PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except per share amounts)

	Successor Company
	September 30, 2005				December 31, 2004
ASSETS
Current Assets:
Cash and cash equivalents		$	20,268			$	17,058
Restricted cash		23,845				21,383
Accounts receivable, net		94,128				141,350
Inventories		48,027				28,033
Regulatory assets		26,697				13,152
Prepaid energy supply		3,080				30,278
Prepaid and other		6,128				8,601
Assets held for sale		20,000				20,000
Current assets of discontinued operations		37,387				71,091
Total current assets		279,560				350,946
Property, Plant, and Equipment, Net		1,392,236				1,379,060
Goodwill		435,076				435,076
Other:
Investments		1,637				5,608
Regulatory assets		219,044				224,192
Other		32,808				18,597
Noncurrent assets of discontinued operations		—				37
Total assets		$	2,360,361			$	2,413,516
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt		$	6,556			$	73,380
Accounts payable		66,192				85,120
Accrued expenses		184,094				131,852
Regulatory liabilities		15,392				19,342
Current liabilities of discontinued operations		16,410				18,374
Total current liabilities		288,644				328,068
Long-term Debt		730,839				763,566
Deferred Income Taxes		63,481				41,354
Noncurrent Regulatory Liabilities		168,290				160,750
Other Noncurrent Liabilities		394,136				410,000
Noncurrent Liabilities of Discontinued Operations		—				443
Total liabilities		1,645,390				1,704,181
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 35,836,021 and 35,689,510, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		358				355
Treasury stock at cost		(2,585		)		—
Paid-in capital		721,459				717,994
Unearned restricted stock		(516		)		(2,093		)
Retained deficit		(7,714		)		(6,944		)
Accumulated other comprehensive income		3,969				23
Total shareholders’ equity		714,971				709,335
Total liabilities and shareholders’ equity		$	2,360,361			$	2,413,516

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(Unaudited)
(in thousands, except per share amounts)

	Successor Company			Predecessor Company				Successor Company			Predecessor Company
	Three Months Ended September 30							Nine Months Ended September 30
	2005			2004				2005			2004
OPERATING REVENUES	$	239,123			$	229,430		$	823,603			$	752,884
COST OF SALES	117,823				116,665			439,388				404,077
GROSS MARGIN	121,300				112,765			384,215				348,807
OPERATING EXPENSES
Operating, general and administrative	59,311				53,391			172,778				163,606
Property and other taxes	18,395				16,794			54,022				51,601
Depreciation	18,424				18,193			55,988				54,611
Reorganization items	2,901				29,361			7,021				43,821
TOTAL OPERATING EXPENSES	99,031				117,739			289,809				313,639
OPERATING INCOME	22,269				(4,974		)	94,406				35,168
Interest Expense (contractual interest of $47,201 and $141,569 for the three and nine months ended 9/30/2004)	(14,924		)		(21,551		)	(47,024		)		(65,455		)
Loss on Debt Extinguishment	—				—			(548		)		—
Investment Income and Other	5,365				1,280			7,562				2,484
Income (Loss) From Continuing Operations Before Income Taxes	12,710				(25,245		)	54,396				(27,803		)
(Provision) Benefit for Income Taxes	(3,411		)		95			(20,330		)		366
Income (Loss) from Continuing Operations	9,299				(25,150		)	34,066				(27,437		)
Discontinued Operations, Net of Taxes	(463		)		(4,417		)	(10,243		)		10,051
Net Income (Loss)	$	8,836			$	(29,567	)	$	23,823			$	(17,386	)
Average Common Shares Outstanding	35,643							35,620
Basic Earnings per Average Common Share
Continuing operations	$	0.26						$	0.96
Discontinued operations	(0.01		)					(0.29		)
Basic	$	0.25						$	0.67
Diluted Earnings per Average Common Share
Continuing operations	$	0.25						$	0.95
Discontinued operations	(0.01		)					(0.29		)
Diluted	$	0.24						$	0.66
Dividends Declared per Average Common Share	$	0.25						$	0.69

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)

	Successor Company				Predecessor Company
	Nine Months Ended September 30,
	2005				2004
					(as revised)
OPERATING ACTIVITIES:
Net Income (loss)		$	23,823			$	(17,386	)
Items not affecting cash:
Depreciation and amortization		55,988				54,611
Amortization of debt issue costs		1,725				8,716
Amortization of restricted stock		4,768				554
Gain on sale of assets		(4,715		)		—
Gain on qualifying facility contract amendment		(4,888		)		—
(Income) loss on discontinued operations, net of taxes		10,243				(10,051		)
Deferred income taxes		20,035				—
Loss on debt extinguishment		548				—
Loss on reorganization items		2,600				19,030
Other noncash (gains) losses		(578		)		1,458
Changes in current assets and liabilities:
Accounts receivable		47,222				16,488
Inventories		(19,994		)		(4,807		)
Prepaid energy supply costs		27,198				32,301
Other current assets		2,473				13,516
Accounts payable		(19,726		)		4,852
Accrued expenses		40,971				12,480
Changes in regulatory assets		(8,397		)		15,865
Changes in regulatory liabilities		(4,245		)		2,660
Other noncurrent assets		(7,977		)		1,136
Other noncurrent liabilities		(20,668		)		3,559
Cash flows provided by continuing operations		146,406				154,982
INVESTING ACTIVITIES:
Change in restricted cash		(2,462		)		5,102
Property, plant, and equipment additions		(53,593		)		(54,172		)
Proceeds from sale of assets		4,971				99
Purchase of investments		(118,800		)		(140,875		)
Proceeds from sale of investments		123,478				70,965
Cash used in continuing investing activities		(46,406		)		(118,881		)
FINANCING ACTIVITIES:
Proceeds from exercise of warrants		91				—
Dividends on common stock		(24,593		)		—
Deferred gas storage		11,271				—
Repayment of long-term debt		(174,782		)		(9,895		)
Treasury stock activity		(2,585		)		—
Issuance of long-term debt		—				55
Financing costs		(2,143		)		(115		)
Equity registration fees		(140		)		—
Line of credit borrowings, net		75,000				—
Cash used in continuing financing activities		(117,881		)		(9,955		)
DISCONTINUED OPERATIONS:
Operating cash flows of discontinued operations, net		(10,977		)		(15,601		)
Investing cash flows of discontinued operations, net		399				32,478
Financing cash flows of discontinued operations, net		—				—
Decrease (Increase) in restricted cash held by discontinued operations		31,669				(17,036		)
Increase in Cash and Cash Equivalents		3,210				25,987
Cash and Cash Equivalents, beginning of period		17,058				15,183
Cash and Cash Equivalents, end of period		$	20,268			$	41,170

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(Unaudited)
(in thousands)

Supplemental Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	(341	)	$	(4,809	)
Interest	32,248			46,789
Reorganization professional fees and expenses	5,266			17,195
Reorganization interest income	—			(321		)
Noncash transactions:
Investment utilized for debt repayment	—			1,474

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Reference is made to Notes to Financial Statements

included in NorthWestern Corporation’s Annual Report)

(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 617,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have distributed electricity and natural gas in Montana since 2002 under the trade name “NorthWestern Energy.”

The consolidated financial statements for the periods included herein have been prepared by NorthWestern Corporation (NorthWestern, we or us), pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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 interim financial statements furnished reflect all adjustments which are, in the opinion of management, necessary to a fair statement of the results for the interim periods presented. 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 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/A for the year ended December 31, 2004 filed with the SEC on July 15, 2005.

On September 14, 2003 (the Petition Date), we filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). On October 19, 2004, the Bankruptcy Court entered an order confirming our Plan of Reorganization (Plan), which became effective on November 1, 2004.

Between September 14, 2003 and November 1, 2004, we operated as a debtor-in-possession under the supervision of the Bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code. In accordance with SOP 90-7, we applied the principles of fresh-start reporting as of the close of business on October 31, 2004, resulting in the creation of a new reporting entity. “Predecessor Company” refers to us prior to emergence from bankruptcy (operations prior to October 31, 2004). “Successor Company” refers to us after emergence from bankruptcy (operations after November 1, 2004).

The accompanying consolidated financial statements include our accounts together with those of our wholly and majority-owned or controlled subsidiaries. The financial statements of Netexit, Inc. (Netexit) and Blue Dot Services, Inc. (Blue Dot) are included in the accompanying consolidated financial statements by virtue of the voting and control rights, and therefore included in references to “subsidiaries.” Netexit and Blue Dot were not party to our recently concluded Chapter 11 case. However on May 4, 2004, Netexit filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. All significant intercompany balances and transactions have been eliminated from the consolidated financial statements.

The operations of Netexit and Blue Dot and our interest in these subsidiaries have been reflected in the consolidated financial statements as Discontinued Operations (see Note 4 for further discussion). We continue to consolidate the operations and financial position of Netexit in our financial statements as we believe that the continued consolidation results in a more meaningful presentation due to our negative investment, our expectation that the bankruptcy will be brief and our anticipated control of Netexit upon its emergence from bankruptcy.

In December 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, or FIN 46R. FIN 46R was issued to replace FIN 46 and clarify the accounting for interests in variable interest entities. FIN 46R requires the consolidation of entities which are determined to be variable interest entities (VIEs) when the reporting company determines that it will absorb a majority of the VIE’s expected losses, receive a majority of the VIE’s residual returns, or both. The company that is required to consolidate the VIE is called the primary beneficiary. Conversely, the reporting company would be required to deconsolidate VIEs that are currently consolidated when the company is not considered to be the primary beneficiary. Variable interests are contractual, ownership or other monetary interests in an entity that change as the fair value of the entity’s net assets exclusive of variable interests change. An entity is considered to be a VIE when its capital is insufficient to permit it to finance its activities without additional subordinated financial support or its equity investors, as a group, lack the characteristics of having a controlling financial interest. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain plants considered Qualifying Facilities (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA). After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. While we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We will continue to make appropriate efforts to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. We continue to account for this qualifying facility contract as an executory contract. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $574.7 million through 2025.

(2) Asset Retirement Obligations

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

Our regulated utility operations have, however, previously recognized removal costs of transmission and distribution assets as a component of depreciation in accordance with regulatory treatment. These amounts do not represent Statement of Financial Accounting Standards (SFAS) No. 143 legal retirement obligations. As of September 30, 2005 and December 31, 2004, we have recognized accrued removal costs of $140.4 million and $132.9 million, respectively, which are included in noncurrent regulatory liabilities. In addition, related to our nonregulated electric operations, we have recognized accrued removal costs of $2.1 million and $2.0 million as of September 30, 2005 and December 31, 2004, respectively.

For our generation properties, we have accrued decommissioning costs since the generating units were first put into service in the amount of $12.7 million and $12.3 million as of September 30, 2005 and

December 31, 2004, respectively, which is classified as a noncurrent regulatory liability. These amounts also do not represent SFAS No. 143 legal retirement obligations.

(3) Goodwill

There were no changes in our goodwill during the three and nine months ended September 30, 2005. Goodwill by segment as of September 30, 2005 and December 31, 2004 is as follows (in thousands):

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

(4) Discontinued Operations

During the second quarter of 2003, we committed to a plan to sell or liquidate our interest in Netexit and Blue Dot. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classified the results of operations of Netexit and Blue Dot as discontinued operations.

In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. Netexit’s amended and restated liquidating plan of reorganization was confirmed by the Bankruptcy Court on September 14, 2005 and the plan became effective on September 29, 2005. According to the terms of the plan:

· NorthWestern received an initial distribution of $20 million in cash on September 29, 2005 for its allowed claims.

· A reserve of an additional $5 million was set aside through the amended plan for an additional distribution to NorthWestern after distributions are made on other allowed unsecured claims.

· A reserve of up to $22.9 million was set aside through the amended plan for payment of allowed non-NorthWestern unsecured claims with distribution to occur only after all such unsecured claims are resolved. Any remaining cash from this reserve, which is not paid out to other allowed unsecured claims, will be paid to NorthWestern.

· $8 million was paid on September 29, 2005 to securities class action claimants to satisfy a $20 million allowed liquidated claim provided to former NorthWestern shareholders in a previously announced court-approved settlement.

· After distributions are made to allowed unsecured, administrative and priority claims, any remaining Netexit estate funds will be paid to NorthWestern.

Based on our current estimate of total allowed claims, NorthWestern anticipates receiving an additional distribution of approximately $22-$24 million from Netexit; however, there are still remaining unresolved priority and unsecured claims. Netexit currently holds approximately $36.6 million in cash, which is included in current assets of discontinued operations on our consolidated financial statements.

As of September 30, 2005 and December 31, 2004, Netexit had current assets of $37.4 million and $66.3 million and current liabilities (excluding intercompany amounts) of $16.4 million and $15.6 million, respectively.

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

	Successor Company				Predecessor Company
	Three Months Ended
	September 30, 2005				September 30, 2004
Revenues		$	—			$	—
Loss before income taxes		(355		)		(1,441		)
Income tax provision		—				—
Loss from discontinued operations, net of income taxes		$	(355	)		$	(1,441	)

	Successor Company				Predecessor Company
	Nine Months Ended
	September 30, 2005				September 30, 2004
Revenues		$	—			$	—
Loss before income taxes		$	(9,697	)		$	(966	)
Gain on disposal		—				11,500
Income tax provision		—				—
Gain (loss) from discontinued operations, net of income taxes		$	(9,697	)		$	10,534

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

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

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

	Successor Company				Predecessor Company
	Three Months Ended
	September 30, 2005				September 30, 2004
Revenues		$	1,728			$	4,275
Loss before income taxes		$	(108	)		$	(602	)
Loss on disposal		—				(2,374		)
Income tax provision		—				—
Loss from discontinued operations, net of income taxes		$	(108	)		$	(2,976	)

	Successor Company				Predecessor Company
	Nine Months Ended
	September 30, 2005				September 30, 2004
Revenues		$	3,177			$	26,940
Loss before income taxes		$	(546	)		$	(4,293	)
Gain on disposal		—				3,810
Income tax provision		—				—
Loss from discontinued operations, net of income taxes		$	(546	)		$	(483	)

(5) Other Comprehensive Income (Loss)

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 excluded. Comprehensive income (loss) consists of net income and other comprehensive income. Net income may include such items as income from continuing operations, discontinued operations, extraordinary items, and cumulative effects of changes in accounting principles. Other comprehensive income (loss) may include foreign currency translations, adjustments of minimum pension liability, gains and losses on derivative instruments qualifying as hedges, and unrealized gains and losses on certain investments in debt and equity securities.

Comprehensive income (loss) is calculated as follows (in thousands):

	Successor Company			Predecessor Company				Successor Company			Predecessor Company
	Three Months Ended September 30,							Nine Months Ended September 30,
	2005			2004				2005			2004
Net income (loss)		$	8,836		$	(29,567	)		$	23,823		$	(17,386	)
Other comprehensive income, net of tax:
Unrealized gain on derivative instruments qualifying as hedges, net of tax of $3,363 and $2,418 for the three and nine months ended September 30, 2005, respectively		5,392			—				3,882			—
Foreign currency translation		93			89				65			35
Comprehensive income (loss)		$	14,321		$	(29,478	)		$	27,770		$	(17,351	)

(6) Income Taxes

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

	Successor Company			Predecessor Company			Successor Company			Predecessor Company
	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Federal statutory rate		35.0	%		(35.0	)%		35.0	%		(35.0	)%
State income, net of federal provisions		3.1			(3.8	)		3.1			(3.8	)
Amortization of investment tax credit		(0.7	)		(0.3	)		(0.6	)		(1.3	)
Dividends received deduction and other investments		(0.5	)		(0.2	)		(0.1	)		(0.2	)
Nondeductible professional fees		1.7			24.9			2.0			22.6
Valuation allowance		—			194.5			—			181.0
Prior year permanent return to accrual adjustments		(14.0	)		(181.2	)		(3.3	)		(164.5	)
Other, net		2.2			0.7			1.3			(0.1	)
		26.8	%		(0.4	)%		37.4	%		(1.3	)%

SFAS 109, Accounting for Income Taxes, requires a company to record income taxes at an estimated annual effective tax rate. The rate is revised, if necessary, at the end of each successive interim period during a fiscal year to the company’s best current estimate of its annual effective tax rate. During the third quarter of each year, in connection with filing our tax return, we record discrete items for the tax effect of prior year permanent return to accrual adjustments. The 2005 adjustment was favorable, primarily related to lower nondeductible professional fees than anticipated, which reduced the effective tax rate for the three and nine months ended September 30, 2005, by 14.0% and 3.3%, respectively.

