NorthWestern 10Q 2008 Q2 Quarterly report

UNITED STATES

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, 2008

Or

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

For the transition period from to

Commission File Number: 1-10499

NORTHWESTERN CORPORATION

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

3010 West 69^th Street, Sioux Falls, South Dakota		57108
(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 preceding 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, a non-
accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one).

Large Accelerated Filer x Accelerated Filer o Non-accelerated Filer o Smaller Reporting Company o

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

	Indicate by check mark whether the registrant has filed all documents and reports required to be filed by
Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by the court. Yes x No o

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

Common Stock, Par Value $.01

38,190,492 shares outstanding at July 25, 2008

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, 2008 and December 31, 2007		5
	Consolidated Statements of Income — Three and Six Months Ended June 30, 2008 and 2007		6
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2008 and 2007		7
	Notes to Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
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 4.	Submission of Matters to a Vote of Security Holders		46
Item 6.	Exhibits		47
SIGNATURES			48

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:

•

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.

•

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; and

•

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

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 Securities and Exchange Commission (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,			December 31,
		2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	24,242		$	12,773
Restricted cash		19,520			14,482
Accounts receivable, net of allowance		116,802			143,482
Inventories		47,304			63,586
Regulatory assets		21,190			27,049
Prepaid energy supply		2,791			3,166
Deferred income taxes		8,813			2,987
Other		43,861			10,829
Total current assets		284,523			278,354
Property, plant, and equipment, net		1,798,735			1,770,880
Goodwill		355,128			355,128
Regulatory assets		113,031			123,041
Other noncurrent assets		19,236			19,977
Total assets	$	2,570,653		$	2,547,380
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,836		$	2,389
Current maturities of long-term debt		19,285			18,617
Accounts payable		69,237			91,588
Accrued expenses		169,631			168,610
Regulatory liabilities		85,297			40,635
Total current liabilities		345,286			321,839
Long-term capital leases		37,412			38,002
Long-term debt		744,432			787,360
Deferred income taxes		100,987			74,046
Noncurrent regulatory liabilities		218,923			194,959
Other noncurrent liabilities		291,648			308,150
Total liabilities		1,738,688			1,724,356
Commitments and Contingencies (Note 14)
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,335,958 and 38,972,551, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		393			393
Treasury stock at cost		(10,781	)		(10,781	)
Paid-in capital		805,426			803,061
Retained earnings		23,835			16,603
Accumulated other comprehensive income		13,092			13,748
Total shareholders’ equity		831,965			823,024
Total liabilities and shareholders’ equity	$	2,570,653		$	2,547,380

See Notes to Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

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

		2008			2007			2008			2007
OPERATING REVENUES	$	276,506		$	259,608		$	662,481		$		626,173
COST OF SALES		149,354			141,255			378,438				360,534
GROSS MARGIN		127,152			118,353			284,043				265,639
OPERATING EXPENSES
Operating, general and administrative		53,866			58,677			113,937				121,125
Property and other taxes		20,540			20,660			44,180				41,252
Depreciation		21,225			20,793			42,316				40,687
TOTAL OPERATING EXPENSES		95,631			100,130			200,433				203,064
OPERATING INCOME		31,521			18,223			83,610				62,575
Interest Expense		(15,848	)		(14,527	)		(31,849	)			(27,747	)
Other (Expense) Income		(161	)		359			422				737
Income Before Income Taxes		15,512			4,055			52,183				35,565
Income Tax Expense		(6,009	)		(1,621	)		(19,229	)			(13,989	)
Net Income	$	9,503		$	2,434		$	32,954		$		21,576
Average Common Shares Outstanding		38,973			35,988			38,973				35,855
Basic Earnings per Average Common Share	$	0.24		$	0.07		$	0.85		$		0.60
Diluted Earnings per Average Common Share	$	0.24		$	0.06		$	0.84		$		0.57
Dividends Declared per Average Common Share	$	0.33		$	0.31		$	0.66		$		0.62

See Notes to Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
		2008			2007
OPERATING ACTIVITIES:
Net Income	$	32,954		$	21,576
Items not affecting cash:
Depreciation		42,316			40,687
Amortization of debt issue costs, discount and deferred hedge gain		1,202			805
Amortization of restricted stock		2,364			4,259
Equity portion of allowance for funds used during construction		(282	)		(163	)
Gain on sale of assets		(110	)		—
Unrealized loss on derivative instruments		6,396			—
Deferred income taxes		21,115			12,712
Changes in current assets and liabilities:
Restricted cash		(5,038	)		(824	)
Accounts receivable		26,780			46,979
Inventories		16,282			3,126
Prepaid energy supply costs		375			(547	)
Other current assets		(288	)		(330	)
Accounts payable		(23,569	)		(18,314	)
Accrued expenses		(5,324	)		3,622
Regulatory assets		5,808			5,893
Regulatory liabilities		11,933			26,493
Other noncurrent assets		12,159			6,822
Other noncurrent liabilities		(20,419	)		(16,559	)
Cash provided by operating activities		124,654			136,237
INVESTING ACTIVITIES:
Property, plant, and equipment additions		(43,087	)		(52,608	)
Colstrip Unit 4 acquisition		—			(40,247	)
Proceeds from sale of assets		29			592
Cash used in investing activities		(43,058	)		(92,263	)
FINANCING ACTIVITIES:
Proceeds from exercise of warrants		—			10,600
Treasury stock activity		—			(6	)
Dividends on common stock		(25,722	)		(22,297	)
Issuance of long-term debt		55,000			—
Repayment of long-term debt		(85,939	)		(3,920	)
Line of credit repayments, net		(12,000	)		(30,000	)
Financing costs		(1,466	)		(281	)
Cash used in financing activities		(70,127	)		(45,904	)
Increase (Decrease) in Cash and Cash Equivalents		11,469			(1,930	)
Cash and Cash Equivalents, beginning of period		12,773			1,930
Cash and Cash Equivalents, end of period	$	24,242		$	—
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes		43			1,274
Interest		24,479			18,993
Significant noncash transactions:
Assumption of debt related to Colstrip Unit 4 acquisition		—			20,438

See Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Reference is made to Notes to Financial Statements

included in NorthWestern Corporation’s Annual Report)

(Unaudited)

(1) Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 650,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have distributed electricity and natural gas in Montana since 2002.

The consolidated financial statements for the periods included herein have been prepared by NorthWestern Corporation, pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. The unaudited consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Although management believes that the condensed disclosures provided are adequate to make the information presented not misleading, management recommends that these unaudited consolidated financial statements be read in conjunction with audited consolidated financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2007.

(2) New Accounting Standards

Accounting Standards Issued

In May 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 162, The Hierarchy of Generally Accepted Accounting Principles (Statement No. 162). Statement No. 162 supersedes the existing hierarchy contained in the U.S. auditing standards. The existing hierarchy was carried over to Statement No. 162 essentially unchanged. The Statement becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The new hierarchy is not expected to change current accounting practice in any area.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133 (SFAS No. 161). SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities, requiring enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This statement will become effective for our fiscal year beginning January 1, 2009. We are still evaluating the impact of SFAS No. 161, if any, but do not expect the statement to have a material impact on our consolidated financial statements.

Accounting Standards Adopted

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 became effective for most fair value measurements, other than leases and certain nonfinancial assets and liabilities, beginning January 1, 2008.

The statement establishes a three-level fair value hierarchy and requires fair value disclosures based upon this hierarchy. The statement also requires that fair value measurements reflect a credit-spread adjustment based on an entity’s own credit standing. Consideration of our own credit risk did not have a material impact on our fair value measurements.

The following table sets forth by level within the fair value hierarchy our assets and liabilities that were measured at fair value on a recurring basis as of June 30, 2008 (in thousands):

At June 30, 2008	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value (1)

Regulated gas derivative asset (2)	$	—	$	38,449		$	—	$	—	$	38,449
Unregulated electric derivative liability	—		(6,396		)	—		—		(6,396		)
Net derivative asset	$	—	$	32,053		$	—	$	—	$	32,053

(1)	Fair value was determined using internal models based on quoted external commodity prices.

(2)	The changes in the fair value of these derivatives are deferred as a regulatory asset or liability until the contracts are settled. Upon settlement, associated proceeds or costs are passed through the applicable cost tracking mechanism to customers.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Normal purchases and sales transactions, as defined by SFAS No. 133, and certain other long-term power purchase contracts are not included in the fair values by source table as they are not recorded at fair value. See Note 7 for further discussion.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115, which permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, with unrealized gains and losses related to these financial instruments reported in earnings at each subsequent reporting date. This option would be applied on an instrument by instrument basis. If elected, unrealized gains and losses on the affected financial instruments would be recognized in earnings at each subsequent reporting date. This statement is effective beginning January 1, 2008. We have assessed the provisions of the statement and elected not to apply fair value accounting to our eligible financial instruments. As a result, adoption of this statement had no impact on our financial results.

(3) Variable Interest Entities

FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, or FIN 46R, requires the consolidation of entities which are determined to be variable interest entities (VIEs) when we are the primary beneficiary of a VIE, which means we have a controlling financial interest. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility and, while we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We continue to account for this qualifying facility contract as an executory contract as we have been unable to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $506.9 million through 2025, and are included in Contractual Obligations and Other Commitments of Management's Discussion and Analysis.

(4) Income Taxes

We have unrecognized tax benefits of approximately $112.0 million as of June 30, 2008. If any of our unrecognized tax benefits were recognized during 2008, they would have no impact on our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statute of limitations within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 2008, we have not recognized expense for interest or penalties, and do not have any amounts accrued at June 30, 2008 and December 31, 2007, respectively, for the payment of interest and penalties.

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

(5) Goodwill

There were no changes in our goodwill during the six months ended June 30, 2008. Goodwill by segment is as follows for June 30, 2008 and December 31, 2007 (in thousands):


Regulated electric	$	241,100
Regulated natural gas		114,028
Unregulated electric		—
	$	355,128

(6) Other Comprehensive Income

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

Comprehensive income is calculated as follows (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Net income	$	9,503		$	2,434		$	32,954		$	21,576
Other comprehensive income (loss), net of tax:
Reclassification of net gains on hedging instruments from OCI to net income		(297	)		(297	)		(594	)		(594	)
Foreign currency translation		20			151			(62	)		170
Comprehensive income	$	9,226		$	2,288		$	32,298		$	21,152

(7) 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. In order to manage these risks, we use both derivative and non-derivative contracts that may provide for settlement in cash or by delivery of a commodity, including:

•

Forward contracts, which commit us to purchase or sell energy commodities in the future,

•

Option contracts, which convey the right to buy or sell a commodity at a predetermined price, and

•

Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity.

