329			340
Treasury stock activity		(600	)		(4,108	)
Dividends on common stock		(34,426	)		(33,043	)
Repayment of long-term debt		(8,448	)		(326,263	)
Line of credit repayments, net		(36,000	)		(36,000	)
Issuance of long term debt		—			320,205
Financing costs		(291	)		(6,874	)
Cash used in continuing financing activities		(54,436	)		(97,461	)
DISCONTINUED OPERATIONS:
Operating cash flows of discontinued operations, net		—			(3,432	)
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		2,749			(1,006	)
Cash and Cash Equivalents, beginning of period		1,930			2,691
Cash and Cash Equivalents, end of period	$	4,679		$	1,685
Supplemental Cash Flow Information:
Cash paid during the period for:
Income Taxes		3,861			112
Interest		31,939			31,338
Significant noncash transactions:
Assumption of debt related to Colstrip Unit 4 acquisition		20,438			—
Additions to property, plant and equipment and capital lease obligations		—			40,210

See Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Reference is made to Notes to Financial Statements

included in NorthWestern Corporation’s Annual Report)

(Unaudited)

(1) Nature of Operations and Basis of Consolidation

We are one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 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 (BBI)

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 $1.5 million during the nine months ended September 30, 2007. Our total transaction related costs since inception were $15.5 million, which have been expensed as incurred.

(3) New Accounting Standards

Accounting Standards Issued

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.

Accounting Standards Adopted

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.

(4) Variable Interest Entities

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 $525.7 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.

(5) Income Taxes

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 $104.6 million as of September 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 September 30, 2008.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the nine months ended September 30, 2007, we have not recognized expense for interest or penalties, and do not have any amounts accrued at September 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.

(6) Goodwill

Our goodwill decreased by approximately $79.9 million during the nine months ended September 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):

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

(7) Other Comprehensive Income

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.

Comprehensive income is calculated as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Net income	$	13,177		$	11,398		$	34,753		$	29,977
Other comprehensive income (loss), net of tax:
Reclassification of net gains on hedging instruments from OCI to net income		(297	)		266			(891	)		(3,619	)
Unrealized gain (loss) on derivative instruments qualifying as hedges, net of tax of $4,686 and ($4,582) in the three and nine months ended September 30, 2006, respectively		—			(150	)		—			12,587
Foreign currency translation		116			—			286			79
Comprehensive income	$	12,996		$	11,514		$	34,148		$	39,024

(8) Risk Management and Hedging Activities

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

Interest Rates

During the second quarter of 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions of approximately $380 million. These swaps 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 $13.1 million and $14.0 million at September 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.

(9) Segment Information

We operate the following business units: (i) regulated electric, (ii) regulated natural gas, (iii) unregulated electric, and (iv) all other, which primarily consists of our remaining unregulated natural gas operations and our unallocated corporate costs. We have changed our management of the unregulated natural gas segment, moved certain customers to our regulated natural gas business unit and sold several customer contracts during 2007; therefore, the unregulated natural gas business unit will no longer be considered a reportable segment under SFAS No. 131. We have two remaining unregulated natural gas contracts that will be presented in the all other segment.

We evaluate the performance of these segments based on gross margin. Items below operating income are not allocated between our 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
September 30, 2007		Electric		Gas			Electric			Other		Eliminations			Total
Operating revenues	$	202,093	$	37,051		$		18,795	$	17,167	$	(9,243	)	$		265,863
Cost of sales		109,924		16,252				5,225		16,535		(8,915	)			139,021
Gross margin		92,169		20,799				13,570		632		(328	)			126,842
Operating, general and administrative		31,431		13,342				7,791		250		(328	)			52,486
Property and other taxes		14,396		5,158				835		4		—				20,393
Depreciation		15,297		4,111				1,053		264		—				20,725
Operating income (loss)		31,045		(1,812	)			3,891		114		—				33,238
Total assets	$	1,509,756	$	739,507		$		120,020	$	16,425	$	—		$		2,385,708
Capital expenditures	$	15,811	$	7,280		$		2,205	$	—	$	—		$		25,296

Three Months Ended	Regulated						Unregulated
September 30, 2006		Electric		Gas			Electric		Other				Eliminations			Total
Operating revenues	$	173,199	$	35,842		$	22,706	$		10,817		$	(7,927	)	$	234,637
Cost of sales		86,758		16,677			5,658			9,466			(7,645	)		110,914
Gross margin		86,441		19,165			17,048			1,351			(282	)		123,723
Operating, general and administrative		30,257		12,818			10,830			(1,194	)		(299	)		52,412
Property and other taxes		13,439		4,765			738			26			—			18,968
Depreciation		14,501		3,644			443			265			—			18,853
Operating income (loss)		28,244		(2,062	)		5,037			2,254			17			33,490
Total assets	$	1,545,714	$	761,399		$	52,495	$		37,223		$	—		$	2,396,831
Capital expenditures	$	18,814	$	9,562		$	1,596	$		92		$	—		$	30,064

Nine Months Ended	Regulated					Unregulated
September 30, 2007		Electric		Gas		Electric		Other			Eliminations				Total
Operating revenues	$	551,166	$	257,272	$	55,674	$	49,953		$	(22,029	)	$		892,036
Cost of sales		290,603		168,386		13,666		47,708			(20,808	)				499,555
Gross margin		260,563		88,886		42,008		2,245			(1,221	)				392,481
Operating, general and administrative		96,770		47,490		23,695		6,877			(1,221	)				173,611
Property and other taxes		43,040		16,098		2,470		37			—					61,645
Depreciation		45,955		12,168		2,423		866			—					61,412
Operating income (loss)		74,798		13,130		13,420		(5,535	)		—					95,813
Total assets	$	1,509,756	$	739,507	$	120,020	$	16,425		$	—			$		2,385,708
Capital expenditures	$	44,362	$	29,397	$	4,146	$	—		$	—			$		77,905