(7) Segment Information

We currently operate our business in five reporting segments: (i) regulated electric operations, (ii) regulated natural gas operations, (iii) unregulated electric, (iv) unregulated natural gas, and (v) all other, which primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments. 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, excluding discontinued operations, are as follows (in thousands):

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

Predecessor Company Three months ended	Regulated			Unregulated
September 30, 2004	Electric	Gas		Electric		Gas	Other		Eliminations			Total
Operating revenues(1)	149,976	39,883			28,018	28,695	462			(17,604	)	229,430
Cost of sales(1)	73,281	24,765			10,088	25,435	356			(17,260	)	116,665
Gross margin	76,695	15,118			17,930	3,260	106			(344	)	112,765
Operating, general and administrative	27,643	11,641			13,067	875	509			(344	)	53,391
Property and other taxes	11,969	3,992			807	17	9			—		16,794
Depreciation	13,852	3,590			304	101	346			—		18,193
Reorganization expenses	—	—			—	—	29,361			—		29,361
Operating income (loss)	23,231	(4,105	)		3,752	2,267	(30,119	)		—		(4,974	)
Total assets	1,502,404	707,116			25,691	66,568	67,686			—		2,369,465
Capital expenditures	13,035	9,829			775	—	4			—		23,643

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

Predecessor Company Nine months ended	Regulated		Unregulated
September 30, 2004	Electric	Gas	Electric		Gas	Other		Eliminations			Total
Operating revenues(1)	425,458	214,328		62,899	96,709	1,720			(48,230	)	752,884
Cost of sales(1)	202,243	140,772		18,883	87,795	1,230			(46,846	)	404,077
Gross margin	223,215	73,556		44,016	8,914	490			(1,384	)	348,807
Operating, general and administrative	83,038	38,378		38,705	2,347	2,522			(1,384	)	163,606
Property and other taxes	36,306	12,807		2,398	52	38			—		51,601
Depreciation	41,564	10,723		913	279	1,132			—		54,611
Reorganization expenses	—	—		—	—	43,821			—		43,821
Operating income (loss)	62,307	11,648		2,000	6,236	(47,023	)		—		35,168
Total assets	1,502,404	707,116		25,691	66,568	67,686			—		2,369,465
Capital expenditures	34,548	15,433		3,942	234	15			—		54,172

(1) In accordance with Emerging Issues Task Force 03-11, Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and not “Held for Trading Purposes” as defined in Issue No. 02-3, which was effective beginning with the fourth quarter of 2003, the Predecessor Company has revised revenues downward from amounts previously reported for the quarter and nine months ended September 30, 2004 to report revenue net versus gross for certain regulated electric and gas contracts that did not physically deliver. These adjustments to revenues did not impact gross margin, operating income or net income as previously reported. These revenue revisions were determined not to be material to the Predecessor Company financial statements. Revenues and cost of sales for the three and nine months ended September 30, 2004 reflected above were each reduced by $19.5 million and $68.6 million, respectively.

(8) New Accounting Standards

In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, or FIN 47. FIN 47 was issued to clarify the accounting for conditional asset retirement obligations in order to have more consistent recognition of liabilities relating to asset retirement obligations and additional information on expected future cash outflows and investments in long-lived assets. While we are currently evaluating the potential impact on our asset retirement obligations, we do not anticipate the effects of FIN 47 will have a material impact on our financial condition or results of operations. FIN 47 is effective for periods ended after December 15, 2005.

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

(9) Reclassifications

Certain 2004 amounts have been reclassified to conform to the 2005 presentation. Such reclassifications have no impact on net income or shareholders’ equity as previously reported.

In 2004, we invested in auction rate securities as part of our cash management strategy. These investments had been historically classified as cash and cash equivalents because of the short duration of their reset periods. Based on converging interpretations of the accounting treatment of auction rate securities we determined that these investments should not be classified as cash and cash equivalents due to their underlying maturities. We also determined that changes in restricted cash should be reflected as an investing activity. As a result, the Consolidated Statement of Cash Flows for the nine months ended September 30, 2004 has been revised to reflect purchase and sales of auction-rate securities and change in

restricted cash as investing activities. These reclassifications have no impact on previously reported total current assets, total assets, working capital position, results of operations or financial covenants.

We have also revised the cash flows presentation related to discontinued operations on our Consolidated Statements of Cash Flows to present cash flows from operating, investing and financing activities of our discontinued operations, instead of in a single line presentation. This change in presentation has no impact on previously reported cash flows from continuing operating, investing or financing activities or results of operations.

In addition, we have revised 2004 revenues and cost of sales as discussed in Note 1 to the second and fourth tables contained in Note 7.

(10) Income per Average Common 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 outstanding used in computing the basic and diluted earnings per share for the three and nine months ended September 30, 2005 are as follows:

	Successor Company
	Three Months Ended September 30, 2005		Nine Months Ended September 30, 2005
Basic computation		35,643,037		35,620,389
Dilutive effect of
Restricted shares		57,271		57,271
Stock warrants		531,851		298,570
Diluted computation		36,232,159		35,976,230

Warrants to purchase 4,617,076 shares of common stock as of September 30, 2005 are dilutive and have been included in the earnings per share calculations. These warrants have an exercise price of $28.04. Under the terms of the warrant agreement, the exercise price of the warrants is subject to adjustment from time to time, based on certain events. These events include additional share issuances and dividend payments. An adjustment is made in the case of a cash dividend if the amount of the cash dividend increases or decreases the exercise price by at least 1%, otherwise such amount is carried forward and taken into account with any subsequent cash dividend. Adjustments in the exercise price also require an adjustment in the number of shares covered by the warrants. As of September 30, 2005 each warrant could be exchanged for 1.02 shares of common stock. Historical earnings per share information for the Predecessor Company has not been presented as all shares were cancelled upon emergence from bankruptcy.

(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, 2005 and 2004 (in thousands):

	Pension Benefits								Other Postretirement Benefits
	Successor Company				Predecessor Company				Successor Company				Predecessor Company
	Three Months Ended September 30
	2005				2004				2005				2004
Components of Net Periodic Benefit Cost
Service cost		$	2,133			$	1,876			$	172			$	337
Interest cost		5,044				5,043				713				1,364
Expected return on plan assets		(5,087		)		(4,712		)		(140		)		(65		)
Amortization of transitional obligation		—				39				—				169
Amortization of prior service cost		—				103				—				—
Recognized actuarial loss		—				321				—				117
Net Periodic Benefit Cost		$	2,090			$	2,670			$	745			$	1,922

	Pension Benefits							Other Postretirement Benefits
	Successor Company			Predecessor Company				Successor Company				Predecessor Company
	Nine Months Ended September 30
	2005			2004				2005				2004
Components of Net Periodic Benefit Cost
Service cost	$	6,399			$	5,629			$	516			$	984
Interest cost	15,132				15,128				2,139				2,185
Expected return on plan assets	(15,261		)		(14,136		)		(420		)		(236		)
Amortization of transitional obligation	—				116				—				—
Amortization of prior service cost	—				311				—				—
Recognized actuarial loss	—				962				—				421
Net Periodic Benefit Cost	$	6,270			$	8,010			$	2,235			$	3,354

On September 15, 2005 we contributed $31.4 million to our pension plans. Historically, the Montana Public Service Commission (MPSC) has utilized a methodology that allows recovery of pension costs on a cash basis. We applied for and received approval of an accounting order from the MPSC to utilize a five-year average of funding cost in our costs of service. Therefore, we maintain a regulatory asset and amortize it based on our five-year average funding requirement. This funding requirement is updated each year utilizing an actuarial analysis based upon current assumptions and asset performance.

(12) 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. We employ established policies and procedures to manage our risk associated with these market fluctuations using various commodity and financial derivative and non-derivative instruments, including forward contracts, swaps and options.

Interest Rates

During the second quarter of 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions of approximately $380 million. These swaps are designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, with the effective portion of gains

and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income in our Consolidated Balance Sheets. We will reclassify gains and losses on the hedges from accumulated other comprehensive income into interest expense in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur. At September 30, 2005, we had $7.1 million in other noncurrent assets based on the market value of our interest rate swaps. These hedging instruments are assessed on a quarterly basis in accordance with SFAS No. 133 to determine if they are effective in offsetting the interest rate risk associated with the forecasted transaction and as of September 30, 2005, we had no hedge ineffectiveness on these swaps.

Commodity Prices

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

At September 30, 2005, we had net unrealized losses of approximately $0.8 million on these hedges recorded in accumulated other comprehensive income, and $0.3 million (including option premium) in other noncurrent assets.

(13) Financing Transaction

On June 30, 2005, we entered into an amended and restated credit agreement that replaced our existing $225 million secured credit facility with an unsecured $200 million senior revolving line of credit with lower borrowing costs. The previous credit facility consisted of a $125 million five-year revolving tranche and a $100 million seven-year term tranche (senior secured term loan B.) In addition, because the amended and restated line of credit is unsecured, $225 million of first mortgage bond collateral securing the previous facility was released by the lenders. The unsecured revolving line of credit will mature on November 1, 2009 and does not amortize. The facility bears interest at a variable rate based upon a grid which is tied to our credit rating from Fitch Investors Service (Fitch), Moody’s Investors Service (Moody’s), and Standard and Poor’s Rating Group (S&P). The ‘spread’ or ‘margin’ ranges from 5¤8% to 1.75% over the London Interbank Offered (LIBO) Rate. The facility currently bears interest at a rate of approximately 5.0%, which is 1.125% over the LIBO Rate.

The amended and restated line of credit continues to include similar covenants with the previous credit facility, which require us to meet certain financial tests, including a minimum interest coverage ratio and a minimum debt to capitalization ratio. The line of credit also contains covenants which, among other things, limit our ability to incur additional indebtedness, create liens, engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, make restricted payments, make loans or advances, and enter into transactions with affiliates. Many of these restrictive covenants will fall away upon the line of credit being rated “investment grade” by two of the three major credit rating agencies consisting of Fitch, Moody’s and S&P. As of September 30, 2005, we are in compliance with all of the covenants under the amended and restated line of credit.

(14) Commitments and Contingencies

Environmental Liabilities

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

We are subject to other environmental laws and regulations including those that relate to former manufactured gas plant sites and other past and present operations and facilities. In addition, we may be subject to financial liabilities related to the investigation and remediation from activities of previous owners or operators of our industrial and generating facilities. The range of exposure for environmental remediation obligations at present is estimated to range between $45.0 million to $84.1 million. Our environmental reserve accrual is $45.0 million as of September 30, 2005.

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three megawatt generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. In April 2003, the Environmental Protection Agency (EPA) announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed partial removal of the contaminated sediments located within the Milltown Reservoir, together with the removal of the Milltown Dam and powerhouse (this remedy was incorporated into the EPA’s formal Record of Decision issued on December 20, 2004). In light of this pre-Record of Decision announcement, we commenced negotiations with the Atlantic Richfield Company, or Atlantic Richfield, to prevent a challenge from Atlantic Richfield to our statutorily exempt status under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) as a potentially responsible party. On September 10, 2003, we executed a confidential settlement agreement with Atlantic Richfield which, among other things, capped our maximum contribution towards remediation of the Milltown Reservoir superfund site. A motion to approve the settlement agreement with Atlantic Richfield was filed with the Bankruptcy Court on October 17, 2003. On April 7, 2004 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 is intended to resolve both our liability with Atlantic Richfield in general accordance with the previously negotiated settlement agreement and establish a framework to resolve our liability with the Government Parties for their claims, including natural resource restoration claims, against NorthWestern as they relate to remediation of the Milltown Site. The Stipulation caps NorthWestern’s and CFB’s collective liability to Atlantic Richfield and the Government Parties at $11.4 million. On June 22, 2004, the Bankruptcy Court approved the Stipulation and the funding of the Atlantic Richfield settlement, as modified by the Stipulation. The amount of the stipulated liability has been fully accrued in the accompanying financial statements. Pursuant to the Stipulation, commencing in August 2004 and each month thereafter, we pay $500,000 alternately into two escrow accounts, one for the State of Montana and one for Atlantic Richfield, until the total agreed amount is funded. As of September 30, 2005, we have fully funded the State of Montana escrow account in the amount of $2.5 million and have funded the Atlantic Richfield account in the amount of $4.5 million. No interest will accrue on the unpaid balance due, and the escrow accounts will remain funded until a final, nonappealable

consent decree is entered by the United States District Court. If, however, a consent decree (i) is not executed by the relevant parties, (ii) is not approved by the United States District Court, or (iii) does not become fully effective, then all funds in the escrow accounts will continue to be held in trust pending further court order. The Stipulation incorporates appropriate releases and indemnifications from Atlantic Richfield under the previously negotiated settlement agreement.

In anticipation of completion of the consent decree negotiations, CFB filed an application to amend its Federal Energy Regulatory Commission (FERC) operating license to allow for the commencement of Stage 1 of the EPA’s proposed plan for the remediation of the Milltown Reservoir superfund site. Stage 1 activities anticipated the permanent drawdown of the Milltown Reservoir and the construction of: (i) the Clark Fork River bypass channel, (ii) a railroad spur to facilitate loading of contaminated sediments to be removed from the reservoir, and (iii) certain equipment access roads. All such construction activity was to take place within FERC jurisdictional areas. On January 19, 2005, the FERC issued an order dismissing CFB’s application, and issuing a notice of intent to accept surrender of CFB’s operating license. On May 6, 2005, the FERC issued a written order, modifying its January 19, 2005 order to deem the Milltown Dam operating license surrendered upon the effective date of the anticipated consent decree. As a result of this order, the FERC will continue to have jurisdiction over the Milltown Dam until the effective date of anticipated consent decree.

Together with CFB, on July 15, 2005, we executed the final consent decree for the Milltown Reservoir superfund site. The consent decree was formally lodged by the United States Department of Justice with the federal district court in Montana. The thirty-day public comment period which began on August 2, 2005 by filing a notice in the Federal Register has closed, with a number of comments having been filed with the EPA. Assuming no formal hearing is held by the federal district judge and no appeal is filed, we believe the court will likely enter the order approving the consent decree by the end of the year. We expect to make a final contribution of approximately $2.5 million when the final consent decree is entered. The terms of the final consent decree are consistent with the Stipulation approved by the Bankruptcy Court.

Legal Proceedings

As a result of the Chapter 11 filing for the period from September 14, 2003 through November 1, 2004, attempts by third parties to collect, secure or enforce remedies with respect to most prepetition claims against us were subject to the automatic stay provisions of Section 362(a) of Chapter 11.

On October 19, 2004, the Bankruptcy Court entered a written order confirming our plan of reorganization. On October 25, 2004, Magten Asset Management Corporation (Magten) filed a notice of appeal of such order seeking, among other things, a reversal of the confirmation order. In connection with this appeal, Magten filed motions with the Bankruptcy Court and the United States District Court for the District of Delaware seeking a stay of the enforcement of the confirmation order to prevent our plan of reorganization from becoming effective. On October 25, 2004, the Bankruptcy Court denied Magten’s motion for a stay, and on October 29, 2004, the Delaware District Court denied Magten’s motion for a stay. With no stay imposed, our plan of reorganization became effective November 1, 2004. On October 26, 2004, Magten filed a notice of appeal of the Bankruptcy Court’s approval of the memorandum of understanding (MOU), which memorialized the settlement of the consolidated securities class actions and consolidated derivative litigation against NorthWestern and others. In March 2005, we moved to dismiss Magten’s appeal of the confirmation order on equitable mootness grounds. Magten’s appeals of the confirmation order and the order approving the MOU have been consolidated before the Delaware District Court. On May 12, 2005, Magten, the Plan Committee and NorthWestern unsuccessfully engaged in mediation to resolve the pending appeals and other pending litigation. On October 21, 2005, the Delaware District Court ordered the parties to mediate their disputes. While we cannot currently predict the impact or resolution of Magten’s appeal of the confirmation order or the mediation, we intend to vigorously defend against the appeal.