SFAS No. 133 requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchase and normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

We have applied the normal purchases and normal sales scope exception, as provided by SFAS No. 133 and interpreted by Derivatives Implementation Guidance Issue C15, to certain contracts involving the purchase and sale of gas and electricity at fixed prices in future periods. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. For certain regulated electric and gas contracts that do not physically deliver, in accordance with EITF 03-11, Reporting Gains and Losses on Derivative Instruments that are Subject to SFAS No. 133 and not “Held for Trading Purposes" as defined in Issue no. 02-3, revenue is reported net versus gross.

While most of our derivative transactions are entered into for the purpose of managing commodity price risk, hedge accounting is only applied where specific criteria are met and it is practicable to do so. In order to apply hedge accounting, the transaction must be designated as a hedge and it must be highly effective in offsetting the hedged risk. Additionally, for hedges of commodity price risk, physical delivery for forecasted commodity transactions must be probable. We use the mark-to-market method of accounting for derivative contracts for which we do not elect or do not qualify for hedge accounting. Under the mark-to-market method of accounting, we record the fair value of these derivatives as assets and liabilities, with changes reflected in our consolidated statements of income. The market prices and quantities used to determine fair value reflect management’s best estimate considering various factors; however, future market prices and actual quantities will vary from those used in recording the derivative asset or liability, and it is possible that such variations could be material.

Commodity Prices

Unregulated Electric - We use derivatives to optimize the value of our unregulated power generation asset. Changes in the fair value for power purchases and sales are recognized on a net basis in operating revenues or cost of sales in the consolidated income statement unless hedge accounting is applied. While our derivative transactions are entered into for the purpose of managing commodity price risk, hedge accounting is only applied where specific criteria are met and it is practicable to do so. In order to apply hedge accounting, the transaction must be designated as a hedge and it must be highly effective in offsetting the hedged risk. Additionally, for hedges of commodity price risk, physical delivery for forecasted commodity transactions must be probable. Transactions that are financially settled are presented on a net basis. For the six months ended June 30, 2008, we recorded unrealized losses in the income statement consistent with the mark-to-market method of accounting discussed above of approximately $6.4 million related to economic hedges where we have locked in forward prices.

Regulated Utilities - Certain contracts for the physical purchase of natural gas associated with our regulated gas utilities do not qualify for normal purchases under SFAS No. 133. Since these contracts are for the purchase of natural gas sold to regulated gas customers, the accounting for these contracts is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulations (SFAS No. 71). We use derivative financial instruments to reduce the commodity price risk associated with the purchase price of a portion of our future natural gas requirements and minimize fluctuations in gas supply prices to our regulated customers. We record assets or liabilities based on the fair value of these derivatives, with offsetting positions recorded as regulatory liabilities or regulatory assets on the consolidated balance sheets. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements. At June 30, 2008 we had a derivative asset, included in other current assets in the consolidated balance sheet, and offsetting regulatory liability of $38.4 million.

Interest Rates

During 2006, we issued $170.2 million of Montana Pollution Control Obligations and $150 million of Montana First Mortgage Bonds. In association with these refinancing transactions, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions. These swaps were designated as cash-flow hedges under SFAS No. 133 with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income (AOCI) in our consolidated balance sheets. We settled $320.2 million of forward starting interest rate swap

agreements, and received aggregate settlement payments of approximately $14.6 million in 2006. We reclassify these gains from AOCI into interest expense in our consolidated statements of income during the periods in which the hedged interest payments occur. AOCI includes unrealized pre-tax gains related to these transactions of $12.2 million and $12.8 million at June 30, 2008 and December 31, 2007, respectively. We expect to reclassify approximately $1.2 million of pre-tax gains on these cash-flow hedges from AOCI into interest expense during the next twelve months. We have no further interest rate swaps outstanding.

(8) Segment Information

We operate the following business units: (i) regulated electric, (ii) regulated natural gas, (iii) unregulated electric, and (iv) all other, which primarily consists of our remaining unregulated natural gas operations and our unallocated corporate costs.

We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments, are as follows (in thousands):

Three months ended,	Regulated						Unregulated
June 30, 2008	Electric			Gas			Electric			Other			Eliminations			Total
Operating revenues	$	178,967		$	80,531		$	16,569		$	8,653		$	(8,214	)	$	276,506
Cost of sales	87,196			49,885			11,624			8,395			(7,746		)	149,354
Gross margin	91,771			30,646			4,945			258			(468		)	127,152
Operating, general and administrative	34,503			15,735			3,219			877			(468		)	53,866
Property and other taxes	14,338			5,484			715			3			—			20,540
Depreciation	15,392			4,001			1,823			9			—			21,225
Operating income (loss)	27,538			5,426			(812		)	(631		)	—			31,521
Interest expense	(9,201		)	(3,286		)	(2,993		)	(368		)	—			(15,848		)
Other income (expense)	376			281			119			(937		)	—			(161		)
Income tax (expense) benefit	(6,646		)	(873		)	1,561			(51		)	—			(6,009		)
Net income (loss)	$	12,067		$	1,548		$	(2,125	)	$	(1,987	)	$	—		$	9,503
Total assets	$	1,543,185		$	754,213		$	256,036		$	17,219		$	—		$	2,570,653
Capital expenditures	$	18,748		$	9,864		$	518		$	—		$	—		$	29,130

Three months ended,	Regulated						Unregulated
June 30, 2007	Electric			Gas			Electric			Other			Eliminations			Total
Operating revenues	$	170,579		$	62,032		$	14,601		$	16,715		$	(4,319	)	$	259,608
Cost of sales	87,890			36,924			4,205			16,180			(3,944		)	141,255
Gross margin	82,689			25,108			10,396			535			(375		)	118,353
Operating, general and administrative	30,831			16,063			7,536			4,622			(375		)	58,677
Property and other taxes	14,453			5,345			856			6			—			20,660
Depreciation	15,280			4,107			954			452			—			20,793
Operating income (loss)	22,125			(407		)	1,050			(4,545		)	—			18,223
Interest expense	(9,848		)	(3,634		)	(677		)	(368		)	—			(14,527		)
Other income	205			40			6			108			—			359
Income tax (expense) benefit	(4,692		)	1,473			(196		)	1,794			—			(1,621		)
Net income (loss)	$	7,790		$	(2,528	)	$	183		$	(3,011	)	$	—		$	2,434
Total assets	$	1,483,660		$	731,352		$	118,604		$	20,325		$	—		$	2,353,941
Capital expenditures	$	16,156		$	14,681		$	1,301		$	—		$	—		$	32,138

Six months ended,	Regulated						Unregulated
June 30, 2008	Electric			Gas			Electric			Other			Eliminations			Total
Operating revenues	$	375,586		$	252,174		$	36,973		$	16,575		$	(18,827	)	$	662,481
Cost of sales	190,251			171,193			18,656			16,159			(17,821		)	378,438
Gross margin	185,335			80,981			18,317			416			(1,006		)	284,043
Operating, general and administrative	69,873			33,659			6,896			4,515			(1,006		)	113,937
Property and other taxes	30,767			11,812			1,594			7			—			44,180
Depreciation	30,787			7,884			3,628			17			—			42,316
Operating income (loss)	53,908			27,626			6,199			(4,123		)	—			83,610
Interest expense	(18,459		)	(6,485		)	(6,169		)	(736		)	—			(31,849		)
Other income (expense)	585			559			132			(854		)	—			422
Income tax (expense) benefit	(12,333		)	(8,163		)	(154		)	1,421			—			(19,229		)
Net income (loss)	$	23,701		$	13,537		$	8		$	(4,292	)	$	—		$	32,954
Total assets	$	1,543,185		$	754,213		$	256,036		$	17,219		$	—		$	2,570,653
Capital expenditures	$	29,482		$	12,594		$	1,011		$	—		$	—		$	43,087

Six months ended,	Regulated						Unregulated
June 30, 2007	Electric			Gas			Electric			Other			Eliminations			Total
Operating revenues	$	349,073		$	220,221		$	36,879		$	32,786		$	(12,786	)	$	626,173
Cost of sales	180,679			152,134			8,441			31,173			(11,893		)	360,534
Gross margin	168,394			68,087			28,438			1,613			(893		)	265,639
Operating, general and administrative	65,339			34,148			15,904			6,627			(893		)	121,125
Property and other taxes	28,644			10,941			1,635			32			—			41,252
Depreciation	30,658			8,057			1,370			602			—			40,687
Operating income (loss)	43,753			14,941			9,529			(5,648		)	—			62,575
Interest expense	(19,598		)	(6,486		)	(903		)	(760		)	—			(27,747		)
Other income	381			194			8			154			—			737
Income tax (expense) benefit	(9,156		)	(3,477		)	(3,652		)	2,296			—			(13,989		)
Net income (loss)	$	15,380		$	5,172		$	4,982		$	(3,958	)	$	—		$	21,576
Total assets	$	1,483,660		$	731,352		$	118,604		$	20,325		$	—		$	2,353,941
Capital expenditures	$	28,552		$	22,115		$	1,941		$	—		$	—		$	52,608

(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 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 deferred share units. Average shares used in computing the basic and diluted earnings per share are as follows:

	Six Months Ended June 30, 2008	Six Months Ended June 30, 2007
Basic computation	38,972,529	35,854,902
Dilutive effect of
Restricted shares	448,939	530,655
Stock warrants	—	1,469,097
Diluted computation	39,421,468	37,854,654

	Three Months Ended June 30, 2008	Three Months Ended June 30, 2007
Basic computation	38,972,551	35,988,340
Dilutive effect of
Restricted shares	448,939	530,655
Stock warrants	—	1,355,872
Diluted computation	39,421,490	37,874,867

Warrants issued in 2004 were exercisable through the close of business November 1, 2007. A total of 406,519 warrants were exercised during the six months ended June 30, 2007. Warrants outstanding as of June 30, 2007 of 4,100,006 were dilutive and included in the 2007 earnings per share calculation.

