SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2006

Or

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

For the transition period from to

Commission File Number: 0-692

NORTHWESTERN CORPORATION

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

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

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

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

Large Accelerated Filer x

Accelerated Filer o

Non-accelerated Filer o

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

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

Common Stock, Par Value $.01

35,493,269 shares outstanding at May 1, 2006

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION			6
Item 1.	Financial Statements (Unaudited)		6
	Consolidated Balance Sheets — March 31, 2006 and December 31, 2005		6
	Consolidated Statements of Income — Three Months Ended March 31, 2006 and 2005		7
	Consolidated Statements of Cash Flows —Three Months Ended March 31, 2006 and 2005		8
	Notes to Consolidated Financial Statements		9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		33
Item 4.	Controls and Procedures		34
PART II. OTHER INFORMATION			35
Item 1.	Legal Proceedings		35
Item 1A.	Risk Factors		35
Item 2.	Issuer Purchases of Equity Securities		39
Item 6.	Exhibits		39
SIGNATURES			40

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

•

the effect of the definitive agreement to sell NorthWestern to Babcock & Brown Infrastructure Limited (BBI), including the consummation of the sale or the termination of the definitive agreement;

•

our ability to avoid or mitigate adverse rulings or judgments against us in our pending litigation arising from our bankruptcy proceeding, the formal investigation being conducted by the Securities and Exchange Commission (SEC), the City of Livonia class action and derivative action, and the Harbinger action contesting our shareholder rights plan;

•

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

•

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

•

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

•

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

In addition, we may not be able to complete the proposed transaction with BBI on acceptable terms, or at all, due to a number of factors, including the failure to obtain approval of our shareholders, regulatory approvals or to satisfy other customary closing conditions. Our Annual Report on Form 10-K, recent and forthcoming Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K and other SEC filings discuss some of the important risk factors that may affect our business, results of operations and financial condition. We undertake no obligation to revise or publicly update any forward-looking statements for any reason.

In connection with the proposed transaction with BBI, we will file a proxy statement with the SEC. Before making any voting or investment decision, investors and security holders are urged to carefully read the entire proxy statement, when it becomes available, and any other relevant documents filed with the SEC, as well as any amendments or supplements to those documents, as they will contain important information about the proposed transaction.

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

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

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

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

PART 1. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

		March 31, 2006			December 31, 2005
ASSETS
Current Assets:
Cash and cash equivalents	$	11,961		$	2,691
Restricted cash		26,283			25,238
Accounts receivable, net of the allowance		134,926			160,856
Inventories		31,713			40,925
Regulatory assets		26,044			38,640
Prepaid energy supply		2,235			1,754
Prepaid and other		8,544			4,397
Assets held for sale		—			20,000
Deferred income taxes		15,707			10,520
Current assets of discontinued operations		2,721			8,472
Total current assets		260,134			313,493
Property, Plant, and Equipment, Net		1,414,154			1,409,205
Goodwill		435,076			435,076
Other:
Investments		1,347			1,297
Regulatory assets		199,908			204,466
Other		48,824			36,866
Total assets	$	2,359,443		$	2,400,403
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	156,934		$	156,455
Accounts payable		59,345			99,419
Accrued expenses		178,777			157,587
Regulatory liabilities		5,761			10,003
Current liabilities of discontinued operations		373			1,195
Total current liabilities		401,190			424,659
Long-term Debt		536,964			586,515
Deferred Income Taxes		121,115			100,192
Noncurrent Regulatory Liabilities		174,476			170,744
Other Noncurrent Liabilities		374,773			380,798
Total liabilities		1,608,518			1,662,908
Commitments and Contingencies (Note 11)
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 35,806,688 and 35,578,847, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		358			358
Treasury stock at cost		(6,676	)		(5,573	)
Paid-in capital		721,590			721,240
Unearned restricted stock		(288	)		(383	)
Retained earnings		26,885			16,889
Accumulated other comprehensive income		9,056			4,964
Total shareholders’ equity		750,925			737,495
Total liabilities and shareholders’ equity	$	2,359,443		$	2,400,403

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

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended March 31,
		2006				2005
OPERATING REVENUES	$		361,482		$	332,117
COST OF SALES			219,672			187,405
GROSS MARGIN			141,810			144,712
OPERATING EXPENSES
Operating, general and administrative			61,327			56,655
Property and other taxes			19,465			18,205
Depreciation			18,829			18,690
Reorganization items			—			3,363
TOTAL OPERATING EXPENSES			99,621			96,913
OPERATING INCOME			42,189			47,799
Interest Expense			(14,436	)		(16,342	)
Investment and Other Income			5,270			607
Income From Continuing Operations Before Income Taxes			33,023			32,064
Income Tax Expense			(12,048	)		(13,670	)
Income From Continuing Operations			20,975			18,394
Discontinued Operations, Net of Taxes			50			524
Net Income	$		21,025		$	18,918
Average Common Shares Outstanding			35,584			35,611
Basic Earnings per Average Common Share
Continuing operations	$		0.59		$	0.52
Discontinued operations			—			0.01
Basic	$		0.59		$	0.53
Diluted Earnings per Average Common Share
Continuing operations	$		0.58		$	0.52
Discontinued operations			—			0.01
Diluted	$		0.58		$	0.53
Dividends Declared per Average Common Share	$		0.31		$	0.22

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

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Three Months Ended March 31,
		2006			2005
OPERATING ACTIVITIES:
Net Income	$	21,025		$	18,918
Items not affecting cash:
Depreciation and amortization		18,829			18,690
Amortization of debt issue costs		659			458
Amortization of restricted stock		255			375
Gain on qualifying facility contract amendment		—			(4,888	)
Income on discontinued operations, net of taxes		(50	)		(524	)
Gain on sale of assets		(584	)		—
Gain on hedging activities		(5,091	)		—
Deferred income taxes		13,174			13,387
Changes in current assets and liabilities:
Accounts receivable		25,930			17,972
Inventories		9,212			14,477
Prepaid energy supply costs		(481	)		13,291
Other current assets		(3,797	)		(1,080	)
Accounts payable		(39,949	)		(22,262	)
Accrued expenses		25,408			36,385
Changes in regulatory assets		17,154			6,279
Changes in regulatory liabilities		(3,412	)		3,536
Other noncurrent assets		(2,211	)		(2,230	)
Other noncurrent liabilities		1,556			(8,265	)
Cash provided by continuing operating activities		77,627			104,519
INVESTING ACTIVITIES:
Restricted cash		(1,045	)		(1,439	)
Property, plant, and equipment additions		(21,174	)		(13,400	)
Proceeds from sale of assets		20,273			5
Proceeds from hedging activities		1,419			—
Purchases of investments		—			(69,900	)
Proceeds from sale of investments		—			25,000
Cash used in continuing investing activities		(527	)		(59,734	)
FINANCING ACTIVITIES:
Deferred gas storage		(11,718	)		(9,116	)
Proceeds from exercise of warrants		190			—
Dividends on common stock		(11,029	)		(7,834	)
Repayment of long-term debt		(3,149	)		(12,039	)
Line of credit borrowings (repayments), net		(46,000	)		—
Treasury stock activity		(1,103	)		(81	)
Financing costs		—			(211	)
Equity registration fees		—			(140	)
Cash used in continuing financing activities		(72,809	)		(29,421	)
DISCONTINUED OPERATIONS:
Operating cash flows of discontinued operations, net		(3,572	)		434
Investing cash flows of discontinued operations, net		2,872			—
Financing cash flows of discontinued operations, net		—			—
(Increase) decrease in restricted cash held by discontinued operations		5,679			(442	)
Increase in Cash and Cash Equivalents		9,270			15,356
Cash and Cash Equivalents, beginning of period		2,691			17,058
Cash and Cash Equivalents, end of period	$	11,961		$	32,414
Supplemental Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	34		$	(14	)
Interest		4,327			6,887
Reorganization professional fees and expenses		—			1,668

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Reference is made to Notes to Financial Statements

included in NorthWestern Corporation’s Annual Report)

(Unaudited)

(1) Nature of Operations and Basis of Consolidation

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

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

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 expect Netexit to complete its liquidation during the second quarter of 2006.

