NorthWestern 10Q 2006 Q2 Quarterly report

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 June 30, 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

35,494,948 shares outstanding at July 28, 2006

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION			5
Item 1.	Financial Statements (Unaudited)		5
	Consolidated Balance Sheets — June 30, 2006 and December 31, 2005		5
	Consolidated Statements of Income (Loss) — Three and Six Months Ended June 30, 2006 and 2005		6
	Consolidated Statements of Cash Flows — Six Months Ended June 30, 2006 and 2005		7
	Notes to Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		42
Item 4.	Controls and Procedures		43
PART II. OTHER INFORMATION			44
Item 1.	Legal Proceedings		44
Item 1A.	Risk Factors		44
Item 2.	Issuer Purchases of Equity Securities		47
Item 6.	Exhibits		48
SIGNATURES			49

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 transaction or the termination of the definitive agreement due to a number of factors, including the failure to obtain regulatory approvals or to satisfy other customary closing conditions;

•

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

•

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

•

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

•

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

•

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

Our Annual Report on Form 10-K, recent and forthcoming Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K and other SEC filings discuss some of the important risk factors that may affect our business, results of operations and financial condition. We undertake no obligation to revise or publicly update any forward-looking statements for any reason.

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)

		June 30, 2006			December 31, 2005
ASSETS
Current Assets:
Cash and cash equivalents	$	3,005		$	2,691
Restricted cash		17,781			25,238
Accounts receivable, net of allowance		89,229			160,856
Inventories		53,597			40,925
Regulatory assets		26,676			38,640
Prepaid energy supply		2,477			1,754
Other current assets		21,084			4,397
Assets held for sale		—			20,000
Deferred income taxes		20,255			10,520
Current assets of discontinued operations		—			8,472
Total current assets		234,104			313,493
Property, Plant, and Equipment, Net		1,425,633			1,409,205
Goodwill		435,076			435,076
Other:
Investments		1,192			1,297
Regulatory assets		197,485			204,466
Other		36,357			36,866
Total assets	$	2,329,847		$	2,400,403
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	156,784		$	156,455
Accounts payable		55,337			99,419
Accrued expenses		137,822			157,587
Regulatory liabilities		13,346			10,003
Current liabilities of discontinued operations		—			1,195
Total current liabilities		363,289			424,659
Long-term Debt		546,441			586,515
Deferred Income Taxes		124,585			100,192
Noncurrent Regulatory Liabilities		177,681			170,744
Other Noncurrent Liabilities		378,059			380,798
Total liabilities		1,590,055			1,662,908
Commitments and Contingencies (Note 11)
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 35,807,884 and 35,494,337, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		358			358
Treasury stock at cost		(9,303	)		(5,573	)
Paid-in capital		721,621			721,240
Unearned restricted stock		(215	)		(383	)
Retained earnings		13,435			16,889
Accumulated other comprehensive income		13,896			4,964
Total shareholders’ equity		739,792			737,495
Total liabilities and shareholders’ equity	$	2,329,847		$	2,400,403

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

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Unaudited)

(in thousands, except per share amounts)

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

		2006			2005			2006				2005
OPERATING REVENUES	$	232,186		$	249,387		$	593,668		$	584,480
COST OF SALES		117,726			131,184			337,398			321,565
GROSS MARGIN		114,460			118,203			256,270			262,915
OPERATING EXPENSES
Operating, general and administrative		68,645			57,431			129,972			114,086
Property and other taxes		18,713			17,422			38,178			35,627
Depreciation		18,751			18,874			37,580			37,564
Reorganization items		—			138			—			3,501
TOTAL OPERATING EXPENSES		106,109			93,865			205,730			190,778
OPERATING INCOME		8,351			24,338			50,540			72,137
Interest Expense		(14,622	)		(15,758	)		(29,058	)		(32,100		)
Loss on Debt Extinguishment		—			(548	)		—			(548		)
Investment and Other Income		3,147			1,590			8,417			2,197
Income (Loss) From Continuing Operations Before Income Taxes		(3,124	)		9,622			29,899			41,686
Income Tax Benefit (Expense)		310			(3,249	)		(11,738	)		(16,919		)
Income (Loss) From Continuing Operations		(2,814	)		6,373			18,161			24,767
Discontinued Operations, Net of Taxes		368			(10,304	)		418			(9,780		)
Net Income (Loss)	$	(2,446	)	$	(3,931	)	$	18,579		$	14,987
Average Common Shares Outstanding		35,511			35,607			35,547			35,609
Basic Earnings per Average Common Share
Continuing operations	$	(0.08	)	$	0.18		$	0.51		$	0.70
Discontinued operations		0.01			(0.29	)		0.01			(0.28		)
Basic	$	(0.07	)	$	(0.11	)	$	0.52		$	0.42
Diluted Earnings per Average Common Share
Continuing operations	$	(0.08	)	$	0.18		$	0.50		$	0.70
Discontinued operations		0.01			(0.29	)		0.01			(0.28		)
Diluted	$	(0.07	)	$	(0.11	)	$	0.51		$	0.42
Dividends Declared per Average Common Share	$	0.31		$	0.22		$	0.62		$	0.44

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

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
		2006			2005
OPERATING ACTIVITIES:
Net Income	$	18,579		$	14,987
Items not affecting cash:
Depreciation		37,580			37,564
Amortization of debt issue costs		1,301			1,067
Amortization of restricted stock		329			1,691
Gain on qualifying facility contract amendment		—			(4,888	)
Income (Loss) from discontinued operations, net of taxes		(418	)		9,780
Gain on sale of assets		(2,392	)		(667	)
Gain on hedging activities		(5,203	)		—
Loss on debt extinguishment		—			548
Deferred income taxes		13,017			16,885
Proceeds from hedging activities		6,292			—
Changes in current assets and liabilities:
Accounts receivable		70,760			50,371
Inventories		(12,672	)		10,737
Prepaid energy supply costs		(723	)		22,801
Other current assets		(3,246	)		334
Accounts payable		(44,240	)		(32,572	)
Accrued expenses		(11,107	)		4,361
Regulatory assets and liabilities		18,609			(145	)
Other noncurrent assets		4,738			6,190
Other noncurrent liabilities		5,229			(6,079	)
Cash provided by continuing operating activities		96,433			132,965
INVESTING ACTIVITIES:
Restricted cash		(2,543	)		(3,599	)
Property, plant, and equipment additions		(45,335	)		(31,617	)
Proceeds from sale of assets		23,304			16
Proceeds from hedging activities		5,355			—
Purchases of investments		—			(118,800	)
Proceeds from sale of investments		—			119,720
Cash used in continuing investing activities		(19,219	)		(34,280	)
FINANCING ACTIVITIES:
Deferred gas storage		(11,718	)		(9,116	)
Proceeds from exercise of warrants		221			20
Dividends on common stock		(22,033	)		(15,671	)
Repayment of long-term debt		(173,795	)		(112,268	)
Line of credit borrowings (repayments), net		(38,000	)		74,750
Treasury stock activity		(3,730	)		(1,591	)
Issuance of long term debt		170,205			—
Financing costs		(5,746	)		(2,025	)
Equity registration fees		—			(140	)
Cash used in continuing financing activities		(84,596	)		(66,041	)
DISCONTINUED OPERATIONS:
Operating cash flows of discontinued operations, net		(3,431	)		524
Investing cash flows of discontinued operations, net		2,872			201
Financing cash flows of discontinued operations, net		—			—
(Increase) decrease in restricted cash held by discontinued operations		8,255			(753	)
Increase in Cash and Cash Equivalents		314			32,616
Cash and Cash Equivalents, beginning of period		2,691			17,058
Cash and Cash Equivalents, end of period	$	3,005		$	49,674

Supplemental Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	112		$	(374	)
Interest		22,662			26,413

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.

Sale of NorthWestern

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

The transaction is conditioned upon a number of federal and state regulatory approvals or reviews, and satisfaction of other customary closing conditions. In order to obtain the appropriate approvals, NorthWestern along with BBI submitted filings to the Montana Public Service Commission (MPSC), Nebraska Public Service Commission (NPSC), South Dakota Public Utilities Commission (SDPUC), and the Federal Energy Regulatory Commission (FERC). With respect to the NPSC, we have received a procedural schedule, which would allow for a decision approving the transaction by October 2006. We expect a decision from FERC prior to the end of the year. We have also received procedural schedules from the SDPUC and MPSC. The SDPUC expects to make a decision on whether or not it has jurisdiction to approve the sale in October 2006. A decision regarding approval from the MPSC is not expected until the second quarter of 2007. In addition, a voluntary notification filing under Exon-Florio was submitted to the Committee on Foreign Investments in the United States (CFIUS) and approved on July 31, 2006. We anticipate submitting the required filings with the United States Federal Trade Commission and the United States Department of Justice under the Hart-Scott-Rodino Antitrust Improvement Act of 1976 and the Federal Communications Commission within the next few months. The transaction is expected to be completed in 2007. Upon closing, NorthWestern’s common stock will cease to be publicly traded.