(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, 2008 and 2007 (in thousands):

		Pension Benefits						Other Postretirement Benefits
		Three Months Ended June 30,
			2008			2007			2008			2007
Components of Net Periodic Benefit Cost
	Service Cost	$	2,033		$	2,185		$	132		$	102
	Interest Cost		5,712			5,501			573			519
	Expected return on plan assets		(6,851	)		(6,388	)		(369	)		(310	)
	Amortization of prior service cost		63			61			—			—
	Recognized actuarial (gain) loss		(268	)		—			(193	)		—
Net Periodic Benefit Cost		$	689		$	1,359		$	143		$	311

		Pension Benefits						Other Postretirement Benefits
		Six Months Ended June 30,
			2008			2007			2008			2007
Components of Net Periodic Benefit Cost
	Service Cost	$	4,203		$	4,474		$	282		$	290
	Interest Cost		11,438			10,900			1,184			1,221
	Expected return on plan assets		(13,607	)		(12,211	)		(658	)		(535	)
	Amortization of prior service cost		123			121			—			(180	)
	Recognized actuarial (gain) loss		(409	)		—			(300	)		—
Net Periodic Benefit Cost		$	1,748		$	3,284		$	508		$	796

In January 2008, we contributed approximately $21.9 million to our pension plans.

(11) Regulatory Matters

Federal Energy Regulatory Commission (FERC) Transmission Rate Case - In October 2006, we filed a request with the FERC for an electric transmission revenue increase. Our requested increase pertains only to FERC jurisdictional wholesale transmission and retail choice customers representing approximately $8.6 million in revenue. In May 2007, we implemented interim rates, which are subject to refund plus interest pending final resolution. We filed settlement documents on February 15, 2008 and are awaiting FERC approval. The interim rate increase contributed approximately $0.4 million and $1.1 million for the three and six months ended June 30, 2008, respectively, to regulated electric margin.

Montana Electric and Natural Gas Rate Case - In July 2007, we filed a request with the Montana Public Service Commission (MPSC) for an electric transmission and distribution revenue increase of $31.4 million, and a natural gas transmission, storage and distribution revenue increase of $10.5 million. In December 2007, we and the Montana Consumer Counsel filed a joint stipulation with the MPSC to settle our electric and natural gas rate cases. Specific terms of the stipulation include:

•

An increase in base electric rates of $10 million and base natural gas rates of $5 million;

•

Interim rates effective January 1, 2008;

•

Capital investment in our electric and natural gas system totaling $38.8 million to be completed in 2008 and 2009 on which we will not earn a return on, but will recover depreciation expense;

•

A commitment of 21 MWs of unit contingent power from Colstrip Unit 4 at Mid-Columbia (Mid-C) Index prices minus $19 per MWH, but not less than zero, to electric supply for a period of 76 months beginning March 1, 2008; and

•

We will submit a general electric and natural gas rate filing no later than July 31, 2009 based on a 2008 test year.

On July 1, 2008, the MPSC approved the stipulated agreement, finalizing the Montana electric and natural gas rate case.

(12) Financing Activities

During the second quarter of 2008, we issued $55 million of South Dakota First Mortgage Bonds at a fixed interest rate of 6.05% maturing May 1, 2018, and used the proceeds to redeem our 7.0%, $55 million South Dakota Mortgage Bonds due August 15, 2023. This transaction will reduce our annual interest expense by approximately $0.5 million.

In addition, we repaid our 5.85%, $7.6 million and 5.9%, $13.8 million South Dakota Pollution Control Bonds maturing in 2023. This transaction will reduce our annual interest expense by approximately $1.3 million.

(13) Proposed Colstrip Unit 4 Transaction

In January 2008, we announced that we had retained a financial advisor to assist us in the evaluation of our strategic options related to our 30% ownership interest in Colstrip Unit 4. Options reviewed included selling our ownership through a competitive bid process, putting the asset in rate base in Montana, or retaining the asset and contracting future sales of the plant output. On June 10, 2008, we entered into an agreement to sell our interest in Colstrip Unit 4 for $404 million in cash, subject to certain working capital adjustments. The agreement provides a timeline of 120 days for us to explore the viability of placing this asset into our Montana utility rate base. The agreement also contains certain termination rights for both us and the buyer in which, under specified circumstances, we may be required to pay a termination fee of $6.3 million or the buyer may be required to pay a termination fee of $20 million.

Consistent with these terms, on June 30, 2008, we submitted a filing with MPSC to initiate a review process to determine if it would be in the public interest to place our interest in Colstrip Unit 4 into rate base at an equivalent value to the negotiated selling price including certain adjustments. If the filing with the MPSC is rejected, the electric utility’s regulated supply group will have an option to purchase power at a discount to Mid-C Index prices as existing contracts expire and power becomes available in future years. In addition, the transaction is conditioned upon FERC approval and other customary closing conditions. We expect to complete this process by the end of 2008.

We have evaluated the potential sale of our interest in Colstrip Unit 4 for classification as held for sale under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The held for sale classification only applies to assets where the sale is subject to terms that are usual and customary for sales of such assets, and the sale of the asset is considered probable. The term probable is used consistent with the meaning associated with it in paragraph 3(a) of SFAS No. 5, Accounting for Contingencies, and refers to a future sale that is "likely to occur." The provisions of the agreement allowing us to explore the rate base alternative do not constitute usual and customary terms and the transaction is not considered probable, as defined, due to the uncertainty surrounding this process with the MPSC. We have continued to reflect the assets and results of operations of Colstrip Unit 4 as continuing operations, and will reevaluate our classification as the process progresses.

(14) Commitments and Contingencies

Environmental Liabilities

Environmental laws and regulations are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. The range of exposure for environmental remediation obligations at present is estimated to range between $19.8 million to $57.0 million. As of June 30, 2008, we have a reserve of approximately $31.2 million. We anticipate that as environmental costs become fixed and reliably determinable, we will seek insurance reimbursement and/or authorization to recover these in rates; therefore, we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

The Clean Air Act Amendments of 1990 and subsequent amendments stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We comply with these existing emission requirements through purchase of sub-bituminous coal, and we believe that we are in compliance with all presently applicable environmental protection requirements and regulations with respect to these plants.

Coal-Fired Plants

We are joint owners in Colstrip Unit 4, a coal-fired power plant located in southeastern Montana, and three coal-fired plants used to serve our South Dakota customer supply demands. Citing its authority under the Clean Air Act, the EPA had finalized Clean Air Mercury Regulations (CAMR) that affected coal-fired plants. These regulations established a cap-and-trade program that would have taken effect in two phases beginning January 2010 and January 2018. Under CAMR, each state was allocated a mercury emissions cap and was required to develop regulations to implement the requirements, which could follow the federal requirements or be more restrictive. In February 2008 the EPA’s CAMR were turned down by the U.S. Court of Appeals for the District of Columbia Circuit; however, under this opinion, the EPA must either properly remove mercury from regulation under the hazardous air pollutant provisions of the Clean Air Act or develop standards requiring maximum achievable control technology for mercury emissions.

Montana has finalized its own rules more stringent than CAMR's 2018 cap that would require every coal-fired generating plant in the state to achieve reduction levels by 2010. The joint owners currently plan to install chemical injection technologies to meet these requirements. We estimate our share of the capital cost would be approximately $1 million, with ongoing annual operating costs of approximately $3 million. If the Montana rules are maintained in their current form and enhanced chemical injection technologies are not sufficiently developed to meet the Montana levels of reduction by 2010, then adsorption/absorption technology with fabric filters at the Colstrip Unit 4 generation facility would be required, which could represent a material cost. Recent tests have shown that it may be possible to meet the Montana rules with more refined chemical injection technology combined with adjustments to boiler/fireball dynamics at a minimal cost. We are continuing to work with the other Colstrip owners to determine the ultimate financial impact of these rules.

In June 2008 the Sierra Club filed a lawsuit in U.S. District Court in South Dakota against NorthWestern and the other joint owners of the Big Stone plant alleging certain violations of the Clean Air Act. For further discussion see the Litigation – Sierra Club section below.

Manufactured Gas Plants

Approximately $25.4 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. In 2007, we completed remediation of sediment in a short segment of Moccasin Creek that had been impacted by the former manufactured gas plant operations. Our current reserve for remediation costs at this site is approximately $11.8 million, and we estimate that approximately $10 million of this amount will be incurred during the next five years.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. On March 30, 2006 and May 17, 2006, the NDEQ released to us the Phase II Limited Subsurface Assessment performed by the NDEQ's environmental consulting firm for Kearney and Grand Island, respectively. We have initiated additional site investigation and assessment work at these locations. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require entry into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the MDEQ's voluntary remediation program for cleanup due to exceedences of regulated pollutants in the groundwater. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the problems at these sites; however, additional groundwater monitoring will be necessary. In Helena, we continue limited operation of an oxygen delivery system implemented to enhance natural biodegradation of pollutants in the groundwater and we are currently evaluating limited source area treatment/removal options. Monitoring of groundwater at this site will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site.

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

Milltown Dam Removal

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the former Milltown Dam site, and previously operated a three MW hydroelectric generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. Dam removal activities were initiated during the first quarter of 2008 and are expected to be complete within a

year. Our remaining obligation to the State of Montana related to this site is approximately $0.6 million, which will be solely funded through the sale or transfer of land and water rights associated with the former Milltown Dam operations.

Other

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

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

•

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

•

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

LEGAL PROCEEDINGS

Magten/Law Debenture/QUIPS Litigation

On July 10, 2008 the Delaware Bankruptcy Court approved the global settlement agreement that resolves the Magten and Law Debenture appeals, the Magten v. Certain Current and Former Officers of CFB litigation, the Magten v. Bank of New York litigation and the Magten and Law Debenture v. NorthWestern Corporation and Certain Individuals. On July 23, 2008 the Ad Hoc Committee filed an appeal to the global settlement agreement, however, we and the other parties involved waived a closing condition and closed on the settlement on July 24, 2008. Under the approved global settlement agreement Magten, Law Debenture, their lawyers and the holders of the QUIPS, collectively received a cash payment of $23 million to be allocated amongst them in accordance with the terms of the global settlement agreement. The cash payment was funded by our repurchase of 782,059 shares held in the disputed claims reserve established under our confirmed Plan of Reorganization (the Plan). In addition, we received a reimbursement of previously incurred legal fees and expenses of $4 million under separate agreements for which no Court approval was requested.

On July 11, 2008, we filed a motion seeking bankruptcy court approval for the purchase of the remaining shares in the disputed claim reserve. The cash from such purchase would be used to make a surplus distribution of all of the remaining assets in the disputed claims reserve to unsecured creditors and debt holders in Class 7 and Class 9 under the Plan, other than the holders of the QUIPS. The motion allows unsecured creditors and debt holders in Class 7 and Class 9 to elect to receive their surplus distribution in stock and accrued dividends or cash. The bankruptcy court approved this motion in July.