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. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility, and while we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We will continue to make appropriate efforts to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. We continue to account for this qualifying facility contract as an executory contract. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $562.6 million through 2025. In addition, we have a 20-year 50 MW tolling contract with a third party. This tolling contract may constitute a VIE, however we have determined the contract is not material for consolidation and have included the estimated annual capacity and energy obligations of approximately $4.4 million in the Contractual Obligations included in Management’s Discussion and Analysis.

(2) Asset Retirement Obligations

We have identified asset retirement obligations, or ARO, liabilities related to our electric and natural gas

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

Our regulated utility operations have, however, previously recognized removal costs of transmission and distribution assets as a component of depreciation in accordance with regulatory treatment. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities pursuant to Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulations. These amounts do not represent SFAS No. 143 legal retirement obligations. As of March 31, 2006 and December 31, 2005, we have recognized accrued removal costs of $145.4 million and $142.6 million, respectively. In addition, for our generation properties, we have accrued decommissioning costs since the generating units were first put into service in the amount of $13.0 million and $12.8 million as of March 31, 2006 and December 31, 2005, respectively.

In connection with the adoption of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), we have recorded a conditional asset retirement obligation of $3.3 million and $3.2 million, as of March 31, 2006 and December 31, 2005, respectively, which increases our property, plant and equipment and other noncurrent liabilities. This is primarily related to Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments. The recording of the obligation has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the ARO is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. The change in our conditional ARO during the three months ended March 31, 2006, is as follows (in thousands):

Liability at January 1, 2006	$	3,233
Accretion expense		63
Liabilities incurred		—
Liabilities settled		—
Revisions to cash flows		42
Liability at March 31, 2006	$	3,338

(3) Goodwill

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

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

(4) Discontinued Operations

NorthWestern received an additional $5.0 million distribution from Netexit in February 2006. Netexit expects to complete its liquidation during the second quarter of 2006 with final distributions to NorthWestern of approximately

$2.3 million.

As of March 31, 2006 and December 31, 2005, Netexit had current assets of $2.7 million and $8.5 million and current liabilities (excluding intercompany amounts) of $0.4 million and $1.2 million, respectively.

(5) Other Comprehensive Income

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

Comprehensive income is calculated as follows (in thousands):

	Three Months Ended March 31,
	2006			2005
Net income	$	21,025		$	18,918
Other comprehensive income, net of tax:
Unrealized gain on derivative instruments qualifying as hedges, net of tax of $2,563 for the three months ended March 31, 2006		4,094			—
Foreign currency translation		(2	)		15
Comprehensive income	$	25,117		$	18,933

(6) Risk Management and Hedging Activities

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

Interest Rates

During the second quarter of 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions of approximately $380 million. These swaps 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 (AOCI) into interest expense in our Consolidated Statements of Income during the periods in which the interest payments being hedged occur. We had net unrealized pre-tax gains of $15.5 million and $8.8 million at March 31, 2006 and December 31, 2005, respectively, recorded in other noncurrent assets and accumulated other comprehensive income 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. During the first quarter of 2006, based on a review of our capital structure and cash flow, and approval by our Board of Directors, we decided not to refinance $60 million included in the interest rate swap that was being carried on our revolver. As the refinancing transaction and associated interest payments will not occur, the market value included in AOCI of $3.8 million was recognized in Investment and Other Income.

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 lease of a 30% share of the Colstrip Unit 4 generation facility. These transactions were designated as cash-flow hedges of

forecasted electric sales of approximately 120,000 MWh in each of the third and fourth quarters of 2006 under the provisions of SFAS No. 133, with unrealized gains and losses being recorded in AOCI in our Consolidated Balance Sheets. Due to changes in forward prices for electricity during the fourth quarter of 2005, we pursued a strategy of utilizing unit-contingent forward sales to lock in the remaining output during the third and fourth quarters of 2006, as a result we undesignated the puts as a hedge of the cash flow variability related to forecasted electric sales in third and fourth quarters of 2006. During the first quarter of 2006 the open put options were sold and we recognized a $1.2 million reduction to cost of sales, reflecting the change in market value since the loss of hedge effectiveness. The amount remaining in AOCI at March 31, 2006, a net unrealized loss of $1.0 million related to the change in market value prior to the loss of hedge effectiveness, will be reclassified into earnings during the third and fourth quarters of 2006.

During the fourth quarter of 2005, the Montana Consumer Counsel (MCC) submitted testimony alleging we were imprudent in our supply procurement and recommended the MPSC consider disallowing portions of our forecast electric and natural gas supply costs contained in the 2005 tracker filings. In March 2006, upon signing a stipulation with the MCC we recognized a loss of approximately $4.1 million ($1.4 million related to settled transactions and $2.7 million related to forward sales), reported as an increase to cost of sales. The stipulation, which has not yet been approved by the MPSC, settles various issues relative to our electric supply costs raised by the MCC. In April 2006, in a commission work session, the MPSC directed their staff to draft an order approving our 2005 Montana natural gas tracker as filed.

(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. We evaluate the performance of these segments based on gross margin. Items below operating income are not allocated between our electric and natural gas segments. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments, excluding discontinued operations, are as follows (in thousands):

Three months ended		Regulated				Unregulated
March 31, 2006		Electric		Gas		Electric		Gas		Other		Eliminations				Total
Operating revenues	$	168,101	$	158,414	$	24,803	$	34,715	$	88		$	(24,639	)	$	361,482
Cost of sales		89,148		119,178		3,371		32,001		53			(24,079	)		219,672
Gross margin		78,953		39,236		21,432		2,714		35			(560	)		141,810
Operating, general and administrative		32,662		16,729		9,923		911		1,662			(560	)		61,327
Property and other taxes		13,487		5,028		922		24		4			—			19,465
Depreciation		14,523		3,672		322		101		211			—			18,829
Total Operating Expenses		60,672		25,429		11,167		1,036		1,877			(560	)		99,621
Operating income (loss)		18,281		13,807		10,265		1,678		(1,842	)		—			42,189
Total assets	$	1,496,443	$	704,310	$	55,922	$	51,033	$	49,014		$	—		$	2,356,722
Capital expenditures	$	17,670	$	2,582	$	922	$	—	$	—		$	—		$	21,174

Three months ended		Regulated				Unregulated
March 31, 2005		Electric		Gas		Electric		Gas		Other		Eliminations				Total
Operating revenues	$	154,362	$	138,604	$	21,454	$	50,343	$	226		$	(32,872	)	$	332,117
Cost of sales		70,066		98,414		3,388		47,767		183			(32,413	)		187,405
Gross margin		84,296		40,190		18,066		2,576		43			(459	)		144,712
Operating, general and administrative		30,072		15,106		9,476		839		1,621			(459	)		56,655
Property and other taxes		12,563		4,798		810		30		4			—			18,205
Depreciation		14,328		3,705		261		101		295			—			18,690
Reorganization items		—		—		—		—		3,363			—			3,363
Total Operating Expenses		56,963		23,609		10,547		970		5,283			(459	)		96,913
Operating income (loss)		27,333		16,581		7,519		1,606		(5,240	)		—			47,799
Total assets	$	1,506,537	$	709,061	$	37,838	$	64,466	$	45,182		$	—		$	2,363,084
Capital expenditures	$	11,053	$	1,833	$	514	$	—	$	—		$	—		$	13,400

(8) Reclassifications to Consolidated Statement of Cash Flows

The accompanying Consolidated Statement of Cash Flows for the three months ended March 31, 2005 includes reclassifications to reflect deferred gas storage arrangements as financing activities and reflect changes in restricted cash as investing activities. The changes related to deferred gas storage arrangements of $9.1 million resulted in an increase to operating cash flows and a corresponding decrease to financing cash flows from amounts previously reported. The changes in restricted cash of $1.4 million resulted in a decrease to investing cash flows and a corresponding increase to operating cash flows from the amounts previously reported. Such reclassifications have no impact on net income or shareholders’ equity as previously reported.