On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern Corporation, Gary Drook, Michael Hanson, Brian Bird, Thomas Knapp and Roger Schrum alleging that NorthWestern and the former and current officers committed fraud by failing to include a sufficient amount of shares in the Class 9 reserve set aside for payment of unsecured claims and thus the confirmation order should be revoked and set aside. We filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of the confirmation order appeal. The October 21,2005 order regarding mediation also applies to this action. While we cannot predict the impact or resolution of Magten’s complaint, we intend to vigorously defend against it.

On April 16, 2004, Magten and Law Debenture initiated an adversary proceeding, the QUIPs Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets of CFB to us. In essence, Magten and Law Debenture are asserting that the transfer of the transmission and distribution assets acquired from the Montana Power Company was a fraudulent conveyance because such transfer left CFB insolvent and unable to pay certain claims. The plaintiffs also assert that they are creditors of CFB as a result of Magten owning a portion of the Series A 8.5% Quarterly Income Preferred Securities for which Law Debenture serves as the Indenture Trustee. By its adversary proceeding, the plaintiffs seek, among other things, the avoidance of the transfer of assets, declaration that the assets were fraudulently transferred and are not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets and the return of such assets to CFB. In August 2004, the Bankruptcy Court granted in part, but denied in part our motion to dismiss the QUIPs Litigation. As a result of filing the appeal of the confirmation order, the Bankruptcy Court has stayed the prosecution of this case until the appeal is finally decided. On September 22, 2005, the Delaware District Court withdrew the reference of this action to the Bankruptcy Court and this case now will be heard by the Delaware District Court. On October 21, 2005, the Delaware District Court ordered the parties to mediate their disputes.

On April 19, 2004, Magten also filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for breaches of fiduciary duties by such officers. Those officers have requested CFB to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. That lawsuit has now been transferred to the Federal District Court in Delaware where many of the other Magten related litigation matters are pending. On October 21,2005, the Delaware District Court ordered the parties to mediate their disputes.

On February 9, 2005, we agreed to settlement terms with Magten and Law Debenture to release all claims, including Magten’s and Law Debenture’s fraudulent conveyance action pending against each other for Magten and Law Debenture receiving the distribution of new common stock and warrants from Class 8(b) in the same amounts as if they had voted to accept the Plan and a distribution from Class 9 of new common stock in the amount of approximately $17.4 million. Prior to seeking approval from the Bankruptcy Court, certain major shareholders and the Plan Committee objected to the settlement on both its economic terms and asserting that the structure of the settlement violated the Plan. After reviewing the objections and undertaking our own analysis of the potential Plan violation, we informed Magten and Law Debenture as well as the Plan Committee and the objecting major shareholders that we would not proceed with the settlement. Magten and Law Debenture filed a motion with our Bankruptcy Court seeking approval of the settlement. On March 10, 2005, the Bankruptcy Court entered an order denying the motion filed by Magten and Law Debenture. Magten and Law Debenture have appealed that order. This appeal has been docketed with the District Court and a briefing schedule issued. On October 21,2005, the Delaware District Court ordered the parties to mediate their disputes. At this time, we cannot predict the impact or resolution of any of these lawsuits, the appeal or reasonably estimate a range of possible loss, which could be material. We intend to vigorously defend against the adversary proceeding, appeal and any subsequently filed similar litigation. The plaintiffs’ claims with respect to the QUIPs Litigation will be

treated as general unsecured, or Class 9, claims and will be satisfied out of the share reserve that we established with respect to the Class 9 disputed claims reserve under the plan of reorganization.

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

On November 6, 2003, the Bankruptcy Court approved a stipulation between NorthWestern and the plaintiffs in McGreevey, et al. v. The Montana Power Company, et al. The stipulation provides that litigation, as against NorthWestern, CFB, The Montana Power Company, The Montana Power L.L.C. and Jack Haffey, be temporarily stayed for 180 days from the date of the stipulation. As a result of the confirmation of our plan of reorganization, the stay has been made permanent. On July 10, 2004, we and the other insureds under the applicable directors and officers liability insurance policies along with the plaintiffs in the McGreevey case, plaintiffs in the In Re Touch America Holdings, Inc. Securities Litigation and the Touch America Creditors Committee reached a tentative settlement through mediation. Among the terms of the tentative settlement, we, CFB and other parties will be released from all claims in this case, the plaintiffs in McGreevey will dismiss their claims against the third party purchasers of the generation assets and non-regulated energy assets of Montana Power Company, including PPL Montana, and a settlement fund in the amount of $67 million (all of which will be contributed by the former Montana Power Company directors and officers liability insurance carriers) will be established. The settlement is subject to the occurrence of several conditions, including approval of the proposed settlement by the Bankruptcy Court in our bankruptcy proceeding, and approval of the proposed settlement by the Federal District Court for the District of Montana, where the class actions are pending. On April 29, 2005, the Federal District Court in Montana denied the plaintiffs’ motion for preliminary approval of the proposed settlement without prejudice and ordered the parties to work out their differences and present a global settlement agreement in 60 days; otherwise, the court would order the parties to resume trial preparations. Even though the parties requested additional time to continue to negotiate to reach a consensus on a global settlement agreement, the Federal District Court requested that the parties respond to certain issues by August 12, 2005. In the event the parties do not reach a global settlement agreement, a settlement is not approved or it does not take effect for any other reason, we intend to vigorously defend against this lawsuit. If we are unsuccessful in defending against this class action lawsuit, the plaintiffs’ litigation claims are channeled to the Directors & Officers Trust established under our Plan, or alternatively, would be subordinated to our other debt under our Plan, and such claims would be treated as securities, or Class 14, claims under our plan of reorganization, and would be entitled to no recovery against NorthWestern under our Plan. Claims by our current and former officers and directors (and the former officers and directors of The Montana Power Company) for indemnification for these proceedings would be channeled into the Directors and Officers Trust established by the Plan. The plaintiffs could elect to proceed directly against CFB and the assets owned by such entity, which are not material to our operations or financial position. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition.

bankruptcy case which they did not do. Under the terms of the settlement with the plaintiffs in the McGreevey case discussed above, they would not file such proceeding.) We have removed the action to the federal court in Montana and filed a motion to transfer the action to the Bankruptcy Court in Delaware. We also filed an adversary action in our Bankruptcy Case seeking injunctive relief against the McGreevey plaintiffs to stop them from pursuing their fraudulent conveyance action outside our bankruptcy case. McGreevey plaintiffs answered the adversary complaint and asserted counterclaims against us alleging the same fraudulent conveyance claims. McGreevey plaintiffs also filed a motion to certify certain issues to the Montana Supreme Court. They also filed a motion to remand the fraudulent conveyance action to state court in Montana and the same motion to certify certain issues to the Montana Supreme Court. On October 19, 2005, the bankruptcy court heard arguments on our motion to show cause why the McGreevey plaintiffs should not be held in contempt of the Bankruptcy Court for violating the terms of the channeling injunction in the confirmation order. On October 25, 2005 the Bankruptcy Court preliminarily enjoined the plaintiffs from further prosecuting their claim against us.

In NorthWestern Corporation vs. PPL Montana, LLC vs. NorthWestern Corporation and Clark Fork and Blackfoot, LLC, No. CV-02-94-BU-SHE, (D. MT), we pursued claims against PPL Montana, LLC (PPL) due to its refusal to purchase the Colstrip transmission assets under the Asset Purchase Agreement (APA) executed by and between The Montana Power Company (MPC) and PP&L Global, Inc. (PPL Global). NorthWestern claimed that PPL (PPL Global’s successor-in-interest under the APA) is required to purchase the Colstrip transmission assets for $97.1 million. PPL had asserted a number of counterclaims against NorthWestern and CFB based in large part upon PPL’s claim that MPC and/or NorthWestern breached two Wholesale Transition Service Agreements and certain indemnification obligations under the APA in the approximate amount of $120 million. PPL also filed a proof of claim and an amended proof of claim against NorthWestern’s bankruptcy estate which asserted substantially the same claims as the PPL counterclaim. Our Bankruptcy Court transferred all the claims for resolution to the federal court in Montana. On May 5, 2005, the parties announced a settlement in principle of all claims and counterclaims, which settlement was approved by our Bankruptcy Court on September 29, 2005 and the lawsuit was dismissed with prejudice by the federal court on October 6, 2005. Under the terms of the settlement, NorthWestern retains the Colstrip transmission assets and PPL paid NorthWestern $9.0 million on October 6, 2005. In conjunction with this settlement, we will recognize a $9.0 million pretax gain in the fourth quarter of 2005. The agreement also covers the cancellation of indemnity obligations stemming from the APA (which obligations we agreed to assume when we purchased MPC’s electric and natural gas transmission and distribution business), and PPL’s withdrawal of its claims pending in NorthWestern’s bankruptcy proceeding, the dismissal and release of claims arising out of the litigation, and the release of the shares from the segregated reserve to the general reserve in NorthWestern’s bankruptcy proceeding.

On April 30, 2003, Mr. Richard Hylland, our former President and Chief Operating Officer, filed a demand for arbitration of contract claims under his employment agreement, as well as tort claims for defamation, infliction of emotional distress and tortious interference and a claim for punitive damages. Mr. Hylland sought relief in the amount of $25 million, plus interest, attorney’s fees, costs, and punitive damages. Mr. Hylland also filed claims in our bankruptcy case similar to the claims in his arbitration demand. We disputed Mr. Hylland’s claims and vigorously defended the arbitration and objected to Mr. Hylland’s claims in our bankruptcy case. As a result of the confirmation of our plan of reorganization, this arbitration commenced with parties having filed dispositive motions. On July 18, 2005, the arbitrator ruled on and denied both Mr. Hylland’s and our dispositive motions, but granted our motions related to our affirmative claims and defenses for setoff and other claims. The parties have negotiated a settlement of this matter, as well as Mr. Hylland’s claims in the bankruptcy proceedings, and NorthWestern’s setoff claims. On August 10, 2005, the Bankruptcy Court approved the settlement and the parties will dismiss the arbitration proceedings. Mr. Hylland received 92,233 shares from the disputed claims reserve as a result of this settlement.

Expanets and NorthWestern have been named defendants in two complaints filed with the Supreme Court of the State of New York, County of Bronx, alleging violations of New York’s prevailing wage laws, breach of contract, unjust enrichment, willful failure to pay wages, race, ethnicity, national origin and/or age discrimination and retaliation. In the complaint entitled Felix Adames et al. v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, Bronx County, Index No. 8664-04, which has not yet been served upon Expanets, 14 former employees of Expanets seek damages in the amount of $27,750,000, plus interest, penalties, punitive damages, costs, and attorney’s fees. In the complaint entitled Wayne Belnavis and David Daniels v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, Bronx County, Index No. 8729-04, two former employees of Expanets seek damages in the amount of $12,500,000, plus interest, penalties, punitive damages, costs, and attorney’s fees. Avaya Inc. has sent NorthWestern and subsidiaries a notice seeking indemnification and defense for these lawsuits under the asset purchase agreement by which Avaya purchased Expanets’ assets. We have responded by accepting in part and rejecting in part the indemnification request. As a result of the Netexit bankruptcy, the cases were removed to federal court in New York and Netexit was dismissed from the lawsuit. NorthWestern and Avaya were dismissed as defendants by the plaintiffs. These claims against Netexit are subject to the claims process of the Netexit bankruptcy proceeding. On October 25, 2005, the Bankruptcy Court orally approved a settlement, which provides the plaintiffs with a $1.8 million allowed claim.

Netexit was also subject to an investigation by the New York City Comptroller’s Office over the same prevailing wage allegations set forth in the Adames and Belnavis lawsuits. The Comptroller’s Office filed a claim in the Netexit bankruptcy and in July 2005, Netexit signed an agreement with the Comptroller’s Office to settle this claim for approximately $1.5 million, which was approved by the Bankruptcy Court on September 29, 2005.

On March 17, 2004, certain minority shareholders of Expanets filed a lawsuit against Avaya Inc., Expanets, NorthWestern Growth Corporation, and Merle Lewis, Dick Hylland and Dan Newell entitled Cohen et al. v Avaya Inc., et al. in U.S. District Court in Sioux Falls, South Dakota contending that (i) the defendants fraudulently induced the shareholders to sell their businesses to Expanets during 1998 and 1999 in exchange for Expanets stock which would have value only if Expanets went public, when in fact no IPO was intended, and (ii) the defendants and NorthWestern (a) hid the true financial condition of NorthWestern, NorthWestern Growth and Expanets, (b) permitted internal controls to lapse, (c) failed to document loans by NorthWestern to Expanets, and (d) allowed the individual defendants to realize millions of dollars in bonus payments at the expense of Expanets and its minority shareholders. The lawsuit alleges federal and state securities laws violations and breaches for fiduciary duties. The plaintiffs filed an amended complaint that reflects one less plaintiff and a clarification on the damages that they seek. In addition, Avaya Inc. has sent NorthWestern a notice seeking indemnification and defense for this lawsuit under the terms of the asset purchase agreement. We have responded by accepting in part and rejecting in part the indemnification request. The case has now been stayed against Expanets due to its bankruptcy filing. The defendants, including NorthWestern Growth Corporation, have filed motions to dismiss, which was granted in part and denied in part, and we have filed a formal objection to the claim the defendants filed in both the Netexit and NorthWestern bankruptcy cases. Claims by our former officers and directors for indemnification for these proceedings would be channeled in to the Directors and Officers Trust established pursuant to NorthWestern’s plan of reorganization. The plaintiff’s litigation claims against Netexit would be subordinated to NorthWestern’s debt and claims of general unsecured creditors in the Netexit bankruptcy, and therefore such claims would not be entitled to recovery. The parties have reached a tentative settlement of this action, and will be seeking approval in both the NorthWestern and Netexit Bankruptcy proceedings at the next omnibus hearing date. If the settlement does not go into effect for any reason, NorthWestern Growth Corporation intends to vigorously defend against this lawsuit, however, we cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material.

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 given them notice of the disclosure statement and plan of reorganization in our bankruptcy case 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. Our Bankruptcy Court on May 4, 2005 found that it did not have jurisdiction over these contracts, dismissed our action against these former employees, and transferred our motion to terminate the contracts to Montana state court where the former employees’ lawsuit is pending. We have appealed that order to the district court in Delaware which has ordered the parties to mediate the issues on appeal. The parties have agreed to mediate the dispute on November 9, 2005. In the event the mediation is not successful, we intend to vigorously defend against this lawsuit. We recorded a loss of $2.6 million in the third quarter of 2005 to reestablish a liability for the present value of amounts due to these former employees under their supplemental retirement contracts, however we cannot currently predict the ultimate impact of this litigation.

In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern, NorthWestern Communications Solutions, Expanets and Blue Dot. This development followed the SEC’s requests for information made in connection with the previously disclosed SEC informal inquiry into questions regarding the restatements and other accounting and financial reporting matters. Since December 2003, we have periodically received and continue to receive subpoenas and informal requests from the SEC requesting documents and testimony from employees regarding these matters. The SEC investigation will continue and any claims alleging violations of federal securities laws made by the SEC may not be extinguished pursuant to our plan of reorganization. In addition, certain of our directors and several employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the Federal Bureau of Investigation (FBI) concerning certain of the allegations made in the class action securities and derivative litigation matters. We have not been advised that NorthWestern is the subject of any FBI investigation. We understand that the FBI and the Internal Revenue Service (IRS) have contacted former employees of ours and our subsidiaries. As of the date hereof, we are not aware of any other governmental inquiry or investigation related to these matters. We are fully cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are contacted in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, for which we can provide no assurance, we may face sanctions, including, but not limited to, monetary penalties and injunctive relief, and any monetary liability incurred by us may be material to our financial position or results of operations.