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

New Accounting Standards

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

(2) Variable Interest Entities

In December 2003, the FASB issued Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, or FIN 46R. FIN 46R was issued to replace FIN 46 and clarify the accounting for interests in variable interest entities. FIN 46R requires the consolidation of entities which are determined to be variable interest entities (VIEs) when the reporting company determines that it will absorb a majority of the VIE’s expected losses, receive a majority of the VIE’s residual returns, or both. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility, and while we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We will continue to make appropriate efforts to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. We continue to account for this qualifying facility contract as an executory contract. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $556.6 million through 2025, and are included in Contractual Obligations and Other Commitments of Management’s Discussion and Analysis.

(3) 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 June 30, 2006 and December 31, 2005, we have recognized accrued removal costs of $148.3 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 $13.1 million and $12.8 million as of June 30, 2006 and December 31, 2005, respectively.

In connection with the adoption of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), we have recorded a conditional asset retirement obligation of $3.4 million and $3.2 million, as of June 30, 2006 and December 31, 2005, respectively, which increases our property, plant and equipment and other noncurrent liabilities. This is primarily related to Department of Transportation requirements to cut, purge and cap

retired natural gas pipeline segments. The initial recording of the obligation had no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the ARO is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. The change in our conditional ARO during the six months ended June 30, 2006, is as follows (in thousands):

Liability at January 1, 2006	$	3,233
Accretion expense		127
Liabilities incurred		—
Liabilities settled		—
Revisions to cash flows		42
Liability at June 30, 2006	$	3,402

(4) Goodwill

There were no changes in our goodwill during the three and six months ended June 30, 2006. Goodwill by segment as of June 30, 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

(5) Other Comprehensive Income (Loss)

The FASB defines comprehensive income as all changes to the equity of a business enterprise during a period, except for those resulting from transactions with owners. For example, dividend distributions are 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 (loss) is calculated as follows (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Net income (loss)	$	(2,446	)	$	(3,931	)	$	18,579		$	14,987
Other comprehensive income (loss), net of tax:
Reclassification of net gains on hedging instruments from OCI to net income (loss)		(61	)		—			(3,885	)		—
Unrealized gain (loss) on derivative instruments qualifying as hedges, net of tax		4,819			(1,510	)		12,738			(1,510	)
Foreign currency translation		81			(20	)		79			(5	)
Comprehensive income (loss)	$	2,393		$	(5,461	)	$	27,511		$	13,472

(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 were designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income in our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive income (AOCI) into interest expense in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur. During the first quarter of 2006, based on a review of our capital structure and cash flow, and approval by our Board of Directors, we decided not to refinance $60 million included in the interest rate swap that was being carried on our revolver. As the refinancing transaction and associated interest payments will not occur, the market value included in AOCI of $3.8 million was recognized in Investment and Other Income. This forward starting interest rate swap was settled during the second quarter of 2006, and we received an aggregate payment of approximately $3.9 million, which is reflected in investing activities on the statement of cash flows. In association with the refinancing transaction completed during the second quarter of 2006, we settled $170.2 million of forward starting interest rate swap agreements, and received an aggregate settlement payment of approximately $6.3 million, which is being amortized as a reduction to interest expense over the term of the underlying debt, resulting in a reduction to the effective interest rate of 0.21%. The cash proceeds related to this hedge are reflected in operating activities on the statement of cash flows.

We had unrealized pre-tax gains of $13.1 million and $8.8 million at June 30, 2006 and December 31, 2005, respectively, remaining in other current assets and AOCI 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.

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 utilized unit-contingent forward sales to lock in the remaining output during the third and fourth quarters of 2006, and as a result we undesignated the put options as a hedge of the cash flow variability. During the first quarter of 2006 the put options were sold and we recognized a $1.3 million reduction to cost of sales, reflecting the change in market value since the loss of hedge effectiveness. These cash proceeds are reflected in investing activities on the statement of cash flows. The amount remaining in AOCI at June 30, 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.

(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
June 30, 2006		Electric		Gas			Electric			Gas		Other			Eliminations			Total
Operating revenues	$	151,007	$	57,688		$	13,707		$	17,522	$	78		$	(7,816	)	$	232,186
Cost of sales		71,478		35,565			3,049			15,055		38			(7,459	)		117,726
Gross margin		79,529		22,123			10,658			2,467		40			(357	)		114,460
Operating, general and administrative		33,381		15,287			10,533			450		9,351			(357	)		68,645
Property and other taxes		13,245		4,558			878			21		11			—			18,713
Depreciation		14,440		3,630			383			100		198			—			18,751
Total operating expenses		61,066		23,475			11,794			571		9,560			(357	)		106,109
Operating income (loss)		18,463		(1,352	)		(1,136	)		1,896		(9,520	)		—			8,351
Total assets	$	1,490,922	$	701,712		$	46,991		$	50,320	$	39,902		$	—		$	2,329,847
Capital expenditures	$	16,360	$	6,054		$	1,742		$	5	$	—		$	—		$	24,161

Three months ended		Regulated				Unregulated
June 30, 2005		Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	144,755	$	65,461	$	19,327	$	32,842	$	125		$	(13,123	)	$	249,387
Cost of sales		70,737		38,492		4,483		30,200		58			(12,786	)		131,184
Gross margin		74,018		26,969		14,844		2,642		67			(337	)		118,203
Operating, general and administrative		32,443		15,057		9,691		359		218			(337	)		57,431
Property and other taxes		12,291		4,287		819		25		—			—			17,422
Depreciation		14,319		3,934		261		101		259			—			18,874
Reorganization items		—		—		—		—		138			—			138
Total operating expenses		59,053		23,278		10,771		485		615			(337	)		93,865
Operating income (loss)		14,965		3,691		4,073		2,157		(548	)		—			24,338
Total assets	$	1,469,013	$	691,400	$	42,104	$	61,432	$	44,673		$	—		$	2,308,622
Capital expenditures	$	14,732	$	2,929	$	555	$	—	$	—		$	—		$	18,216

Six months ended		Regulated				Unregulated
June 30, 2006		Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	319,108	$	216,102	$	38,510	$	52,237	$	166		$	(32,455	)	$	593,668
Cost of sales		160,626		154,743		6,420		47,056		91			(31,538	)		337,398
Gross margin		158,482		61,359		32,090		5,181		75			(917	)		256,270
Operating, general and administrative		66,043		32,016		20,456		1,361		11,013			(917	)		129,972
Property and other taxes		26,732		9,586		1,800		45		15			—			38,178
Depreciation		28,963		7,302		705		201		409			—			37,580
Total operating expenses		121,738		48,904		22,961		1,607		11,437			(917	)		205,730
Operating income (loss)		36,744		12,455		9,129		3,574		(11,362	)		—			50,540
Total assets	$	1,490,922	$	701,712	$	46,991	$	50,320	$	39,902		$	—		$	2,329,847
Capital expenditures	$	34,031	$	8,636	$	2,663	$	5	$	—		$	—		$	45,335

Six months ended		Regulated				Unregulated
June 30, 2005		Electric		Gas		Electric		Gas		Other			Eliminations			Total
Operating revenues	$	299,117	$	204,065	$	40,781	$	83,185	$	351		$	(43,019	)	$	584,480
Cost of sales		140,803		136,906		7,871		77,967		241			(42,223	)		321,565
Gross margin		158,314		67,159		32,910		5,218		110			(796	)		262,915
Operating, general and administrative		62,515		30,163		19,167		1,198		1,839			(796	)		114,086
Property and other taxes		24,854		9,085		1,629		55		4			—			35,627
Depreciation		28,647		7,639		522		202		554			—			37,564
Reorganization items		—		—		—		—		3,501			—			3,501
Total Operating Expenses		116,016		46,887		21,318		1,455		5,898			(796	)		190,778
Operating income (loss)		42,298		20,272		11,592		3,763		(5,788	)		—			72,137
Total assets	$	1,469,013	$	691,400	$	42,104	$	61,432	$	44,673		$	—		$	2,308,622
Capital expenditures	$	25,786	$	4,762	$	1,069	$	—	$	—		$	—		$	31,617