(9) Earnings Per Share

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

	March 31, 2006	March 31, 2005
Basic computation	35,584,267	35,611,026
Dilutive effect of
Restricted shares	35,164	114,157
Stock warrants	881,165	—
Diluted computation	36,500,596	35,725,183

There were 4,608,712 warrants outstanding as of March 31, 2006, which are dilutive and have been included in the earnings per share calculations. As of March 31, 2006 each warrant had an exercise price of $27.17 and could be exchanged for 1.05 shares of common stock. As of March 31, 2005, there were 4,620,297 warrants outstanding, which were antidilutive and excluded from the earnings per share calculation. Under the terms of the warrant agreement, the exercise price of the warrants is subject to adjustment from time to time, based on certain events. These events include additional share issuances and dividend payments. An adjustment is made in the case of a cash dividend if the amount of the cash dividend increases or decreases the exercise price by at least 1%, otherwise such amount is carried forward and taken into account with any subsequent cash dividend. Adjustments in the exercise price also require an adjustment in the number of shares covered by the warrants. A total of 6,921 warrants were exercised during the three months ended March 31, 2006.

(10) Employee Benefit Plans

Net periodic benefit cost for our pension and other postretirement plans consists of the following for the three months ended March 31, 2006 and 2005 (in thousands):

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,
	2006			2005			2006			2005
Components of Net Periodic Benefit Cost
Service cost	$	2,133		$	2,044		$	172		$	219
Interest cost		5,044			5,087			713			722
Expected return on plan assets		(5,087	)		(4,916	)		(141	)		(161	)
Amortization of prior service cost		60			—			—			—
Net Periodic Benefit Cost	$	2,150		$	2,215		$	744		$	780

(11) 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.

The range of exposure for environmental remediation obligations at present is estimated to range between $29.5 million to $66.2 million. Our environmental reserve accrual is $44.6 million as of March 31, 2006. We anticipate that as environmental costs become fixed and determinable we will seek insurance coverage and/or authorization to recover these costs in rates, therefore we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

Manufactured Gas Plants

Approximately $27.6 million of our environmental reserve accrual is related to manufactured gas plants. Two formerly operated manufactured gas plants located in Aberdeen and Mitchell, South Dakota, have been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS), list as contaminated with coal tar residue. We are currently investigating these sites pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. At this time, we know that no material remediation is necessary at the Mitchell location. Remediation commenced at the Aberdeen site in 2006. Our current reserve for remediation costs at the Aberdeen site is approximately $14.4 million, and we estimate that approximately $13.1 million of this amount will be incurred during the next five years. At present, we cannot estimate with a reasonable degree of certainty the timing of remediation cleanup at the other South Dakota sites.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. In August 2002, the Nebraska Department of Environmental Quality (NDEQ) conducted site-screening investigations at these sites for alleged soil and groundwater contamination. During 2004, the NDEQ conducted Phase I Environmental Site Assessments of the Kearney and Grand Island locations, using funding provided by the Targeted Brownfields Assessment (TBA) Program. During 2005, the NDEQ conducted Phase II

investigations of soil and groundwater at these two locations using funding provided by the TBA Program. On March 30, 2006, the NDEQ released to us the Phase II Limited Subsurface Assessment performed by the NDEQ’s environmental consulting firm, and we are evaluating the results of this report. At present, we cannot determine with a reasonable degree of certainty the timing of any remediation cleanup at our Nebraska locations.

In addition, we own sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require entry into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena sites, however, were placed into the MDEQ’s voluntary remediation program for cleanup due to the existence of exceedences in groundwater of regulated pollutants. We conducted additional groundwater monitoring during 2005 at the Butte and Missoula sites and, at this time, we believe that natural attenuation should address the problems at these sites. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may be necessary to prevent certain contaminants from migrating offsite. We are currently evaluating the results of a pilot program meant to promote aerobic degradation of certain targeted contaminants. During 2006, we will complete our evaluation of the pilot program and also evaluate other alternatives including monitored natural attenuation. In light of these activities, continued monitoring of groundwater at this site is necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the timing of additional remediation at the Helena site.

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

Milltown Mining Waste

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three megawatt generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. In April 2003, the Environmental Protection Agency (EPA) announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed partial removal of the contaminated sediments located within the Milltown Reservoir, together with the removal of the Milltown Dam and powerhouse (this remedy was incorporated into the EPA’s formal Record of Decision issued on December 20, 2004). In light of this pre-Record of Decision announcement, we entered into a stipulation (Stipulation) with Atlantic Richfield, the EPA, the Department of the Interior, the State of Montana and the Confederated Salish and Kootenai Tribes (collectively the Government Parties), which capped NorthWestern’s and CFB’s collective liability to Atlantic Richfield and the Government Parties at $11.4 million. The amount of the stipulated liability has been fully accrued in the accompanying financial statements. As of March 31, 2006, we have fully funded escrow accounts for the State of Montana in the amount of $2.5 million and Atlantic Richfield in the amount of $7.5 million. In April 2006, these escrowed amounts were released to the parties in accordance with the terms of the consent decree described below.

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

Other

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

Legal Proceedings

Magten/Law Debenture/QUIPS Litigation

On April 16, 2004, Magten Asset Management Corporation (Magten) and Law Debenture Trust Company (Law Debenture) initiated an adversary proceeding, which we refer to as the QUIPs Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets and liabilities of CFB to us. In essence, Magten and Law Debenture are asserting that the transfer of the transmission and distribution assets acquired from the Montana Power Company was a fraudulent conveyance because such transfer left CFB insolvent and unable to pay certain claims. The plaintiffs also assert that they are creditors of CFB as a result of Magten owning a portion of the Series A 8.5% Quarterly Income Preferred Securities for which Law Debenture serves as the Indenture Trustee. 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 will now hear this lawsuit. The parties will now prepare for trial of this lawsuit.

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 and the parties are preparing for trial.

On October 19, 2004, the Bankruptcy Court entered a written order confirming our Plan. On October 25, 2004, Magten filed a notice of appeal of such order seeking, among other things, a reversal of the confirmation order. In connection with this appeal, Magten’s efforts to obtain a stay of the enforcement of the confirmation order to prevent our Plan from becoming effective were denied by the Bankruptcy Court on October 25, 2004 and by the United States District Court for the District of Delaware on October 29, 2004. With no stay imposed, our Plan became effective November 1, 2004. On October 26, 2004, Magten filed a notice of appeal of the Bankruptcy Court’s approval of the memorandum of understanding (MOU), which memorialized the settlement of the consolidated securities class actions and consolidated derivative litigation against NorthWestern and others. In March 2005, we moved to dismiss Magten’s appeal of the confirmation order on equitable mootness grounds. Magten’s appeals of the confirmation order and the order approving the MOU have been consolidated before the Delaware District Court. While we cannot currently predict the impact or resolution of Magten’s appeal of the confirmation order or the MOU, we intend to vigorously defend against the appeals.

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 NorthWestern 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, briefing has been completed, and we are awaiting a decision of the District Court. 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 Federal

District Court withdrew the reference, will now hear the lawsuit, and we intend to vigorously defend against the lawsuit.

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

McGreevey Litigation

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

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. that temporarily stayed the litigation, as against NorthWestern, CFB, The Montana Power Company, The Montana Power L.L.C. and Jack Haffey. As a result of the confirmation of our Plan, the stay has been made permanent. On July 10, 2004, we and the other insured parties 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. There are various issues preventing a consensus on a global settlement and the Federal District Court has now stayed the case pending resolution of bankruptcy issues in the Touch America and NorthWestern bankruptcy cases. 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 treated as securities, or Class 14, claims and would be entitled to no recovery 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.

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 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 25, 2005 the Bankruptcy Court preliminarily enjoined the plaintiffs from further prosecuting their claim. The McGreevey plaintiffs have asked for leave to appeal this order and we have asked the Delaware District Court to deny the request. We cannot currently predict the impact or resolution of this litigation.