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

Each year we submit a natural gas tracker filing for recovery of natural gas costs. The MPSC reviews such filings and makes a determination as to whether or not our natural gas procurement activities were prudent. If the MPSC finds that we have not exercised prudence, it can disallow such costs. On July 3, 2003, the MPSC issued orders disallowing the recovery of certain gas supply costs for the 2003 and 2004 tracker years. The MPSC also rejected a motion for reconsideration filed by us on July 14, 2003. We filed suit in Montana state court on July 28, 2003, seeking to overturn the MPSC’s decision to disallow recovery of these costs. A tracker year runs from July to June, and because of the MPSC orders, we were disallowed recovery of $6.2 million and $4.6 million for the 2003 and 2004 tracker years, respectively. The MPSC has approved a stipulation between us and the Montana Consumer Counsel regarding the recovery of natural gas costs for the 2003 and 2004 tracking years. With this stipulation as a foundation, we have settled with the MPSC and have been allowed recovery of previously disallowed gas costs of $4.6 million. As a result of the settlement, we recorded gas supply revenue of $4.6 million in the second quarter of 2005.

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

Disputed Claims Reserve

Upon consummation of our plan of reorganization, we established a reserve of approximately 4.4 million shares of common stock from the shares allocated to holders of our trade vendor claims in excess of $20,000 and holders of Class 9 unsecured claims. The shares held in this reserve may be used to resolve various outstanding unsecured claims and unliquidated litigation claims, to the extent these claims were not resolved or deemed allowed upon consummation of our plan of reorganization. If these claims ultimately exceed the reserve, then such claimants would share pro rata as to the shares, if any, remaining in the reserve. We have surrendered control over the common stock provided with respect to the Class 9 reserve and the shares so reserved are administered by our transfer agent; therefore we recognized the issuance of the common stock upon emergence. If excess shares remain in the reserve after satisfaction of all obligations, such amounts would be reallocated pro rata to the allowed Class 7 and 9 claimants.

Other Items

Mr. Drook resigned his employment as President and Chief Executive Officer and all other related positions including his position as a member of the Board of Directors, effective March 29, 2005. In connection with his resignation, Mr. Drook entered into a Separation and Consulting Agreement (Agreement) in which we agreed to pay Mr. Drook the sum of $1.1 million to be paid in equal bi-weekly installments for the 24-month period commencing June 1, 2005. The payment shall become due and payable, less any sums already paid, in the event of Mr. Drook’s disability or death or a change of control of NorthWestern. Under additional terms of the Agreement, Mr. Drook’s remaining unvested portion of restricted stock awards were fully vested, we are obligated to self-fund a life insurance benefit on a term basis in the amount of $1 million until June 1, 2007. Mr. Drook was not able to sell his Sioux Falls residence by November 1, 2005; therefore, pursuant to the Agreement, NorthWestern will be required to purchase it at fair value determined through an appraisal process.

Mr. Schrum resigned his employment as Vice President, Human Resources and Communications effective October 7, 2005. In connection with his resignation, Mr. Schrum entered into a waiver and release (Release) in which we agreed to pay Mr. Schrum $95,000. Under additional terms of the Release, Mr. Schrum’s remaining unvested portion of restricted stock awards were fully vested. Mr. Schrum also entered into a consulting agreement with us to provide services at a fixed hourly rate for a period of approximately six months.

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. “Predecessor Company” refers to us prior to emergence from bankruptcy (operations prior to October 31, 2004). “Successor Company” refers to us after emergence from bankruptcy (operations after November 1, 2004).

OVERVIEW

On September 14, 2003 (the Petition Date), the Predecessor Company filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). On October 19, 2004, the Bankruptcy Court entered an order confirming our Plan of Reorganization (Plan) and the Plan became effective on November 1, 2004.

Between September 14, 2003, and November 1, 2004, the Predecessor Company operated as a debtor-in-possession under the supervision of the Bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code. In accordance with SOP 90-7, we applied the principles of fresh-start reporting as of the close of business on October 31, 2004.

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. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions, including those related to goodwill, qualifying facilities liabilities, impairment of long-lived assets and revenue recognition, among others. Actual results could differ from those estimates.

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

Fresh Start Reporting

Upon applying fresh-start reporting, a new reporting entity (the Successor Company) is deemed to be created and the recorded amounts of assets and liabilities are adjusted to reflect their estimated fair values. The enterprise value was determined using various valuation methods including, (i) reviewing historical financial information (ii) comparing us and our projected performance to the market values of comparable companies, (iii) performing industry precedent transaction analysis, and (iv) considering certain economic and industry information relevant to the operating business. The estimated enterprise value is highly dependent upon achieving the future financial results set forth in the projections used in the valuation upon our emergence from bankruptcy, and is necessarily based on a variety of estimates and assumptions which, though considered reasonable by management, may not be realized and are inherently subject to significant business and economic uncertainties and contingencies, many of which are beyond our control.

Goodwill

We believe that the accounting estimate related to determining the fair value of goodwill, and thus any impairment, is a “critical accounting estimate” because: (i) it is highly susceptible to change from period to period since it requires company management to make cash flow assumptions about future revenues, operating costs and discount rates over an indefinite life; and (ii) recognizing an impairment has had a significant impact on the assets reported on our balance sheet and our operating results. Management’s assumptions about future sales margins and volumes require significant judgment because actual margins and volumes have fluctuated in the past and are expected to continue to do so. In estimating future margins, we use our internal budgets.

Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets, was issued during 2001 and is effective for all fiscal years beginning after December 15, 2001. According to the guidance set forth in SFAS No. 142, we are required to evaluate our goodwill for impairment at least annually (October 1) and more frequently when indications of impairment exist. Accounting standards require that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, we compare the implied fair value of the reporting unit’s goodwill with its carrying value.

Qualifying Facilities Liability

Certain QFs under PURPA require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. As of September 30, 2005, our gross contractual obligation related to the QFs is approximately $1.6 billion. A portion of the costs incurred to purchase this energy is recoverable though rates authorized by the MPSC, totaling approximately $1.3 billion through 2029. Upon adoption of fresh-start reporting, we recomputed the fair value of the liability to be approximately $143.8 million based on the net present value of the difference between our obligations under the QFs and the related amount recoverable. During the first quarter of 2005, we amended one of these contracts, which reduced our capacity and energy rates over the term of the contract (through 2028). As a result of this amendment, we reduced our QF liability based on the new rates, resulting in a $4.9 million gain. At September 30, 2005, our estimated QF liability was $136.5 million. The determination of the discount rate used to establish this liability was a significant assumption. We determined the appropriate discount rate to be 7.75%, in accordance with Statement of Financial Accounting Concepts No. 7, Using Cash Flow Information and Present Value in Accounting Measures. We believe that 7.75% approximates the rate we could have negotiated with an independent lender for a similar transaction under comparable terms and conditions as of the fresh-start reporting date. In computing the liability, we have also had to make various estimates in relation to contract costs, capacity utilization, and recoverable amounts. Actual QF utilization, QF contract amendments and future regulatory changes relating to QFs could significantly impact our results of operations.

Long-lived Assets

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

During the fourth quarter of 2004, we recorded an additional impairment charge of $10.0 million due to further decline in the estimated realizable value of our investment in our Montana First Megawatts electric generation project. We had recorded impairment charges of $12.4 million and $35.7 million in previous years.

Revenue Recognition

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

Regulatory Assets and Liabilities

Our regulated operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and default electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. If any part of our operations become no longer subject to the provisions of SFAS No. 71, then we would need to evaluate the probable future recovery of or reduction in revenue with respect to the related regulatory assets and liabilities. In addition, we would need to determine if there was any impairment to the carrying costs of deregulated plant and inventory assets.

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

Pension and Postretirement Benefit Plans

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

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

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

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

Income Taxes

We realized substantial cancellation of indebtedness (COD) income in 2004. For tax purposes, we were not required to include any COD income in our taxable income when we emerged, however we were required to reduce certain tax attributes up to the amount of COD income. During the third quarter of 2005, we filed our 2004 tax return and reduced our consolidated net operating loss carryforwards (CNOLs) by approximately $575 million of COD income. After filing our 2004 tax return, we have approximately $276 million of CNOLs that may be used to offset taxable income in 2005 and future years. This includes approximately $118 million of Blue Dot CNOLs (included in discontinued operations) which is currently fully reserved. Under our plan of reorganization, there was an “ownership change” as defined under Internal Revenue Code Section 382 in connection with our emergence from bankruptcy, which provides an annual limit on the ability to utilize our CNOLs. Based on this limitation and our current assumptions, we estimate the majority of our CNOLs will be utilized. Upon the adoption of fresh-start reporting, we removed substantially all of the valuation allowance against our deferred tax assets related to continuing operations because, based on our current projections, we believe it is more likely than not that these assets will be realized. While we believe our assumptions are reasonable, changes to these assumptions could materially affect our results.

In addition, during the third quarter of 2005, Blue Dot sold its last remaining operating location. We are currently reviewing our tax position as it relates to Blue Dot and we anticipate completing our assessment during the fourth quarter of 2005.

Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. Management has established a liability based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, management evaluates the liability in light of any additional information and adjusts the balance as necessary to reflect the best estimate of the future outcomes. We believe our established liability is appropriate for estimated exposures, however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our consolidated statement of operations and provision for income taxes.

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

RESULTS OF OPERATIONS

The following is a summary of our consolidated results of operations for the three-month and nine-month periods ended September 30, 2005 and 2004. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment.

Factors Affecting Results of Continuing Operations

Our revenues may fluctuate substantially with changes in supply costs, which are typically collected in rates from customers and therefore do not impact gross margin. Revenues are also impacted to a lesser extent by customer usage, which is primarily affected by weather and growth. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

OVERALL CONSOLIDATED RESULTS

Three Months Ended September 30, 2005 Compared to the Three Months Ended September 30, 2004

Consolidated revenues for the three months ended September 30, 2005 were $239.1 million, an increase of $9.7 million, or 4.2%, over the same period in 2004. Revenue from our regulated electric and natural gas segments increased $10.2 million due to higher supply costs. Regulated electric revenue also increased $5.3 million due to higher transmission and distribution sales and $0.8 million from transmitting more energy across our lines for others, while our regulated gas wholesale revenues decreased $8.5 million. In addition, our unregulated gas segment revenues increased $1.5 million, mainly from an increase in supply costs, which was mostly offset by a $1.2 million decrease in unregulated electric revenue. A $1.2 decrease in intersegment eliminations also contributed to the overall revenue increase.

Consolidated cost of sales for the three months ended September 30, 2005 was $117.8 million, an increase of $1.1 million, or 0.9%, over the same period in 2004. This increase was primarily due to $9.0 million in higher regulated electric cost of sales offset by a decrease of $8.8 million in regulated natural gas cost of sales. Regulated natural gas cost of sales for the three months ended September 30, 2004 includes a $1.6 million loss on a fixed price sales contract. A $1.2 decrease in intersegment eliminations also contributed to the cost of sales increase.

Consolidated gross margin for the three months ended September 30, 2005 was $121.3 million, an increase of $8.5 million, or 7.5%, over gross margin of $112.8 million in 2004. Margins in our regulated electric segment increased $6.3 million due to higher volume sales to our transmission and distribution customers. Margins in our regulated gas segment increased $2.2 million primarily because we recorded a $1.6 million loss on a fixed price sales contract in the third quarter of 2004.

Gross margin as a percentage of revenues was 50.7% for the three months September 30, 2005, compared to 49.2% in the same period 2004. Gross margin as a percentage of revenue is primarily impacted by the fluctuations that occur in regulated electric and natural gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Consolidated operating, general and administrative expenses were $59.3 million for the three months ended September 30, 2005 as compared to $53.4 million in the same period 2004. The 2005 expense includes approximately $2.5 million of increased pension expense and approximately $2.9 million in compensation expense related to a broad based stock grant to employees. This was offset by a lease expense decrease of approximately $2.5 million in the third quarter of 2005 due to the extension of our operating lease for the Colstrip Unit 4 generation facility. Property and other taxes were $18.4 million in 2005 as compared to $16.8 million in 2004. Depreciation expense was $18.4 million in 2005 as compared to $18.2 million in 2004.

Reorganization items consists of bankruptcy related professional fees and expenses. These expenses totaled $2.9 million for the three months ended September 30, 2005 as compared to $29.4 million during the same period in 2004. While we have emerged from bankruptcy, we are still incurring reorganization related professional fees, primarily associated with the resolution of the QUIPs litigation and the resolution of other disputed Class 9 claims. The reorganization expenses for the three months ended September 30, 2005 includes a $2.6 million loss associated with the reestablishment of a liability that was removed from our balance sheet upon emergence from bankruptcy for contracts of former Montana Power Company employees. We continue to pay professional fees incurred by the Plan Committee in addition to our own professional fees.

Consolidated operating income for the three months ended September 30, 2005 was $22.3 million, as compared to a consolidated operating loss of $5.0 million in 2004. This $27.3 million increase was primarily due to the higher gross margins and decreased expense related to reorganization items noted above.

Consolidated interest expense for the three months ended September 30, 2005 was $14.9 million, a decrease of $6.6 million, or 31.0%, from 2004. This decrease was attributable to repayment of approximately $175 million in secured debt since September 30, 2004, as well as our November 1, 2004 financing transaction, which replaced a $390 million senior secured term loan with lower interest rate debt. See “Liquidity and Capital Resources” for additional information regarding our financing transactions.

Consolidated investment income and other for the three months ended September 30, 2005 was $5.4 million, an increase of $4.1 million from 2004. This increase was primarily due to a $4.7 million gain from the sale of excess sulfur dioxide (SO2) emission allowances. Each allowance permits a generating unit to emit one ton of SO2 during or after a specified year. The market value of SO2 emission allowances increased significantly during the third quarter 2005 and we sold our excess SO2 emission allowances covering years 2011 through 2016. Proceeds from the sale of these emission allowances are not subject to regulatory jurisdiction. We have excess SO2 emission allowances remaining for years 2017 through 2031, however the market for these years is presently illiquid and these allowances have no carrying value in our financial statements.

Consolidated provision for income taxes for the three months ended September 30, 2005 was $3.4 million as compared to a benefit of $0.1 million in 2004. While we were in bankruptcy, we maintained a valuation allowance against our deferred tax assets. Due to our significant net operating losses, the valuation allowance had the effect of minimizing our income tax expense as most changes in income were offset by an increase or decrease in the valuation allowance. Upon emergence from bankruptcy, we reduced our valuation allowance; therefore our provision has increased. 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 2008, based on our anticipated use of net operating losses.

Loss from discontinued operations for the three months ended September 30, 2005 was $0.5 million as compared to $4.4 million for the same period in 2004. The 2004 results were due to losses realized on the disposal of Blue Dot locations and professional fees related to the Netexit bankruptcy proceedings.

Consolidated net income for the three months ended September 30, 2005 was $8.8 million, a $38.4 million improvement as compared to the same period in 2004. This improvement was primarily related to the higher margins, decreased operating and interest expenses, and improved discontinued operating results, partly offset by an increase in income taxes discussed above.

Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004

Consolidated revenues for the nine months ended September 30, 2005 were $823.6 million, an increase of $70.7 million, or 9.4%, over the same period in 2004. Revenue from our regulated electric and natural gas segments increased $55.2 million from higher supply costs. In addition, our regulated electric segment revenue also increased $11.3 million from higher transmission and distribution sales. Our unregulated gas segment revenues increased $16.6 million mainly from increased supply costs, and our unregulated electric revenues increased $9.8 million due primarily to higher market prices. This increase in revenues was partially offset by $16.6 million in higher intersegment eliminations.