(8) Reclassifications to Consolidated Statement of Cash Flows

The accompanying Consolidated Statement of Cash Flows for the six months ended June 30, 2005 includes reclassifications to reflect deferred gas storage arrangements as financing 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. 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:

	Six Months Ended June 30, 2006	Six Months Ended June 30, 2005
Basic computation	35,547,310	35,608,877
Dilutive effect of
Restricted shares	35,164	62,677
Stock warrants	1,156,109	172,031
Diluted computation	36,738,583	35,843,585

	Three Months Ended June 30, 2006	Three Months Ended June 30, 2005
Basic computation	35,510,760	35,606,762
Dilutive effect of
Restricted shares	—	62,677
Stock warrants	—	322,027
Diluted computation	35,510,760	35,991,466

There were 4,607,570 warrants outstanding as of June 30, 2006, which are dilutive for the three and six months ended June 30, 2006 and have been included in the earnings per share calculations. As of June 30, 2006 each warrant had an exercise price of $26.86 and could be exchanged for 1.06 shares of common stock. As of June 30, 2005, there were 4,619,059 warrants outstanding, which were dilutive for the six months ended June 30, 2005 and included in the earnings per share calculation. All the restricted shares and warrants were excluded from the diluted net income per share calculation for the three months ended June 30, 2006 due to the loss from continuing operations. 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 8,063 warrants were exercised during the six months ended June 30, 2006.

(10) Employee Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
	2006			2005			2006			2005
Components of Net Periodic Benefit Cost
Service cost	$	2,392		$	2,133		$	198		$	172
Interest cost		5,351			5,044			675			713
Expected return on plan assets		(5,642	)		(5,087	)		(274	)		(140	)
Amortization of prior service cost		61			—			—			—
Net Periodic Benefit Cost	$	2,162		$	2,090		$	599		$	745

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
	2006			2005			2006			2005
Components of Net Periodic Benefit Cost
Service cost	$	4,525		$	4,266		$	370		$	344
Interest cost		10,395			10,087			1,388			1,426
Expected return on plan assets		(10,729	)		(10,174	)		(415	)		(281	)
Amortization of prior service cost		121			—			—			—
Net Periodic Benefit Cost	$	4,312		$	4,179		$	1,343		$	1,489

(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 $19.5 million to $56.1 million. Our environmental reserve accrual is $34.5 million as of June 30, 2006. We anticipate that as environmental costs become fixed and determinable we will seek insurance coverage and/or authorization to recover these costs in rates, therefore we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

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.

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 of regulated pollutants in the groundwater. 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. In April 2006, we released escrowed amounts of $2.5 million and $7.5 million to the State of Montana and Atlantic Richfield, respectively, in accordance with the terms of the consent decree described below.

On July 18, 2005, CFB and we executed the Milltown Reservoir superfund site consent decree, which

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

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. 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. The Delaware District Court has jurisdiction over this lawsuit. Plaintiffs attempted to commence discovery in the QUIPS Litigation in January 2006. However, as a result of NorthWestern’s filing of a Motion for a Protective Order to limit the scope of discovery sought by plaintiffs, no discovery has commenced, and there has been no substantive activity in this case since February 2006.

On April 19, 2004, Magten also filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for alleged breaches of fiduciary duties by such officers in connection with the same transaction described above which is at issue in the QUIPS Litigation, namely the transfer of the transmission and distribution assets acquired from the Montana Power Company to NorthWestern. Those officers have requested CFB to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. That lawsuit was transferred to the Federal District Court in Delaware in July 2005 and is consolidated with the QUIPS Litigation for purposes of discovery and pre-trial matters. As with the QUIPS Litigation, discovery has not yet commenced in this action pending the District Court’s decision on NorthWestern’s Motion for a Protective Order to limit the scope of discovery, which was joined by the defendants in this action as well.

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, pending actions and appeals, including the QUIPS Litigation, in exchange for which Magten and Law Debenture would receive a distribution of new common stock and warrants from Class 8(b) in the same amounts as if they had voted to accept the Plan and a distribution of the reserve of new common stock which had been set aside for them in the Class 9 Disputed Claims Reserve pursuant to NorthWestern’s Plan, in the amount of approximately $17.4 million at “Plan Value.” Prior to seeking approval from the Bankruptcy Court, certain major shareholders and the Plan Committee objected to the settlement on both its economic terms and on the basis that the structure of the settlement violated the Plan. After reviewing the objections and undertaking our own analysis of the potential Plan violation, we informed Magten and Law Debenture as well as the Plan Committee and the objecting major shareholders that we would not proceed with the settlement. Magten and Law Debenture filed a motion with the 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 seeking to revoke the Confirmation Order on the grounds that it was procured by fraud as a result of the alleged failure to adequately fund the Class 9 Disputed Claims Reserve with enough shares of New Common Stock to satisfy a potential full recovery on all pending claims against NorthWestern’s bankruptcy estate which were outstanding at the time the Plan became Effective on November 1, 2004. The plaintiffs also alleged breach of fiduciary duty on the part of certain former and current officers in connection with the alleged under-funding of the Disputed Claims Reserve. NorthWestern filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of the Confirmation Order appeal. This action remains stayed in the Bankruptcy Court, pending a decision by the District Court on plaintiff’s appeal of the Confirmation Order.

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.

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

City of Livonia / Harbinger Litigation

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

The settlement does not confer a financial award to either party and NorthWestern will contest any request for reimbursement of legal fees or other expenses related to this case.

In February 2006, our directors and we 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 shareholder rights plan may not prevent plaintiff from seeking to build a coalition slate with other shareholders or circulate a referendum to shareholders. On March 20, 2006, Harbinger intervened in the City of Livonia action. During the second quarter of 2006, Harbinger voluntarily dismissed its intervention in the City of Livonia lawsuit and its action in the Delaware court.

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. The former employees have also amended their complaint to add claims against our bankruptcy lawyers. We are engaged in discovery and anticipate a trial sometime in the first half of 2007. We intend to vigorously defend against this lawsuit; however we cannot currently predict the ultimate impact of this litigation.

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

Relative to Colstrip Unit 4’s long-term coal supply contract with Western Energy Company (WECO), Mineral Management Service of the United States Department of Interior issued orders to WECO in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 and 4. The orders assert that additional royalties are owed as a result of WECO not paying royalties under a coal transportation agreement from 1991 through 2001. WECO has

appealed these orders and this matter is currently pending before the Interior Board of Land Appeals of the Department of Interior. In addition, the Montana Department of Revenue has asserted various tax and royalty demands, which are being appealed. We are monitoring the progression of these matters. WECO has asserted that any potential judgment would be considered a pass-through cost under the coal supply agreement. Based on our review, we do not believe any potential judgment would qualify as a pass-through cost under the terms of the coal supply agreement. Neither the outcome of these matters nor the associated costs can be predicted at this time.

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

Gain Contingency

On March 15, 2006, an arbitration panel concluded that we are entitled to receive payment of approximately $9.5 million from an insurance provider related to an insurance coverage dispute over a settlement that occurred in 2002. We signed a settlement agreement with the insurance provider and in July 2006 we received a payment of $3.1 million. Under the terms of our settlement agreement, we expect to collect an additional $6.3 million during August and September 2006. As of June 30, 2006, we have not recorded a receivable related to this settlement as our accounting policy related to settlement gains is to recognize the benefit in the period the cash is actually received. We expect to record this settlement as a reduction to operating, general and administrative expenses during the third quarter of 2006.

(12) Refinancing Transaction

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

(13) Subsequent Events

On July 5, 2006 we signed a seven-year power purchase agreement with PPL Montana (PPL) beginning July 1, 2007. Over the life of the agreement we will purchase 13.7 million megawatt hours at a cost of approximately $675 million. Our purchase obligation under this agreement is not conditioned upon approval by the MPSC, however we will, in a timely manner, seek review by the MPSC of the key commercial terms (price, term and quantity) set forth in the agreement.

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

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

OVERVIEW

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

Sale of NorthWestern

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

Although we believe that the expectation as to timing for the closing of the merger described above is reasonable, no assurances can be given as to the timing of the receipt of any required regulatory approvals or that all regulatory approvals will be received.

We have incurred and expect to continue to incur advisor and professional fees associated with the transaction. Our operating results for the three and six months ended June 30, 2006 were significantly affected by these transaction costs. This included a $4.3 million initial payment to our strategic advisor for services related to the transaction with BBI. Under the terms of the agreement with our strategic advisor we will be required to pay an additional $4.3 million upon shareholder approval of the proposed transaction and $8.6 million upon consummation of the proposed transaction. Our operating results are discussed in further detail below.