Other Litigation

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

In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern, NorthWestern Communications Solutions, Expanets and Blue Dot. Since December 2003, we have periodically received and continue to receive subpoenas and informal requests from the SEC requesting documents and testimony from former and current employees as well as third parties regarding these matters. In January 2006, the SEC issued several Wells notices to individuals formerly associated with a now-defunct subsidiary. There have been no findings or adjudication of the underlying allegations in the Wells notices, and the SEC’s investigation is ongoing and it could issue additional Wells notices. In addition, certain of our former directors and several former and current employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the FBI and IRS concerning certain of the allegations made in the now resolved class action securities and derivative litigation as well as other matters. We have not been advised that NorthWestern is the subject of any FBI or IRS investigation. We are not aware of any other governmental inquiry or investigation related to these matters. We are fully cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are requested to do so in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, as a result of a ruling by the Bankruptcy Court, the SEC may not be able to pursue civil sanctions, including, but not limited to, monetary penalties against NorthWestern. The SEC did not appeal such order within the allowed appeal period. The SEC could, however, pursue other remedies and penalties against NorthWestern.

In November 2005, we and our directors were named as defendants in a shareholder class action and derivative action entitled City of Livonia Employee Retirement System v. Draper, et al., pending in the U.S. District Court for the District of South Dakota. The plaintiff claims, among other things, that the directors breached their fiduciary duties by not sufficiently negotiating with Montana Public Power Inc. and Black Hills Corporation, two entities that had made public, unsolicited offers to purchase NorthWestern. After the Board of Directors adopted our shareholders’ rights plan on December 5, 2005, this plaintiff also sought a temporary restraining order and preliminary injunction to prevent the implementation of the rights plan or any other defensive measures. On December 16, 2005, the Federal District Court denied the plaintiff’s application. The Federal District Court has scheduled a trial on plaintiffs’ request for a permanent injunction against the rights plan and other measures, which is scheduled to commence on May 30, 2006. We intend to vigorously defend against the plainitffs’ claims; however, we cannot currently predict the ultimate impact of this litigation.

In February 2006, we and our directors were named as defendants in an action entitled Harbinger Capital Partners Master Fund I, LTD v. Hanson, et al., pending in the Delaware Court of Chancery for Newcastle County. The plaintiffs sought a preliminary and permanent injunction finding that the application of the beneficial ownership

provisions of the shareholders’ rights plan may not prevent plaintiff from seeking to build a coalition slate with other shareholders or circulate a referendum to shareholders. On February 22, 2006, the Delaware Court of Chancery denied plaintiff’s request for expedited proceedings on their preliminary injunction motion, ruling that it would await rulings on the issue by the Federal Court in South Dakota. The court has not set a schedule in this action. We intend to vigorously defend against the plaintiff’s claims; however, we cannot currently predict the ultimate outcome of this litigation.

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

On March 15, 2006, an arbitration panel concluded that we are entitled to payment of approximately $9.5 million from an insurance provider. This conclusion relates to an insurance coverage dispute over a settlement that occurred in 2002. The insurance provider has agreed to pay us during the third quarter of 2006 and we expect to record a pretax gain of approximately $9.5 million after we receive payment from the insurance provider.

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

Disputed Claims Reserve

Upon consummation of our Chapter 11 Plan of Reorganization (Plan), 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, as these claims were not resolved or deemed allowed upon consummation of our Plan. We have surrendered control over the common stock provided and the shares reserve is 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, then such amounts would be reallocated pro rata to the allowed Class 7 and 9 claimants.

(12) Subsequent Events

As discussed in Note 1, on April 25, 2006 we reached an agreement with BBI to acquire NorthWestern. Based upon the number of shares outstanding at April 25, 2006, the transaction is valued at approximately $2.2 billion, including the assumption of outstanding debt. The transaction is conditioned upon approval by our shareholders, a number of federal and state regulatory approvals or reviews, and satisfaction of other customary closing conditions. In connection with the proposed transaction, NorthWestern will file a proxy statement with the SEC. The transaction is expected to be completed in 2007. Upon closing, NorthWestern’s common stock will cease to be publicly traded. In addition, our stock repurchase program was cancelled in May 2006.

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

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

OVERVIEW

In 2005, we received informal proposals from parties who were interested in buying us. In keeping with its fiduciary duties, our Board of Directors directed senior management and its financial advisor to commence an evaluation of all strategic alternatives to maximize value for all shareholders. In addition, early in 2006 the Board of Directors established a Mergers and Acquisitions Committee. In connection with the review, we identified and invited interested parties to submit formal acquisition proposals. All interested parties were invited to perform due diligence, and the Board’s financial advisor and senior management actively engaged with the bidders as they considered their final offers.

On April 25, 2006, we announced that we had reached a definitive agreement with Babcock & Brown Infrastructure Limited (BBI), an infrastructure investment company listed on the Australian Stock Exchange, under which BBI will acquire NorthWestern Corporation in an all-cash transaction at $37 per share. Based upon the number of shares outstanding at April 25, 2006, the transaction is valued at approximately $2.2 billion, including the assumption of outstanding debt. The transaction is conditioned upon approval by our shareholders, a number of federal and state regulatory approvals or reviews, and satisfaction of other customary closing conditions. In connection with the proposed transaction, NorthWestern will file a proxy statement with the SEC. The transaction is expected to be completed in 2007. Upon closing, NorthWestern’s common stock will cease to be publicly traded.

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

Consolidated net income for the three months ended March 31, 2006 was $21.0 million as compared to $18.9 million in 2005. The improvement was primarily due to increased investment and other income of $4.7 million and decreases in interest expense and income taxes. These improvements were partially offset by decreased margins and increased operating expenses.

During the first quarter of 2006 we completed the sale of our Montana First Megawatts generation assets for $20 million. We used the cash proceeds along with cash from operations to repay $49.1 million of debt and paid dividends on common stock of $11.0 million. In addition, as of April 2006, two of the three agencies that rate our debt have assigned an investment grade rating to certain of our outstanding secured debt.

RESULTS OF OPERATIONS

Factors Affecting Results of Continuing Operations

Our revenues may fluctuate substantially with changes in commodity costs, which are generally collected in rates from customers. Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is

primarily affected by weather. In addition, the applicable state regulatory commissions approve the commodity price recovery for electric and natural gas utility service within their respective jurisdictions.

Weather affects the demand for electricity and natural gas, especially among residential and commercial customers. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity. The weather’s effect is measured using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily actual temperature is less than the baseline and is a more relevant measurement in the colder months. Cooling degree-days result when the average daily actual temperature is greater than the baseline and is a more relevant measurement in the warmer months. The statistical weather information provided in our regulated segments represents a comparison of these degree-days, as applicable.

OVERALL CONSOLIDATED RESULTS

The following is a summary of our results of operations for the three month periods ended March 31, 2006 and 2005. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment.

	Three Months Ended March 31,
	2006			2005			Change			% Change
	(in millions)
Operating Revenues
Regulated Electric	$	168.1		$	154.4		$	13.7		8.9		%
Regulated Natural Gas		158.4			138.6			19.8		14.3
Unregulated Electric		24.8			21.5			3.3		15.3
Unregulated Natural Gas		34.7			50.3			(15.6	)	(31.0	)
Other		0.1			0.2			(0.1	)	(50.0	)
Eliminations		(24.6	)		(32.9	)		8.3		25.2
	$	361.5		$	332.1		$	29.4		8.9		%

Consolidated revenues for the three months ended March 31, 2006 were $361.5 million, an increase of $29.4 million, or 8.9%, over the same period in 2005. This increase was primarily due to higher supply costs of approximately $36.4 million in our regulated electric and natural gas segments, which are collected in rates from our customers. In addition, intersegment eliminations decreased $8.3 million due to decreased sales by our unregulated segments to our regulated segments. Primarily offsetting the increase in revenue was a decrease of $15.6 million in our unregulated natural gas segment due to the transition of certain customers to other commodity suppliers.