Consolidated cost of sales for the nine months September 30, 2005 was $439.4 million, an increase of $35.3 million, or 8.7%, over the same period in 2004. Consistent with revenue, the increase in our regulated business cost of sales was primarily due to higher supply costs, including an increase of $18.5 million in our regulated electric segment and a $14.9 million increase in our regulated gas segment. The increase in regulated electric supply costs was due to higher volume sales to our transmission and distribution customers and higher supply costs which are collected in rates from our customers, partly offset by decreases in out of market costs of approximately $7.1 million associated with our QF contracts, including a $4.9 million gain in the first quarter of 2005 related to a QF contract amendment. In addition, we incurred a $2.1 million loss in the second quarter 2004 related to a dispute settlement with a wholesale

power supply vendor. The increase in regulated gas supply costs was due to higher volume sales, offset by the recovery in the second quarter 2005 of $4.6 million of gas costs previously disallowed by the MPSC. In the nine months ended September 30, 2004, we recorded $2.8 million of disallowed gas costs and a $2.8 million loss on a fixed price sales contract.Our unregulated gas costs increased $17.0 million, primarily due to higher average gas prices, and our unregulated electric supply costs increased $3.7 million due to higher volumes from increased plant availability. Partially offsetting this increase was a $16.8 million increase in intersegment eliminations.

Consolidated gross margin for the nine months ended September 30, 2005 was $384.2 million, an increase of $35.4 million, or 10.1%, over gross margin of $348.8 million in 2004. Margins in our regulated electric segment increased $18.1 million primarily due to $11.3 million higher volume sales to our transmission and distribution customers and decreases in out of market costs of approximately $7.1 million associated with our QF contracts, including a gain of approximately $4.9 million in the first quarter of 2005 due to a QF contract amendment. A $2.3 million decrease in wholesale revenues partially offset these increases. In addition, we recorded a $2.1 million loss in the second quarter of 2004 related to a dispute settlement with a wholesale power supply vendor. Margins in our regulated gas segment increased $11.0 million primarily due to the recovery of $4.6 million in the second quarter of 2005 of gas supply costs previously disallowed by the MPSC. In addition, during the first nine months of 2004, we wrote off $2.8 million associated with the MPSC’s disallowance of gas costs and $2.8 million related to a fixed price sales contract. Our unregulated electric segment margins increased $6.8 million primarily due to higher market prices.

Gross margin as a percentage of revenues was 46.7% for the nine months ended September 30, 2005, a slight increase from 46.3% in the same period 2004. Gross margin as a percentage of revenue is primarily impacted by the fluctuations that occur in regulated electric and natural gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Consolidated operating, general and administrative expenses for the nine months ended September 30, 2005 increased $9.2 million, or 5.6%, as compared to the same period in 2004. This increase was primarily due to an increase in pension expense of approximately $7.4 million, approximately $1.9 million in severance and restricted stock expense associated with the resignation of our former CEO, approximately $0.8 million in compensation expense related to the vesting of restricted stock granted to directors and employees, and approximately $2.9 million in compensation expense related to the broad based stock grant to employees, partially offset by reduced lease expense of approximately $5.0 million related to the extension of our operating lease for the Colstrip Unit 4 generation facility. Property and other taxes were $54.0 million in 2005 as compared to $51.6 million in 2004. Depreciation expense was $56.0 million in 2005 as compared to $54.6 million in 2004.

Reorganization items consist of bankruptcy related professional fees and expenses. These expenses totaled $7.0 million for the nine months ended September 30, 2005 as compared to $43.8 million in 2004. While we have emerged from bankruptcy, we are still incurring reorganization related professional fees, primarily associated with the resolution of the QUIPs litigation and the resolution of other disputed Class 9 claims. As discussed above, the expenses for the nine months ended September 30, 2005 includes a $2.6 million loss for the reestablishment of a liability that was removed from our balance sheet upon emergence from bankruptcy. We continue to pay professional fees incurred by the Plan Committee in addition to our own professional fees.

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

Consolidated operating income for the nine months ended September 30, 2005 was $94.4 million, as compared to $35.2 million in 2004. This $59.2 million increase was primarily due to the higher gross margins and decreased expense related to reorganization items noted above.

Consolidated interest expense for the nine months ended September 30, 2005 was $47.0 million, a decrease of $18.5 million, or 28.2%, from 2004. This decrease was attributable to repayment of approximately $175 million in secured debt since September 30, 2004, as well as our November 1, 2004 financing transaction, which replaced our $390 million senior secured term loan with lower interest rate debt. See “Liquidity and Capital Resources” for additional information regarding our financing transactions.

Consolidated investment income and other for the nine months ended September 30, 2005 was $7.6 million, an increase of $5.1 million from 2004. This increase was primarily due to a $4.7 million gain from the sale of SO2 emission allowances.

Consolidated provision for income taxes for the nine months ended September 30, 2005 was $20.3 million as compared to a benefit of $0.4 million in 2004. While we were in bankruptcy, we maintained a valuation allowance against our deferred tax assets. Due to our significant net operating losses, the valuation allowance had the effect of minimizing our income tax expense as most changes in income were offset by an increase or decrease in the valuation allowance. Upon emergence from bankruptcy, we reduced our valuation allowance based on our estimated realizability of these tax benefits. We expect our effective tax rate for 2005 to be approximately 41%. Many of the professional fees associated with our reorganization are not deductible for tax purposes in accordance with the Internal Revenue Code, which increases our effective tax rate. 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 2008, based on our anticipated use of net operating losses.

Loss from discontinued operations for the nine months ended September 30, 2005 was $10.2 million as compared to income of $10.1 million in 2004. The loss in 2005 is primarily related to settlements reached in Netexit’s bankruptcy proceedings. The 2004 results were primarily due to a Netexit gain of $11.5 million related to a settlement with Avaya.

Consolidated net income for the nine months ended September 30, 2005 was $23.8 million, an improvement of $41.2 million over a consolidated net loss of $17.4 million in 2004. This improvement was primarily related to the higher margins and decreased operating and interest expenses, substantially offset by an increase in income taxes and the loss on discontinued operations discussed above.

REGULATED OPERATIONS

Regulated Electric Segment

Three Months Ended September 30, 2005 Compared to the Three Months Ended September 30, 2004

	Results
	2005			2004			Change			Change %
	(in millions)
Electric supply revenue	$	76.1		$	67.2			$	8.9		13.2	%
Transmission & distribution revenue	74.3			69.0				5.3			7.7
Rate schedule revenue	150.4			136.2				14.2			10.4
Transmission	10.3			9.5				0.8			8.4
Wholesale	2.8			2.6				0.2			7.7
Miscellaneous	1.8			1.7				0.1			5.9
Total Revenues	$	165.3		$	150.0			$	15.3		10.2
Supply costs	76.4			68.4				8.0			11.7
Other cost of sales	5.9			4.9				1.0			20.4
Total Cost of Sales	$	82.3		$	73.3			$	9.0		12.3
Gross Margin	83.0			$	76.7			$	6.3		8.2	%
% GM/Rev	50.2		%	51.1		%

	Volumes MWH
	2005	2004	Change			Change %
	(in thousands)
Retail Electric
Residential	634	581		53			9.1	%
Commercial	1,022	980		42			4.3
Industrial	791	724		67			9.3
Other	85	79		6			7.6
Total Retail Electric	2,532	2,364		168			7.1	%
Wholesale Electric	58	91		(33	)		(36.3	)%

Rate Schedule Revenue

Rate schedule revenue consists of revenue earned from customers for electric supply and transmission and distribution of electricity. Rate schedule revenue 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, 2005 increased $14.2 million, or 10.4% over results in the same period of 2004. This increase consisted of $8.9 million related to increased electric supply revenues and $5.3 million related to increased transmission and distribution revenues. Electric supply revenues increased $6.1 million from higher supply costs which are collected in rates from our customers and $2.8 million due to increased volumes. This increase in volumes was also the primary cause of the transmission and distribution revenue increase, with a 9.1% increase in volumes used by our residential customers, a 4.3% increase in volumes used by our commercial customers, and a 9.3% increase in volumes used by our industrial customers.

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 caused the $0.8 million, or 8.4%, increase in transmission revenue for the three months ended September 30, 2005.

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 increased $0.2 million, or 7.7%, primarily due to $1.8 million, or 72.1%, higher average prices partially offset by a $1.6 million, or 36.8%, decrease in volumes sold in the secondary markets. We had less energy available to sell during the third quarter of 2005 due to the combination of increased retail demand due to warmer weather and decreased plant availability resulting from maintenance.

Gross Margin

Gross margin for the three months ended September 30, 2005 increased $6.3 million, or 8.2% over the same period in 2004, primarily due to $5.3 million in higher volume sales to our transmission and distribution customers.

Margin as a percentage of revenues decreased to 50.2% for the three months ended September 30, 2005, from 51.1% for 2004. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Volumes

Retail electric volumes for the three months ended September 30, 2005 totaled 2,532,068 MWHs, compared with 2,364,328 MWHs in the same period in 2004. This increase was primarily related to a 1.7% increase in customer growth and warmer summer weather in the current period as compared to the prior period in all regulated markets, with an 18% and 91% increase in cooling degree days in Montana and South Dakota, respectively. A cooling degree day is a unit used to relate the day’s temperature to energy demands, and is defined as the difference between 65° F and the average of the high and low temperatures in a given day. Wholesale electric volumes in the third quarter of 2005 were 57,579 MWHs, compared with 91,043 MWHs in the same period in 2004. Regulated wholesale electric volumes decreased during the third quarter of 2005 resulting from increased retail demand due to warmer weather and lower generation plant availability due to scheduled maintenance.

Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004

	Results
	2005			2004			Change				Change %
	(in millions)
Electric supply revenue	$	212.4		$	182.4			$	30.0			16.4	%
Transmission & distribution revenue	210.9			199.6				11.3				5.7
Rate schedule revenue	423.3			382.0				41.3				10.8
Transmission	28.8			29.2				(0.4		)		(1.4	)
Wholesale	6.9			9.2				(2.3		)		(25.0	)
Miscellaneous	5.4			5.0				0.4				8.0
Total Revenues	$	464.4		$	425.4			$	39.0			9.2
Supply costs	208.0			189.5				18.5				9.8
Other cost of sales	15.1			12.7				2.4				18.9
Total Cost of Sales	$	223.1		$	202.2			$	20.9			10.3
Gross Margin	$	241.3		$	223.2			$	18.1			8.1	%
% GM/Rev	52.0		%	52.5		%

	Volumes MWH
	2005	2004	Change			Change %
	(in thousands)
Retail Electric
Residential	1,911	1,814		97			5.3	%
Commercial	2,858	2,771		87			3.1
Industrial	2,272	2,149		123			5.7
Other	150	153		(3	)		(2.0	)
Total Retail Electric	7,191	6,887		304			4.4	%
Wholesale Electric	171	309		(138	)		(44.7	)%

Rate Schedule Revenue

Electric rate schedule revenue for the nine months ended September 30, 2005 increased $41.3 million, or 10.8% over results in the first nine months of 2004. This increase consisted of $30.0 million related to increased electric supply revenues and $11.3 million related to increased transmission and distribution revenues. Electric supply revenues increased $13.2 million from higher supply costs which are collected in rates from our customers and $16.8 million due to an increase in volumes. This increase in volumes was also the primary cause of the transmission and distribution revenue increase, with a 5.3% increase in volumes used by our residential customers, a 3.1% increase in volumes used by our commercial customers, and a 5.7% increase in volumes used by our industrial customers.

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. The absence of price differentials in the market was the primary reason for the $0.4 million, or 1.4%, decrease in transmission revenue.

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. During the nine months ended September 30, 2005, these revenues decreased $2.3 million, or 25.0%, as compared to the same period in 2004. This decrease was primarily due to a $5.6 million, or 44.7%, decrease in volumes sold in the secondary markets partially offset by $3.3 million, or 36.3% higher average prices. We had less energy available to sell due to the combination of increased retail demand due to warmer weather and decreased plant availability resulting from scheduled maintenance.

Gross Margin

Gross margin for the nine months ended September 30, 2005 increased $18.1 million, or 8.1% over the first nine months of 2004, primarily due to $11.3 million higher volume sales to our transmission and distribution customers and decreases in out of market costs of approximately $7.1 million associated with our QF contracts, including a $4.9 million gain related to a QF contract amendment. This amendment reduces our capacity and energy rates over the term of the contract (through 2028) and we have reduced our QF liability based on the new rates. QF costs can differ substantially from year to year depending on the actual output of the QF’s as compared to the estimates we used in recording our QF liability. A $2.3 million decrease in wholesale revenues partially offset these increases. In addition, we recorded a $2.1 million loss in the second quarter of 2004 related to a dispute settlement with a wholesale power supply vendor.

Margin as a percentage of revenues decreased to 52.0% for the nine months ended September 30, 2005, from 52.5% for 2004. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Volumes

Regulated retail electric volumes for the nine months ended September 30, 2005 totaled 7,191,335 MWHs, compared with 6,886,776 MWHs in the same period in 2004. This increase was primarily related to a 1.7% increase in customer growth and warmer summer weather in the nine months as compared to the prior period in all regulated markets. Regulated wholesale electric volumes in the first nine months of 2005 were 170,992 MWHs, compared with 309,365 MWHs in the same period in 2004. Regulated wholesale electric volumes decreased during the first nine months of 2005 resulting from increased retail demand due to warmer weather and lower generation plant availability due to scheduled maintenance.

Regulated Natural Gas Segment

Three Months Ended September 30, 2005 Compared to the Three Months Ended September 30, 2004

	Results
	2005			2004			Change				Change %
	(in millions)
Gas supply revenue	$	15.7		$	14.4			$	1.3			9.0	%
Transportation, distribution & storage revenue	12.5			12.2				0.3				2.5
Rate schedule revenue	28.2			26.6				1.6				6.0
Wholesale revenue	—			8.5				(8.5		)		(100.0	)
Transportation	4.5			4.1				0.4				9.8
Miscellaneous	0.6			0.7				(0.1		)		(14.3	)
Total Revenues	$	33.3		$	39.9			$	(6.6	)		(16.5	)
Supply costs	15.8			16.0				(0.2		)		(1.3	)
Wholesale supply costs	—			8.5				(8.5		)		(100.0	)
Other cost of sales	0.2			0.3				(0.1		)		(33.3	)
Total Cost of Sales	$	16.0		$	24.8			$	(8.8	)		(35.5	)
Gross Margin	$	17.3		$	15.1			$	2.2			14.6	%
% GM/Rev	52.0		%	37.8		%

	Volumes MMbtu
	2005	2004	Change			Change %
	(in thousands)
Retail Gas
Residential	1,255	1,324		(69	)		(5.2	)%
Commercial	969	1,000		(31	)		(3.1	)
Industrial	12	14		(2	)		(14.3	)
Other	15	6		9			150.0
Total Retail Gas	2,251	2,344		(93	)		(4.0	)%

Rate Schedule Revenue

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

Gas supply revenues for the three months ended September 30, 2005 increased $1.3 million, or 9.0% over results in the second quarter of 2004. This increase consisted of a $2.0 million increase in supply costs partly offset by a $0.7 million, or 4.0%, decrease in volumes.

Wholesale Revenue

Wholesale revenue decreased $8.5 million due to reduced sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.

Transportation Revenue

Transportation revenue consists of revenue earned for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. Transportation revenue increased slightly for the third quarter 2005 as compared to the same period 2004.

Gross Margin

Gross margin was $17.3 million for the three months ended September 30, 2005, an increase of $2.2 million, or 14.6%, from the same period in 2004 primarily due to the slightly higher transportation revenue and the write off of $1.6 million during the third quarter of 2004 related to a fixed price sales contract.

