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 in this Quarterly Report, 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 we will achieve our projections. Factors that may cause such differences include, but are not limited to:

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 and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, 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 any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications 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.


	June 30, 2009			December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	22,963		$	11,292
Restricted cash	16,640			14,727
Accounts receivable, net	97,962			155,672
Inventories	47,350			70,741
Regulatory assets	48,822			46,905
Deferred income taxes	11,352			685
Prepaid and other	15,285			13,395
Total current assets	260,374			313,417
Property, plant, and equipment, net	1,852,378			1,839,699
Goodwill	355,128			355,128
Regulatory assets	223,380			233,102
Other noncurrent assets	28,710			20,691
Total assets	$	2,719,970		$	2,762,037
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,328		$	1,193
Current maturities of long-term debt	5,982			228,045
Accounts payable	56,121			94,685
Accrued expenses	210,310			215,431
Regulatory liabilities	46,882			49,223
Total current liabilities	320,623			588,577
Long-term capital leases	36,202			36,798
Long-term debt	862,997			634,011
Deferred income taxes	143,233			114,707
Noncurrent regulatory liabilities	234,612			222,969
Other noncurrent liabilities	353,342			401,442
Total liabilities	1,951,009			1,998,504
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,477,951 and 35,941,842, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	395			395
Treasury stock at cost	(89,554		)	(89,487		)
Paid-in capital	807,065			805,900
Retained earnings	39,203			34,371
Accumulated other comprehensive income	11,852			12,354
Total shareholders' equity	768,961			763,533
Total liabilities and shareholders' equity	$	2,719,970		$	2,762,037

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenues
Electric	$	173,463		$	178,967		$	381,450		$	375,586
Gas	61,330			80,531			220,133			252,174
Other	920			17,008			5,033			34,721
Total Revenues	235,713			276,506			606,616			662,481
Operating Expenses
Cost of sales	106,840			149,354			314,850			378,438
Operating, general and administrative	60,898			53,866			126,317			113,937
Property and other taxes	18,246			20,540			42,535			44,180
Depreciation	22,260			21,225			44,982			42,316
Total Operating Expenses	208,244			244,985			528,684			578,871
Operating Income	27,469			31,521			77,932			83,610
Interest Expense	(18,002		)	(15,848		)	(33,136		)	(31,849		)
Other Income (Expense)	198			(161		)	789			422
Income Before Income Taxes	9,665			15,512			45,585			52,183
Income Tax Expense	(3,567		)	(6,009		)	(16,674		)	(19,229		)
Net Income	$	6,098		$	9,503		$	28,911		$	32,954
Average Common Shares Outstanding	35,940			38,973			35,937			38,973
Basic Earnings per Average Common Share	$	0.17		$	0.24		$	0.80		$	0.85
Diluted Earnings per Average Common Share	$	0.17		$	0.24		$	0.80		$	0.84
Dividends Declared per Average Common Share	$	0.335		$	0.33		$	0.67		$	0.66

	Six Months Ended June 30,
	2009			2008
OPERATING ACTIVITIES:
Net Income	$	28,911		$	32,954
Items not affecting cash:
Depreciation	44,982			42,316
Amortization of debt issue costs, discount and deferred hedge gain	1,122			1,202
Amortization of restricted stock	1,164			2,364
Equity portion of allowance for funds used during construction	(275		)	(282		)
Gain on sale of assets	(223		)	(110		)
Unrealized loss on derivative instruments	—			6,396
Deferred income taxes	17,858			21,115
Changes in current assets and liabilities:
Restricted cash	(1,913		)	(5,038		)
Accounts receivable	57,710			26,780
Inventories	23,391			16,282
Prepaid energy supply costs	182			375
Other current assets	(2,028		)	(288		)
Accounts payable	(39,097		)	(23,569		)
Accrued expenses	(9,867		)	(5,324		)
Regulatory assets	963			5,808
Regulatory liabilities	(2,341		)	11,933
Other noncurrent assets	11,387			12,159
Other noncurrent liabilities	(46,395		)	(20,419		)
Cash provided by operating activities	85,531			124,654
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(46,986		)	(43,087		)
Proceeds from sale of assets	326			29
Cash used in investing activities	(46,660		)	(43,058		)
FINANCING ACTIVITIES:
Dividends on common stock	(24,079		)	(25,722		)
Issuance of long-term debt, net of discount	249,833			55,000
Repayment of long-term debt	(135,011		)	(85,939		)
Line of credit borrowings	237,000			14,000
Line of credit repayments	(345,000		)	(26,000		)
Financing costs	(9,943		)	(1,466		)
Cash used in financing activities	(27,200		)	(70,127		)
Increase in Cash and Cash Equivalents	11,671			11,469
Cash and Cash Equivalents, beginning of period	11,292			12,773
Cash and Cash Equivalents, end of period	$	22,963		$	24,242
Supplemental Cash Flow Information:
Cash paid during the period for:
Income Taxes	2			43
Interest	20,305			24,479

(Reference is made to Notes to Financial Statements included in NorthWestern Corporation’s Annual Report)

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 656,000 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 Condensed Consolidated Financial Statements (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 (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited 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. Events occurring subsequent to June 30, 2009, have been evaluated as to their potential impact to the Financial Statements through the date of issuance, July 29, 2009.

The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with audited Financial Statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

In June 2009, the Financial Accounting Standards Board (FASB) issued Statements of Financial Accounting Standards (SFAS) No. 166, Accounting for Transfers of Financial Assets (SFAS No. 166), and No. 167, Amendments to FASB Interpretation No. 46(R) (SFAS No. 167), which change the way entities account for securitizations and special-purpose entities. SFAS No. 166 is a revision to SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and will require more information about transfers of financial assets, including securitization transactions, and any continuing exposure to the risks related to such transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures.