Other Highlights

On July 5, 2006 we signed a seven-year power purchase agreement with PPL Montana (PPL) beginning July 1, 2007. This agreement provides for us to initially purchase 325 megawatts to meet more than one-third of our near-term Montana default supply requirements. The megawatt hours purchased decline over the seven-year period, allowing us to methodically transition our Montana default supply electricity mix to more diverse resources. Over the life of the agreement NorthWestern will purchase 13.7 million megawatt hours at a cost of approximately $675 million. Our purchase obligation under this agreement is not conditioned upon approval by the MPSC, however we will, in a timely manner, seek review and by the MPSC on the key commercial terms (price, term and quantity) set forth in the agreement. The structure of this power purchase agreement provides us with flexibility to pursue other long-term electricity supply options and is consistent with our 2005 Electricity Default Supply Resource Plan that was filed with the MPSC in December 2005.

On May 23, 2006, the MPSC approved our 2005 (July 2004 through June 2005) annual natural gas cost tracker as filed, including the 2006 (July 2005 through June 2006) projected cost component to the extent actual costs were known at the time of the hearing.

We completed the liquidation of Netexit in May 2006, and NorthWestern received additional cash proceeds of approximately $7.7 million during the six months ended June 30, 2006. In addition, during the first quarter of 2006 we completed the sale of our Montana First Megawatts generation assets and received net additional proceeds of $17.2 million.

In May 2006 we completed the refinancing of our Montana Pollution Control Obligations, reducing our annual interest expense by approximately $2.4 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.

We have also made progress in settling certain of our outstanding litigation claims. We reached a memorandum of understanding during the second quarter of 2006 to settle the City of Livonia Employees’ Retirement System putative shareholder class action and derivative lawsuit filed November 2005, with no financial award to either party. In June 2006, we signed a settlement agreement with the shareholder plaintiffs in the McGreevey lawsuit. In the event the agreement is approved, the claims against us in the McGreevey lawsuits will be dismissed. For further information see the legal proceedings section of Note 11 to the consolidated financial statements.

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 and six month periods ended June 30, 2006 and 2005. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment.

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

	Three Months Ended June 30,
			2006				2005				Change			% Change
	(in millions)
Operating Revenues
Regulated Electric		$		151.0		$		144.7		$		6.3			4.4		%
Regulated Natural Gas				57.7				65.5				(7.8	)		(11.9	)
Unregulated Electric				13.7				19.3				(5.6	)		(29.0	)
Unregulated Natural Gas				17.5				32.8				(15.3	)		(46.6	)
Other				0.1				0.1				—			—
Eliminations				(7.8	)			(13.0	)			5.2			(40.0	)
		$		232.2		$		249.4		$		(17.2	)		(6.9	)	%

		Three Months Ended June 30,
				2006				2005				Change			% Change
		(in millions)
	Cost of Sales
Regulated Electric			$		71.5		$		70.7		$		0.8			1.1		%
Regulated Natural Gas					35.6				38.5				(2.9	)		(7.5	)
Unregulated Electric					3.0				4.5				(1.5	)		(33.3	)
Unregulated Natural Gas					15.0				30.2				(15.2	)		(50.3	)
Other					0.1				0.1				—			—
Eliminations					(7.5	)			(12.8	)			5.3			41.4
			$		117.7		$		131.2		$		(13.5	)		(10.3	)	%

		Three Months Ended June 30,
				2006						2005						Change					% Change
		(in millions)
Gross Margin
Regulated Electric			$			79.5			$			74.0			$			5.5					7.4				%
Regulated Natural Gas						22.1						27.0						(4.9		)			(18.1		)
Unregulated Electric						10.7						14.8						(4.1		)			(27.7		)
Unregulated Natural Gas						2.5						2.6						(0.1		)			(3.8		)
Other						—						—						—					—				%
	Eliminations						(0.3	)					(0.2	)					(0.1			)		(50.0		)
					$		114.5				$		118.2				$		(3.7			)		(3.1		)		%

Consolidated gross margin for the three months ended June 30, 2006 was $114.5 million, a decrease of $3.7 million, or 3.1%, from gross margin of $118.2 million in 2005. Margin in our regulated electric segment increased

$5.5 million primarily due to higher transmission revenue. The decrease in regulated natural gas margin from 2005 is primarily due to the inclusion in margin in the second quarter of 2005 of a $4.6 million recovery of supply costs that were previously disallowed by the MPSC. Unregulated electric margin decreased $4.1 million primarily due to strong hydro generation during the second quarter of 2006 that increased supply in the wholesale electricity market, resulting in reduced demand for our Colstrip Unit 4 power.

Margin as a percentage of revenues increased to 49.3% for 2006, from 47.4% 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 June 30,
			2006			2005			Change			% Change
	(in millions)
Operating Expenses
Operating, general and administrative		$		68.6	$		57.4	$		11.2			19.5		%
Property and other taxes				18.7			17.4			1.3			7.5
Depreciation				18.8			18.9			(0.1	)		(0.5	)
Reorganization items				—			0.1			(0.1	)		(100.0	)
		$		106.1	$		93.8	$		12.3			13.1		%

Consolidated operating, general and administrative expenses were $68.6 million for the three months ended June 30, 2006 as compared to $57.4 million in 2005. This increase was primarily due to approximately $8.0 million in transaction related costs pursuant to the proposed BBI acquisition. While an acquiring entity typically capitalizes its acquisition related costs, those incurred by an acquiree are expensed as incurred. These costs during the second quarter of 2006 included a $4.3 million payment to our strategic advisor for rendering an opinion on the proposed transaction with BBI. Under the terms of the agreement with our strategic advisor we will be required to pay an additional $4.3 million upon shareholder approval of the proposed transaction and $8.6 million upon consummation of the proposed transaction. Since these additional payments are contingent on future events occurring, they will be expensed in the periods the contingencies are resolved. Additional increases to 2006 operating, general and administrative expenses consisted of $1.9 million in higher professional fees primarily associated with addressing outstanding shareholder litigation and a $1.0 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 $18.7 million for the three months ended June 30, 2006 as compared to $17.4 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 June 30, 2006 as compared to $18.9 million in 2005.

Consolidated operating income for the three months ended June 30, 2006 was $8.4 million, as compared to $24.3 million in 2005. This $15.9 million decrease was primarily due to lower margins and increased expenses discussed above.

Consolidated interest expense for the three months ended June 30, 2006 was $14.6 million, a decrease of $1.2 million, or 7.6%, from 2005. This decrease was primarily attributable to a $94 million decrease in debt in 2005. We anticipate additional reductions in interest expense during the remainder of 2006 due to our debt reduction efforts and lower rates as a result of refinancing transactions. See “Liquidity and Capital Resources” for additional information regarding our refinancing activities.

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

Consolidated investment and other income for the three months ended June 30, 2006 was $3.1 million, an increase of $1.5 million from 2005. This increase was primarily due to a $2.3 million gain on the sale of a partnership interest in oil and gas properties in May 2006. We have no further interests in oil and gas properties.

Consolidated income tax benefit for the three months ended June 30, 2006 was $0.3 million as compared to a provision of $3.2 million in 2005. Portions of our acquisition related fees are non-deductible for taxes, which will increase our effective tax rate in 2006. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

Income from discontinued operations for the three months ended June 30, 2006 was $0.4 million compared to a loss of $10.3 million for the same period in 2005. The income in 2006 related to the final liquidation of Netexit, while the 2005 loss primarily related to a settlement reached with securities class action claimants in Netexit’s bankruptcy proceedings.

Consolidated net loss for the three months ended June 30, 2006 was $2.4 million, compared to a loss of $3.9 million for the same period in 2005. This improvement was primarily related to the change in discontinued operations, higher investment and other income and a decrease in interest expense and income taxes. Increased operating expenses and decreased margins partially offset this improvement.