Margin as a percentage of revenue increased to 52.0% for 2005, from 37.8% for 2004. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Volumes

Regulated retail natural gas volumes were 2,251,246 MMbtu (million British Thermal Units) during the third quarter of 2005, compared with 2,343,984 MMbtu or a 4.0% decrease from the same period in 2004. This decrease was due to warmer weather and customer conservation efforts in the current period as compared to the prior period in all regulated markets.

Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004

	Results
	2005			2004			Change				Change %
	(in millions)
Gas supply revenue	$	138.7		$	113.5			$	25.2			22.2	%
Transportation, distribution & storage revenue	65.9			65.4				0.5				0.8
Rate schedule revenue	204.6			178.9				25.7				14.4
Wholesale revenue	16.8			20.0				(3.2		)		(16.0	)
Transportation	13.1			12.4				0.7				5.6
Miscellaneous	2.9			3.0				(0.1		)		(3.3	)
Total Revenues	$	237.4		$	214.3			$	23.1			10.8
Supply costs	134.3			119.4				14.9				12.5
Wholesale supply costs	16.8			20.0				(3.2		)		(16.0	)
Other cost of sales	1.8			1.4				0.4				28.6
Total Cost of Sales	$	152.9		$	140.8			$	12.1			8.6
Gross Margin	$ 84.5			$ 73.5				$	11.0			15.0	%
% GM/Rev	35.6		%	34.3		%

	Volumes MMbtu
	2005	2004	Change			Change %
	(in thousands)
Retail Gas
Residential	12,344	12,455		(111	)		(0.9	)%
Commercial	7,465	7,387		78			1.1
Industrial	117	132		(15	)		(11.4	)
Other	95	81		14			17.3
Total Retail Gas	20,021	20,055		(34	)		(0.2	)%

Rate Schedule Revenue

Gas supply revenues in the first nine months of 2005 increased $25.2 million, or 22.2% over results in the first nine months of 2004. This increase primarily consisted of a $20.8 million increase in supply costs and the recognition of $4.6 million for the recovery of supply costs previously disallowed by the MPSC.

Wholesale Revenue

Wholesale revenue decreased $3.2 million due to reduced sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.

Transportation Revenue

Transportation revenue consists of revenue earned for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. Transportation revenue increased $0.7 million for the first nine months of 2005 as compared to the same period 2004.

Gross Margin

Gross margin was $84.5 million in the first nine months of 2005, an increase of $11.0 million, or 15.0%, from the same period in 2004 primarily due to the recovery of previously disallowed gas costs as discussed above and the higher transportation revenue. In addition, during the first nine months of 2004, we wrote off $2.8 million associated with the MPSC’s disallowance of gas costs and $2.8 million related to a fixed price sales contract.

Margin as a percentage of revenue increased to 35.6% for 2005, from 34.3% for 2004. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Volumes

Regulated retail natural gas volumes were 20,021,412 MMbtu (million British Thermal Units) during the first nine months of 2005, compared with 20,054,664 MMbtu, a slight decrease from the same period in 2004.

UNREGULATED OPERATIONS

Unregulated Electric Segment

Our unregulated electric segment reflects the operations of our Colstrip Unit 4 division and CFB’s results arising from the ownership and operation of the three-megawatt Milltown Dam hydroelectric facility. We sell our leased share of Colstrip Unit 4 generation, representing approximately 222 megawatts at full load, principally to two unrelated third parties under agreements through December, 2010. We also have a separate agreement to repurchase 111 megawatts through December, 2010.

Three Months Ended September 30, 2005 Compared to the Three Months Ended September 30, 2004

	Results
	2005			2004			Change				Change %
	(in millions)
Total Revenues	$	26.8		$	28.0			$	(1.2	)		(4.3	)%
Supply costs	8.2			9.5				(1.3		)		(13.7	)
Wheeling costs	0.7			0.6				0.1				16.7
Total Cost of Sales	$	8.9		$	10.1			$	(1.2	)		(11.9	)
Gross Margin	$	17.9		$	17.9			$	—			—	%
% GM/Rev	66.8		%	63.9		%

Volumes MWH

2005

2004

Change

Change %

(in thousands)

Wholesale Electric

437

395

10.6

Revenue

Unregulated electric revenue decreased $1.2 million, or 4.3%. This decrease is due to a combination of factors, including less favorable pricing under existing agreements offset by increased market prices for additional volumes generated as compared to the third quarter of 2004.

Gross Margin

Gross margin remained flat as compared to the same period in 2004.

Volumes

Unregulated electric volumes were 436,931 MWHs in the third quarter of 2005, compared with 395,183 MWHs in the same period in 2004. The 2005 increase in volumes was due primarily to generation plant availability with less down time for scheduled maintenance.

Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004

	Results
	2005			2004			Change				Change %
	(in millions)
Total Revenues	$	72.7		$	62.9			$	9.8			15.6	%
Supply costs	20.0			16.3				3.7				22.7
Wheeling costs	1.9			2.6				(0.7		)		(26.9	)
Total Cost of Sales	$	21.9		$	18.9			$	3.0			15.9
Gross Margin	$	50.8		$	44.0			$	6.8			15.5	%
% GM/Rev	69.9		%	70.0		%

Volumes MWH

2005

2004

Change

Change %

(in thousands)

Wholesale Electric

1,403

1,121

282

25.2

Revenue

Unregulated electric revenue increased $9.8 million, or 15.6%, due primarily to higher market prices and a 25.2% increase in volumes. We had more energy available to sell due to increased plant availability in 2005 with less down time for scheduled maintenance.

Gross Margin

Gross margin increased $6.8 million, or 15.5%, primarily due to higher market prices partially offset by a $3.7 million increase in supply costs resulting primarily from the higher volumes.

Volumes

Unregulated electric volumes were 1,403,337 MWHs in the first nine months of 2005, compared with 1,121,189 MWHs in the same period in 2004. The 2005 increase in volumes was due primarily to increased generation plant availability with less down time for scheduled maintenance.

Unregulated Natural Gas Segment

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

Three Months Ended September 30, 2005 Compared to the Three Months Ended September 30, 2004

Results

2005

2004

Change

Change %

(in millions)

Total Revenue

30.2

28.7

1.5

5.2

Supply costs

26.9

25.4

1.5

5.9

Gross Margin

3.3

—

% GM/Rev

10.9

11.5

Volumes MMbtu

2005

2004

Change

Change %

(in thousands)

Wholesale Gas

4,244

4,141

103

2.5

Revenue

Unregulated natural gas revenue increased $1.5 million, or 5.2%, due primarily to increases in average price and volumes, offset by a $5.5 million decrease in supply revenue from large volume customers. We are encouraging certain customers to contract directly with other providers for their supply needs as we receive little to no margin on supply costs.

Gross Margin

Gross margin remained flat for the third quarter 2005 as compared to the same period 2004.

Volumes

Unregulated wholesale natural gas volumes delivered totaled 4,244,035 MMbtu in the third quarter of 2005, as compared with 4,141,364 MMbtu during the same period in 2004. The increase in volumes in the third quarter of 2005 is due primarily to sales to ethanol facilities in South Dakota.

Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004

Results

2005

2004

Change

Change %

(in millions)

Total Revenue

113.3

96.7

16.6

17.2

Supply costs

104.8

87.8

17.0

19.4

Gross Margin

8.5

8.9

(0.4

)

(4.5

% GM/Rev

7.5

9.2

Volumes MMbtu

2005

2004

Change

Change %

(in thousands)

Wholesale Gas

15,557

14,645

912

6.2

Revenue

Unregulated natural gas revenue increased $16.6 million, or 17.2%, due primarily to a 19.6% increase in average price and an 6.2% increase in volumes.

Gross Margin

Gross margin decreased $0.4 million, or 4.5%, primarily due to losses recorded on out of market fixed price sales contracts during the first quarter 2005.

Volumes

Unregulated wholesale natural gas volumes delivered totaled 15,557,089 MMbtu in the first nine months of 2005, compared with 14,644,612 MMbtu during the same period in 2004. The increase in volumes in 2005 is due primarily to sales to ethanol facilities in South Dakota.

DISCONTINUED OPERATIONS

Discontinued Communications Segment Operations

· NorthWestern received an initial distribution of $20 million in cash on September 29, 2005 for its allowed claims.

· A reserve of an additional $5 million was set aside through the amended plan for an additional distribution to NorthWestern after distributions are made on other allowed unsecured claims.

· After distributions are made to allowed unsecured, administrative and priority claims, any remaining Netexit estate funds will be paid to NorthWestern.

Based on our current estimate of total allowed claims, NorthWestern anticipates receiving an additional distribution of approximately $22-24 million from Netexit; however, there are still remaining unresolved priority and unsecured claims. Netexit currently holds approximately $36.6 million in cash, which is included in current assets of discontinued operations on our consolidated financial statements.

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

	Successor Company				Predecessor Company
	Three Months Ended
	September 30, 2005				September 30, 2004
Revenues		$	—			$	—
Loss before income taxes		(355		)		(1,441		)
Income tax provision		—				—
Loss from discontinued operations, net of income taxes		$	(355	)		$	(1,441	)

	Successor Company				Predecessor Company
	Nine Months Ended
	September 30, 2005				September 30, 2004
Revenues		$	—			$	—
Loss before income taxes		$	(9,697	)		$	(966	)
Gain on disposal		—				11,500
Income tax provision		—				—
Gain (loss) from discontinued operations, net of income taxes		$	(9,697	)		$	10,534

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

Discontinued HVAC Segment Operations

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

	Successor Company				Predecessor Company
	Three Months Ended
	September 30, 2005				September 30, 2004
Revenues		$	1,728			$	4,275
Loss before income taxes		$	(108	)		$	(602	)
Loss on disposal		—				(2,374		)
Income tax provision		—				—
Loss from discontinued operations, net of income taxes		$	(108	)		$	(2,976	)

	Successor Company				Predecessor Company
	Nine Months Ended
	September 30, 2005				September 30, 2004
Revenues		$	3,177			$	26,940
Loss before income taxes		$	(546	)		$	(4,293	)
Gain on disposal		—				3,810
Income tax provision		—				—
Loss from discontinued operations, net of income taxes		$	(546	)		$	(483	)

Status of Other Noncore Asset Sales

We are attempting to sell our interest in Montana Megawatts I, LLC, or MMI, our indirect wholly-owned subsidiary that owns the Montana First Megawatts generation project, a partially constructed, 260 megawatt, natural gas-fired, combined-cycle electric generation facility located in Great Falls, Montana. On February 17, 2005, our subsidiary, NorthWestern Generation I, LLC, the sole member of MMI, entered into a non-binding letter of intent to sell all of the member interests of MMI to a non-affiliated third party. While the term of this letter of intent has expired, MMI continues to discuss possible transactions with the non-affiliated third party while continuing to market the assets for sale. Any sale will be subject to board approval.

We continue to work with an equipment broker and numerous interested equipment buyers to sell generation equipment held by MMI. Our goal is to complete a sale of this equipment on or before December 31, 2005. Any equipment sale will be subject to board approval. The remaining non-equipment assets, including land, are also available for sale. It is uncertain as to when or what, if any, value we may receive from these assets.

LIQUIDITY AND CAPITAL RESOURCES

We are focused on maintaining a strong liquidity position and strengthening our balance sheet, thereby improving our credit profile. During the nine months ended September 30, 2005, we used existing cash to repay $99.8 million of debt, including an early principal payment of $25 million on our senior secured term loan B. In addition to these repayments we also paid dividends on common stock of $24.6 million, and contributed $31.4 million to our pension plans.

Financing Transaction

On June 30, 2005, we entered into an amended and restated credit agreement that replaced our existing $225 million secured credit facility with an unsecured $200 million senior revolving line of credit with lower borrowing costs. The previous credit facility consisted of a $125 million five-year revolving tranche and a $100 million seven-year term tranche (senior secured term loan B.) In addition, because the amended and restated line of credit is unsecured, the $225 million of first mortgage bond collateral securing the previous facility was released by the lenders. The unsecured revolving line of credit will mature on November 1, 2009 and does not amortize. The facility bears interest at a variable rate based upon a grid which is tied to our credit rating from Fitch, Moody’s, and S&P. The ‘spread’ or ‘margin’ ranges from 5¤8% to 1.75% over the London Interbank Offered (LIBO) Rate. The facility currently bears interest at a rate of approximately 5.0%, which is 1.125% over the LIBO Rate.

The amended and restated line of credit continues to include covenants similar to the previous credit facility, which require us to meet certain financial tests, including a minimum interest coverage ratio and a minimum debt to capitalization ratio. The amended and restated line of credit also contains covenants which, among other things, limit our ability to incur additional indebtedness, create liens, engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, make restricted payments, make loans or advances, and enter into transactions with affiliates. Many of these restrictive covenants will fall away upon the line of credit being rated “investment grade” by two of the three major credit rating agencies consisting of Fitch, Moody’s and S&P. As of September 30, 2005, we are in compliance with all of the covenants under the amended and restated line of credit.

Credit Ratings

S&P, Moody’s and Fitch are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of November 1, 2005, our ratings with these agencies are as follows:

Senior Secured
Rating

Senior Unsecured
Rating

Corporate Rating

Outlook

S&P

BB+

B+

Negative

Moody’s

Ba1

Ba2

N/A

Positive

Fitch

BBB-

BB+

N/A

Positive

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

** The negative outlook assigned by S&P is due to the uncertainty surrounding Montana Public Power Inc.’s bid to purchase NorthWestern. S&P noted that should the offer be rejected or withdrawn they would likely affirm ratings and assign a positive outlook. However, if the bid is approved, then the ratings could be lowered or withdrawn. For further information please see our “Risk Factors” section.

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

Cash Flows

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 generally exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows from the electric business during the summer cooling season and utilization of our existing line of credit, is used to purchase natural gas to place in storage for heating season deliveries, perform necessary maintenance, and make capital improvements in plant.

Our liquidity is also impacted by the various monthly cost tracking mechanisms we use to recover electric and gas supply costs. The 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 payment of supply costs and revenue receipt from customers, cyclical over and under collection situations arise. We usually under collect in the fall and winter and over collect in the spring. Additionally, a regulatory procedural delay in implementing our 2004/2005 Montana annual electric and natural gas tracker filings, combined with the rapid increase in electric and natural gas costs, have increased the short-term tracking under collection. We project that our Montana gas and electric trackers will be under collected by approximately $22 million at December 31, 2005, which amount will be reflected as a regulatory asset. Our ability to utilize our company owned gas inventory currently in storage during the winter period will limit our natural gas under collection on a cash basis. Our ability to recover the current under collections by June 30, 2006 is based on volume and commodity price assumptions over the next nine months. If our assumptions are incorrect, then the under collection will not be fully recovered by June 30, 2006. Any under collected balance will be amortized and collected in rates over the following tracker year.

We believe that our cash on hand, operating cash flows, and borrowing capacity, taken as a whole, provide sufficient resources to fund our ongoing operating requirements, debt maturities, anticipated dividends and estimated future capital expenditures during the next twelve months. Additional debt repayments of approximately $40 million were made in July 2005. In August 2005, we utilized our line of credit to repay $60 million of term debt that matured. In September 2005 we received an initial distribution of $20 million in cash from our allowed claim in the Netexit bankruptcy, which was utilized to repay $20 million of our line of credit. As of November 1, 2005, our availability under the line of credit was approximately $101 million.

Based upon the terms of Netexit’s restated liquidating plan of reorganization and our current estimate of total allowed claims, NorthWestern anticipates receiving an additional distribution of approximately $22-24 million from Netexit; however, there are still remaining unresolved priority and unsecured claims. In addition, we anticipate receiving approximately $20 million from the sale of MMI’s generation equipment and site.

On November 8, 2005, our Board of Directors authorized a common stock repurchase program that allows us to repurchase up to $75 million of common stock. Purchases under the stock repurchase program may be made in the general open market, in privately negotiated transactions, and through purchases made in accordance with Rule 10(b)(5)(i) under the Securities Exchange Act of 1934. The purchases will be based on a number of factors, including price, volume and timing. On November 8, 2005, our Board of Directors also declared a quarterly common stock dividend of 31 cents per share, payable on December 31, 2005 to common shareholders of record as of December 15, 2005.