	Three Months Ended March 31,
	2006			2005			Change			% Change
	(in millions)
Cost of Sales
Regulated Electric	$	89.1		$	70.1		$	19.0		27.1		%
Regulated Natural Gas		119.2			98.4			20.8		21.1
Unregulated Electric		3.4			3.4			—		—
Unregulated Natural Gas		32.0			47.8			(15.8	)	(33.1	)
Other		0.1			0.1			—		—
Eliminations		(24.1	)		(32.4	)		8.3		25.6
	$	219.7		$	187.4		$	32.3		17.2		%

Consolidated cost of sales for the three months ended March 31, 2006 was $219.7 million, an increase of $32.3 million, or 17.2%, over the same period in 2005. Consistent with the changes in revenue, the increase was primarily

due to higher supply costs of $25.4 million in our regulated natural gas segment and $19.8 million in our regulated electric segment. Partially offsetting this increase was a $15.8 million decrease in unregulated gas costs primarily due to the transition of certain customers as discussed above. Intersegment eliminations decreased $8.3 million.

	Three Months Ended March 31,
	2006			2005			Change			% Change
	(in millions)
Gross Margin
Regulated Electric	$	79.0		$	84.3		$	(5.3	)	(6.3	)	%
Regulated Natural Gas		39.2			40.2			(1.0	)	(2.5	)
Unregulated Electric		21.4			18.1			3.3		18.2
Unregulated Natural Gas		2.7			2.5			0.2		8.0
Other		—			0.1			(0.1	)	(100.0	)	%
Eliminations		(0.5	)		(0.5	)		—		—
	$	141.8		$	144.7		$	(2.9	)	(2.0	)	%

Consolidated gross margin for the three months ended March 31, 2006 was $141.8 million, a decrease of $2.9 million, or 2.0%, from gross margin of $144.7 million in 2005. Margins in our regulated electric segment decreased $5.3 million primarily because the first quarter of 2005 included a $4.9 million gain related to a QF contract amendment. In addition, during March 2006 we signed a stipulation with the Montana Consumer Counsel to settle various issues they raised relative to our 2005 and 2006 electric tracker filings. As a result of this stipulation we are responsible for replacement costs related to certain forward sales contracts for periods after July 1, 2005. These forward sales extend through 2007. We recognized a loss in cost of sales of $1.4 million during the first quarter of 2006 related to the removal of replacement costs from our electric tracker for these sales contracts between July 1, 2005 and March 31, 2006. Additionally, regulated electric cost of sales includes a $2.7 million loss based on the market value of the remaining forward sales through 2007. These decreases were partially offset by higher transmission and distribution margins and an increase in our unregulated electric segment margins of $3.3 million due to higher average rates and a gain on the settlement of put options.

Margin as a percentage of revenues decreased to 39.2% for 2006, from 43.6% for 2005. Gross margin as a percentage of revenue is primarily impacted by the fluctuations that occur in regulated electric and natural gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

	Three Months Ended March 31,
	2006		2005		Change			% Change
	(in millions)
Operating Expenses
Operating, general and administrative	$	61.3	$	56.6	$	4.7		8.3		%
Property and other taxes		19.5		18.2		1.3		7.1
Depreciation		18.8		18.7		0.1		0.5
Reorganization items		—		3.4		(3.4	)	(100.0	)
	$	99.6	$	96.9	$	2.7		2.8		%

Consolidated operating, general and administrative expenses were $61.3 million for the three months ended March 31, 2006 as compared to $56.6 million in 2005. This increase was primarily due to $2.9 million in higher professional fees associated with assessing our strategic alternatives and addressing outstanding litigation, and a $1.7 million increase in our allowance for uncollectible accounts due to increases in past due customer account balances. We continually monitor our accounts receivable balances and collections from customers, particularly in light of the increases in energy supply costs since mid-2005.

Property and other taxes were $19.5 million for the three months ended March 31, 2006 as compared to $18.2 million in 2005. This increase was primarily due to a higher valuation assessment and increased mill levies in our Montana service territory.

Depreciation expense was $18.8 million for the three months ended March 31, 2006 as compared to $18.7 million in 2005.

Reorganization items in 2005 of $3.4 million consisted of bankruptcy related professional fees and expenses. While we continue to incur professional fees during 2006 associated with various legal proceedings that must be resolved before our bankruptcy case can be closed, these costs are included in operating, general and administrative expenses.

Consolidated operating income for the three months ended March 31, 2006 was $42.2 million, as compared to $47.8 million in 2005. This $5.6 million decrease was primarily due to lower margins and increased expenses discussed above.

Consolidated interest expense for the three months ended March 31, 2006 was $14.4 million, a decrease of $1.9 million, or 11.7%, from 2005. This decrease was primarily attributable to a $94 million decrease in debt in 2005. We anticipate additional reductions in interest expense during 2006 as we repay borrowings on our unsecured revolver and refinance existing debt at lower rates. See “Liquidity and Capital Resources” for additional information regarding our refinancing activities.

Consolidated investment and other income for the three months ended March 31, 2006 was $5.3 million, an increase of $4.7 million from 2005. This increase was primarily due to a $3.8 million gain related to an interest rate swap and a $0.4 million gain on the sale of the company-owned aircraft.

Consolidated provision for income taxes for the three months ended March 31, 2006 was $12.0 million as compared to $13.7 million in 2005. Our effective tax rate for the first quarter 2006 was 36.5% as compared to 42.6% for the first quarter of 2005. Many of the professional fees associated with our reorganization were not deductible for tax purposes which increased our effective tax rate in 2005. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

Consolidated net income for the three months ended March 31, 2006 was $21.0 million, an increase of $2.1 million, or 11.1%, over $18.9 million in 2005. This improvement was primarily related to higher investment and other income and a decrease in interest expense and income taxes. Decreased margins and increased operating expenses partially offset this improvement.

REGULATED ELECTRIC SEGMENT

Three Months Ended March 31, 2006 Compared to the Three Months Ended March 31, 2005

	Results
	2006			2005			Change			% Change
	(in millions)
Electric supply revenue	$	81.0		$	69.8		$	11.2		16.0		%
Transmission & distribution revenue		71.8			70.9			0.9		1.3
Rate schedule revenue		152.8			140.7			12.1		8.6
Transmission		10.2			9.2			1.0		10.9
Wholesale		3.0			2.6			0.4		15.4
Miscellaneous		2.1			1.9			0.2		10.5
Total Revenues		168.1			154.4			13.7		8.9		%
Supply costs		84.4			64.6			19.8		30.7
Wholesale		1.0			0.9			0.1		11.1
Other cost of sales		3.7			4.6			(0.9	)	(19.6	)
Total Cost of Sales		89.1			70.1			19.0		27.1		%
Gross Margin	$	79.0		$	84.3		$	(5.3	)	(6.3	)	%
% GM/Rev		47.0	%		54.6	%

	Volumes MWH
	2006	2005	Change		% Change
	(in thousands)
Retail Electric
Residential	733	728	5		0.7		%
Commercial	936	941	(5	)	(0.5	)
Industrial	768	756	12		1.6
Other	24	24	—		—
Total Retail Electric	2,461	2,449	12		0.5		%
Wholesale Electric	70	71	(1	)	(1.4	)	%

Average Customer Counts	2006	2005	Change	% Change
Montana	317,796	311,747	6,049	1.9	%
South Dakota	58,674	58,314	360	0.6	%
Total	376,470	370,061	6,409	1.7	%

Rate Schedule Revenue

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

Electric rate schedule revenue for the three months ended March 31, 2006 increased $12.1 million, or 8.6% over results in 2005. Electric supply revenue, which consists of supply costs that are collected in rates from customers, increased $11.2 million primarily from 16.2% higher average prices.

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, which are the primary reason for the $1.0 million, or 10.9%, increase 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. These revenues increased $0.4 million primarily due to higher average prices. We anticipate reduced wholesale volumes and revenues for the remainder of 2006 as compared to 2005, due to Powder River Basin coal delivery issues causing a projected decrease in generation at the Big Stone Plant.