Six Months Ended June 30, 2006 Compared to the Six Months Ended June 30, 2005

		Six Months Ended June 30,
				2006				2005				Change			% Change
		(in millions)
Operating Revenues
	Regulated Electric		$		319.1		$		299.1		$		20.0			6.7		%
	Regulated Natural Gas				216.1				204.1				12.0			5.9
	Unregulated Electric				38.5				40.8				(2.3	)		(5.6	)
	Unregulated Natural Gas				52.2				83.2				(31.0	)		(37.3	)
	Other				0.2				0.3				(0.1	)		(33.3	)
	Eliminations				(32.4	)			(43.0	)			10.6			24.7
			$		593.7		$		584.5		$		9.2			1.6		%

	Six Months Ended June 30,
			2006			2005				Change			% Change
			(in millions)
Cost of Sales
Regulated Electric		$		160.6		$	140.8		$		19.8			14.1		%
Regulated Natural Gas				154.7			136.9				17.8			13.0
Unregulated Electric				6.4			7.9				(1.5	)		(19.0	)
Unregulated Natural Gas				47.0			78.0				(31.0	)		(39.7	)
Other				0.1			0.2				(0.1	)		(50.0	)
Eliminations				(31.4	)		(42.2	)			10.8			25.6
		$		337.4		$	321.6		$		15.8			4.9		%

		Six Months Ended June 30,
							2006					2005					Change				% Change
			(in millions)
Gross Margin
Regulated Electric				$		158.5			$		158.3			$		0.2				0.1				%
Regulated Natural Gas						61.4					67.2					(5.8		)		(8.6		)
Unregulated Electric						32.1					32.9					(0.8		)		(2.4		)
Unregulated Natural Gas						5.2					5.2					—				—
Other						0.1					0.1					—				—
	Eliminations						(1.0	)				(0.8	)				(0.2		)		(25.0		)
					$		256.3			$		262.9			$		(6.6		)		(2.5		)		%

Consolidated gross margin for the six months ended June 30, 2006 was $256.3 million, a decrease of $6.6 million, or 2.5%, from gross margin of $262.9 million in 2005. The decrease in regulated natural gas margin is primarily due to the inclusion of a $4.6 million recovery of supply costs during the second quarter of 2005 that were previously disallowed by the MPSC. The regulated electric gross margin increase in 2006 was primarily due to increased transmission revenues and retail volumes offset by the items discussed below. During March 2006 we signed a stipulation with the Montana Consumer Counsel to settle various issues raised relative to our 2005 and 2006 electric tracker filings. As a result of this stipulation we are responsible for replacement costs related to certain forward sales contracts for periods after July 1, 2005. These forward sales extend through 2007. We recognized a loss in cost of sales of $1.4 million during the first quarter of 2006 related to the removal of replacement costs from our electric tracker for these sales contracts between July 1, 2005 and March 31, 2006. Additionally, regulated electric cost of sales includes a $2.7 million loss based on the market value of the remaining forward sales through 2007. Regulated electric results for the six months ended June 30, 2005 also included a $4.9 million gain related to a QF contract amendment.

Margin as a percentage of revenues decreased to 43.2% for 2006, from 45.0% 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.

	Six Months Ended June 30,
			2006			2005			Change			% Change
			(in millions)
Operating Expenses
Operating, general and administrative		$		130.0	$		114.1	$		15.9			13.9		%
Property and other taxes				38.2			35.6			2.6			7.3
Depreciation				37.6			37.6			—			—
Reorganization items				—			3.5			(3.5	)		(100.0	)
		$		205.8	$		190.8	$		15.0			7.9		%

Consolidated operating, general and administrative expenses were $130.0 million for the six months ended June 30, 2006 as compared to $114.1 million in 2005. The $15.9 million increase was primarily due to approximately $8.5 million in transaction related costs pursuant to the proposed BBI acquisition, approximately $1.3 million in higher professional fees associated with assessing our strategic alternatives and addressing outstanding litigation, approximately $3.4 million in increased operating costs primarily due to increased line clearance, maintenance and fuel costs, as well as a $2.7 million increase in our allowance for uncollectible accounts due to increases in past due customer account balances.

Property and other taxes were $38.2 million for the six months ended June 30, 2006 as compared to $35.6 million in 2005. This increase was primarily due to a higher valuation assessment and increased mill levies in our Montana service territory.

Depreciation expense remained flat for the six months ended June 30, 2006 as compared to 2005.

Reorganization items in 2005 of $3.5 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 six months ended June 30, 2006 was $50.5 million, as compared to $72.1 million in 2005. This $21.6 million decrease was primarily due to lower margins and increased expenses discussed above.

Consolidated interest expense for the six months ended June 30, 2006 was $29.1 million, a decrease of $3.0 million, or 9.3%, from 2005. This decrease was primarily attributable to a $94 million decrease in debt in 2005. We anticipate additional reductions in interest expense during the remainder of 2006 due to our debt reduction efforts and lower rates as a result of refinancing transactions. See “Liquidity and Capital Resources” for additional information regarding our refinancing activities.

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

Consolidated investment and other income for the six months ended June 30, 2006 was $8.4 million, an increase of $6.2 million from 2005. This increase was primarily due to a $3.9 million gain related to an interest rate swap and a $2.3 million gain on the sale of a partnership interest in oil and gas properties.

Consolidated provision for income taxes for the six months ended June 30, 2006 was $11.7 million as compared to $16.9 million in 2005. Our effective tax rate for 2006 was 39.3% as compared to 40.5% for 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.

Income from discontinued operations for the six months ended June 30, 2006 was $0.4 million compared to a loss of $9.8 million for the same period in 2005. The income in 2006 related to the final liquidation of Netexit, while the 2005 loss primarily related to a settlement reached with securities class action claimants in Netexit’s bankruptcy proceedings.

Consolidated net income for the six months ended June 30, 2006 was $18.6 million, an increase of $3.6 million, or 24.0%, over $15.0 million in 2005. This improvement was primarily related to the change in discontinued operations, higher investment and other income and a decrease in interest expense and income taxes. Increased operating expenses and decreased margins partially offset this improvement.

REGULATED ELECTRIC SEGMENT

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

			Results
			2006				2005				Change			% Change
			(in millions)
	Electric supply revenue	$		67.4		$		66.5		$		0.9			1.4		%
	Transmission & distribution revenue			66.6				65.8				0.8			1.2
	Rate schedule revenue			134.0				132.3				1.7			1.3
	Transmission			13.6				9.4				4.2			44.7
	Wholesale			1.4				1.5				(0.1	)		(6.7	)
	Miscellaneous			2.0				1.5				0.5			33.3
	Total Revenues			151.0				144.7				6.3			4.4		%
	Supply costs			66.7				65.6				1.1			1.7
	Wholesale			0.6				0.5				0.1			20.0
	Other cost of sales			4.2				4.6				(0.4	)		(8.7	)
	Total Cost of Sales			71.5				70.7				0.8			1.1		%
	Gross Margin	$		79.5		$		74.0		$		5.5			7.4		%
% GM/Rev			52.6		%		51.1		%

	Volumes MWH
	2006		2005		Change			% Change
	(in thousands)
Retail Electric
Residential		556		549		7			1.3		%
Commercial		931		895		36			4.0
Industrial		746		726		20			2.8
Other		52		41		11			26.8
Total Retail Electric		2,285		2,211		74			3.3		%
Wholesale Electric		42		43		(1	)		(2.3	)	%

Average Customer Counts		2006		2005		Change		% Change
	Montana		319,744		313,508		6,236		2.0	%
	South Dakota		58,901		58,504		397		0.7	%
	Total		378,645		372,012		6,633		1.8	%

	2006 as compared to:
Cooling Degree-Days	2005	Historic Average
Montana	182% warmer	44% warmer
South Dakota	30% warmer	40% warmer

Rate Schedule Revenue

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

Electric rate schedule revenue for the three months ended June 30, 2006 increased $1.7 million, or 1.3% over results in 2005, primarily due to 3.3% higher volumes.

Transmission Revenue

Transmission revenue consists of revenue earned for transmitting energy across our lines for customers who select other suppliers and for off-system, or open access, customers. Transmission revenues in Montana can fluctuate substantially from year to year based on market conditions in surrounding states. For example, during the second quarter of 2006 the Pacific Northwest experienced strong hydro generation, which resulted in increased electric supply at significantly lower prices than states to our south. Since Pacific Northwest energy prices were substantially lower than in these states, suppliers realized more profit by transmitting electricity across our lines. We refer to these differences as price differentials, which are the primary reason for the $4.2 million, or 44.7%, increase in transmission revenue.

Gross Margin

Gross margin for the three months ended June 30, 2006 increased $5.5 million, or 7.4% as compared to the second quarter 2005 primarily due to the $4.2 million increase in transmission revenue.

Margin as a percentage of revenues increased to 52.6% for 2006, from 51.1% 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 June 30, 2006 totaled 2,284,546 MWHs, which increased 3.3% as compared with 2,210,579 MWHs in the same period in 2005 due to a combination of customer growth and warmer weather. Regulated wholesale electric volumes in the second quarter of 2006 were 42,426 MWHs, a slight decrease from 42,860 MWHs in the same period in 2005.