As of September 30, 2005, cash and cash equivalents were $20.3 million, compared with $17.1 million at December 31, 2004, and $41.2 million as of September 30, 2004. Cash provided by continuing operations totaled $146.4 million during the nine months ended September 30, 2005, compared to $155.0 million during the nine months ended September 30, 2004. Due to the seasonality of our business, our cash flows from operations and revenues are typically lower during the second and third quarters of each year.

Cash used in investing activities of continuing operations totaled $46.4 million during the nine months ended September 30, 2005 compared to $118.9 million in 2004. During 2005, we received approximately $123.5 million of proceeds from the sale of short-term investments net of approximately $118.8 million used for the purchase of short-term investments, we received approximately $4.9 million of proceeds from the sale of assets and we used approximately $53.6 million to make property, plant and equipment additions. During 2004, we used cash of approximately $140.9 million to purchase short-term investments net of approximately $71.0 million received from the sale of short-term investments. In addition, we used approximately $54.2 million during 2004 to make property, plant and equipment additions.

Cash used in financing activities of continuing operations totaled $117.9 million during the nine months ended September 30, 2005 compared to $10.0 million in 2004. In 2005 we made debt repayments of $99.8 million, and paid dividends on common stock of $24.6 million. We also received $11.3 million from deferred gas storage financing transactions with third parties. In addition during June 2005, as discussed above, we replaced a $225 million credit facility with a $200 million revolving line of credit. Cash used during 2004 was for scheduled principal payments on debt.

The decrease in restricted cash held by discontinued operations during the nine months ended September 30, 2005 was primarily due to Netexit’s $20 million distribution to us, along with payment of other allowed claims pursuant to its liquidating plan of reorganization. The increase in restricted cash held by discontinued operations during the nine months ended September 30, 2004 was primarily due to a settlement in which Netexit received $17.5 million.

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, 2005 for each of the periods presented. See our Annual Report on Form 10-K/A for the year ended December 31, 2004 for additional discussion.

	Total		2005		2006		2007		2008		2009		Thereafter
	(in thousands)
Long-term Debt	$	737,395	$	497	$	156,445	$	6,770	$	6,058	$	81,054	$	486,571
Future minimum operating lease payments(1)	297,358		16,553		34,163		33,566		32,591		32,358		148,127
Estimated Pension and Other Postretirement Obligations(2)	91,000		2,000		25,000		25,000		25,000		14,000		N/A
Qualifying Facilities(3)	1,631,609		27,322		56,398		58,420		60,574		62,598		1,366,297
Supply and Capacity Contracts(4)	1,819,582		180,396		535,815		289,490		192,879		178,319		442,683
Interest payments on debt	451,983		18,837		46,017		34,916		34,656		33,649		283,908
Total Commitments	$	5,028,927	$	245,605	$	853,838	$	448,162	$	351,758	$	401,978	$	2,727,586

(1) Our operating leases include a lease agreement for our share of the Colstrip Unit 4 generation facility requiring payments of $32.2 million annually through 2010 and decreasing to $14.5 million annually through 2018.

(2) We have only estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. In the third quarter of 2005, we contributed approximately $31.4 million to our pension plans.

(3) The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2032. Our estimated gross contractual obligation related to the QFs is approximately $1.6 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.3 billion. The obligation and payments reflected on this schedule represent the estimated gross contractual obligation as of September 30, 2005.

(4) We have entered into various purchase commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 30 years.

NEW ACCOUNTING STANDARDS

See Note 8 for a discussion of new accounting standards.

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.

Parties objecting to confirmation of our plan of reorganization may appeal the order confirming our plan of reorganization and may challenge the confirmation through litigation.

On October 22, 2004, Magten filed a motion with the Bankruptcy Court seeking a stay of the confirmation order pending resolution of their appeal of such order, which notice of appeal was filed on October 25, 2004. On October 25, 2004, the Bankruptcy Court denied Magten’s motion for a stay. Thereafter, Magten requested that the United States District Court for the District of Delaware impose a stay of the effectiveness of the confirmation order pending resolution of Magten’s appeal. On October 29, 2004, the Delaware District Court denied Magten’s motion for a stay. In March 2005 we moved to dismiss Magten’s appeal of the confirmation order on equitable mootness grounds. Magten’s appeals of the confirmation order and the order approving the memorandum of understanding have been consolidated before the District Court. A briefing on the appeals and motion to dismiss have been completed and we are awaiting a decision of the Delaware District Court. On May 12, 2005, Magten, the Plan Committee and NorthWestern unsuccessfully engaged in mediation to resolve the pending appeals and other pending litigation. On October 21, 2005, the Delaware District Court ordered the parties to mediate their disputes. Although we will vigorously prosecute the motion to dismiss the appeal and defend against the appeal, we cannot currently predict the impact or resolution of Magten’s appeal of the confirmation order.

On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern, Gary Drook, Michael Hanson, Brian Bird, Thomas Knapp and Roger Schrum alleging that the Company and former and current officers committed fraud by failing to include sufficient stock in the Class 9 reserve for payment of unsecured claims, and requesting, among other relief, that the confirmation order be revoked and set aside. We filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of the confirmation order appeal. On October 21,2005, the Delaware District Court ordered the parties to mediate their disputes. While we cannot predict the impact or resolution of Magten’s complaint, we intend to vigorously defend against it.

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

We have incurred and will continue to incur significant costs associated with outstanding litigation. These costs, which are being expensed as incurred, are expected to have an adverse affect on our results of operations and cash flows. Although our plan of reorganization has been successfully consummated and we have emerged from bankruptcy, we expect to continue to incur significant costs in connection with the steps necessary to close the bankruptcy case which include, among other things, resolution of remaining unsecured claims, administration of the claim reserve, coordination with the Plan Committee and the resolution of appeals and certain pending litigation.

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

Under our plan of reorganization, holders of certain claims received distributions of shares of our common stock. Harbert Distressed Investment Master Fund Ltd. (Harbert) is affiliated with or manages funds which, based on the most recent information made available to us, collectively received more than 20% of our new common stock. Harbert could acquire additional claims or shares, or divest claims or

shares in the future. Our prepetition senior unsecured noteholders, trade vendors with claims in excess of $20,000 and holders of our trust preferred securities and our quarterly income preferred securities received, collectively, approximately 9% of our new common stock. Other than Harbert, however, we are not aware of any entity that owns or controls 10% or more of our common stock distributed upon emergence pursuant to our plan of reorganization.

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

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

We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al., now pending in federal court in Montana. The lawsuit, which was filed by the former shareholders of The Montana Power Company (many of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of The Montana Power Company), claims that the disposition of various generating and energy-related assets by The Montana Power Company was void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern is named as a defendant due to the fact that we purchased the unit membership interest of The Montana Power, LLC, which the plaintiffs’ claim is a successor to The Montana Power Company. On July 10, 2004, we and the other insureds under the applicable directors and officers liability insurance policies along with the plaintiffs in the McGreevey case, plaintiffs in the In Re Touch America Holdings, Inc. Securities Litigation and the Touch America Creditors Committee reached a tentative settlement as a result of mediation. Among the terms of the tentative settlement, we, our wholly-owned subsidiary CFB, and other parties will be released from all claims in this case, the plaintiffs in McGreevey will dismiss their claims against the third party purchasers of the generation assets and non-regulated energy assets of Montana Power Company, including PPL Montana, and a settlement fund in the amount of $67 million (all of which will be contributed by the former Montana Power Company directors and officers liability insurance carriers) will be established. The settlement is subject to the occurrence of several conditions, including approval of the proposed settlement by the Bankruptcy Court in our bankruptcy proceeding, approval of the Touch America bankruptcy court, and approval of the proposed settlement by the Federal District Court for the District of Montana, where the class action is pending. Plaintiffs in the McGreevey class action have filed a motion for approval of the settlement. On April 29, 2005, the Federal District Court in Montana denied the plaintiffs’ motion for preliminary approval of the proposed settlement without prejudice and ordered the parties to work out their differences and present a global settlement agreement in 60 days; otherwise, the court would order the parties to resume trial preparations. The parties requested additional time to reach a final settlement agreement. The Federal District Court in Montana ordered the parties to respond by August 12, 2005 to certain questions concerning the issues raised in the case. In the event the parties do not reach a global settlement agreement, a settlement is not approved or it does not take effect for any other reason, we cannot predict the ultimate outcome of this litigation, but we intend to vigorously defend against this

lawsuit. The Bankruptcy Court entered an order permitting the plaintiffs in McGreevey to file a fraudulent conveyance action against us if we were not able to consummate the settlement; however, it is not certain that the plaintiffs could pursue such action post emergence. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition.

On August 9, 2005, McGreevey plaintiffs filed an action in Montana state court claiming that our transfer of certain assets to CFB was a fraudulent transfer. (The plaintiffs received approval in our bankruptcy case to initiate a similar fraudulent conveyance action as an adversary proceeding in our bankruptcy case which they did not do. Under the terms of the settlement with the plaintiffs in the McGreevey case discussed above, they would not file such proceeding.) We have removed the action to the federal court in Montana and filed a motion to transfer the action to the Bankruptcy Court in Delaware. We also filed an adversary action in our Bankruptcy Case seeking injunctive relief against the McGreevey plaintiffs to stop them from pursuing their fraudulent conveyance action outside our Bankruptcy Case. McGreevey plaintiffs answered the adversary complaint and asserted counterclaims against us alleging the same fraudulent conveyance claims. McGreevey plaintiffs also filed a motion to certify certain issues to the Montana Supreme Court. They also filed a motion to remand the fraudulent conveyance action to state court in Montana and the same motion to certify certain issues to the Montana Supreme Court. On October 19, 2005, the Bankruptcy Court heard arguments on our rule to show cause why the McGreevey plaintiffs should not be held in contempt of the Bankruptcy Court for violating the terms of the channeling injunction in the confirmation order. On October 25, 2005 the Bankruptcy Court preliminarily enjoined plaintiffs from further prosecuting their claim against us. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition.

We are a defendant in litigation related to our quarterly income preferred securities, which litigation is related to the transfer of certain assets to NorthWestern from our subsidiary, CFB. Certain current and former officers of CFB are defendants in a lawsuit related to the same transfer of assets. Our business could be harmed and there could be a material adverse impact on our financial condition if we do not successfully resolve the lawsuit.

Certain creditors and parties-in-interest have initiated legal action against us related to the transfer of the assets and liabilities comprising our Montana utility operations from CFB to NorthWestern, and seek the removal of such assets from our estate or the imposition of a constructive trust for the benefit of such creditors. This litigation currently is stayed pending termination of the appeal of the order confirming our plan of reorganization filed by Magten. On October 21, 2005, the Delaware District Court ordered the parties to mediate their disputes. This litigation could adversely affect our business, results of operations, and our financial condition.

We are the subject of a formal investigation by the SEC relating to the restatement of our 2002 quarterly financial statements and other accounting and financial reporting matters. If the investigation was to result in a regulatory proceeding or action against us, then our business and financial condition could be harmed.

In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern and affiliated companies NorthWestern Communications Solutions, Expanets and Blue Dot. This development followed the SEC’s requests for information made in connection with the previously disclosed SEC informal inquiry into questions regarding the restatements and other accounting and financial reporting matters. Since

December 2003, we have periodically received and continue to receive subpoenas from the SEC requesting documents and testimony from employees regarding these matters. The SEC investigation will continue, and while no claims have been filed, any claims alleging violations of federal securities laws made by the SEC may not be discharged pursuant to our plan of reorganization.

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

We are cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are contacted in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, then we may face sanctions, including, but not limited to, monetary penalties and injunctive relief and any monetary liability incurred by us may be material to our financial position or results of operations.

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

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

Our utility businesses are regulated by certain state commissions. As a result, these commissions review the regulated utility’s books and records, which could result in rate changes and have a material adverse effect on our results of operations and financial condition.

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

We are currently subject to limited regulation under the Public Utility Holding Company Act of 1935, as amended (PUHCA or the Act); however, we may become subject to additional PUHCA requirements if certain of our 10% shareholders or other shareholders are not deemed to be “exempt” holding companies under the Act. Complying with additional PUHCA requirements could make it more difficult for us to enter into financing arrangements, conduct nonutility lines of business or acquire other businesses or assets.

We are subject to limited regulation under PUHCA, because more than 20% of our voting stock (following the distribution under the approved bankruptcy plan) is currently held by Harbert or affiliates of Harbert. Harbert has applied for status as an “exempt” holding company, under Section 3(a)(4) of PUHCA, on the basis that it is only temporarily a holding company. In its application for exempt status, Harbert has represented that it will reduce its holdings below 10% within three years from its initial filing in November 2004 and it will not take an active role in our management. Pending action by the SEC on its application (and assuming that the application was filed in good faith and the relevant facts have not changed), Harbert is statutorily entitled to exempt status upon its filing. As a result of Harbert’s holdings and the Harbert application having been filed, we are a “subsidiary” of an “exempt holding company,” and are subject to Section 9 of PUHCA, but are not otherwise subject to the Act. NorthWestern itself is not a utility holding company, because all of our utility operations are conducted at the parent level.

Attorneys for Magten have recently sent a letter advising NorthWestern that Law Debentures has filed a Protest and Request for Hearing (Protest) regarding Harbert’s application. The Protest contends that Harbert is not properly within the terms of the exemption as a “temporary” company, because it set out to acquire the NorthWestern interests, and the acquisition was not incidental to debts otherwise owed, and that in any event, Harbert has controlled and influenced NorthWestern’s management and Board to such an extent that Harbert’s application should be denied and it should be subject to regulation as a holding company. In that letter, attorneys for Magten also allege that any sale of NorthWestern to a third party may be voidable, a breach of the fiduciary duty of the directors, and otherwise subject to challenge by Magten and allege what we believe are unsubstantiated violations of federal securities laws by us. We cannot predict what impact Magten’s actions will have on the SEC’s consideration of Harbert’s PUHCA application.

Under PUHCA, the SEC does not regulate rates and charges for the sale or distribution of gas or electricity, but it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. If Harbert were denied an exemption, or if other entities became holders of more than 10% of our voting stock either individually or as a group acting together, and were not otherwise exempt from the Act, then we would be subject to additional requirements under PUHCA, including requirements for SEC approval before issuing securities, entering into financing arrangements, entering or continuing lines of business not necessary or appropriate to our utility businesses, or acquiring other utility assets or businesses. Under the Act, transactions which should have been subject to SEC approval, but for which SEC approval was not obtained are voidable under certain circumstances, even where a third party has entered into the transaction. Under Section 3 of the Act, an exemption is statutorily in effect so long as an application for the exemption was filed in good faith, and has not been denied by the SEC. Transactions occurring during the pendency of an application would be voidable only if the SEC denied the application, and there were a final determination that the application had not been filed in good faith, such that the statutory grant of the exemption during the pendency was not applicable.

On August 8, 2005, the Domenici-Barton Energy Policy Act of 2005 (the Act) went into effect, which among other things, effective February 8,2005 repeals PUHCA (which is administered by the SEC) and enacts the Public Utility Holding Company Act of 2005, which will be administered by the FERC under

new rules currently being developed. We cannot predict at the present time how these new rules will affect us.

Our obligation to supply a minimum annual quantity of qualifying facility (QF) power to the Montana default supply could expose us to material commodity price risk if we are required to supply any quantity deficiency during a time of high commodity prices.

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

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the default supply with a certain minimum amount of QF power at an agreed upon price per megawatt. The annual minimum energy requirement is achievable under normal operations, including normal periods of planned and forced outages. Furthermore, we will not realize commodity price risk, unless any required replacement energy cost is in excess of the total amount recovered under the QF contracts, which is currently approximately $65.00 per MWH for base-load energy.