Each matter, described below in greater detail, generally related to claims of certain holders of quarterly income preferred securities in our Chapter 11 bankruptcy case.

Magten and Law Debenture v. NorthWestern Corporation - Magten Asset Management Corporation (Magten) and Law Debenture Trust Company (Law Debenture) initiated an adversary proceeding, which we referred 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 asserted that the transfer of the transmission and distribution assets acquired from the Montana Power Company was a fraudulent conveyance because it allegedly left CFB insolvent and unable to pay certain claims. The plaintiffs also asserted that they were creditors of CFB as a result of Magten owning a portion of the Series A 8.45% Quarterly Income Preferred Securities (QUIPS) for which Law Debenture serves as the Indenture Trustee. Plaintiffs sought , among other things, the avoidance of the transfer of assets, declaration that the assets were fraudulently transferred and were not NorthWestern’s property, the imposition

of constructive trusts over the transferred assets and the return of such assets to CFB.

Magten v. Certain Current and Former Officers of CFB - On April 19, 2004, Magten filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for alleged breaches of fiduciary duties by such officers in connection with the same transaction described above which is at issue in the QUIPS Litigation, namely the transfer of the transmission and distribution assets acquired from the Montana Power Company to NorthWestern.

Magten v. Bank of New York - In July 2006, Magten served a complaint against The Bank of New York (“BNY”) in an action filed in New York state court, seeking damages for alleged breach of contract, breach of fiduciary duty and negligence in connection with the same transaction described above which is at issue in the QUIPS Litigation. Specifically, Magten alleged that BNY, as the Indenture Trustee at the time of the 2002 transfer of assets from Montana Power Company to NorthWestern, should have taken steps to protect the QUIPS holders' interests by seeking to set aside the transfer and imposing a constructive trust on the assets. BNY has asserted a right to indemnification by NorthWestern for legal fees and costs incurred in defending against Magten's claims pursuant to the terms of the Indenture governing the QUIPS under which BNY served as Trustee.

Magten and Law Debenture v. NorthWestern Corporation and Certain Individuals - On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern and certain former and current officers and directors seeking to revoke the Confirmation Order of NorthWestern’s Plan 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 disputed 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.

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), contends that the disposition of various generating and energy-related assets by The Montana Power Company are 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. (now CFB), which plaintiffs claim is a successor to the Montana Power Company.

We are one of the defendants in a second class action lawsuit brought by the McGreevey plaintiffs, also entitled McGreevey, et al. v. The Montana Power Company, et al., pending in U.S. District Court in Montana. This lawsuit, like the Magten litigation described above, seeks, among other things, the avoidance of the transfer of assets from CFB to us, declaration that the assets were fraudulently transferred and are not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets, and the return of such assets to CFB.

In June 2006, we and the McGreevey plaintiffs entered into an agreement to settle all claims brought by the McGreevey plaintiffs in all of the actions described above, wherein the McGreevey plaintiffs executed a covenant not to execute against us, and we quit claimed any interest we had in any claims we may or may not have under any applicable directors and officers liability insurance policy, against any insurers for contractual or extracontractual damages, and against certain defendants in the McGreevey lawsuits. In November 2006, this agreement was approved by the Delaware Bankruptcy Court and the claims were discharged. We filed a joint motion with the plaintiffs' attorneys in U.S. District Court in Montana to dismiss the claims against us in the McGreevey lawsuits. On March 16, 2007, the U.S. District Court in Montana denied the motion to dismiss us from the McGreevey lawsuits, questioning the benefits of the settlement to be received by the class members in the settlement and the authority of the plaintiffs' counsel to have negotiated the settlement without a class having been certified by the court. On January 11, 2008, the U.S. District Court in Montana suggested that the settlement agreement was invalid because the plaintiffs' attorneys had not secured the court's permission to engage in settlement discussions. The District Court enjoined the plaintiffs from taking any further action in any of these matters. The plaintiffs appealed the District Court’s January 11^th

injunction to the Ninth Circuit U.S. Court of Appeals, where on July 10, 2008, the Ninth Circuit U.S. Court of Appeals heard oral arguments; a determination is pending. We do not anticipate a resolution of this litigation before class representatives and class counsel are approved by the U.S. District Court in Montana. However, we believe that given the scope of the Order confirming the Plan and the injunctions issued by the Delaware Bankruptcy Court which channeled the claims to the D&O Trust, we have limited exposure to the plaintiffs for damages arising from the McGreevey claims. We will continue to vigorously defend against these claims and explore ways to remove ourselves from the lawsuits.

City of Livonia

In November 2005, we and our directors were named as defendants in a shareholder class action and derivative action entitled City of Livonia Employee Retirement System v. Draper, et al., pending in the U.S. District Court for the District of South Dakota. The plaintiff claimed, 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, the City of Livonia amended its complaint to add allegations that our directors had erred in choosing an offer from Babcock and Brown Infrastructure Limited (BBI) because it was not the most attractive offer they had received for the company. In December 2006, the plaintiffs agreed to dismiss the lawsuit with prejudice on the condition that the federal court would retain jurisdiction over any award of attorneys' fees. Plaintiffs filed a motion for attorneys' fees and costs seeking $9.9 million on the grounds that the Board's acceptance of the BBI offer was attributable to their efforts. On December 13, 2007, the federal court ordered additional simultaneous briefing on the issue of whether, in light of the BBI termination, the Livonia litigation had benefited our shareholders. In March 2008 the district court ruled that the plaintiffs’ lawyers should receive approximately $1.8 million in fees and costs. We had filed an appeal of the court’s order in the U.S. Court of Appeals for the Eighth Circuit, and had also filed a lawsuit in South Dakota state court against the insurance carrier as the carrier would not provide a definitive decision that any award of attorneys' fees would be reimbursed by insurance proceeds. We recorded a $1.8 million liability during the first quarter of 2008, pending the outcome of the appeal and lawsuit against the insurance carrier. In May 2008, this litigation was settled, resulting in a payment directly from our insurance carrier to the plaintiffs’ lawyers. We reversed the $1.8 million liability during the second quarter of 2008.

Ammondson

In April 2005, a group of former employees of the Montana Power Company filed a lawsuit in the state court of Montana against us and certain officers styled Ammondson, et al. v. NorthWestern Corporation, et al., Case No. DV-05-97. The former employees have alleged that by moving to terminate their supplemental retirement contracts in our bankruptcy proceeding without having listed them as claimants or giving them notice of the disclosure statement and Plan, that we breached those contracts, and breached a covenant of good faith and fair dealing under Montana law and by virtue of filing a complaint in our Bankruptcy Case against those employees from seeking to prosecute their state court action against NorthWestern, we had engaged in malicious prosecution and should be subject to punitive damages. In May 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, thereby removing any claim from consideration in the resolution of our bankruptcy case. In February 2007, a jury verdict was rendered against us in Montana state court, which ordered us to pay $17.4 million in compensatory and $4.0 million in punitive damages in a case called Ammondson, et al. v. NorthWestern Corporation, et al. Due to the verdict, we recognized a loss of $19.0 million in our 2006 results of operations to increase our recorded liability related to this claim. The Montana state court reviewed the amount of the punitive damages under state law and did not alter the amount. We have appealed the judgment to the Montana Supreme Court and posted a $25.8 million bond. We intend to vigorously pursue the appeal; however, there can be no assurance that we will prevail in our efforts. Interest accrues on the verdict amount during the appeal process.

Sierra Club

On June 10, 2008, Sierra Club filed a complaint in the U.S. District Court for the District of South Dakota (Northern Division) against the Company and two other co-owners (the Defendants) of Big Stone Generating Station (Big Stone). The complaint alleges certain violations of the (i) Prevention of Significant Deterioration and (ii) New Source Performance Standards (NSPS) provisions of the Clean Air Act and certain violations of the South Dakota State Implementation Plan (South Dakota SIP). The action further alleges that the Defendants modified and operated

Big Stone without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. Plaintiff alleges that Defendants’ actions have contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. Plaintiff seeks both declaratory and injunctive relief to bring the Defendants into compliance with the Clean Air Act and the South Dakota SIP and to require Defendants to remedy the alleged violations. Plaintiff also seeks unspecified civil penalties, including a beneficial mitigation project. We believe that these claims are without merit and that Big Stone has been and is being operated in compliance with the Clean Air Act and the South Dakota SIP. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation and Contingencies

FERC Investigation

During the second quarter of 2007, we voluntarily informed the FERC of several potential regulatory compliance issues related to our natural gas business. The FERC is conducting an ongoing investigation into these matters. Based on our current assessment we do not anticipate the outcome of the FERC’s investigation will have a material adverse effect on our financial position.

Colstrip Energy Limited Partnership

In December 2006, the MPSC issued an order finalizing certain qualifying facility rates for the periods July 1, 2003 through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a qualifying facility with which we have a power purchase agreement through 2025. Under the terms of the power purchase agreement with CELP, energy and capacity rates were fixed through June 30, 2004 (with a small portion to be set by the MPSC's determination of rates in the annual avoided cost filing), and beginning July 1, 2004 through the end of the contract, energy and capacity rates are to be determined each year pursuant to a formula. CELP filed a complaint against NorthWestern and the MPSC in Montana district court on July 6, 2007 which contests the MPSC’s order. CELP is disputing inputs in to the rate-setting formula, used by us and approved by the MPSC on an annual basis, to calculate energy and capacity payments for the contract years 2004, 2005 and 2006. CELP is claiming that NorthWestern breached the power purchase agreement causing damages, which CELP asserts are not presently known but believed to be approximately $22 million for contract years 2004, 2005 and 2006. If the MPSC's order is upheld in its current form, we anticipate reducing our QF liability by approximately $25 to $50 million as our estimate of energy and capacity rates for the remainder of the contract period would be reduced. A temporary restraining order was agreed to by the parties and has been issued restraining us from implementing the rates finalized by the MPSC order pending an ultimate decision on CELP's complaint. On June 30, 2008, the state district court judge granted our motions to enforce the contractual arbitration provision and to stay all discovery and proceedings against NorthWestern Energy, pending the decision of the required contract arbitration. The state district court, on June 30, 2008, also granted a motion by the MPSC to bifurcate, having the effect of separating the issues between contract/tort claims and the administrative appeal of the MPSC’s orders; which we supported. The order also stayed the appellate decision pending a decision in our arbitration proceedings. We believe that we will prevail in the arbitration and intend to vigorously defend our positions. Concurrently, an adversary proceeding against CELP requesting a declaratory judgment has been sought by us in the Delaware Bankruptcy Court. On July 10, 2008, the Bankruptcy Court held a hearing and verbally advised the parties that they are to settle a scheduling order which provides for briefing and a July 30, 2008 hearing on CELP’s motion to stay the proceedings.