Six Months Ended June 30, 2006 Compared to the Six Months Ended June 30, 2005

			Results
			2006				2005					Change			% Change
			(in millions)
	Electric supply revenue	$			148.5		$		136.3		$		12.2			9.0		%
	Transmission & distribution revenue				138.4				136.7				1.7			1.2
	Rate schedule revenue				286.9				273.0				13.9			5.1
	Transmission				23.8				18.5				5.3			28.6
	Wholesale				4.4				4.1				0.3			7.3
	Miscellaneous				4.0				3.5				0.5			14.3
	Total Revenues				319.1				299.1				20.0			6.7		%
	Supply costs				151.1				130.2				20.9			16.1
	Wholesale				1.6				1.4				0.2			14.3
	Other cost of sales				7.9				9.2				(1.3	)		(14.1	)
	Total Cost of Sales				160.6				140.8				19.8			14.1		%
	Gross Margin	$			158.5		$		158.3		$		0.2			0.1		%
% GM/Rev				49.7		%		52.9		%

	Volumes MWH
	2006		2005		Change			% Change
	(in thousands)
Retail Electric
Residential		1,289		1,277		12			0.9		%
Commercial		1,867		1,836		31			1.7
Industrial		1,514		1,481		33			2.2
Other		76		65		11			16.9
Total Retail Electric		4,746		4,659		87			1.9		%
Wholesale Electric		112		113		(1	)		(0.9	)	%

Average Customer Counts		2006		2005		Change		% Change
	Montana		318,894		312,751		6,143		2.0	%
	South Dakota		58,759		58,398		361		0.6	%
	Total		377,653		371,149		6,504		1.8	%

	2006 as compared to:
Cooling Degree-Days	2005	Historic Average
Montana	182% warmer	44% warmer
South Dakota	30% warmer	40% warmer

Rate Schedule Revenue

Electric rate schedule revenue for the six months ended June 30, 2006 increased $13.9 million, or 5.1% over results in 2005. Electric supply revenue, which consists of supply costs that are collected in rates from customers, increased $12.2 million primarily from 7.2% higher average prices. Transmission and distribution revenue increased $1.7 million primarily due to a 1.9% increase in volumes.

Transmission Revenue

As discussed above, the Pacific Northwest experienced strong hydro generation during the second quarter of 2006, creating significant price differentials and a $5.3 million, or 28.6%, increase in transmission revenue as compared to the six months ended June 30, 2005.

Wholesale Revenue

Wholesale revenue is derived from our joint ownership in generation facilities. Excess power not used by our South Dakota customers is sold in the wholesale market. These revenues increased $0.3 million primarily due to higher average prices. During the second quarter of 2006 we received less power from our interest in the Big Stone plant than we originally anticipated due to coal delivery issues. We believe the coal delivery issues have been resolved and expect the Big Stone plant to operate near capacity for the remainder of 2006.

Gross Margin

Gross margin for the six months ended June 30, 2006 increased $0.2 million, or 0.1% as compared to the same period in 2005. The gross margin increase in 2006 was primarily due to the increased transmission revenues and retail volumes offset by the items discussed below. During March 2006 we signed a stipulation with the Montana Consumer Counsel to settle various issues they raised relative to our 2005 and 2006 electric tracker filings. As a result of this stipulation we are responsible for replacement costs related to certain forward sales contracts for periods after July 1, 2005. These forward sales extend through 2007. We recognized a loss in cost of sales of $1.4 million during the first quarter of 2006 related to the removal of replacement costs from our electric tracker for these sales contracts between July 1, 2005 and March 31, 2006. Additionally, cost of sales includes a $2.7 million loss based on the market value of the remaining forward sales through 2007. Results for the six months ended June 30, 2005 also included a $4.9 million gain related to a QF contract amendment.

Margin as a percentage of revenues decreased to 49.7% for 2006, from 52.9% 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 six months ended June 30, 2006 totaled 4,745,751 MWHs, which increased 1.9% as compared with 4,659,267 MWHs in the same period in 2005 due primarily to a 1.8% increase in customer growth and warmer weather. Regulated wholesale electric volumes in the second quarter of 2006 were 112,298 MWHs, a slight decrease from 113,413 MWHs in the same period in 2005.

REGULATED NATURAL GAS SEGMENT

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

			Results
			2006				2005				Change			% Change
			(in millions)
Gas supply revenue	$	34.7			$	35.7			$	(1.0		)	(2.8		)	%
Transportation, distribution & storage revenue		16.9				17.7				(0.8		)	(4.5		)
Rate schedule revenue		51.6				53.4				(1.8		)	(3.4		)
Transportation & storage		4.6				4.3				0.3			7.0
Wholesale revenue		0.3				6.8				(6.5		)	(95.6		)
Miscellaneous		1.2				1.0				0.2			20.0
Total Revenues		57.7				65.5				(7.8		)	(11.9		)	%
Supply costs		34.8				31.0				3.8			12.3
Wholesale supply costs		0.3				6.8				(6.5		)	(95.6		)
Other cost of sales		0.5				0.7				(0.2		)	(28.6		)
Total Cost of Sales		35.6				38.5				(2.9		)	(7.5)			%
Gross Margin	$	22.1			$	27.0			$	(4.9		)	(18.1		)	%
% GM/Rev		38.3		%		41.2		%

		Volumes MMbtu
		2006		2005		Change			% Change
		(in thousands)
Retail Gas
	Residential		2,703		3,002		(299	)		(10.0	)	%
	Commercial		1,815		1,783		32			1.8
	Industrial		19		21		(2	)		(9.5	)
	Other		22		25		(3	)		(12.0	)
	Total Retail Gas		4,559		4,831		(272	)		(5.6	)	%

Average Customer Counts		2006		2005		Change		% Change
	Montana		170,822		166,989		3,833		2.3	%
	South Dakota		82,185		81,831		354		0.4
	Total		253,007		248,820		4,187		1.7	%

	2006 as compared to:
Heating Degree-Days	2005	Historic Average
Montana	21% warmer	17% warmer
South Dakota	7% warmer	14% warmer
Nebraska	9% warmer	14% 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 June 30, 2006 decreased $1.8 million, or 3.4% over results in 2005. Gas supply revenues, which consist of supply costs that are collected in rates from customers, decreased $1.0 million, due to the recovery of $4.6 million of supply costs in the second quarter of 2005 previously disallowed by the MPSC, and a decrease in volumes of 5.6% due to warmer weather, partially offset by an increase in average rates.

Transportation & Storage Revenue

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

Wholesale Revenue

Wholesale revenue decreased $6.5 million, or 95.6%, 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 June 30, 2006 decreased $4.9 million, or 18.1% over the second quarter 2005, primarily because the second quarter of 2005 included the recognition of $4.6 million for recovery of supply costs previously disallowed by the MPSC.

Margin as a percentage of revenue decreased to 38.3% for 2006, from 41.2% 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 4,559,407 MMbtu (million British Thermal Units) during the three months ended June 30, 2006, a 5.6 % decline from 4,830,827 MMbtu for the same period in 2005. This decline was due primarily to warmer weather in all regulated markets.

Six Months Ended June 30, 2006 Compared to the Six Months Ended June 30, 2005

			Results
			2006				2005				Change			% Change
			(in millions)
	Gas supply revenue	$		147.1		$		123.0		$		24.1			19.6		%
	Transportation, distribution & storage revenue			51.0				53.3				(2.3	)		(4.3	)
	Rate schedule revenue			198.1				176.3				21.8			12.4
	Transportation & storage			9.0				8.6				0.4			4.7
	Wholesale revenue			5.9				16.9				(11.0	)		(65.1	)
	Miscellaneous			3.1				2.3				0.8			34.8
	Total Revenues			216.1				204.1				12.0			5.9		%
	Supply costs			147.3				118.6				28.7			24.2
	Wholesale supply costs			5.9				16.9				(11.0	)		(65.1	)
	Other cost of sales			1.5				1.4				0.1			7.1
	Total Cost of Sales			154.7				136.9				17.8			13.0		%
	Gross Margin	$		61.4		$		67.2		$		(5.8	)		(8.6	)	%
% GM/Rev			28.4		%		32.9		%

		Volumes MMbtu
		2006		2005		Change			% Change
		(in thousands)
Retail Gas
	Residential		9,969		11,089		(1,120	)		(10.1	)	%
	Commercial		6,238		6,496		(258	)		(4.0	)
	Industrial		97		105		(8	)		(7.6	)
	Other		85		80		5			6.3
	Total Retail Gas		16,389		17,770		(1,381	)		(7.8	)	%

Average Customer Counts		2006		2005		Change		% Change
	Montana		170,768		166,936		3,832		2.3	%
	South Dakota		82,726		82,342		384		0.5
	Total		253,494		249,278		4,216		1.7	%

	2006 as compared to:
Heating Degree-Days	2005	Historic Average
Montana	10% warmer	10% warmer
South Dakota	9% warmer	17% warmer
Nebraska	11% warmer	19% warmer

Rate Schedule Revenue

Gas rate schedule revenue for the six months ended June 30, 2006 increased $21.8 million, or 12.4% over results in 2005. Gas supply revenues, which consist of supply costs that are collected in rates from customers, increased $36.5 million due to 29.7% higher average rates, partially offset by a $12.4 million, or 7.8% weather related decrease in volumes. The volume decrease also caused the $2.3 million decrease in transportation, distribution and storage revenue. In addition, 2005 revenues included the recovery of $4.6 million of supply costs previously disallowed by the MPSC.