However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to secure the quantity deficiency from other sources. Since we own no material generation in Montana, the anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility. A recent stipulation with the MCC addresses how any energy shortfall will be managed and further restricts some of our ability to protect against such events. This stipulation is currently pending before the MPSC.

The value of our Colstrip Unit 4 leasehold improvements could be significantly impacted by changes in commodity prices due to our inability to fully hedge our output after July 1, 2007.

Our Colstrip Unit 4 division offered to provide 90 megawatts of baseload energy into default supply for a term of 11.5 years, commencing on July 1, 2007 at an average price of $35.80 per megawatt hour. This offered price is materially below market based upon current projected wholesale power prices. Given that we lack the ability to fully financially hedge the remaining uncommitted Colstrip 4 output, a significant decline in the current projection of wholesale power prices could impair our investment in the Colstrip 4 leasehold improvements.

Our electric and natural gas distribution systems are subject to municipal condemnation.

The government of each of the municipalities in which we provide electric or natural gas service has the right to condemn our facilities in that community and to establish a municipal utility distribution system to serve customers by use of such facilities, subject to the approval of the voters of the community and the payment to NorthWestern of fair market value for our facilities, including compensation for the cancellation of our service rights. If we lose a material portion of our distribution systems to municipal condemnation, then our results of operations and financial condition could be harmed because we may not be able to replace or repurchase income generating assets in a timely manner, if at all.

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

Our electric and natural gas utility business is seasonal and weather patterns can have a material impact on their financial performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, 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.

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

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 could under-recover our costs, which would adversely impact our results of operations.

We do not own any natural gas reserves or regulated electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and substantially all of our Montana electricity supply pursuant to contracts with third-party suppliers. In light of this reliance on third-party suppliers, we are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, we might be required to purchase gas and/or electricity supply 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 utility business is subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and liabilities.

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

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

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past

operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be predicted. Our range of exposure for environmental remediation obligations is estimated to be $45.0 million to $84.1 million. We had an environmental reserve of $45.0 million at September 30, 2005. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or government claims for damages allegedly associated with specific environmental conditions. These environmental liabilities will continue and any claims with respect to environmental liabilities will not be extinguished pursuant to our plan of reorganization. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.

The loss of our investment grade credit ratings has impacted our borrowing costs and liquidity, and we expect that our non-investment grade status will continue to affect our cash flows.

Upon emergence from bankruptcy, we were assigned a non-investment grade credit rating. Our current non-investment grade ratings have impacted our borrowing costs. In addition, with a limited number of suppliers, we continue to either prepay or post collateral in the form of cash and letters of credit to support our operations. We also began payment of quarterly dividends on our common stock in the first quarter of 2005, which may delay our ability to achieve an investment grade rating for our debt securities. While we are working to resolve many of the concerns cited by the credit rating agencies, we cannot assure you that our credit ratings will improve in the foreseeable future.

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

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

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

We have in the past received and may receive in the future unsolicited indications of interest, proposals or offers to acquire us or some or all of our assets. We are not soliciting offers from prospective buyers. As we have stated on prior occasions, as a public company we may receive such indications of interest, proposals or offers, and if we do, our Board of Directors will evaluate them and respond as appropriate. There can be no assurance that we will pursue any such indication of interest, proposal or offer, and we reserve the right not to pursue any acquisition of us or any of our assets as determined by our Board of Directors. As a consequence of any decision not to pursue an acquisition of us, our stockholders would not be able to sell or exchange their shares of common stock at any premium offered by the prospective buyer in the proposed transaction. As a matter of policy, we will not comment on or provide market updates as to the status of any indications of interest, proposals or offers we may receive from time

to time, or the course of discussions with any prospective buyers, nor will we comment upon any rumors with regard to any possible sale.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Interest Rate Risk

We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We primarily use fixed rate debt and limited variable rate long-term debt to partially finance mandatory debt retirements. These variable rate debt agreements expose us to market risk related to changes in interest rates. We manage this risk by taking advantage of market conditions when timing the placement of long-term or permanent financing. All of our debt has fixed interest rates, with the exception of our new credit facility entered into on June 30, 2005, which bears interest at a variable rate (currently approximately 5.0%) tied to the London Interbank Offered (LIBO) Rate. Based upon amounts outstanding as of September 30, 2005, a 1% increase in the LIBO rate would increase annual interest expense on this line of credit by approximately $0.8 million.

During the second quarter of 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposure associated with anticipated refinancing transactions. While we are exposed to changes in the fair value of these instruments, they are designed such that any economic loss in value is generally offset by interest rate savings at the time the future anticipated financing is completed. Changes in the fair value of these instruments are recorded into equity and then reclassified into earnings in the same period during which the item being hedged affects earnings. At September 30, 2005, the market value of these instruments, representing the amount we would receive upon their termination, was approximately $7.1 million.

Commodity Price Risk

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

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

In our unregulated electric segment, due to our lease of the Colstrip Unit 4 generation facility, we are exposed to the market price fluctuations of electricity. We have entered into forward contracts for the sale of a significant portion of Colstrip 4’s generation through March 2006. To the extent Colstrip 4 experiences any unplanned outages, we would need to secure the quantity deficiency from the wholesale market to fulfill our forward sales contracts. As of September 30, 2005, market prices exceeded our contracted

forward sales prices by approximately $22.8 million. To mitigate price risk, during the second quarter of 2005 we implemented a risk management strategy of utilizing put options in conjunction with our forward fixed price sales of expected generation output. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Income (Loss) until delivery or settlement occurs. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement.

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

Counterparty Credit Risk

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). As discussed below, we have made various improvements in our internal controls which we believe have remediated the material weakness in our internal control over financial reporting that was previously reported in our Annual Report on Form 10-K/A. Based on this evaluation, and based on these improved internal controls, 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 were effective to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of the 1934 are recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

Changes in Internal Control Over Financial Reporting

We previously reported in our Annual Report on Form 10-K/A actions that continue in 2005 to improve policies, procedures and control activities over regulated and unregulated energy procurement to address the material weakness described in our Annual Report on Form 10-K/A.

During 2005, we believe we have eliminated the material weakness by improving control activities to meet the following objectives:

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

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

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

These control activities and specific actions include:

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

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

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

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

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

· Not allowing speculative trading; and

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

We believe the changes in our internal controls described above have remediated the material weakness. We have tested these control activities and found them to be operating effectively. We will continue to monitor the sustainability of new controls on an ongoing basis and seek to identify improvements to existing controls. Except for these improvements described above, there have been no other changes in our internal control over financial reporting during the nine months ended September 30, 2005 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

On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern Corporation, Gary Drook, Michael Hanson, Brian Bird, Thomas Knapp and Roger Schrum alleging that NorthWestern and the former and current officers committed fraud by failing to include a sufficient amount of shares in the Class 9 reserve set aside for payment of unsecured claims and thus the confirmation order should be revoked and set aside. We filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of the confirmation order appeal. The October 21, 2005 order regarding mediation also applies to this action. While we cannot predict the impact or resolution of Magten’s complaint, we intend to vigorously defend against it.

On April 19, 2004, Magten also filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for breaches of fiduciary duties by such officers. Those officers have requested CFB to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. That lawsuit has now been transferred to the Federal District Court in Delaware where many of the other Magten related litigation matters are pending. On October 21, 2005, the Delaware District Court ordered the parties to mediate their disputes.

On February 9, 2005, we agreed to settlement terms with Magten and Law Debenture to release all claims, including Magten’s and Law Debenture’s fraudulent conveyance action pending against each other for Magten and Law Debenture receiving the distribution of new common stock and warrants from Class 8(b) in the same amounts as if they had voted to accept the Plan and a distribution from Class 9 of new common stock in the amount of approximately $17.4 million. Prior to seeking approval from the Bankruptcy Court, certain major shareholders and the Plan Committee objected to the settlement on both its economic terms and asserting that the structure of the settlement violated the Plan. After reviewing the objections and undertaking our own analysis of the potential Plan violation, we informed Magten and Law Debenture as well as the Plan Committee and the objecting major shareholders that we would not proceed with the settlement. Magten and Law Debenture filed a motion with our Bankruptcy Court seeking approval of the settlement. On March 10, 2005, the Bankruptcy Court entered an order denying the motion filed by Magten and Law Debenture. Magten and Law Debenture have appealed that order. This appeal has been docketed with the District Court and a briefing schedule issued. On October 21, 2005, the Delaware District Court ordered the parties to mediate their disputes. At this time, we cannot predict the impact or resolution of any of these lawsuits, the appeal or reasonably estimate a range of possible loss, which could be material. We intend to vigorously defend against the adversary proceeding, appeal and any subsequently filed similar litigation. The plaintiffs’ claims with respect to the QUIPs Litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the share reserve that we established with respect to the Class 9 disputed claims reserve under the plan of reorganization.

and a settlement fund in the amount of $67 million (all of which will be contributed by the former Montana Power Company directors and officers liability insurance carriers) will be established. The settlement is subject to the occurrence of several conditions, including approval of the proposed settlement by the Bankruptcy Court in our bankruptcy proceeding, and approval of the proposed settlement by the Federal District Court for the District of Montana, where the class actions are pending. On April 29, 2005, the Federal District Court in Montana denied the plaintiffs’ motion for preliminary approval of the proposed settlement without prejudice and ordered the parties to work out their differences and present a global settlement agreement in 60 days; otherwise, the court would order the parties to resume trial preparations. Even though the parties requested additional time to continue to negotiate to reach a consensus on a global settlement agreement, the Federal District Court requested that the parties respond to certain issues by August 12, 2005. In the event the parties do not reach a global settlement agreement, a settlement is not approved or it does not take effect for any other reason, we intend to vigorously defend against this lawsuit. If we are unsuccessful in defending against this class action lawsuit, the plaintiffs’ litigation claims are channeled to the Directors & Officers Trust established under our Plan, or alternatively, would be subordinated to our other debt under our Plan, and such claims would be treated as securities, or Class 14, claims under our plan of reorganization, and would be entitled to no recovery against NorthWestern under our Plan. Claims by our current and former officers and directors (and the former officers and directors of The Montana Power Company) for indemnification for these proceedings would be channeled into the Directors and Officers Trust established by the Plan. The plaintiffs could elect to proceed directly against CFB and the assets owned by such entity, which are not material to our operations or financial position. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition.

On August 9, 2005, McGreevey plaintiffs filed an action in Montana state court claiming that our transfer of certain assets to CFB was a fraudulent transfer. (The plaintiffs received approval in our bankruptcy case to initiate a similar fraudulent conveyance action as an adversary proceeding in our bankruptcy case which they did not do. Under the terms of the settlement with the plaintiffs in the McGreevey case discussed above, they would not file such proceeding.) We have removed the action to the federal court in Montana and filed a motion to transfer the action to the Bankruptcy Court in Delaware. We also filed an adversary action in our Bankruptcy Case seeking injunctive relief against the McGreevey plaintiffs to stop them from pursuing their fraudulent conveyance action outside our bankruptcy case. McGreevey plaintiffs answered the adversary complaint and asserted counterclaims against us alleging the same fraudulent conveyance claims. McGreevey plaintiffs also filed a motion to certify certain issues to the Montana Supreme Court. They also filed a motion to remand the fraudulent conveyance action to state court in Montana and the same motion to certify certain issues to the Montana Supreme Court. On October 19, 2005, the bankruptcy court heard arguments on our motion to show cause why the McGreevey plaintiffs should not be held in contempt of the Bankruptcy Court for violating the terms of the channeling injunction in the confirmation order. On October 25, 2005 the Bankruptcy Court preliminarily enjoined the plaintiffs from further prosecuting their claim against us.

counterclaim. Our Bankruptcy Court transferred all the claims for resolution to the federal court in Montana. On May 5, 2005, the parties announced a settlement in principle of all claims and counterclaims, which settlement was approved by our Bankruptcy Court on September 29, 2005 and the lawsuit was dismissed with prejudice by the federal court on October 6, 2005. Under the terms of the settlement, NorthWestern retains the Colstrip transmission assets and PPL paid NorthWestern $9.0 million on October 6, 2005. In conjunction with this settlement, we will recognize a $9.0 million pretax gain in the fourth quarter of 2005. The agreement also covers the cancellation of indemnity obligations stemming from the APA (which obligations we agreed to assume when we purchased MPC’s electric and natural gas transmission and distribution business), and PPL’s withdrawal of its claims pending in NorthWestern’s bankruptcy proceeding, the dismissal and release of claims arising out of the litigation, and the release of the shares from the segregated reserve to the general reserve in NorthWestern’s bankruptcy proceeding.

requesting documents and testimony from employees regarding these matters. The SEC investigation will continue and any claims alleging violations of federal securities laws made by the SEC may not be extinguished pursuant to our plan of reorganization. In addition, certain of our directors and several employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the Federal Bureau of Investigation (FBI) concerning certain of the allegations made in the class action securities and derivative litigation matters. We have not been advised that NorthWestern is the subject of any FBI investigation. We understand that the FBI and the Internal Revenue Service (IRS) have contacted former employees of ours and our subsidiaries. As of the date hereof, we are not aware of any other governmental inquiry or investigation related to these matters. We are fully cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are contacted in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, for which we can provide no assurance, we may face sanctions, including, but not limited to, monetary penalties and injunctive relief, and any monetary liability incurred by us may be material to our financial position or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On July 14, 2005, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

1. All of the Directors were elected to serve a one-year term as Directors until the 2006 Annual Meeting.

	VOTES FOR:		VOTES WITHHELD:
Stephen P. Adik		16,086,453		12,517,756
E. Linn Draper		16,082,451		12,520,758
Jon S. Fossel		16,086,541		12,517,668
Michael J. Hanson		24,899,895		3,704,314
Julia L. Johnson		16,086,313		12,517,896
Philip L. Maslowe		16,086,200		12,518,009

2. The ratification of Deloitte & Touche, LLP as our independent auditors was approved. With respect to holders of common stock, the number of affirmative votes cast was 28,385,870, the number of votes cast against was 47,742, and the number of abstentions was 170,597.

ITEM 6. EXHIBITS

(a) Exhibits

Exhibit 10.1—Separation and Consulting Agreement between Roger Schrum and NorthWestern Corporation dated September 1, 2005.

Exhibit 31.1—Certification of chief executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 31.2—Certification of chief financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.1—Certification of chief executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2—Certification of chief financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Delaware		46-0172280
(State of Incorporation)		IRS Employer Identification No.

			Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		5
Item 1.	Financial Statements (Unaudited)	5
	Consolidated Balance Sheets—September 30, 2005 and December 31, 2004	5
	Consolidated Statements of Income (Loss)—Three and Nine Months Ended September 30, 2005 and 2004	6
	Consolidated Statements of Cash Flows—Nine Months Ended September 30, 2005 and 2004	7
	Notes to Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	58
Item 4.	Controls and Procedures	59
PART II. OTHER INFORMATION		61
Item 1.	Legal Proceedings	61
Item 4.	Submission of Matters to a Vote of Security Holders	67
Item 6.	Exhibits	67
SIGNATURES		68

	NORTHWESTERN CORPORATION
Date: November 9, 2005	By:	/s/ BRIAN B. BIRD
		Brian B. Bird
		Vice President and Chief Financial Officer Duly Authorized Officer and Principal Financial Officer

Exhibit Number		Description
*10.1		Separation and Consulting Agreement between Roger Schrum and NorthWestern Corporation dated September 1, 2005.
*31.1		Certification of principal executive officer pursuant to 17 CFR 240. 13a-14, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2		Certification of chief financial officer pursuant to 17 CFR 240. 13a-14, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1		Certification of principal executive officer pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		Certification of chief financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Schrum		NORTHWESTERN ENERGY


		By:
Address:		Its:	Vice President and General Counsel


Date:	, 2005	Date:		, 2005

Date: November 9, 2005
/s/ MICHAEL J. HANSON
Michael J. Hanson
President & Chief Executive Officer