Colstrip Unit 4 Coal Royalties

Relative to our joint ownership in Colstrip Unit 4, the Mineral Management Service of the United States Department of Interior (MMS) issued two orders to Western Energy Company (WECO) in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 and 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 and 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. On April 28, 2005, the appeals division of the MMS issued an order that reduced the amount claimed based upon the applicable statute of limitations. The State of Montana issued a demand to WECO in May 2005 consistent with the MMS position outlined above on these transportation revenues. Further, on September 28, 2006, the MMS issued an order to pay additional royalties on the basis of an audit of WECO's royalty payments during the three years

2002 to 2004. WECO appealed these orders to the Interior Board of Land Appeals of the United States Department of Interior (IBLA) who affirmed the orders on September 12, 2007. WECO filed a complaint and request for declaratory ruling in the US District Court for the District of Columbia in January 2008 seeking relief from the orders issued by the MMS and affirmed by the IBLA, and we continue to monitor the appeals process. The Colstrip Units 3 and 4 owners and WECO currently dispute the responsibility of the expenses if the MMS position prevails. We believe that the Colstrip Units 3 and 4 owners have reasonable defenses in this matter. However, if the MMS position prevails and WECO succeeds in passing the expense responsibility to the owners, our share of the alleged additional royalties would be 15 percent, or approximately $6.0 million, and we would have ongoing royalty expenses related to coal transportation. While the percentage of our share of the alleged additional royalties is not expected to change, the estimated amount may increase as the MMS updates its assessment to reflect ongoing royalty and interest expenses.

Blue Dot Arbitration

During the second quarter of 2008, our subsidiary Blue Dot Services, LLC (Blue Dot) lost an arbitration matter with an insurance carrier and the insurance carrier was awarded $3.4 million plus interest related to a dispute that originated in 2007. The award was partially satisfied by $2.5 million in letter of credit draws by the insurance carrier. Blue Dot has approximately $300,000 in remaining cash and will likely need to liquidate through a bankruptcy filing. We classified Blue Dot as a discontinued operation in 2003. We do not anticipate Blue Dot’s ultimate liquidation will have a material adverse effect, if any, on our financial position.

MPSC Investigation

During the first quarter of 2008, the MPSC opened a proceeding to investigate our compliance with a 2004 MPSC order limiting our ability to provide loans, guarantees, advances, equity investments or working capital to subsidiaries or affiliates. This proceeding is in response to an MCC complaint that we violated the MPSC’s order when we purchased our previously leased interests in Colstrip Unit 4. We have provided documentation to the MPSC that we did not violate their order. The investigation is ongoing and we do not anticipate the outcome will have a material adverse effect, if any, on our financial position.

We are also subject to various other legal proceedings, governmental audits 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.

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, provides electricity and natural gas to approximately 650,000 customers in Montana, South Dakota and Nebraska. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended December 31, 2007.

Highlights

Recent highlights include:

•

Improved net income of $7.1 million as compared with the second quarter of 2007 due to higher margins as discussed below;

•

Began trading on the New York Stock Exchange beginning May 1, 2008;

•

Announced a share buyback program for approximately 3.1 million shares, equal to the number of shares in our disputed claim reserve;

•

Concluded our review of strategic options related to our interest in Colstrip Unit 4 by signing a purchase and sale agreement with Bicent (Montana) Power Company LLC (Bicent) for $404 million in cash. The agreement allows us to explore the viability of placing the asset in rate base;

•

Obtained approval of the stipulated agreement in our Montana electric and natural gas rate case filings by the MPSC;

•

Secured an upgrade of our senior secured and senior unsecured credit ratings by Moody’s Investors Service (Moody’s), giving us an investment grade credit rating with each of the three independent credit-rating agencies that rate us, including Fitch Investors Service (Fitch) and Standard and Poor’s Rating Group (S&P); and

•

Received approval of the settlement with Magten by the Bankruptcy Court, which resolves the last significant claim in our bankruptcy case and provides for reimbursement of previously incurred legal fees and expenses of $4 million.

Proposed Colstrip Unit 4 Transaction

Magten Settlement

In July 2008, the US Bankruptcy Court approved a settlement agreement between NorthWestern, Magten Asset

Management (Magten), Law Debenture Trust Company of New York (Law Debenture) and the Plan Committee that resolves the litigation related to claims of holders of quarterly income preferred securities (QUIPS) in our Chapter 11 bankruptcy case. On July 23, 2008 the Ad Hoc Committee filed an appeal to the global settlement agreement, however, we and the other parties involved waived a closing condition and closed on the settlement on July 24, 2008. Under the approved global settlement agreement Magten, Law Debenture, their lawyers and the holders of the QUIPS, collectively received a cash payment of $23 million to be allocated amongst them in accordance with the terms of the global settlement agreement. The cash payment was funded by our repurchase of 782,059 shares held in the disputed claims reserve established under our confirmed Plan of Reorganization. This settlement resolves the last significant claim from the bankruptcy case, and also provided for reimbursement of previously incurred legal fees and expenses of $4 million. See Note 14 – Legal Proceedings for further discussion.

OVERALL CONSOLIDATED RESULTS

The following is a summary of our results of operations for the three and six months ended June 30, 2008 and 2007. 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, 2008 Compared with the Three Months Ended June 30, 2007

	Three Months Ended June 30,
		2008			2007			Change		% Change
		(in millions)
Operating Revenues
Regulated Electric	$	179.0		$	170.6		$	8.4		4.9		%
Regulated Natural Gas		80.5			62.0			18.5		29.8
Unregulated Electric		16.5			14.6			1.9		13.0
Other		8.7			16.7			(8.0	)	(47.9	)
Eliminations		(8.2	)		(4.3	)		(3.9	)	(90.7	)
	$	276.5		$	259.6		$	16.9		6.5		%

	Three Months Ended June 30,
		2008			2007			Change		% Change
		(in millions)
Cost of Sales
Regulated Electric	$	87.2		$	87.9		$	(0.7	)	(0.8	)	%
Regulated Natural Gas		49.9			36.9			13.0		35.2
Unregulated Electric		11.6			4.2			7.4		176.2
Other		8.4			16.2			(7.8	)	(48.1	)
Eliminations		(7.8	)		(4.0	)		(3.8	)	(95.0	)
	$	149.3		$	141.2		$	8.1		5.7		%

	Three Months Ended June 30,
		2008			2007			Change		% Change
		(in millions)
Gross Margin
Regulated Electric	$	91.8		$	82.7		$	9.1		11.0		%
Regulated Natural Gas		30.6			25.1			5.5		21.9
Unregulated Electric		4.9			10.4			(5.5	)	(52.9	)
Other		0.3			0.5			(0.2	)	(40.0	)
Eliminations		(0.4	)		(0.3	)		(0.1	)	(33.3	)
	$	127.2		$	118.4		$	8.8		7.4		%

Consolidated gross margin for the three months ended June 30, 2008 was $127.2 million, an increase of $8.8 million, or 7.4%, as compared with gross margin of $118.4 million in the second quarter of 2007. The following summarizes components of the change:

	Gross Margin
	2008 vs. 2007
	(Millions of Dollars)
Rate increases	$	4.9
Regulated electric and gas volumes	3.0
Regulated electric QF supply costs	3.9
Regulated electric wholesale	2.0
Unregulated electric volumes	5.2
Unregulated electric pricing and fuel supply costs	(5.5		)
Unregulated electric unrealized loss on forward contracts	(5.2		)
Other	0.5
Improvement in Gross Margin	$	8.8

Improvements in gross margin were due to regulated electric and gas rate increases, increases in volumes from customer growth and usage, and lower qualifying facility (QF) supply costs based on actual QF pricing and output. In addition, we had improved electric wholesale margin due to increased plant availability. These improvements were partially offset by an overall decrease in our unregulated electric margin primarily due to a combination of lower average contracted prices and an increase in unrealized losses on forward contracts due to changes in forward prices of electricity. These forward contracts economically hedge a portion of our Colstrip Unit 4 output through 2009. The unrealized losses will reverse as the power is delivered and the underlying transactions are executed.

	Three Months Ended June 30,
		2008		2007		Change		% Change
		(in millions)
Operating Expenses
Operating, general and administrative	$	53.9	$	58.7	$	(4.8	)	(8.2	)	%
Property and other taxes		20.5		20.6		(0.1	)	(0.5	)
Depreciation		21.2		20.8		0.4		1.9
	$	95.6	$	100.1	$	(4.5	)	(4.5	)	%

Consolidated operating, general and administrative expenses were $53.9 million for the three months ended June 30, 2008 as compared with $58.7 million in the second quarter of 2007.

	Operating, General & Administrative Expenses
	2008 vs. 2007
	(Millions of Dollars)
Operating lease expense	$	(3.6	)
Legal and professional fees	(4.5		)
Other	3.3
Reduction in Operating, General & Administrative Expenses	$	(4.8	)

The reduction in operating, general and administrative expenses of $4.8 million was primarily due to decreased operating lease expense related to the purchase of our previously leased interest in Colstrip Unit 4 during 2007 (we expect operating lease expense to decrease $14.4 million in 2008) and lower legal and professional fees, which includes the reversal of the $1.8 million judgment related to the City of Livonia shareholder litigation that was previously recorded in the first quarter of 2008 due to an insurance recovery. In July 2008, we received a reimbursement of previously incurred legal fees in connection with the Magten settlement discussed above. This

receipt will reduce our operating, general and administrative expenses by $4.0 million during the third quarter of 2008.

Property and other taxes remained flat, with $20.5 million for the three months ended June 30, 2008 as compared to $20.6 million in the second quarter of 2007. Property taxes in 2007 are net of approximately $1.7 million collected through our Montana property tax tracker.

Depreciation expense was $21.2 million for the three months ended June 30, 2008 as compared with $20.8 million in the second quarter of 2007. The increase was primarily due to the purchase of our previously leased interest in Colstrip Unit 4.

Consolidated operating income for the three months ended June 30, 2008 was $31.5 million, as compared with $18.2 million in the second quarter of 2007. This $13.3 million increase was due to the $8.8 million increase in gross margin and lower operating expenses as discussed above.