Nine Months Ended	Regulated						Unregulated
September 30, 2006		Electric		Gas			Electric		Other				Eliminations			Total
Operating revenues	$	492,307	$		253,552	$	61,216	$		61,612		$	(40,382	)	$	828,305
Cost of sales		247,384			171,420		12,078			56,613			(39,183	)		448,312
Gross margin		244,923			82,132		49,138			4,999			(1,199	)		379,993
Operating, general and administrative		96,300			45,373		31,286			10,641			(1,216	)		182,384
Property and other taxes		40,171			14,351		2,538			86			—			57,146
Depreciation		43,464			10,946		1,148			875			—			56,433
Operating income (loss)		64,988			11,462		14,166			(6,603	)		17			84,030
Total assets	$	1,545,714	$		761,399	$	52,495	$		37,223		$	—		$	2,396,831
Capital expenditures	$	52,845	$		18,197	$	4,259	$		98		$	—		$	75,399

(10) Earnings Per Share

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

	Nine Months Ended September 30, 2007	Nine Months Ended September 30, 2006
Basic computation	36,062,574	35,534,894
Dilutive effect of
Restricted shares	469,207	101,100
Stock warrants	1,000,483	1,303,693
Diluted computation	37,532,264	36,939,687

	Three Months Ended September 30, 2007	Three Months Ended September 30, 2006
Basic computation	36,471,146	35,510,467
Dilutive effect of
Restricted shares	469,207	101,100
Stock warrants	543,401	1,417,404
Diluted computation	37,483,754	37,028,971

Warrants outstanding as of September 30, 2007 and 2006 of 3,120,655 and 4,603,071, respectively, are dilutive and have been included in the diluted earnings per share calculations. These warrants are exercisable through the close of business November 1, 2007. Each warrant could be exchanged for 1.11 and 1.07 shares of common stock and have an exercise price of $25.29 and $26.55 as of September 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. In August 2007, we amended the warrant agreement to allow for a cashless or “net exercise” method of exercising warrants. A total of 979,351 warrants were exercised during the nine months ended September 30, 2007.

(11) Employee Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
	2007			2006			2007			2006
Components of Net Periodic Benefit Cost
Service cost	$	2,236		$	2,262		$	145		$	185
Interest cost		5,449			5,198			611			693
Expected return on plan assets		(6,106	)		(5,364	)		(267	)		(207	)
Amortization of prior service cost		61			60			—			—
Recognized actuarial (gain) loss		—						(89	)		—
Net Periodic Benefit Cost	$	1,640		$	2,156		$	400		$	671

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
	2007			2006			2007			2006
Components of Net Periodic Benefit Cost
Service cost	$	6,710		$	6,787		$	435		$	555
Interest cost		16,349			15,593			1,832			2,081
Expected return on plan assets		(18,317	)		(16,093	)		(802	)		(622	)
Amortization of prior service cost		182			181			—			—
Recognized actuarial (gain) loss		—			—			(269	)		—
Net Periodic Benefit Cost	$	4,924		$	6,468		$	1,196		$	2,014

During the nine months ended September 30, 2007, we contributed approximately $21.8 million to our pension plans. We expect to contribute an additional $0.9 million to our pension plans during the remainder of 2007.

(12) Commitments and Contingencies

ENVIRONMENTAL LIABILITIES

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 September 30, 2007, we have a reserve of approximately $33.3 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.

Coal-Fired Plants

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.

Manufactured Gas Plants

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 Environment 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 have initiated additional site investigation and assessment work at these locations. 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. Evaluation of recently collected data from the Helena site is ongoing, which will help to complete our evaluation and assessment of remediation technologies 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.

Milltown Mining Waste

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three megawatt generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. In April 2003, the Environmental Protection Agency (EPA) announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed partial removal of the contaminated sediments located within the Milltown Reservoir, together with the removal of the Milltown Dam and powerhouse (this remedy was incorporated into the EPA’s formal Record of Decision issued on December 20, 2004). In light of this pre-Record of Decision announcement, we 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.

Other

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:

•

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

•

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

LEGAL PROCEEDINGS

Magten/Law Debenture/QUIPS Litigation

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 NorthWestern, the imposition of constructive trusts over the transferred assets and the return of such assets to CFB. On July 18, 2007, the Delaware District Court extended the discovery schedule and scheduled 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 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. On July 18, 2007, the Delaware District Court extended the discovery schedule and scheduled 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 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 should be treated as general unsecured, or Class 9, claims which would be satisfied out of the Class 9 Disputed Claims Reserve established under the Plan.

McGreevey Litigation

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

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., 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, in October 2005 obtained an order enjoining the McGreevey plaintiffs from prosecuting the 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.

City of Livonia

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. Since that time, there has been no substantive activity in the case. We are awaiting a decision by the federal court and we believe that any award of attorneys’ fees would be reimbursed by insurance proceeds.

Ammondson

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. 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.

Other Litigation and Contingencies

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 on an annual basis, to calculate energy and capacity payments for the contract years 2004, 2005 and 2006. 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, 2005 and 2006. A temporary restraining order has been issued restraining us from implementing the rates finalized by the MPSC order pending a decision on CELP’s request for a preliminary injunction. We believe CELP has no basis for their complaint and intend to vigorously defend this 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 $4.5 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.

(13) Colstrip Unit 4 Acquisition

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 September 30, 2007. The debt was incurred by the Owner Trust to finance the initial purchase of the undivided interest in Colstrip Unit 4.

(14) Rate Matters

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. This base rate request was based on a return on equity of 11.25 percent, an equity ratio of 51.5 percent and rate base of $53.2 million. Hearings have been scheduled for November 2007, and we anticipate finalizing the rate case and implementing new rates during the fourth quarter of 2007.

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. This base rate request was based on a return on equity of 11.25 percent, an equity ratio of 51.5 percent and rate base of $25.6 million. We are negotiating the rate case directly with the cities we serve in Nebraska, and anticipate finalizing the rate case and implementing new rates during the fourth quarter of 2007.