Transportation & Storage Revenue

Transportation and storage revenue increased $0.4 million for the six months ended June 30, 2006 as compared to the same period 2005.

Wholesale Revenue

Wholesale revenue decreased $11.0 million, or 65.1%, 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 six months ended June 30, 2006 decreased $5.8 million, or 8.6% over the same period in 2005 primarily due to warmer weather and the recovery of $4.6 million of supply costs reflected in the 2005 margin, which were previously disallowed by the MPSC.

Margin as a percentage of revenue decreased to 28.4% for 2006, from 32.9% 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 16,388,651 MMbtu (million British Thermal Units) during the six months ended June 30, 2006, a 7.8 % decline from 17,770,167 MMbtu for the same period in 2005. This decline was due primarily to warmer weather in all regulated markets.

UNREGULATED ELECTRIC SEGMENT

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

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

			Results
					2006				2005				Change			% Change
			(in millions)
Total Revenues		$		13.7			$	19.3			$	(5.6		)	(29.0		)	%
Supply costs				2.3				3.9				(1.6		)	(41.0		)
Wheeling costs				0.7				0.6				0.1			16.7
Total Cost of Sales		$		3.0			$	4.5			$	(1.5		)	(33.3		)	%
Gross Margin		$		10.7			$	14.8			$	(4.1		)	(27.7		)	%
	% GM/Rev				78.1	%			76.7	%

Volumes MWH

2006

2005

Change

% Change

(in thousands)

Wholesale Electric

241

456

(215

)

(47.1

)

Revenue

Unregulated electric revenue decreased $5.6 million, or 29.0%, for the three months ended June 30, 2006 primarily due to $7.9 million, or 47.1% lower volumes partially offset by $2.1 million, or 24.7%, higher average prices. The strong hydro generation in the Pacific Northwest during the second quarter of 2006 provided increased supply in the wholesale electricity market, resulting in reduced demand for our Colstrip power. In addition, we had less energy available to sell due to scheduled maintenance in 2006.

Gross Margin

Gross margin decreased $4.1 million, or 27.7%, primarily due to lower volumes related to the strong hydro generation discussed above.

Volumes

Unregulated electric volumes were 241,113 MWHs in the second quarter of 2006, compared with 455,661 MWHs in the same period in 2005. This decrease was primarily due to reduced demand resulting from strong hydro generation in the Pacific Northwest.

Six Months Ended June 30, 2006 Compared to the Six Months Ended June 30, 2005

		Results
				2006				2005				Change			% Change
		(in millions)
	Total Revenues		$		38.5		$		40.8		$		(2.3	)		(5.6	)	%
	Supply costs				4.8				6.6				(1.8	)		(27.3	)
	Wheeling costs				1.6				1.3				0.3			23.1
	Total Cost of Sales		$		6.4		$		7.9		$		(1.5	)		(19.0	)	%
	Gross Margin		$		32.1		$		32.9		$		(0.8	)		(2.4	)	%
% GM/Rev				83.4		%		80.6		%

Volumes MWH

2006

2005

Change

% Change

(in thousands)

Wholesale Electric

662

901

(239

)

(26.5

)

Revenue

Unregulated electric revenue decreased $2.3 million, or 5.6%, for the six months ended June 30, 2006 primarily due to $9.4 million, or 26.5% lower volumes partially offset by $6.8 million, or 25.3%, higher average prices. The lower volumes in 2006 were primarily due to reduced demand as discussed above along with decreased plant availability.

Gross Margin

Gross margin decreased $0.8 million, or 2.4%, primarily due to lower volumes partially offset by higher average prices and a $1.3 million reduction to cost of sales related to the settlement of put options.

Volumes

Unregulated electric volumes were 662,318 MWHs for the six months ended June 30, 2006, compared with 901,243 MWHs in the same period in 2005. The lower volumes in 2006 were due to reduced demand as discussed above.

UNREGULATED NATURAL GAS SEGMENT

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

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

Results

2006

2005

Change

% Change

(in millions)

Total Revenue

17.5

32.8

(15.3

)

(46.6

)

Supply costs

15.0

30.2

(15.2

)

(50.3

)

Gross Margin

2.5

2.6

(0.1

)

(3.8

)

% GM/Rev

14.3

7.9

Volumes MMbtu

2006

2005

Change

% Change

(in thousands)

Wholesale Gas

4,122

4,311

(189

)

(4.4

)

Revenue

Unregulated natural gas revenue decreased $15.3 million, or 46.6%, due primarily to certain customers contracting directly with other providers for their commodity supply needs. We have continued to encourage certain customers to choose other commodity suppliers as we receive little to no margin on commodity costs.

Gross Margin

Gross margin remained almost flat for the second quarter 2006 as compared to the same period 2005.

Volumes

Unregulated wholesale natural gas volumes delivered totaled 4,122,328 MMbtu in 2006, compared with 4,310,669 MMbtu in 2005. This decrease was due primarily to unplanned outages at various ethanol facilities in South Dakota and the transfer of certain customers to our regulated gas segment.

Six Months Ended June 30, 2006 Compared to the Six Months Ended June 30, 2005

Results

2006

2005

Change

% Change

(in millions)

Total Revenue

52.2

83.2

(31.0

)

(37.3

)

Supply costs

47.0

78.0

(31.0

)

(39.7

)

Gross Margin

5.2

% GM/Rev

10.0

6.2

Volumes MMbtu

2006

2005

Change

% Change

(in thousands)

Wholesale Gas

9,662

11,313

(1,651

)

(14.6

)

Revenue

Unregulated natural gas revenue decreased $31.0 million, or 37.3%, due primarily to certain customers contracting directly with other providers for their commodity supply needs. We have continued to encourage certain customers to choose other commodity suppliers as we receive little to no margin on commodity costs.

Gross Margin

Gross margin remained flat for the six months ended June 30, 2006 as compared to the same period 2005.

Volumes

Unregulated wholesale natural gas volumes delivered totaled 9,661,502 MMbtu in 2006, compared with 11,313,053 MMbtu in 2005. This decrease was due primarily to unplanned outages at various ethanol facilities in South Dakota and the transfer of certain customers to our regulated gas segment.

LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2006, we had cash and cash equivalents of $3.0 million, and revolver availability of $141.4 million. During the six months ended June 30, 2006, we used existing cash to repay $41.6 million of debt, including repayments of $38.0 million on our revolver. In addition to these repayments we paid dividends on common stock of $22.0 million, property tax payments of approximately $35 million, and our semi-annual Colstrip Unit 4 operating lease payment of approximately $16.1 million. During the six months ended June 30, 2006, we also received net proceeds of $17.2 million from the sale of our Montana First Megawatts generation assets, and $7.7 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. As of June 30, 2006, we are over collected on our current Montana natural gas and electric trackers by approximately $0.5 million.