Gross Margin

Gross margin for the three months ended March 31, 2006 decreased $5.3 million, or 6.3% as compared to the first quarter 2005. This decrease was primarily because the first quarter of 2005 included a $4.9 million gain related to a QF contract amendment. In addition, during March 2006 we signed a stipulation with the Montana Consumer Counsel to settle various issues they raised relative to our 2005 and 2006 electric tracker filings. As a result of this stipulation we are responsible for replacement costs related to certain forward sales contracts for periods after July 1, 2005. These forward sales extend through 2007. We recognized a loss in cost of sales of $1.4 million during the first quarter of 2006 related to the removal of replacement costs from our electric tracker for these sales contracts between July 1, 2005 and March 31, 2006. Additionally, cost of sales includes a $2.7 million loss based on the market value of the remaining forward sales through 2007. These decreases were partially offset by higher transmission and distribution margins.

Margin as a percentage of revenues decreased to 47.0% for 2006, from 54.6% for 2005 due to the items discussed above. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Volumes

Regulated retail electric volumes for the three months ended March 31, 2006 totaled 2,461,206 MWHs, which increased slightly as compared with 2,448,688 MWHs in the same period in 2005 due primarily to a 1.7% increase in customer growth. Regulated wholesale electric volumes in the first quarter of 2006 were 69,872 MWHs, a slight decrease from 70,553 MWHs in the same period in 2005.

REGULATED NATURAL GAS SEGMENT

Three Months Ended March 31, 2006 Compared to the Three Months Ended March 31, 2005

	Results
	2006			2005			Change			% Change
	(in millions)
Gas supply revenue	$	112.4		$	87.2		$	25.2		28.9		%
Transportation, distribution & storage revenue		33.9			35.8			(1.9	)	(5.3	)
Rate schedule revenue		146.3			123.0			23.3		18.9
Transportation & storage		4.4			4.3			0.1		2.3
Wholesale revenue		5.7			10.1			(4.4	)	(43.6	)
Miscellaneous		2.0			1.2			0.8		66.7
Total Revenues		158.4			138.6			19.8		14.3		%
Supply costs		112.6			87.2			25.4		29.1
Wholesale supply costs		5.7			10.1			(4.4	)	(43.6	)
Other cost of sales		0.9			1.1			(0.2	)	(18.2	)
Total Cost of Sales		119.2			98.4			20.8		21.1		%
Gross Margin	$	39.2		$	40.2		$	(1.0	)	(2.5	)	%
% GM/Rev		24.7	%		29.0	%

	Volumes MMbtu
	2006	2005	Change		% Change
	(in thousands)
Retail Gas
Residential	7,266	8,087	(821	)	(10.2	)	%
Commercial	4,423	4,713	(290	)	(6.2	)
Industrial	77	84	(7	)	(8.3	)
Other	63	55	8		14.5
Total Retail Gas	11,829	12,939	(1,110	)	(8.6	)	%

Average Customer Counts	2006	2005	Change	% Change
Montana	171,834	167,951	3,883	2.3	%
South Dakota	83,163	82,692	471	0.6
Total	254,997	250,643	4,354	1.7	%

	2006 as compared to:
Heating Degree-Days	2005	Historic Average
Montana	5% warmer	8% warmer
South Dakota	10% warmer	17% warmer
Nebraska	12% warmer	20% warmer

Rate Schedule Revenue

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

Gas rate schedule revenue for the three months ended March 31, 2006 increased $23.3 million, or 18.9% over results in 2005. Gas supply revenues, which consist of supply costs that are collected in rates from customers, increased $35.3 million, or 40.5%, due to higher average rates, partially offset by a $10.5 million, or 8.6% decrease in volumes primarily due to warmer weather. This volume decrease also caused the $1.9 million decrease in transportation, distribution and storage revenue.

Transportation & Storage Revenue

Transportation revenue consists of revenue earned for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. Transportation revenue remained flat for the three months ended March 31, 2006 as compared to the same period 2005. Transportation and storage revenues can fluctuate significantly from year to year based on the anticipated spread and volatility between summer and winter gas prices. For example, producers may elect to store summer gas production for later delivery during the traditionally higher priced winter heating season. Likewise, choice customers may utilize storage to secure lower priced summer gas production for use during the winter season.

Wholesale Revenue

Wholesale revenue decreased $4.4 million, or 43.6%, due to a decrease in sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.

Gross Margin

Gross margin for the three months ended March 31, 2006 decreased $1.0 million, or 2.5% over the first quarter 2005 primarily due to warmer weather.

Margin as a percentage of revenue decreased to 24.7% for 2006, from 29.0% for 2005. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are generally collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Volumes

Regulated retail natural gas volumes were 11,829,245 MMbtu (million British Thermal Units) during the three months ended March 31, 2006, compared with 12,939,339 MMbtu or an 8.6% decline from the same period in 2005. This decline was due primarily to warmer weather in all regulated markets.

UNREGULATED ELECTRIC SEGMENT

Three Months Ended March 31, 2006 Compared to the Three Months Ended March 31, 2005

Our unregulated electric segment reflects the operations of our Colstrip Unit 4 division, which includes our lease of a 30% share of the Colstrip Unit 4 generation facility, and CFB’s results arising from the ownership and operation of the three-megawatt Milltown Dam hydroelectric facility. We sell our Colstrip Unit 4 generation, representing approximately 222 megawatts at full load, principally to two unrelated third parties under agreements through December, 2010. We also have a separate agreement to repurchase 111 megawatts through December 2010. These 111 megawatts are available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 megawatts have been offered to supply a portion of the Montana default supply load (included in our regulated electric segment) for a term of 11.5 years at an average nominal price of $35.80 per megawatt hour.

	Results
		2006			2005			Change		% Change
	(in millions)
Total Revenues	$	24.8		$	21.5		$	3.3		15.3		%
Supply costs		2.5			2.7			(0.2	)	(7.4	)
Wheeling costs		0.9			0.7			0.2		28.6
Total Cost of Sales	$	3.4		$	3.4		$	—		—		%
Gross Margin	$	21.4		$	18.1		$	3.3		18.2		%
% GM/Rev		86.3	%		84.2	%

	Volumes MWH
	2006	2005	Change		% Change
	(in thousands)
Wholesale Electric	421	446	(25	)	(5.6	)	%

Revenue

Unregulated electric revenue increased $3.3 million, or 15.3%, for the three months ended March 31, 2006 primarily due to $4.2 million, or 22.3%, higher average prices partially offset by $1.0 million, or 5.6% lower volumes. We had less energy available to sell due to decreased plant availability resulting from unscheduled maintenance.

Gross Margin

Gross margin increased $3.3 million, or 18.2%, primarily due to higher average rates. In addition, an increase in fuel supply costs in the current year was partially offset by a $1.3 million reduction to cost of sales related to the settlement of put options.

Volumes

Unregulated electric volumes were 421,205 MWHs in the first quarter of 2006, compared with 445,582 MWHs in the same period in 2005. This decrease was due primarily to increased downtime for plant maintenance in 2006.

UNREGULATED NATURAL GAS SEGMENT

Three Months Ended March 31, 2006 Compared to the Three Months Ended March 31, 2005

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

Results

2006

2005

Change

% Change

(in millions)

Total Revenue

34.7

50.3

(15.6

)

(31.0

)

Supply costs

32.0

47.8

(15.8

)

(33.1

)

Gross Margin

2.7

2.5

0.2

8.0

% GM/Rev

7.8

5.0

	Volumes MMbtu
	2006	2005	Change		% Change
	(in thousands)
Wholesale Gas	5,539	7,002	(1,463	)	(20.9	)	%

Revenue

Unregulated natural gas revenue decreased $15.6 million, or 31.0%, due primarily to certain customers contracting directly with other providers for their commodity supply needs. We have encouraged certain customers to choose other commodity suppliers as we receive little to no margin on commodity costs.