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, and anticipate finalizing the rate case in the first quarter of 2008.

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. This base rate request was based on a return on equity of 12 percent and 11.75 percent, respectively, a common equity ratio of 51.5 percent and rate base of $667.4 million and $265.4 million, respectively. Intervenor testimony in the case is due by November 9, 2007, and hearings have been scheduled for January 2008. We anticipate finalizing the rate case during the second quarter of 2008.

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.

OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, is one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 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.

Highlights

Highlights for the three months ended September 30, 2007 include:

•

Filing an electric and natural gas rate case in Montana requesting a combined revenue increase of approximately $41.9 million;

•

Improved outlook on our long-term corporate credit rating from Standard and Poor’s Rating Group (S&P) to positive from stable; and

•

Increasing our quarterly dividend to 33 cents per share, representing an increase of two cents per share from the prior payout period.

Termination of Merger Agreement with Babcock & Brown Infrastructure Limited

We incurred transaction related costs of approximately $1.5 million, and $13.9 million during the nine months ended September 30, 2007, and year-ended December 31, 2006, respectively, which have been expensed as incurred.

OVERALL CONSOLIDATED RESULTS

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

	Three Months Ended September 30,
		2007			2006			Change		% Change
		(in millions)
Operating Revenues
Regulated Electric	$	202.1		$	173.2		$	28.9		16.7		%
Regulated Natural Gas		37.1			35.8			1.3		3.6
Unregulated Electric		18.8			22.7			(3.9	)	(17.2	)
Other		17.1			10.8			6.3		58.3
Eliminations		(9.3	)		(7.9	)		(1.4	)	17.7
	$	265.8		$	234.6		$	31.2		13.3		%

	Three Months Ended September 30,
		2007			2006			Change		% Change
		(in millions)
Cost of Sales
Regulated Electric	$	109.9		$	86.8		$	23.1		26.6		%
Regulated Natural Gas		16.3			16.6			(0.3	)	(1.8	)
Unregulated Electric		5.2			5.7			(0.5	)	(8.8	)
Other		16.5			9.5			7.0		73.7
Eliminations		(8.9	)		(7.7	)		(1.2	)	15.6
	$	139.0		$	110.9		$	28.1		25.3		%

	Three Months Ended September 30,
		2007			2006			Change		% Change
		(in millions)
Gross Margin
Regulated Electric	$	92.2		$	86.4		$	5.8		6.7		%
Regulated Natural Gas		20.8			19.2			1.6		8.3
Unregulated Electric		13.6			17.0			(3.4	)	(20.0	)
Other		0.6			1.3			(0.7	)	(53.8	)
Eliminations		(0.4	)		(0.2	)		(0.2	)	(100.0	)
	$	126.8		$	123.7		$	3.1		2.5		%

Consolidated gross margin for the three months ended September 30, 2007 was $126.8 million, an increase of $3.1 million, or 2.5%, as compared with gross margin of $123.7 million in the third quarter of 2006. Margins in our regulated electric segment increased $5.8 million primarily due to warmer summer weather and customer growth. Margin in our regulated natural gas segment increased $1.6 million primarily due to increased transportation and storage revenue from the move of certain unregulated customers and our Nekota pipelines to the regulated business, and customer growth. Offsetting these increases was a decrease of $3.4 million in our unregulated electric segment primarily due to lower average contracted prices partially offset by higher volumes.

	Three Months Ended September 30,
			2007			2006			Change		% Change
	(in millions)
Operating Expenses
Operating, general and administrative		$		52.5	$		52.4	$		0.1		0.2	%
Property and other taxes				20.4			19.0			1.4		7.4
Depreciation				20.7			18.8			1.9		10.1
		$		93.6	$		90.2	$		3.4		3.8	%

Consolidated operating, general and administrative expenses were $52.5 million for the three months ended September 30, 2007 as compared with $52.4 million in the third quarter of 2006. This reflects $5.6 million in lower transaction related costs pursuant to the proposed BBI acquisition and reduced lease expense of $3.1 million for our Colstrip Unit 4 generating facility in 2007. Due to our purchase of the Owner Participant interest in a portion of the Colstrip Unit 4 generating facility in March 2007, our annual lease expense (a component of operating, general and administrative expenses) will decrease by approximately $7.8 million. The 2006 results include a $9.3 million reduction of operating, general and administrative expenses due to an insurance settlement received.

Property and other taxes were $20.4 million for the three months ended September 30, 2007 as compared with $19.0 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. In addition, an appeal of our 2005 valuation before the State Tax Appeal Board in Montana was denied and we intend to file an appeal in state court. 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 $20.7 million for the three months ended September 30, 2007, an increase of $1.9 million over the third quarter of 2006 primarily due to higher plant and property in service and our purchase of the Owner Participant interest in a portion of the Colstrip Unit 4 generating facility in March 2007. We expect annual depreciation expense to increase by approximately $2.0 million as a result of this purchase.

Consolidated operating income for the three months ended September 30, 2007 was $33.2 million, as compared with $33.5 million in the third quarter of 2006.

Consolidated interest expense for the three months ended September 30, 2007 was $14.6 million as compared with $13.8 million in 2006. This increase was due to approximately $0.5 million of interest expense recorded related to the Ammondson verdict and $0.7 million of interest expense on debt assumed related to the purchase in March 2007 of Mellon’s Owner Participant interest in a portion of the Colstrip Unit 4 generating facility. We expect annual interest expense to increase by approximately $2.6 million as a result of this purchase. Partially offsetting this increase was a decrease in interest expense from refinancing transactions completed in 2006.

Consolidated other income for the three months ended September 30, 2007 was $0.9 million, an improvement of $1.3 million from the third quarter of 2006.