Consolidated interest expense for the three months ended June 30, 2008 was $15.8 million, an increase of $1.3 million, or 9.0%, from the second quarter of 2007. This increase was primarily related to the additional debt incurred with the purchase of our previously leased interest in Colstrip Unit 4.

Consolidated income tax expense for the three months ended June 30, 2008 was $6.0 million as compared with $1.6 million in the second quarter of 2007. Our effective tax rate for 2008 was 38.7% as compared to 39.0% for 2007. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

Consolidated net income for the three months ended June 30, 2008 was $9.5 million as compared with $2.4 million for the second quarter of 2007. This increase was primarily due to improved margins.

Six Months Ended June 30, 2008 Compared with the Six Months Ended June 30, 2007

	Six Months Ended June 30,
		2008			2007			Change		% Change
		(in millions)
Operating Revenues
Regulated Electric	$	375.6		$	349.1		$	26.5		7.6		%
Regulated Natural Gas		252.2			220.2			32.0		14.5
Unregulated Electric		37.0			36.8			0.2		0.5
Other		16.5			32.8			(16.3	)	(49.7	)
Eliminations		(18.8	)		(12.8	)		(6.0	)	(46.9	)
	$	662.5		$	626.1		$	36.4		5.8		%

	Six Months Ended June 30,
		2008			2007			Change		% Change
		(in millions)
Cost of Sales
Regulated Electric	$	190.3		$	180.7		$	9.6		5.3		%
Regulated Natural Gas		171.2			152.1			19.1		12.6
Unregulated Electric		18.7			8.4			10.3		122.6
Other		16.1			31.2			(15.1	)	(48.4	)
Eliminations		(17.8	)		(11.9	)		(5.9	)	(49.6	)
	$	378.5		$	360.5		$	18.0		5.0		%

	Six Months Ended June 30,
		2008			2007			Change		% Change
		(in millions)
Gross Margin
Regulated Electric	$	185.3		$	168.4		$	16.9		10.0		%
Regulated Natural Gas		81.0			68.1			12.9		18.9
Unregulated Electric		18.3			28.4			(10.1	)	(35.6	)
Other		0.4			1.6			(1.2	)	(75.0	)
Eliminations		(1.0	)		(0.9	)		(0.1	)	(11.1	)
	$	284.0		$	265.6		$	18.4		6.9		%

Consolidated gross margin was $284.0 million for the six months ended June 30, 2008, an increase of $18.4 million, or 6.9%, from gross margin in the same period of 2007. The following summarizes components of the change:

	Gross Margin
	2008 vs. 2007
	(Millions of Dollars)
Rate increases	$	10.6
Regulated electric and gas volumes	10.0
Regulated electric QF supply costs	3.5
Regulated electric wholesale	2.6
Unregulated electric volumes	8.1
Unregulated electric pricing and fuel supply costs	(11.8		)
Unregulated electric unrealized loss on forward contracts	(6.4		)
Other	1.8
Improvement in Gross Margin	$	18.4

Improvements in regulated electric and gas margin were due to an increase in rates, an increase in volumes from customer growth and usage, and lower qualifying facility (QF) supply costs based on actual QF pricing and output. In addition, we had improved electric wholesale margin due to increased plant availability. These improvements were partially offset by an overall decrease in our unregulated electric margin primarily due to a combination of lower average contracted prices and an unrealized loss on forward contracts as discussed above.

	Six Months Ended June 30,
		2008		2007		Change		% Change
		(in millions)
Operating Expenses
Operating, general and administrative	$	113.9	$	121.1	$	(7.2	)	(5.9	)	%
Property and other taxes		44.2		41.3		2.9		7.0
Depreciation		42.3		40.7		1.6		3.9
	$	200.4	$	203.1	$	(2.7	)	(1.3	)	%

Consolidated operating, general and administrative expenses were $113.9 million for the six months ended June 30, 2008 as compared with $121.1 million in the same period of 2007.

	Operating, General & Administrative Expenses
	2008 vs. 2007
	(Millions of Dollars)
Operating lease expense	$	(8.5	)
Legal and professional fees	(1.7		)
Other	3.0
Reduction in Operating, General & Administrative Expenses	$	(7.2	)

The reduction in operating, general and administrative expenses of $7.2 million was primarily due to decreased operating lease expense related to the purchase of our previously leased interest in Colstrip Unit 4 during 2007 (we expect operating lease expense to decrease $14.4 million in 2008) and lower legal and professional fees.

Property and other taxes were $44.2 million for the six months ended June 30, 2008 as compared to $41.3 million in the same period of 2007. Property taxes in 2007 are net of approximately $2.9 million collected through our Montana property tax tracker.

Depreciation expense was $42.3 million for the six months ended June 30, 2008 as compared with $40.7 million in the same period of 2007. The increase was primarily due to the purchase of our previously leased interest in Colstrip Unit 4.

Consolidated operating income for the six months ended June 30, 2008 was $83.6 million, as compared with $62.6 million in the same period of 2007. This $21.0 million increase was due to the $18.4 million increase in gross margin and lower operating expenses as discussed above.

Consolidated interest expense for the six months ended June 30, 2008 was $31.8 million, an increase of $4.1 million, or 14.8%, from the same period of 2007. This increase was primarily related to the additional debt incurred with the purchase of our previously leased interest in Colstrip Unit 4.

Consolidated income tax expense for the six months ended June 30, 2008 was $19.2 million as compared with $14.0 million in the same period of 2007. Our effective tax rate for 2008 was 38.7% as compared to 39.0% for 2007.

Consolidated net income for the six months ended June 30, 2008 was $33.0 million compared with $21.6 million for the same period of 2007. This increase was primarily due to higher operating income offset by higher interest and income tax expense as discussed above.

REGULATED ELECTRIC SEGMENT

Three Months Ended June 30, 2008 Compared with the Three Months Ended June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

179.0

170.6

8.4

4.9

Total Cost of Sales

87.2

87.9

(0.7

)

(0.8

)

Gross Margin

91.8

82.7

9.1

11.0

% GM/Rev

51.3

48.5

The following summarizes the components of the changes in regulated electric margin for the three months ended June 30, 2008 and 2007:

	Gross Margin
	2008 vs. 2007
	(Millions of Dollars)
QF supply costs	$	3.9
Montana jurisdiction transmission and distribution rate increase	2.6
Wholesale	2.0
Customer growth and usage	0.5
FERC jurisdiction transmission interim rate increase (subject to refund)	0.4
Transmission volumes	(0.9		)
Other	0.6
Improvement in Gross Margin	$	9.1

This improvement is due to the annual adjustment of our QF related supply costs to reflect actual QF pricing and output, which was lower than our estimate; rate increases; and slightly higher wholesale margin due to increased plant availability. Lower transmission volumes with less demand to transmit energy for others across our lines partly offset these increases.

The following summarizes regulated electric volumes and customer counts for the three months ended June 30, 2008 and 2007:

	Volumes MWH
	2008		2007		Change			% Change
	(in thousands)
Retail Electric
Montana		498		461		37			8.0		%
South Dakota		105		103		2			1.9
Residential		603		564		39			6.9
Montana		756		754		2			0.3
South Dakota		200		193		7			3.6
Commercial		956		947		9			1.0
Industrial		773		746		27			3.6
Other		38		45		(7	)		(15.6	)
Total Retail Electric		2,370		2,302		68			3.0		%
Wholesale Electric		82		33		49			148.5		%

Average Customer Counts		2008		2007		Change			% Change
	Retail Electric
	Montana		265,820		262,209		3,611			1.4		%
	South Dakota		47,882		47,603		279			0.6
	Residential		313,702		309,812		3,890			1.3
	Montana		59,449		58,106		1,343			2.3
	South Dakota		11,522		11,373		149			1.3
	Commercial		70,971		69,479		1,492			2.1
	Industrial		71		70		1			1.4
	Other		5,559		5,699		(140	)		(2.5	)
	Total Retail Electric		390,303		385,060		5,243			1.4		%

	2008 as compared to:
Cooling Degree-Days	2007	Historic Average
Montana	37% colder	21% colder
South Dakota	84% colder	75% colder

Regulated electric volumes increased due primarily to customer growth. Regulated wholesale electric volumes increased due to increased plant availability as compared with 2007. Although the weather in our service territories was significantly colder than the prior year, our customer usage is not highly sensitive to these changes during the shoulder months between the heating and cooling seasons.

Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

375.6

349.1

26.5

7.6

Total Cost of Sales

190.3

180.7

9.6

5.3

Gross Margin

185.3

168.4

16.9

10.0

% GM/Rev

49.3

48.2

The following summarizes the components of the changes in regulated electric margin for the six months ended June 30, 2008 and 2007:

	Gross Margin
	2008 vs. 2007
	(Millions of Dollars)
Customer growth, usage and colder weather	$	5.0
Montana jurisdiction transmission and distribution rate increase	4.7
QF supply costs	3.5
Wholesale	2.6
FERC jurisdiction transmission interim rate increase (subject to refund)	1.1
Transmission volumes	(0.9		)
Other	0.9
Improvement in Gross Margin	$	16.9

This improvement is primarily due to rate increases and increased volumes from customer growth, usage and colder weather, lower QF supply costs as discussed above, and improved wholesale margin due to increased plant availability. Lower transmission volumes with less demand to transmit energy for others across our lines partly offset these increases.

The following summarizes regulated electric volumes and customer counts for the six months ended June 30, 2008 and 2007:

	Volumes MWH
	2008		2007		Change			% Change
	(in thousands)
Retail Electric
Montana		1,167		1,096		71			6.5		%
South Dakota		264		251		13			5.2
Residential		1,431		1,347		84			6.2
Montana		1,555		1,542		13			0.8
South Dakota		422		396		26			6.6
Commercial		1,977		1,938		39			2.0
Industrial		1,534		1,480		54			3.6
Other		63		70		(7	)		(10.0	)
Total Retail Electric		5,005		4,835		170			3.5		%
Wholesale Electric		131		65		66			101.5		%

Average Customer Counts		2008		2007		Change			% Change
	Retail Electric
	Montana		265,962		262,191		3,771			1.4		%
	South Dakota		47,895		47,634		261			0.5
	Residential		313,857		309,825		4,032			1.3
	Montana		59,299		57,912		1,387			2.4
	South Dakota		11,427		11,279		148			1.3
	Commercial		70,726		69,191		1,535			2.2
	Industrial		71		71		—			—
	Other		5,106		5,146		(40	)		(0.8	)
	Total Retail Electric		389,760		384,233		5,527			1.4		%

	2008 as compared to:
Cooling Degree-Days	2007	Historic Average
Montana	37% colder	21% colder
South Dakota	84% colder	75% colder

Regulated electric volumes increased due primarily to customer growth, usage and colder weather during the first quarter of 2008. Regulated wholesale electric volumes increased due to increased plant availability as compared with 2007. There are no cooling degree days in the first three months of the year in our service territories; therefore, cooling degree-days are the same for the three and six months ended June 30, 2008.