Cash Flows

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

		Six Months Ended June 30,
		2006			2005
Continuing Operating Activities
Net income	$	18.6		$	15.0
Non-cash adjustments to net income		44.2			61.9
Proceeds from hedging activities		6.3			—
Changes in working capital		17.3			55.9
Other		10.0			0.1
		96.4			132.9
Continuing Investing Activities
Property, plant and equipment additions		(45.3	)		(31.6	)
Restricted cash		(2.5	)		(3.6	)
Sale of assets		23.3			—
Proceeds from hedging activities		5.3			—
Net proceeds from (purchases) sales of investments		—			0.9
		(19.2	)		(34.3	)
Continuing Financing Activities
Net repayment of debt		(41.6	)		(37.5	)
Dividends on common stock		(22.0	)		(15.7	)
Deferred gas storage		(11.7	)		(9.1	)
Other		(9.3	)		(3.7	)
		(84.6	)		(66.0	)
Discontinued Operations		7.7			—
Net Increase in Cash and Cash Equivalents	$	0.3		$	32.6
Cash and Cash Equivalents, beginning of period	$	2.7		$	17.1
Cash and Cash Equivalents, end of period	$	3.0		$	49.7

Cash Provided By Continuing Operating Activities

As of June 30, 2006, cash and cash equivalents were $3.0 million, compared with $2.7 million at December 31, 2005, and $49.7 million at June 30, 2005. Cash provided by continuing operating activities totaled $96.4 million during the six months ended June 30, 2006, compared to $132.9 million during the six months ended June 30, 2005. This decrease in operating cash flows is primarily related to increases in gas injections into inventory earlier in the season, and higher energy payables due to higher market prices during the heating season, offset by significant collections of supply costs from customers in 2006 through the trackers discussed above. In addition, operating cash flows in the six months ended June 30, 2005 were positively impacted 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 $19.2 million during the six months ended June 30, 2006 compared to $34.3 million during the six months ended June 30, 2005. During the six months ended June 30, 2006 we received cash proceeds of $23.3 million from the sale of assets and $5.3 million from the settlement of hedges, offset by cash used of approximately $45.3 million for property, plant and equipment additions. During the six months ended June 30, 2005, we used approximately $31.6 million for property, plant and equipment additions.

Cash Used In Continuing Financing Activities

Cash used in financing activities of continuing operations totaled $84.6 million during the six months ended June 30, 2006 compared to $66.0 million during the six months ended June 30, 2005. During the second quarter of 2006 we have made debt repayments of $41.6 million, paid dividends on common stock of $22.0 million, and paid $11.7 million for deferred storage transactions. Cash used to repurchase shares during the six months ended June 30, 2006

was approximately $3.7 million. In addition, in association with our pollution control obligation refinancing transaction completed during the second quarter of 2006, we capitalized $5.7 million of financing costs. During the six months ended June 30, 2005 we made debt repayments of $37.5 million and paid dividends on common stock of $15.7 million.

Discontinued Operations Cash Flows

The decrease in restricted cash held by discontinued operations during the six months ended June 30, 2006 was due to Netexit’s $7.7 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 and estimated future capital expenditures during the next twelve months. As of June 30, 2006, our revolver availability was approximately $141.4 million.

During the third quarter of 2006, we anticipate refinancing our $150 million, 7.30% first mortgage bonds that are set to mature on December 1, 2006. We expect the interest rate on the refinancing to be approximately 6.5%.

The common stock repurchase program announced during the fourth quarter of 2005 allowed us to repurchase up to $75 million of common stock. During the six months ended June 30, 2006, we repurchased approximately $ 3.7 million of common stock. Our stock repurchase program was cancelled in May 2006.

Our Board of Directors has approved the purchase of approximately 79 megawatts of our undivided interest in the Colstrip Unit 4 generation facility from Mellon Leasing for approximately $59 million. The transaction is expected to be completed by December 31, 2006.

Refinancing Transaction

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 June 30, 2006. See our Annual Report on Form 10-K for the year ended December 31, 2005 for additional discussion.

		Total		2006		2007		2008		2009		2010			Thereafter
	(in thousands)
Long-term Debt	$	703,226	$	152,867	$	6,761	$	6,057	$	41,047	$		6,123	$	490,371
Future Minimum Operating Lease Payments(1)	264,946		17,301		34,086		33,015		32,423		32,293			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)	1,604,287		56,398		58,420		60,574		62,598		64,580			1,301,717
Supply and Capacity Contracts(4)	1,486,411		284,115		374,036		191,371		161,820		155,379			319,690
Contractual Interest Payments on Debt	379,461		40,289		30,021		30,679		29,005		27,306			222,161
Total Commitments	$	4,533,031	$	573,670	$	525,324	$	343,696	$	348,893	$		291,681	$	2,449,767

(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. Our Board of Directors has approved a buy out of a portion of the Colstrip Unit 4 lease, which is expected to close by December 31, 2006. We are continuing to assess the potential of a buy out of the remaining portion of the lease.

(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. On July 5, 2006 we signed a seven-year power purchase agreement with PPL beginning July 1, 2007. Over the life of the agreement we will purchase 13.7 million megawatt hours at a cost of approximately $675 million. This commitment is not reflected in the June 30, 2006 obligations.

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Interest Rate Risk

We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. All of our debt has fixed interest rates, with the exception of our revolver, which bears interest at a variable rate (currently approximately 6.5%) tied to the London Interbank Offered Rate (LIBOR). Based upon amounts outstanding as of June 30, 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 exposures associated with anticipated refinancing transactions of approximately $380 million. These swaps were designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income in our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive income (AOCI) into interest expense in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur. During the first quarter of 2006, based on a review of our capital structure and cash flow, and approval by our Board of Directors, we decided not to refinance $60 million included in the interest rate swap that was being carried on our revolver. This forward starting interest rate swap was settled during the second quarter of 2006, and we received an aggregate payment of approximately $3.9 million. In association with the tax-exempt financing transaction completed during the second quarter of 2006, we settled $170.2 million of forward starting interest rate swap agreements, and received an aggregate settlement payment of approximately $6.3 million, which is being amortized as a reduction to interest expense over the term of the underlying debt, resulting in a reduction to the effective interest rate of 0.21%. We had unrealized pre-tax gains of $13.1 million at June 30, 2006 in other current assets based on the market value of our remaining interest rate swap.

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 June 30, 2006, market prices exceeded our contracted forward sales prices by approximately $1.6 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 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 June 30, 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 June 30, 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 various federal and state regulatory approvals. If the sale is not completed, our shareholders may not be able to obtain the premium for their shares of common stock offered in the proposed transaction.

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

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

These costs, which are being expensed as incurred, have had, and may continue to have an adverse affect on our results of operations and cash flows. Pending litigation matters are discussed in detail under the Legal Proceedings section in Note 11 to the Consolidated Financial Statements. An adverse result in any of these matters could have an adverse effect on our business.

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

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

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

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

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

Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rates through our monthly trackers. During the fourth quarter of 2005, the 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 settles various issues relative to our electric supply costs raised by the MCC and has been approved by the MPSC. In May 2006, the MPSC approved our 2005 annual natural gas tracker as filed. To the extent our energy supply costs are deemed imprudent by the MPSC or other applicable state regulatory commissions, we would under-recover our costs, which could adversely impact our results of operations.

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

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

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

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

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

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

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

Many of these environmental laws and regulations create permit and license requirements and provide for substantial civil and criminal fines which, if imposed, could result in material costs or liabilities. We cannot predict with certainty the occurrence of a private tort allegation or government claim for damages associated with specific

environmental conditions. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities in order to meet future requirements and obligations under environmental laws.

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be predicted. Our range of exposure for environmental remediation obligations is estimated to be $19.5 million to $56.1 million. We had an environmental reserve of $34.5 million at June 30, 2006. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or claims for damages allegedly associated with specific environmental conditions. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.

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. Our stock repurchase program was cancelled in May 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

April 1, 2006 — April 30, 2006	85,706	$	30.65	85,706	$	68.5 million
May 1, 2006 — May 31, 2006	—		—	—		—
June 1, 2006 — June 30, 2006	—		—	—		—
Total	85,706			85,706

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: August 3, 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

EXHIBIT 31.1

CERTIFICATION PURSUANT TO

17 CFR 240. 13a-14

PROMULGATED UNDER

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Michael J. Hanson, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of NorthWestern Corporation;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

(b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 3, 2006
/s/ MICHAEL J. HANSON
Michael J. Hanson
President and Chief Executive Officer

Exhibit 31.2

CERTIFICATION PURSUANT TO

17 CFR 240.13a-14

PROMULGATED UNDER

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Brian B. Bird, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of NorthWestern Corporation;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d 15(e) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information ; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: August 3, 2006
/s/ BRIAN B. BIRD
Brian B. Bird
Vice President and Chief Financial Officer

EXHIBIT 32.1

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

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 3, 2006		/s/ MICHAEL J. HANSON
		Michael J. Hanson
		President and Chief Executive Officer

Exhibit 32.2

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

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 3, 2006	/s/ BRIAN B. BIRD
	Brian B. Bird
	Vice President and Chief Financial Officer

Positive
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Litigious
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NorthWestern (NWE) 10-Q2006 Q2 Quarterly report

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