Consolidated provision for income taxes for the three months ended September 30, 2007 was $6.3 million as compared with $7.9 million in the third quarter of 2006. Our effective tax rate for 2007 was 32.3% as compared to 40.9% for 2006. Portions of our BBI transaction related costs were considered non-deductible for taxes in 2006; however, with the termination of the agreement these costs became deductible, resulting in a reduction to our tax provision of approximately $1.2 million for the three months ended September 30, 2007. While we reflect an income

tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

Consolidated net income for the three months ended September 30, 2007 was $13.2 million, an improvement of $1.8 million as compared with $11.4 million in the third quarter of 2006.

Nine Months Ended September 30, 2007 Compared with the Nine Months Ended September 30, 2006

	Nine Months Ended September 30,
		2007			2006			Change		% Change
		(in millions)
Operating Revenues
Regulated Electric	$	551.2		$	492.3		$	58.9		12.0		%
Regulated Natural Gas		257.3			253.5			3.8		1.5
Unregulated Electric		55.7			61.2			(5.5	)	(9.0	)
Other		49.9			61.6			(11.7	)	(19.0	)
Eliminations		(22.0	)		(40.3	)		18.3		(45.4	)
	$	892.1		$	828.3		$	63.8		7.7		%

	Nine Months Ended September 30,
		2007			2006			Change		% Change
		(in millions)
Cost of Sales
Regulated Electric	$	290.6		$	247.4		$	43.2		17.5		%
Regulated Natural Gas		168.4			171.4			(3.0	)	(1.8	)
Unregulated Electric		13.7			12.1			1.6		13.2
Other		47.7			56.6			(8.9	)	(15.7	)
Eliminations		(20.8	)		(39.2	)		18.4		(46.9	)
	$	499.6		$	448.3		$	51.3		11.4		%

	Nine Months Ended September 30,
		2007			2006			Change		% Change
		(in millions)
Gross Margin
Regulated Electric	$	260.6		$	244.9		$	15.7		6.4		%
Regulated Natural Gas		88.9			82.1			6.8		8.3
Unregulated Electric		42.0			49.1			(7.1	)	(14.5	)
Other		2.2			5.0			(2.8	)	(56.0	)
Eliminations		(1.2	)		(1.1	)		(0.1	)	9.1
	$	392.5		$	380.0		$	12.5		3.3		%

Consolidated gross margin for the nine months ended September 30, 2007 was $392.5 million, an increase of $12.5 million, or 3.3%, over gross margin of $380.0 million in 2006. Margins in our regulated electric segment increased $15.7 million due primarily to customer growth, warmer summer weather, 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 partially offset by lower wholesale sales in the secondary market. Margin in our regulated natural gas segment increased $6.8 million due to colder weather, customer growth and increased transportation and storage revenue from the move of certain unregulated customers and our Nekota pipelines to the regulated business. Offsetting these

increases was a decrease of $7.1 million in unregulated electric margin primarily due to lower average contracted prices and higher fuel supply costs, partially offset by an increase in volumes resulting from higher demand and plant availability.

	Nine Months Ended September 30,
			2007	2006				Change		% Change
			(in millions)
Operating Expenses
Operating, general and administrative		$	173.6	$	182.4	$	(8.8		)	(4.8	)	%
Property and other taxes			61.7		57.2		4.5			7.9
Depreciation			61.4		56.4		5.0			8.9
		$	296.7	$	296.0	$	0.7			0.2		%

Consolidated operating, general and administrative expenses were $173.6 million for the nine months ended September 30, 2007 as compared with $182.4 million in the same period of 2006. This decrease was primarily due to $11.7 million in lower transaction related costs pursuant to the proposed BBI acquisition as discussed above and reduced lease expense of $8.0 million for our interest in the Colstrip Unit 4 generating facility as discussed above.The 2006 results include a $9.3 million reduction in operating, general and administrative expenses due to an insurance settlement received.

Property and other taxes were $61.7 million for the nine months ended September 30, 2007 as compared with $57.2 million in 2006. This increase was primarily due to a higher valuation assessment in our Montana service territory as discussed above.

Depreciation expense was $61.4 million for the nine months ended September 30, 2007 as compared with $56.4 million in 2006 primarily due to higher plant and property in service and our purchase of the Owner Participant interest in a portion of the Colstrip Unit 4 generating facility discussed above.

Consolidated operating income for the nine months ended September 30, 2007 was $95.8 million, as compared with $84.0 million in 2006. This $11.8 million increase was primarily due to the higher margins discussed above.

Consolidated interest expense for the nine months ended September 30, 2007 was $42.4 million as compared with $42.8 million in 2006. This includes increased interest expense of approximately $1.3 million related to the Ammondson verdict, and $1.6 million of interest expense on debt assumed related to the purchase in March 2007 of Mellon’s Owner Participant interest in a portion of the Colstrip Unit 4 generating facility. Offsetting this increase was a decrease in interest expense from refinancing transactions completed in 2006.

Consolidated other income for the nine months ended September 30, 2007 was $1.6 million, a decrease of $6.4 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 nine months ended September 30, 2007 was $20.3 million as compared with $19.7 million in 2006. Our effective tax rate for 2007 was 36.8% as compared to 40.0% for 2006. Portions of our BBI transaction related costs were considered non-deductible for taxes in 2006; however, with the termination of the agreement these costs became deductible, resulting in a reduction to our tax provision of approximately $1.2 million for the nine months ended September 30, 2007.

Consolidated net income for the nine months ended September 30, 2007 was $34.8 million, an increase of $4.8 million, or 16.0%, over $30.0 million in 2006. This improvement was primarily related to higher margins, partially offset by a decrease in other income.