REGULATED NATURAL GAS SEGMENT

Three Months Ended June 30, 2008 Compared with the Three Months Ended June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

80.5

62.0

18.5

29.8

Total Cost of Sales

49.9

36.9

13.0

35.2

Gross Margin

30.6

25.1

5.5

21.9

% GM/Rev

38.0

40.5

The following summarizes the components of the changes in regulated natural gas margin for the three months ended June 30, 2008 and 2007:

	Gross Margin
	2008 vs. 2007
	(Millions of Dollars)
Colder weather and customer growth	$	3.4
South Dakota and Nebraska jurisdictions transportation and distribution rate increase	1.1
Montana jurisdiction transportation and distribution rate increase	0.8
Storage	0.2
Improvement in Gross Margin	$	5.5

This improvement is primarily due to increased volumes due to colder weather and 1.3% customer growth, along with rate increases.

The following summarizes regulated natural gas volumes, customer counts and heating degree-days for the three months ended June 30, 2008 and 2007:

	Volumes Dekatherms
	2008		2007		Change			% Change
	(in thousands)
Retail Gas
Montana		2,523		1,955		568			29.1		%
South Dakota		589		466		123			26.4
Nebraska		526		412		114			27.7
Residential		3,638		2,833		805			28.4
Montana		1,234		981		253			25.8
South Dakota		542		434		108			24.9
Nebraska		596		483		113			23.4
Commercial		2,372		1,898		474			25.0
Industrial		16		24		(8	)		(33.3	)
Other		29		20		9			45.0
Total Retail Gas		6,055		4,775		1,280			26.8		%

Average Customer Counts		2008		2007		Change			% Change
	Retail Gas
	Montana		155,546		152,968		2,578			1.7		%
	South Dakota		36,498		36,527		(29	)		(0.1	)
	Nebraska		36,344		36,109		235			0.7
	Residential		228,388		225,604		2,784			1.2
	Montana		21,770		21,308		462			2.2
	South Dakota		5,760		5,732		28			0.5
	Nebraska		4,519		4,513		6			0.1
	Commercial		32,049		31,553		496			1.6
	Industrial		305		312		(7	)		(2.2	)
	Other		139		141		(2	)		(1.4	)
	Total Retail Gas		260,881		257,610		3,271			1.3		%

	2008 as compared with:
Heating Degree-Days	2007	Historic Average
Montana	25% colder	10% colder
South Dakota	36% colder	12% colder
Nebraska	44% colder	10% colder

Regulated natural gas volumes increased due to colder weather and customer growth.

Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

252.2

220.2

32.0

14.5

Total Cost of Sales

171.2

152.1

19.1

12.6

Gross Margin

81.0

68.1

12.9

18.9

% GM/Rev

32.1

30.9

The following summarizes the components of the changes in regulated natural gas margin for the six months ended June 30, 2008 and 2007:

	Gross Margin
	2008 vs. 2007
	(Millions of Dollars)
Colder weather and customer growth	$	5.9
South Dakota and Nebraska jurisdictions transportation and distribution rate increase	2.8
Montana jurisdiction transportation and distribution rate increase	2.0
Transfer of previously unregulated customers	0.7
Storage	0.6
Other	0.9
Improvement in Gross Margin	$	12.9

This improvement is primarily due to increased volumes due to colder weather and 1.3% customer growth along with rate increases.

The following summarizes regulated natural gas volumes, customer counts and heating degree-days for the six months ended June 30, 2008 and 2007:

	Volumes Dekatherms
	2008		2007		Change			% Change
	(in thousands)
Retail Gas
Montana		8,091		6,989		1,102			15.8		%
South Dakota		2,196		1,992		204			10.2
Nebraska		1,931		1,794		137			7.6
Residential		12,218		10,775		1,443			13.4
Montana		3,991		3,510		481			13.7
South Dakota		1,920		1,615		305			18.9
Nebraska		1,880		1,707		173			10.1
Commercial		7,791		6,832		959			14.0
Industrial		136		96		40			41.7
Other		82		108		(26	)		(24.1	)
Total Retail Gas		20,227		17,811		2,416			13.6		%

Average Customer Counts		2008		2007		Change			% Change
	Retail Gas
	Montana		155,652		152,953		2,699			1.8		%
	South Dakota		36,706		36,708		(2	)		—
	Nebraska		36,616		36,441		175			0.5
	Residential		228,974		226,102		2,872			1.3
	Montana		21,728		21,247		481			2.3
	South Dakota		5,799		5,764		35			0.6
	Nebraska		4,556		4,548		8			0.2
	Commercial		32,083		31,559		524			1.7
	Industrial		306		315		(9	)		(2.9	)
	Other		139		140		(1	)		(0.7	)
	Total Retail Gas		261,502		258,116		3,386			1.3		%

	2008 as compared with:
Heating Degree-Days	2007	Historic Average
Montana	14% colder	3% colder
South Dakota	11% colder	5% colder
Nebraska	12% colder	5% colder

Regulated natural gas volumes increased due to colder weather and customer growth.

UNREGULATED ELECTRIC SEGMENT

Three Months Ended June 30, 2008 Compared with the Three Months Ended June 30, 2007

Our unregulated electric segment primarily consists of our joint ownership in the Colstrip Unit 4 generation facility, which represents approximately 30% or approximately 222 MWs at full load. We sell our Colstrip Unit 4 output principally to two unrelated third parties under agreements through December 2010. Under a separate agreement we repurchase 111 MWs through December 2010. These 111 MWs were available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 MWs of base-load energy from Colstrip Unit 4 are being supplied to the Montana electric supply load (included in our regulated electric segment) for a term of 11.5 years at an average nominal price of $35.80 per MWH. In addition, 21 MWs of base-load energy from Colstrip Unit 4 are being provided to the Montana electric supply load for a term of 76 months beginning in March 2008 at $19 per MWH below the Mid-C Index price with a floor of zero.

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

16.5

14.6

1.9

13.0

Total Cost of Sales

11.6

4.2

7.4

176.2

Gross Margin

4.9

10.4

(5.5

)

(52.9

)

% GM/Rev

29.7

71.2

The following summarizes the components of the changes in unregulated electric margin for the three months ended June 30, 2008 and 2007:

	Gross Margin
	2008 vs. 2007
	(Millions of Dollars)
Volumes	$	5.2
Average prices	(3.2		)
Unrealized loss on forward contracts	(5.2		)
Fuel supply costs	(2.3		)
Decline in Gross Margin	$	(5.5	)

The decrease in margin was primarily due to lower average contracted prices and higher fuel supply costs. In addition, we recorded an unrealized loss of $5.2 million during the second quarter of 2008 on forward contracts due to changes in forward prices of electricity. These contracts economically hedge a portion of our Colstrip Unit 4 output through 2009, and do not qualify for hedge accounting, therefore market value adjustments are included in cost of sales. The unrealized losses will reverse as the power is delivered and the underlying transactions are executed. An increase in volumes from higher plant availability partly offset these decreases.

The following summarizes unregulated electric volumes for the three months ended June 30, 2008 and 2007:

	Volumes MWH
	2008	2007	Change	% Change
	(in thousands)
Wholesale Electric	416	307	109	35.5	%

The increase in energy available to sell as compared with 2007 was due to increased plant availability.

We expect our margin to decrease throughout 2008 under the terms of our Colstrip Unit 4 commitments to Montana regulated electric supply discussed above. See the Overview section for additional information related to our Colstrip Unit 4 strategic review process.

Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

37.0

36.8

0.2

0.5

Total Cost of Sales

18.7

8.4

10.3

122.6

Gross Margin

18.3

28.4

(10.1

)

(35.6

)

% GM/Rev

49.5

77.2

The following summarizes the components of the changes in unregulated electric margin for the six months ended June 30, 2008 and 2007:

	Gross Margin
	2008 vs. 2007
	(Millions of Dollars)
Volumes	$	8.1
Average prices	(8.8		)
Unrealized loss on forward contracts	(6.4		)
Fuel supply costs	(3.0		)
Decline in Gross Margin	$	(10.1	)

The decrease in margin was primarily due to lower average contracted prices and higher fuel supply costs. In addition, as discussed above, we recorded an unrealized loss of $6.4 million during the first six months of 2008 related to economic hedges due to changes in forward prices of electricity. An increase in volumes from higher plant availability partly offset these decreases.

The following summarizes unregulated electric volumes for the six months ended June 30, 2008 and 2007:

	Volumes MWH
	2008	2007	Change	% Change
	(in thousands)
Wholesale Electric	891	735	156	21.2	%

The increase in energy available to sell as compared with 2007 was due to increased plant availability.

LIQUIDITY AND CAPITAL RESOURCES

We utilize our revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to reduce borrowings. As of June 30, 2008, we had cash and cash equivalents of $24.2 million, and revolver availability of $178.4 million. During the six months ended June 30, 2008, we used existing cash to repay $42.9 million of debt, paid dividends on common stock of $25.7 million, property tax payments of $42.8 million and contributed $21.9 million to our pension plans.

Factors Impacting our Liquidity

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

The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we usually under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms, which do not impact net income, can have a significant effect on cash flow from operations and make year-to-year comparisons difficult.

As of June 30, 2008, we are over collected on our current Montana natural gas and electric trackers by approximately $35.7 million, as compared with an over collection of $20.7 million as of June 30, 2007. This over collection is primarily due to increases in our electric supply rates during 2007 based on higher forward contracted prices. This has the effect of phasing in the supply cost increases over two years.