Gross Margin

Gross margin increased slightly for the three months ended March 31, 2006 as compared to the same period in 2005 primarily due to losses recorded on out of market fixed price sales contracts in the first quarter 2005.

Volumes

Unregulated wholesale natural gas volumes delivered totaled 5,539,174 MMbtu in 2006, compared with 7,002,384 MMbtu in 2005. This decrease is due primarily to unplanned outages at various ethanol facilities in South Dakota and the transfer of certain customers to our regulated gas segment.

LIQUIDITY AND CAPITAL RESOURCES

As of March 31, 2006, we had cash and cash equivalents of $12.0 million, and revolver availability of $151.4 million. During the three months ended March 31, 2006, we used existing cash to repay $49.1 million of debt, including repayments of $46.0 million on our revolver. In addition to these repayments we paid dividends on common stock of $11.0 million. During the first quarter of 2006, we also received net proceeds of $17.2 million from the sale of our Montana First Megawatts generation assets, and $5.0 million related to our allowed claim in Netexit’s bankruptcy.

Factors Impacting our Liquidity

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

The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of supply and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above, therefore we usually under collect in the fall and winter and over collect in the spring. 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, significantly increased our under collection. As of March 31, 2006, we are under collected on our current Montana natural gas and electric trackers by approximately $26.1 million. Based on current forecasted commodity price and volume assumptions, we anticipate our under collected position will decrease to a range of approximately $6-8 million by the end of the tracking year, June 30, 2006. Any under collected balance at the end of the tracking year will be amortized and collected in rates over the following tracker year.

Cash Flows

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

		Three Months Ended March 31,
		2006			2005
Continuing Operating Activities
Net income	$	21.0		$	18.9
Non-cash adjustments to net income		27.2			27.5
Changes in working capital		16.3			58.8
Other		13.1			(0.7	)
		77.6			104.5
Continuing Investing Activities
Property, plant and equipment additions		(21.2	)		(13.4	)
Restricted cash		(1.0	)		(1.4	)
Sale of assets		20.3			—
Proceeds from hedging activities		1.4			—
Net proceeds from (purchases) sales of investments		—			(44.9	)
		(0.5	)		(59.7	)
Continuing Financing Activities
Net repayment of debt		(49.1	)		(12.0	)
Dividends on common stock		(11.0	)		(7.8	)
Deferred gas storage		(11.7	)		(9.1	)
Other		(1.0	)		(0.5	)
		(72.8	)		(29.4	)
Discontinued Operations		5.0			—
Net Increase in Cash and Cash Equivalents	$	9.3		$	15.4
Cash and Cash Equivalents, beginning of period	$	2.7		$	17.0
Cash and Cash Equivalents, end of period	$	12.0		$	32.4

Cash Provided By Continuing Operating Activities

As of March 31, 2006, cash and cash equivalents were $12.0 million, compared with $2.7 million at December 31, 2005, and $32.4 million at March 31, 2005. Cash provided by continuing operating activities totaled $77.6 million during the three months ended March 31, 2006, compared to $104.5 million during the three months ended March 31, 2005. This decrease in operating cash flows is primarily related to larger uncollected energy supply costs due to higher prices, which is discussed above in the “Factors Impacting Our Liquidity” section. In addition, our cash flows from operations during the first quarter of 2005 includes cash provided of $13.3 million due to improved credit terms reflected in the reduction of prepaid energy supply.

Cash Used In Continuing Investing Activities

Cash used in investing activities of continuing operations totaled $0.5 million during the three months ended March 31, 2006 compared to $59.7 million during the three months ended March 31, 2005. During the first quarter of 2006 we received cash proceeds from the sale of assets of approximately $20.3 million and used approximately $21.2 million for property, plant and equipment additions. In 2005, we used approximately $13.4 million for property, plant and equipment additions, and approximately $44.9 million for the purchase of short-term investments.

Cash Used In Continuing Financing Activities

Cash used in financing activities of continuing operations totaled $72.8 million during the three months ended March 31, 2006 compared to $29.4 million during the three months ended March 31, 2005. During the first quarter of 2006 we have made debt repayments of $49.1 million, paid dividends on common stock of $11.0 million, and paid $11.7 million for deferred storage transactions. In the first quarter of 2005 we made debt repayments of $12.0 million, paid dividends on common stock of $7.8 million and paid $9.1 million for deferred storage transactions. 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. Cash used to repurchase shares during the first quarter of 2006 was approximately $1.1 million.

Discontinued Operations Cash Flows

The decrease in restricted cash held by discontinued operations during the three months ended March 31, 2006 was primarily due to Netexit’s $5.0 million distribution to us.

Sources and Uses of Funds

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, share repurchases and estimated future capital expenditures during the next twelve months. We paid down the $35 million outstanding as of March 31, 2006 on our revolver during April 2006 and, as of April 30, 2006, our revolver availability was approximately $181 million.

The common stock repurchase program announced during the fourth quarter of 2005 allows us to repurchase up to $75 million of common stock. During the first quarter of 2006, we repurchased approximately $1.1 million of common stock. Our stock repurchase program was cancelled in May 2006.

During the second quarter of 2006, we expect to make property tax payments of approximately $35 million, and our semi-annual Colstrip Unit 4 operating lease payment of approximately $16.1 million. We also anticipate refinancing our $150 million, 7.30% first mortgage bonds that are set to mature on December 1, 2006. The amount of debt reduction, dividends and repurchase of common stock is subject to certain factors including the use of existing cash, cash equivalents and the receipt of cash from operations.

Refinancing Transaction

On May 9, 2006 we expect to close in escrow our refinancing of $170.2 million of Pollution Control obligations. The actual redemption of these obligations is scheduled for May 30, 2006. Upon redemption the interest rate will be

lowered from 6.125 % and 5.9% to 4.65%. These obligations, which mature in August 2023, are secured by certain Montana electric and natural gas assets.

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 March 31, 2006. See our Annual Report on Form 10-K for the year ended December 31, 2005 for additional discussion.

	Total		2006		2007		2008		2009		2010		Thereafter
	(in thousands)
Long-term Debt	$	693,898	$	153,308	$	6,761	$	6,057	$	41,047	$	6,123	$	480,602
Future minimum operating lease payments(1)	281,215		33,927		33,926		32,861		32,381		32,292		115,828
Estimated Pension and Other Postretirement Obligations(2)	94,700		22,700		22,000		22,000		22,000		6,000		N/A
Qualifying Facilities(3)	1,617,948		42,737		58,420		60,574		62,598		64,580		1,329,039
Supply and Capacity Contracts(4)	1,566,840		345,025		314,313		189,526		165,906		158,716		393,354
Contractual interest payments on debt (5)	375,661		36,727		30,526		30,183		28,758		27,306		222,161
Total Commitments	$	4,630,262	$	634,424	$	465,946	$	341,201	$	352,690	$	295,017	$	2,540,984

(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. We are assessing a potential buy out or restructuring of this lease during 2006.

(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. Based on our projected contribution levels and current assumptions, we estimate that our pension plans will be fully funded in 2009.

(3)

The Qualifying Facilities (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.

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

(5)	Contractual interest payments assumes the refinancing of $170.2 million of pollution control obligations to a rate of 4.65%.

Credit Ratings

Fitch Investors Service (Fitch), Moody’s Investors Service (Moody’s) and Standard and Poor’s Rating Group (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of April 27, 2006, our ratings with these agencies are as follows:

	Senior Secured Rating		Senior Unsecured Rating		Corporate Rating	Outlook
Fitch	BBB		BBB-		BBB-	Stable
Moody’s	Ba1		Ba2		N/A	Positive
S&P	BBB-	*	BB-	*	BB+	Negative	**

*	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. Our current outstanding senior secured debt in South Dakota and Nebraska is rated BB+ by S&P.