REGULATED ELECTRIC SEGMENT

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

		Results
		2007				2006				Change			% Change
		(in millions)
Electric supply revenue	$		106.3		$		83.9		$		22.4			26.7		%
Transmission & distribution revenue			78.5				74.1				4.4			5.9
Rate schedule revenue			184.8				158.0				26.8			17.0
Transmission			13.0				10.8				2.2			20.4
Wholesale			2.2				2.4				(0.2	)		(8.3	)
Miscellaneous			2.1				2.0				0.1			5.0
Total Revenues			202.1				173.2				28.9			16.7		%
Supply costs			105.5				83.8				21.7			25.9
Wholesale			0.7				0.9				(0.2	)		(22.2	)
Other cost of sales			3.7				2.1				1.6			76.2
Total Cost of Sales			109.9				86.8				23.1			26.6		%
Gross Margin	$		92.2		$		86.4		$		5.8			6.7		%
% GM/Rev		45.6		%		49.9		%

	Volumes MWH
	2007	2006		Change			% Change
	(in thousands)
Retail Electric
Residential	699		675		24			3.6		%
Commercial	1,102		1,068		34			3.2
Industrial	770		759		11			1.4
Other	95		91		4			4.4
Total Retail Electric	2,666		2,593		73			2.8		%
Wholesale Electric	54		64		(10	)		(15.6	)	%

Average Customer Counts	2007	2006	Change	% Change
Montana	327,519	321,748	5,771	1.8	%
South Dakota	59,590	59,133	457	0.8	%
Total	387,109	380,881	6,228	1.6	%

	2007 as compared to:
Cooling Degree-Days	2006	Historic Average
Montana	17% Warmer	79% Warmer
South Dakota	17% Warmer	58% Warmer

Rate Schedule Revenue

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

Electric rate schedule revenue for the three months ended September 30, 2007 increased $26.8 million, or 17.0% over results in the third quarter of 2006. Electric supply revenue, which consists of supply costs that are collected in

rates from customers, increased $22.4 million consisting of $18.9 million due to 23.0% higher average prices and $3.5 million due to a 2.8% increase in volumes. The volume related increase was due to a combination of warmer summer weather and 1.6% customer growth. In addition, transmission and distribution revenue increased $4.4 million due to the increase in volumes.

Transmission Revenue

Transmission revenue consists of revenue earned for transmitting energy across our lines for customers who select other suppliers and for off-system, or open access, customers. Transmission revenues in Montana can fluctuate substantially from year to year based on market conditions in surrounding states. For example, if energy costs are substantially higher in California than in states to our east, suppliers may realize more profit by transmitting electricity across our lines into the California market than by buying electricity within California. We refer to these differences as price differentials. These price differentials account for approximately $1.6 million of the increase in transmission revenue. In May 2007, we implemented an interim increase in our transmission rates (subject to refund), which accounts for approximately $0.6 million of the increase in transmission revenue.

Gross Margin

Gross margin for the three months ended September 30, 2007 increased $5.8 million, or 6.7% as compared with the third quarter of 2006. This increase was due primarily to the warmer summer weather and customer growth.

Volumes

Regulated retail electric volumes for the three months ended September 30, 2007 totaled 2,665,512 MWHs, an increase of 2.8% from 2,592,823 MWHs in the same period in 2006 due primarily to warmer summer weather and customer growth. Regulated wholesale electric volumes in the third quarter of 2007 were 54,262 MWHs, a decrease from 64,194 MWHs in the same period in 2006 resulting from plant down time due to scheduled maintenance. We expect further plant down time in the fourth quarter 2007 due to maintenance.

Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006

	Results
	2007			2006					Change			% Change
	(in millions)
Electric supply revenue	$	282.5		$		234.5		$		48.0			20.5		%
Transmission & distribution revenue		221.5				210.2				11.3			5.4
Rate schedule revenue		504.0				444.7				59.3			13.3
Transmission		36.8				34.6				2.2			6.4
Wholesale		4.5				6.8				(2.3	)		(33.8	)
Miscellaneous		5.9				6.2				(0.3	)		(4.8	)
Total Revenues		551.2				492.3				58.9			12.0		%
Supply costs		279.2				237.0				42.2			17.8
Wholesale		1.5				2.4				(0.9	)		(37.5	)
Other cost of sales		9.9				8.0				1.9			23.8
Total Cost of Sales		290.6				247.4				43.2			17.5		%
Gross Margin	$	260.6		$		244.9		$		15.7			6.4		%
% GM/Rev		47.3	%		49.7		%

	Volumes MWH
	2007			2006	Change			% Change
	(in thousands)
Retail Electric
Residential		2,046	1,964			82			4.2		%
Commercial		3,040	2,935			105			3.6
Industrial		2,250	2,273			(23	)		(1.0	)
Other		164	167			(3	)		(1.8	)
Total Retail Electric		7,500	7,339			161			2.2		%
Wholesale Electric		119	176			(57	)		(32.4	)	%

Average Customer Counts	2007	2006	Change		% Change
Montana	325,771	319,845		5,926	1.9	%
South Dakota	59,421	58,884		537	0.9	%
Total	385,192	378,729		6,463	1.7	%

	2007 as compared to:
Cooling Degree-Days	2006	Historic Average
Montana	17% Warmer	74% Warmer
South Dakota	15% Warmer	56% Warmer

Rate Schedule Revenue

Electric rate schedule revenue for the nine months ended September 30, 2007 increased $59.3 million, or 13.3% over results in 2006. Electric supply revenue, which consists of supply costs that are collected in rates from customers, increased $48.0 million, consisting of $40.8 million due to 17.6% higher average prices, and $7.2 million due to a 2.2% increase in volumes. The volume related increase was due to a combination of warmer summer weather and 1.7% customer growth. In addition, transmission and distribution revenue increased $11.3 million primarily due to increased residential and commercial volumes due to warmer summer weather.

Transmission Revenue

Transmission revenue for the nine months ended September 30, 2007 increased $2.2 million, or 6.4% due to price differentials as discussed above of approximately $1.4 million, and an interim increase in our transmission rates (subject to refund) implemented in May 2007 of approximately $0.8 million.