Cash Flows

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

		Six Months Ended June 30,
		2008			2007
Operating Activities
Net income	$	33.0		$	21.6
Non-cash adjustments to net income		73.0			58.3
Changes in working capital		27.0			66.0
Other		(8.4	)		(9.7	)
		124.6			136.2
Investing Activities
Property, plant and equipment additions		(43.1	)		(52.6	)
Sale of assets		—			0.6
Colstrip Unit 4 acquisition		—			(40.2	)
		(43.1	)		(92.2	)
Financing Activities
Net repayment of debt		(42.9	)		(33.9	)
Dividends on common stock		(25.7	)		(22.3	)
Other		(1.5	)		10.3
		(70.1	)		(45.9	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	11.4		$	(1.9	)
Cash and Cash Equivalents, beginning of period	$	12.8		$	1.9
Cash and Cash Equivalents, end of period	$	24.2		$	—

Cash Provided by Operating Activities

As of June 30, 2008, cash and cash equivalents were $24.2 million, as compared with $12.8 million at December 31, 2007 and no cash and cash equivalents at June 30, 2007. Cash provided by operating activities totaled $124.6 million for the six months ended June 30, 2008 as compared with $136.2 million during the six months ended June 30, 2007. This decrease in operating cash flows was primarily related to the timing of accounts receivable collections, partially offset by decreased purchases of storage gas and higher net income.

Cash Used in Investing Activities

Cash used in investing activities totaled $43.1 million during the six months ended June 30, 2008, as compared with $92.2 million during the six months ended June 30, 2007. During the six months ended June 30, 2008 we invested $43.1 million in property, plant and equipment additions as compared with $52.6 million in 2007. In addition, in 2007 we used $40.2 million to complete the purchase of a portion of our previously leased interest in the Colstrip Unit 4 generating facility.

Cash Used in Financing Activities

Cash used in financing activities totaled $70.1 million during the six months ended June 30, 2008, as compared with $45.9 million during the six months ended June 30, 2007. During the six months ended June 30, 2008 we have made net debt repayments of $42.9 million and paid dividends on common stock of $25.7 million. During the six months ended June 30, 2007 we made debt repayments of $33.9 million and paid dividends on common stock of $22.3 million.

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 July 25, 2008, our availability under our revolving line of credit was approximately $180.7 million.

We announced a common stock repurchase program during the second quarter 2008, which allows us to repurchase approximately 3.1 million shares. This amount is equal to the number of shares in the disputed claims reserve established under our Plan of Reorganization that was confirmed by the bankruptcy court in 2004. We anticipate using approximately $75 million to $80 million to repurchase these shares during the remainder of 2008. There were no purchases during the second quarter of 2008.

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, 2008. See our Annual Report on Form 10-K for the year ended December 31, 2007 for additional discussion.

		Total		2008		2009		2010		2011		2012			Thereafter
	(in thousands)
Long-term Debt	$	763,717	$	9,684	$	120,045	$	23,605	$	6,578	$		3,792	$	600,013
Capital Leases	39,248		1,282		1,246		1,174		1,265		1,363			32,918
Future Minimum Operating Lease Payments	4,403		860		1,394		992		609		444			104
Estimated Pension and Other Postretirement Obligations (1)	87,300		2,100		22,200		22,600		21,500		18,900			N/A
Qualifying Facilities (2)	1,489,468		30,287		61,586		63,589		65,323		67,111			1,201,572
Supply and Capacity Contracts (3)	1,887,669		333,081		487,719		343,225		138,632		130,572			454,440
Contractual Interest Payments on Debt (4)	334,792		22,135		40,602		36,203		34,052		33,639			168,161
Total Commitments (5)	$	4,606,597	$	399,429	$	734,792	$	491,388	$	267,959	$		255,821	$	2,457,208

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

(2)

The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2032. Our estimated gross contractual obligation related to the QFs is approximately $1.5 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.2 billion.

(3)	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 22 years.

(4)	Contractual interest payments include an assumed average interest rate of 3.9% on the $100 million floating rate nonrecourse loan through maturity in December 2009 and no revolver borrowings.

(5)	Potential tax payments related to uncertain tax positions are not practicable to estimate and have been excluded from this table.

Credit Ratings

Fitch, Moody’s and S&P are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of July 25, 2008, our current ratings with these agencies are as follows:

	Senior Secured Rating	Senior Unsecured Rating	Corporate Rating	Outlook
Fitch (1)	BBB	BBB-	BBB-	Positive
Moody’s (2)	Baa2	Baa3	N/A	Positive
S&P (3)	A- (MT) BBB+ (SD)	BBB-	BBB	Stable

(1)	Fitch changed our outlook from stable to positive on June 23, 2008.

(2)	Moody’s upgraded our senior secured and senior unsecured credit ratings on July 9, 2008 from Baa3 and Ba2, respectively, as reflected above.

(3)	S&P upgraded our senior secured, senior unsecured, and corporate credit ratings during the first quarter of 2008 from BBB, BB-, and BB+, respectively, as reflected above.

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

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, 2008, 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, 2007. 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 market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.

Interest Rate Risk

We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. All of our debt has fixed interest rates, with the exception of our revolver and the Colstrip Lease Holdings (CLH) $100 million loan. The revolving credit facility bears interest at a variable rate (currently approximately 3.67% as of June 30, 2008) tied to the London Interbank Offered Rate (LIBOR) plus a credit spread. The CLH loan currently bears interest at approximately 4.04%, which is 1.25% over LIBOR. Based upon amounts outstanding as of June 30, 2008, a 1% increase in the LIBOR would increase our annual interest expense by approximately $1.0 million.

Commodity Price Risk

Commodity price risk is one of our most significant risks due to our lack of ownership of natural gas reserves or regulated electric generation assets within the Montana market, and our unregulated joint ownership interest in Colstrip Unit 4. 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 regulated electric supply requirements, we employ the use of market purchases, including forward purchase and sales contracts. These types of contracts are included in our electric 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 we use forward contracts to manage our exposure to the market price of electricity. We have entered into unit-contingent forward contracts for the sale of a significant portion of the output. In addition, we have economically hedged a portion of our output through 2009. As of June 30, 2008 market prices exceeded our contracted forward sales prices by approximately $6.4 million. These market value adjustments will reverse as the power is delivered.

In our all other segment, we currently have a capacity contract through 2013 with a pipeline that gives us basis risk depending on gas prices at two different delivery points. We have sales contracts with certain customers that provide for a selling price based on the index price of gas coming from a delivery point in Ventura, Iowa. The pipeline capacity contract allows us to take delivery of gas from Canada, which has historically been cheaper than gas coming from Ventura, even when including transportation costs. If the Canadian gas plus transportation cost exceeds the index price at Ventura, then we will lose money on these gas sales. The annual capacity payments are approximately $1.8 million, which represents our maximum annual exposure related to this basis risk.

Counterparty Credit Risk

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

ITEM 4.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the three months ended June 30, 2008 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 14, 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 our interest in Colstrip Unit 4 to Bicent will only be completed if certain conditions are met, including review of the option to place the asset in rate base and various federal regulatory approvals. We may not be able to obtain an equivalent selling price yielding the same economic value if the transaction is not completed.

On June 10, 2008, we entered into an agreement to sell our interest in Colstrip Unit 4 for $404 million in cash, subject to certain working capital adjustments. The agreement provides a timeline of 120 days for us to explore the viability of placing this asset into our Montana utility rate base. Consistent with these terms, on June 30, 2008, we submitted a filing with MPSC to initiate a review process to determine if it would be in the public interest to place our interest in Colstrip Unit 4 into rate base at an equivalent value to the negotiated selling price. If the MPSC does not include the asset in our Montana utility rate base as requested in the filing, we intend to complete the sale of Colstrip 4 pursuant to the terms of the purchase agreement. However, consummation of the sale is subject to significant conditions, and if those conditions are not fulfilled, or if Bicent (Montana) Power Company, the purchaser, does not perform its obligations under the purchase agreement, we may not be able to obtain a selling price equivalent to the current agreement.

We are subject to extensive governmental laws and regulations that affect our industry and our operations, which could have a material adverse effect on our results of operations and financial condition.

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

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

We are subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and liabilities.

We are subject to extensive laws and regulations imposed by federal, state and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, solid waste disposal and other environmental considerations. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations; however, possible future developments, including the promulgation of more stringent environmental laws and regulations, such as the new mercury emissions rules in Montana, and the timing of future enforcement proceedings that may be taken by environmental authorities could affect the costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures.

In addition to the requirements related to the mercury emissions rules noted above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse emissions, including a recent US Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor

organizations. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost to us of such reductions could be significant.

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

Our range of exposure for current environmental remediation obligations is estimated to be $19.8 million to $57.0 million. We had an environmental reserve of $31.2 million at June 30, 2008. 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.

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

Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rates through our monthly trackers. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, we would under recover our costs, which could adversely impact our results of operations.

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

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

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

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the electric supply with a certain minimum amount of power at an agreed upon price per MW. 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.

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 for our regulated generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of

unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone I Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major regulated generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

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

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or cool summers in the future, our results of operations and financial condition could be adversely affected. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas.

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

A downgrade of our credit ratings could adversely affect our liquidity, as counter parties could require us to post collateral. In addition, our ability to raise capital on favorable terms could be hindered, and our borrowing costs could increase.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On May 21, 2008, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

All of the Directors were elected to serve a one-year term as Directors until the 2009 Annual Meeting.

	VOTES FOR:		VOTES WITHHELD:
Stephen P. Adik		28,747,062		489,014
E. Linn Draper		28,746,192		489,884
Jon S. Fossel		28,750,349		485,727
Michael J. Hanson		28,750,272		485,804
Julia L. Johnson		28,751,838		484,238
Philip L. Maslowe		28,759,157		476,919
D. Louis Peoples		28,717,964		518,112

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

	FOR:	AGAINST:		ABSTAIN:
Votes	28,762,538		473,538		—

ITEM 6.			EXHIBITS
	(a)	Exhibits

Exhibit 4.1—Eighth Supplemental Indenture, dated as of May 1, 2008, by and between NorthWestern Corporation and The Bank of New York, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993.

Exhibit 10.1—Purchase and Sale Agreement, dated June 9, 2008, among Bicent (Montana) Power Company LLC and NorthWestern Corporation.

Exhibit 99.1—Bond Purchase Agreement, dated May 1, 2008, between NorthWestern Corporation and initial purchasers.

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: July 31, 2008	By:	/s/ BRIAN B. BIRD
		Brian B. Bird
		Chief Financial Officer
		Duly Authorized Officer and Principal Financial Officer

EXHIBIT INDEX

Exhibit Number		Description
*4.1		Eighth Supplemental Indenture, dated as of May 1, 2008, by and between NorthWestern Corporation and The Bank of New York, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993.
*10.1		Purchase and Sale Agreement, dated June 9, 2008, among Bicent (Montana) Power Company LLC and NorthWestern Corporation.
*99.1		Bond Purchase Agreement, dated May 1, 2008, between NorthWestern Corporation and initial purchasers.
*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

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Good

NorthWestern (NWE) 10-Q2008 Q2 Quarterly report

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