**	The negative outlook assigned by S&P is due to the uncertainty surrounding BBI’s acquisition of NorthWestern. For further information please see our “Risk Factors” section.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Interest Rate Risk

We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. All of our debt has fixed interest rates, with the exception of our revolver, which bears interest at a variable rate (currently approximately 5.9%) tied to the London Interbank Offered Rate (LIBOR). Based upon amounts outstanding as of March 31, 2006, a 1% increase in the LIBOR would increase annual interest expense on this line of credit by approximately $0.4 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 March 31, 2006, the market value of these instruments, representing the amount we would receive upon their termination, was approximately $15.5 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 natural gas reserves or regulated electric generation assets within the Montana market. Several factors influence price levels and volatilities. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

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

In our unregulated electric segment, due to our lease of a 30% share of the Colstrip Unit 4 generation facility, we are exposed to the market price fluctuations of electricity. We have entered into forward contracts for the sale of a significant portion of Colstrip Unit 4’s generation through the first quarter of 2007. To the extent Colstrip Unit 4 experiences any unplanned outages, we would need to secure the quantity deficiency from the wholesale market to fulfill our forward sales contracts. As of March 31, 2006, market prices exceeded our contracted forward sales prices by approximately $4.3 million.

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 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). Based on this evaluation our principal executive officer and principal financial officer have concluded that, as of March 31, 2006, our disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the three months ended March 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

See Note 11, Commitments and Contingencies, to the Consolidated Financial Statements for information about legal proceedings.

ITEM 1A.

RISK FACTORS

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

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

The agreement to sell NorthWestern to BBI will be completed only if certain conditions are met, including approval of the sale by our shareholders and various federal and state regulatory approvals. Accordingly, there may be uncertainty regarding the completion of the transaction. If the sale is not completed, then our shareholders may not be able to obtain a premium for their shares of common stock offered in the proposed transaction. In addition, this uncertainty may cause customers, suppliers and other parties with whom we do business to delay or defer decisions concerning NorthWestern, which could negatively affect our business. Such parties may also seek to change existing agreements or arrangements with us as a result of the sale, or may choose not to continue to do business with us. Any such delay or deferral of decisions or changes in existing agreements or arrangements could have a material adverse effect on our business regardless of whether the sale is completed.

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

We have incurred and will continue to incur significant costs associated with outstanding litigation and the SEC investigation. These costs, which are being expensed as incurred, are expected to have an adverse affect on our results of operations and cash flows. Pending litigation includes significant matters such as Magten/Law Debenture, McGreevey, the SEC investigation, and various other matters, which are discussed in detail under Part II, Item 1, Legal Proceedings. An adverse result in any of these matters could have an adverse effect on our business.

Certain of our shareholders may have the ability to influence certain aspects of our business operations.

Harbinger Capital Partners Master Fund I, Ltd. f/k/a Harbert Distressed Investment Master Fund Ltd. (Harbinger) is affiliated with or manages funds, which based on the most recent information made available to us, collectively owns approximately 6% of our common stock. Harbinger could acquire additional shares, or divest of shares in the future.

On December 5, 2005, we adopted a shareholders’ rights plan in order to protect NorthWestern against coercive actions by third parties that could be detrimental to the best interests of all the shareholders and to permit the Board of Directors to review and evaluate its strategic alternatives in an orderly fashion. Under the rights plan, preferred stock purchase rights will be distributed as a dividend at the rate of one right for each share of common stock of NorthWestern held by shareholders of record as of the close of business on December 15, 2005. The rights will expire on December 5, 2015. The rights generally will be exercisable only if a person or group acquires beneficial ownership of 15% or more of our common stock. A person or group who beneficially owns 15% or more of the outstanding shares of our common stock prior to the adoption of the rights plan will not cause the rights to become exercisable upon adoption of the rights plan. As a result, the rights will not be triggered even though Harbinger beneficially owned approximately 20% of the outstanding shares of our common stock prior to the adoption of the rights plan. However, Harbinger will cause the rights to become exercisable if it (subject to certain exceptions) becomes the

beneficial owner of additional shares of our common stock or its beneficial ownership decreases below 15% and subsequently, increases to 15% or more.

If any holders of a significant number of the shares of our common stock were to act as a group, then such holders could cause the rights to become exercisable. If the rights plan could not be enforced as a result of an adverse decision by the Federal District Court in the City of Livonia lawsuit or by the Court of Chancery in the Harbinger lawsuit, 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 shareholder approval, such as an amendment to our articles 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 subject to extensive governmental regulations that affect our industry and our operations. Existing and changed regulations and possible deregulation have the potential to impose significant costs, increase competition and change rates which could have a material adverse effect on our results of operations and financial condition.

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

We are regulated by commissions in the states we serve. As a result, these commissions review our books and records, 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.

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

Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rates through our monthly trackers. During the fourth quarter of 2005, the Montana Consumer Counsel (MCC) submitted testimony alleging we were imprudent and recommending the MPSC consider disallowing portions of our forecasted electric and natural gas supply costs contained in the 2005 tracker filings. In March 2006, upon signing a stipulation with the MCC we recognized a loss of approximately $1.4 million related to the removal of replacement costs for certain forward sales transactions from our 2006 electric tracker forecast. The stipulation, which has not yet been approved by the MPSC, settles various issues relative to our electric supply costs raised by the MCC. We cannot predict how the MPSC will act on the stipulation and to the extent our energy supply costs are deemed imprudent by the MPSC or other applicable state regulatory commissions, we would under-recover our costs, which could adversely impact our results of operations. In April 2006, in a commission work session, the MPSC directed their staff to draft an order approving our 2005 Montana natural gas tracker as filed.

We do not own any natural gas reserves or regulated electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and substantially all of our Montana electricity supply pursuant to contracts with third-party suppliers. In light of this reliance on third-party suppliers, we

are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, then we might be required to purchase gas and/or electricity supply requirements in the energy markets, which may not be on commercially reasonable terms, if at all. If prices were higher in the energy markets, it could result in a temporary material under-recovery that would reduce our liquidity.

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

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

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

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

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

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

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.

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

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity issues and/or increased prices for coal transportation from a sole supplier. Coal stockpiles at the Big Stone Plant were substantially depleted during the first quarter of 2006 and generation is being reduced until coal stockpiles can be replenished. As a result, we may have to buy replacement power in the open market to serve our retail customers,

which would result in higher electric rates for our retail customers through fuel clause adjustments and make us less competitive in wholesale electric markets. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

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

Our electric and natural gas utility business is seasonal and weather patterns can have a material impact on 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.

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 $29.5 million to $66.2 million. We had an environmental reserve of $44.6 million at March 31, 2006. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or government claims for damages allegedly associated with specific environmental conditions. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.

Our ability to access the capital markets is dependent on our ability to obtain certain regulatory approvals and constrained by 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, prior to our obtaining investment grade ratings, specific debt covenants restrict our ability to borrow above a 60% debt to capital threshold without further lender approval.

ITEM 2.

ISSUER PURCHASES OF EQUITY SECURITIES

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 under a specific trading plan. Purchases under the stock repurchase program may be made in the general open market in accordance with Rule 10b-18 under the Securities Exchange Act of 1934. We are also authorized to make privately negotiated repurchases in appropriate circumstances. The purchases will be based on a number of factors, including price, volume and timing. The following table provides information regarding stock repurchases during the first quarter of 2006. All of the following were open market transactions:

	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased Under Publicly Announced Plans or Programs	Dollar Value of Shares That May Yet Be Purchased Under the Plan

January 1, 2006 — January 31, 2006	—		—	—		—
February 1, 2006 — February 28, 2006	35,600	$	31.01	35,600	$	71.1 million
March 1, 2006 — March 31, 2006	—		—	—		—
Total	35,600			35,600

ITEM 6.

EXHIBITS

(a)

Exhibits

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

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

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

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

SIGNATURES

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

	NORTHWESTERN CORPORATION
Date: May 4, 2006	By:	/s/ BRIAN B BIRD
		Brian B. Bird
		Chief Financial Officer
		Duly Authorized Officer and Principal Financial Officer

EXHIBIT INDEX

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

*	Filed herewith