Wholesale Revenues

Wholesale revenues are derived from our joint ownership in generation facilities. Excess power not used by our South Dakota customers is sold in the wholesale market. These revenues for the nine months ended September 30, 2007 decreased $2.3 million, or 33.8%, primarily due to a 32.4% decrease in volumes sold in the secondary markets. We had less wholesale energy available to sell due to decreased plant availability resulting from scheduled maintenance.

Gross Margin

Gross margin for the nine months ended September 30, 2007 increased $15.7 million, or 6.4% as compared with the same period in 2006. This improvement was due primarily to customer growth, warmer summer weather, and the inclusion in 2006 results of higher cost of sales due to a $4.1 million loss recorded as a result of a stipulation with the Montana Consumer Counsel. This increase was partially offset by lower wholesale sales in the secondary market.

Volumes

Regulated retail electric volumes for the nine months ended September 30, 2007 totaled 7,500,288 MWHs, which increased 2.2% as compared with 7,338,574 MWHs in the same period in 2006 due primarily to warmer summer weather and customer growth. Regulated wholesale electric volumes in 2007 were 119,270 MWHs, a decrease from 176,492 MWHs in the same period in 2006 resulting from increased plant down time due to scheduled maintenance.

REGULATED NATURAL GAS SEGMENT

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

		Results
		2007				2006			Change		% Change
		(in millions)
Gas supply revenue	$	14.3		$	14.2			$	0.1		0.7		%
Transportation, distribution & storage revenue		13.7			13.0				0.7		5.4
Rate schedule revenue		28.0			27.2				0.8		2.9
Transportation & storage		6.0			5.0				1.0		20.0
Wholesale revenue		1.6			2.1				(0.5	)	(23.8	)
Miscellaneous		1.5			1.5				—		—
Total Revenues		37.1			35.8				1.3		3.6		%
Supply costs		14.3			14.2				0.1		0.7
Wholesale supply costs		1.6			2.1				(0.5	)	(23.8	)
Other cost of sales		0.4			0.3				0.1		33.3
Total Cost of Sales		16.3			16.6				(0.3	)	(1.8	)	%
Gross Margin	$	20.8		$	19.2			$	1.6		8.3		%
% GM/Rev		56.1	%		53.6		%

	Volumes Dekatherms
	2007	2006	Change		% Change
	(in thousands)
Retail Gas
Residential	1,176	1,194	(18	)	(1.5	)	%
Commercial	1,027	999	28		2.8
Industrial	15	4	11		275.0
Other	5	31	(26	)	(83.9	)
Total Retail Gas	2,223	2,228	(5	)	(0.2	)	%

Average Customer Counts	2007	2006	Change	% Change
Montana	173,777	169,867	3,910	2.3	%
South Dakota	42,067	41,441	626	1.5
Nebraska	40,308	40,181	127	0.3
Total	256,152	251,489	4,663	1.9	%

	2007 as compared to:
Heating Degree-Days	2006	Historic Average
Montana	3% Warmer	23% Warmer
South Dakota	30% Warmer	184% Warmer
Nebraska	30% Warmer	205% Warmer

Rate Schedule Revenue

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.

Transportation, distribution and storage revenue for the three months ended September 30, 2007 increased $0.7 million from results in the third quarter of 2006 primarily due to 1.9% customer growth, partially offset by lower average usage per residential customer.

Transportation & 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 $1.0 million in the third quarter of 2007 as compared with the third quarter of 2006, primarily due to the transfer of certain previously unregulated customers and our Nekota pipelines into the regulated business. 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

Wholesale revenue decreased $0.5 million due to a decrease in sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.

Gross Margin

Gross margin for the three months ended September 30, 2007 increased $1.6 million, or 8.3% over the third quarter of 2006 due to higher transportation and storage revenue from the move of certain unregulated customers and our Nekota pipelines to the regulated business and customer growth.

Volumes

Regulated retail natural gas volumes were 2,223,491 dekatherms during the three months ended September 30, 2007, compared with 2,227,857 dekatherms for the same period in 2006.

Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006

		Results
		2007				2006				Change				% Change
		(in millions)
Gas supply revenue		$	148.1		$		161.3		$		(13.2	)	(8.2		)	%
Transportation, distribution & storage revenue			69.6				63.6				6.0		9.4
Rate schedule revenue			217.7				224.9				(7.2	)	(3.2		)
Transportation & storage			17.5				14.9				2.6		17.4
Wholesale revenue			18.1				8.0				10.1		126.3
Miscellaneous			4.0				5.7				(1.7	)	(29.8		)
Total Revenues			257.3				253.5				3.8		1.5			%
Supply costs			148.1				161.3				(13.2	)	(8.2		)
Wholesale supply costs			18.1				8.0				10.1		126.3
Other cost of sales			2.2				2.1				0.1		4.8
Total Cost of Sales			168.4				171.4				(3.0	)	(1.8		)	%
Gross Margin		$	88.9		$		82.1		$		6.8		8.3			%
% GM/Rev	34.6			%		32.4		%

	Volumes Dekatherms
	2007	2006	Change		% Change
	(in thousands)
Retail Gas
Residential	11,951	11,163	788		7.1		%
Commercial	7,859	7,237	622		8.6
Industrial	111	101	10		9.9
Other	114	116	(2	)	(1.7	)
Total Retail Gas	20,035	18,617	1,418		7.6		%

Average Customer Counts	2007	2006	Change	% Change
Montana	174,362	170,468	3,894	2.3	%
South Dakota	42,400	41,693	707	1.7
Nebraska	40,767	40,665	102	0.3
Total	257,529	252,826	4,703	1.9	%

	2007 as compared to:
Heating Degree-Days	2006	Historic Average
Montana	1% Colder	10% Warmer
South Dakota	15% Colder	3% Warmer
Nebraska	17% Colder	5% Warmer

Rate Schedule Revenue

Gas rate schedule revenue for the nine months ended September 30, 2007 decreased $7.2 million, or 3.2% from results in 2006. Gas supply revenues, which consist of supply costs that are collected in rates from customers, decreased $13.2 million, consisting of $23.7 million due to 14.7% lower average rates partly offset by $10.5 million due to a 7.6%, increase in volumes resulting from colder weather and customer growth. This volume increase also caused the $6.0 million increase in transportation, distribution and storage revenue.

Transportation & Storage Revenue

Wholesale Revenue

Wholesale revenue increased $10.1 million, or 126.3%, 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

Gross margin for the nine months ended September 30, 2007 increased $6.8 million, or 8.3% over the same period in 2006 primarily due to colder weather, customer growth and increased transportation and storage revenue as discussed above.

Volumes

Regulated retail natural gas volumes were 20,034,749 dekatherms during the nine months ended September 30, 2007, compared with 18,616,509 dekatherms, an increase of 7.6% over the same period in 2006. This increase was due primarily to colder weather and customer growth.

UNREGULATED ELECTRIC SEGMENT

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

Our unregulated electric segment primarily consists of a 30% share of the Colstrip Unit 4 generation facility. We sell our Colstrip Unit 4 output, representing approximately 222 megawatts at full load, principally to two unrelated third parties under agreements through December 2010. Under a separate agreement we repurchase 111 megawatts through December 2010. These 111 megawatts were 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 are being 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.

		Results
				2007					2006					Change			% Change
		(in millions)
Total Revenues	$		18.8				$	22.7				$	(3.9		)	(17.2		)	%
Supply costs			4.5					4.8					(0.3		)	(6.3		)
Wheeling costs			0.7					0.9					(0.2		)	(22.2		)
Total Cost of Sales	$		5.2				$	5.7				$	(0.5		)	(8.8		)	%
Gross Margin	$		13.6				$	17.0				$	(3.4		)	(20.0		)	%
% GM/Rev					72.3	%				74.9	%

Volumes MWH

2007

2006

Change

% Change

(in thousands)

Wholesale Electric

454

414

9.7

Revenue

Unregulated electric revenue decreased $3.9 million, or 17.2%, for the three months ended September 30, 2007 primarily due to 20.9% lower average contracted prices partially offset by 9.7% higher volumes.

Gross Margin

Gross margin decreased $3.4 million, or 20.0%, with lower average contracted prices partially offset by higher volumes.

Volumes

Unregulated electric volumes were 453,846 MWHs in the third quarter of 2007, an increase of 9.7% over 413,974 MWHs in the same period in 2006. We had more energy available to sell in 2007 due to unplanned plant outages in 2006 related to plant maintenance.

Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006

	Results
			2007				2006				Change			% Change
	(in millions)
Total Revenues		$		55.7		$		61.2		$		(5.5	)		(9.0	)	%
Supply costs				11.4				9.6				1.8			18.8
Wheeling costs				2.3				2.5				(0.2	)		(8.0	)
Total Cost of Sales		$		13.7		$		12.1		$		1.6			13.2		%
Gross Margin		$		42.0		$		49.1		$		(7.1	)		(14.5	)	%
% GM/Rev			75.4		%		80.2		%

Volumes MWH

2007

2006

Change

% Change

(in thousands)

Wholesale Electric

1,189

1,076

113

10.5

Revenue

Unregulated electric revenue decreased $5.5 million, or 9.0%, for the nine months ended September 30, 2007 primarily due to 12.4% lower average contracted prices partially offset by 10.5% higher volumes.

Gross Margin

Gross margin decreased $7.1 million, or 14.5%, due primarily to lower average contracted prices and higher fuel supply costs, partially offset by an increase in volumes resulting from higher demand and plant availability.

Volumes

Unregulated electric volumes were 1,189,188 MWHs for the nine months ended September 30, 2007, an increase of 10.5% over 1,076,292 MWHs in 2006,primarily due to increased demand. 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. In addition, we had less energy available to sell in 2006 due to decreased plant availability resulting from planned and unplanned outages for plant maintenance.

ALL OTHER

This primarily consists of our remaining unregulated natural gas operations and unallocated corporate costs. We previously disclosed our intent to sell our unregulated natural gas business or transfer the remaining customers and contracts to our regulated natural gas business. We have moved certain customers to our regulated natural gas business unit and sold several customer contracts during 2007; therefore, the unregulated natural gas business unit will no longer be considered a reportable segment under SFAS No. 131. We have two remaining unregulated natural gas contracts (a supply contract and an interstate capacity agreement) that will be presented in all other.

LIQUIDITY AND CAPITAL RESOURCES

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 of September 30, 2007, we had cash and cash equivalents of $4.7 million, and revolver availability of $156.6 million. During the nine months ended September 30, 2007, we used existing cash to repay $44.4 million of debt, including repayments of $36.0 million on our revolver. In addition to these repayments, we paid dividends on common stock of $34.4 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 $21.9 million to our pension plans.

Factors Impacting our Liquidity

Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas sales and transportation services typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing 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. However, as of September 30, 2007, we are over collected on our current Montana natural gas and electric trackers by approximately $18.6 million, as compared with an undercollection of $2.7 million as of September 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.

Cash Flows

The following table summarizes our consolidated cash flows (in millions):

		Nine Months Ended September 30,
		2007			2006
Continuing Operating Activities
Net income	$	34.8		$	30.0
Non-cash adjustments to net income		85.9			73.5
Proceeds from hedging activities		—			14.5
Changes in working capital		55.1			23.5
Other		(1.9	)		(6.0	)
		173.9			135.5
Continuing Investing Activities
Property, plant and equipment additions		(77.9	)		(75.3	)
Sale of assets		1.4			23.3
Proceeds from hedging activities		—			5.3
Colstrip Unit 4 acquisition		(40.2	)		—
		(116.7	)		(46.7	)
Continuing Financing Activities
Net repayment of debt		(44.4	)		(42.1	)
Dividends on common stock		(34.4	)		(33.0	)
Deferred gas storage		—			(11.7	)
Other		24.4			(10.7	)
		(54.4	)		(97.5	)
Discontinued Operations		—			7.7
Net Increase in Cash and Cash Equivalents	$	2.8		$	(1.0	)
Cash and Cash Equivalents, beginning of period	$	1.9		$	2.7
Cash and Cash Equivalents, end of period	$	4.7		$	1.7

Cash Provided By Continuing Operating Activities

As of September 30, 2007, cash and cash equivalents were $4.7 million, as compared with $1.9 million at December 31, 2006 and $1.7 million at September 30, 2006. Cash provided by continuing operating activities totaled $173.9 million for the nine months ended September 30, 2007 as compared with $135.5 million during the nine months ended September 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, decreased purchases of storage gas and higher net income. In addition, proceeds received from hedging activities during the nine months ended September 30, 2006 partially offsets these increases.

Cash Used in Continuing Investing Activities

Cash used in investing activities of continuing operations totaled $116.7 million during the nine months ended September 30, 2007, as compared with $46.7 million during the nine months ended September 30, 2006. During the nine months ended September 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 $77.9 million for property, plant and equipment additions. During the nine months ended September 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 $75.3 million for property, plant and equipment additions.

Cash Used in Continuing Financing Activities

Cash used in financing activities of continuing operations totaled $54.4 million during the nine months ended September 30, 2007, as compared with $97.5 million during the nine months ended September 30, 2006. During the nine months ended September 30, 2007 we have made debt repayments of $44.4 million and paid dividends on common stock of $34.4 million, offset by cash proceeds of $25.3 million received from the exercise of warrants. During the nine months ended September 30, 2006 we made debt repayments of $42.1 million, paid dividends on common stock of $33.0 million, and paid $11.7 million for deferred storage transactions. Cash used to repurchase shares during the nine months ended September 30, 2006 was approximately $4.1 million. In addition, in association with our debt refinancing transactions completed during 2006, we capitalized $6.9 million of financing costs.

Sources and Uses of Funds

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 October 26, 2007, our availability under our revolving line of credit was approximately $170.6 million.

We have entered into a definitive agreement with SGE (New York) Associates to purchase SGE’s Owner Participant interest in the Colstrip Unit 4 generation facility for approximately $128.4 million, including the assumption of $28.9 million of debt. This interest represents approximately 143 megawatts. We expect to complete this purchase during the fourth quarter of 2007.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of September 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)	$	681,545	$	2,438	$	10,115	$	24,927	$	12,366	$		6,578	$	625,121
Capital Leases	40,899		510		1,677		1,269		1,174		1,265			35,004
Future Minimum Operating Lease Payments (1)	232,916		16,634		33,874		33,119		32,740		14,872			101,677
Estimated Pension and Other Postretirement Obligations (2)	96,190		1,150		26,490		22,870		23,340		22,340			N/A
Qualifying Facilities (3)	1,533,283		14,605		59,497		61,586		63,589		65,323			1,268,683
Supply and Capacity Contracts (4)	1,965,750		168,955		475,840		307,058		282,534		145,602			585,761
Contractual Interest Payments on Debt (5)	399,576		7,733		39,798		38,672		36,847		35,830			240,696
Total Commitments	$	4,950,159	$	212,025	$	647,291	$	489,501	$	452,590	$		291,810	$	2,856,942

(1)	During the first quarter of 2007, we completed the purchase of the Owner Participant interest in a portion of the Colstrip Unit 4 generating facility, which increased our long-term debt obligations, and reduced our operating lease payments. See Note 13, Colstrip Unit 4 Acquisition.

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

(3)

The Qualifying Facilities (QFs) require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our estimated gross contractual obligation related to the QFs is approximately $1.5 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.2 billion.

(4)	We have entered into various purchase commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years.

(5)	Contractual interest payments include an assumed average interest rate of 5.4% on an estimated revolving line of credit balance of $14.0 million through maturity in November 2009, which is our only variable rate debt.

Credit Ratings

Fitch Investors Service (Fitch), Moody’s Investors Service (Moody’s) and 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:

	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+	Positive

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

During the third quarter of 2007, S&P revised its outlook on our long-term corporate credit rating to positive from stable. In addition, S&P modified the criteria related to assigning ratings on all U.S. utilities’ first mortgage bonds. As a result of the new criteria, S&P upgraded our first mortgage bonds to BBB from BBB-.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

As of September 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.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Interest Rate Risk

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

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 all other 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.

Counterparty Credit Risk

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

ITEM 4.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the three months ended September 30, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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

ITEM 1A.

RISK FACTORS

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

We have incurred, and 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 perform 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, we are obligated to supply 90 megawatts of base-load energy from Colstrip Unit 4 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 $33.3 million at September 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.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On August 8, 2007, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

All of the Directors were elected to serve a one-year term as Directors until the 2008 Annual Meeting.

	VOTES FOR:		VOTES WITHHELD:
Stephen P. Adik		27,268,356		75,925
E. Linn Draper		27,268,176		76,105
Jon S. Fossel		27,268,198		76,082
Michael J. Hanson		27,268,407		75,874
Julia L. Johnson		27,268,954		75,327
Philip L. Maslowe		27,260,232		84,049
D. Louis Peoples		27,268,150		76,131

The ratification of Deloitte & Touche, LLP as our independent auditors was approved.

	FOR:	AGAINST:		ABSTAIN:
Votes	27,291,452		35,702		17,129

ITEM 6.

EXHIBITS

(a)

Exhibits

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.

SIGNATURES

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.

	NORTHWESTERN CORPORATION
Date: October 31, 2007	By:	/s/ BRIAN B. BIRD
		Brian B. Bird
		Chief Financial Officer
		Duly Authorized Officer and Principal Financial Officer

EXHIBIT INDEX

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.

*	Filed herewith

Date: October 31, 2007
/s/ MICHAEL J. HANSON
Michael J. Hanson
President and Chief Executive Officer