SFAS No. 167 is a revision to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities (FIN 46R), and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar) rights should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. SFAS No 167 revises the approach to determining the primary beneficiary of a variable interest entity (VIE) to be more qualitative in nature and requires companies to more frequently reassess whether they must consolidate a VIE. SFAS No. 166 and SFAS No. 167 are effective for fiscal years beginning after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. We are currently evaluating the impact, if any, of adopting SFAS No. 166 and SFAS No. 167 on our financial position and results of operations.

In July 2009, the FASB issued SFAS No. 168, FASB Accounting Standards Codification (SFAS No. 168), as the single source of authoritative nongovernmental GAAP. The Codification is effective for interim and annual periods ending after September 15, 2009. All existing accounting standards are superseded as described in SFAS No. 168, aside from those issued by the SEC. All other accounting literature not included in the Codification is nonauthoritative. We do not expect the adoption of SFAS No. 168 to impact our financial position or results of operations. This statement will be reflected in our disclosures beginning with the third quarter of 2009.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS No. 141R), which replaces SFAS No. 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired. SFAS No. 141R also establishes disclosure requirements, which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, and interim periods within those fiscal years. SFAS No. 141R was effective beginning January 1, 2009; accordingly, any business combinations we engage in will be recorded and disclosed in accordance with this statement. In addition, if any of our unrecognized tax benefits reverse, they will affect the income tax provision in the period of reversal rather than goodwill. See Note 4, Income Taxes, for further information.

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. The disclosures required by this statement are included in Note 7, Risk Management and Hedging Activities.

In April 2009, the FASB issued three Final Staff Positions (FSPs) intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. The FSPs are effective for interim and annual periods ending after June 15, 2009. FSP 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP 157-4), provides guidelines for making fair value measurements more consistent with the principles presented in FASB Statement No. 157, Fair Value Measurements, and relates to determining fair values when there is no active market or where the price inputs being used represent distressed sales. FSP 115-2 and 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (FSP 115-2 and 124-2), provide additional guidance on presenting impairment losses on securities to bring consistency to the timing of impairment recognition, and provide clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold. The FSP also requires increased and more timely disclosures sought by investors regarding expected cash flows, credit losses, and an aging of securities with unrealized losses. The adoption of FSP 157-4, FSP 115-2 and 124-2, did not have a material impact on our financial position or results of operations.

FSP 107-1, Interim Disclosures about Fair Value of Financial Instruments (FSP 107-1), increases the frequency of fair value disclosures required by SFAS No. 107, Disclosures About Fair Value of Financial Instruments (SFAS No. 107). FSP 107-1 relates to fair value disclosures for any financial instruments that are not currently reflected on the balance sheet of companies at fair value. Prior to issuing this FSP, fair values for these assets and liabilities were only required to be disclosed once a year. The FSP now requires these disclosures on a quarterly basis, providing qualitative and quantitative information about fair value estimates for all those financial instruments not measured on the balance sheet at fair value. The disclosures required by this statement are included in Note 8, Fair Value Measurements.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS No. 165), which provides guidance to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 does not result in significant

changes in the subsequent events that an entity reports. Rather, SFAS No. 165 requires disclosure of the date through which subsequent events have been evaluated and whether that date represents the date the financial statements were issued or were available to be issued. SFAS No. 165 is effective for interim and annual periods ending after June 15, 2009. The disclosures required by this statement are included in Note 1, Nature of Operations and Basis of Consolidation.

FIN 46R requires the consolidation of entities which are determined to be 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 (QF) plants. After evaluation of these contracts, we believe one QF contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this QF 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 QF contract as an executory contract as we have been unable to obtain the necessary information from this QF 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 QF, our estimated gross contractual payments aggregate approximately $481.4 million through 2025, and are included in Contractual Obligations and Other Commitments of Management's Discussion and Analysis.

We have unrecognized tax benefits of approximately $115.0 million as of June 30, 2009, including approximately $78.3 million that if recognized, would impact 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 statutes 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, 2009, we have not recognized expense for interest or penalties, and do not have any amounts accrued at June 30, 2009 and December 31, 2008, respectively, for the payment of interest and penalties.

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

There were no changes in our goodwill during the six months ended June 30, 2009. Goodwill by segment is as follows for both June 30, 2009 and December 31, 2008 (in thousands):

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.

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income	$	6,098		$	9,503		$	28,911		$	32,954
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		141			20			92			(62	)
Comprehensive income	$	5,942		$	9,226		$	28,409		$	32,298

We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. Commodity price risk is one of our most significant risks due to our lack of ownership of natural gas reserves and minimal ownership of regulated electric generation assets within the Montana market. Several factors influence price levels and volatility. 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.

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts, such as fixed-price forward purchase and sales contracts. The objective of these transactions is to fix the price for a portion of anticipated energy purchases to supply our regulated customers. These types of contracts are included in our electric and natural gas supply portfolios 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. We do not maintain a trading portfolio, and do not currently have any derivatives transactions that are not used for risk management purposes. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

The accounting requirements for derivative instruments are governed by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended, which 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 evaluate new and existing transactions and agreements to determine whether they are derivatives. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria prescribed by SFAS No. 133, both at the time of designation and on an ongoing basis. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market.

We have applied the normal purchase and normal sale scope exception (NPNS), as provided by SFAS No. 133 and interpreted by Derivatives Implementation Guidance Issue C15, to most of our contracts involving the physical

purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Financial Statements at June 30, 2009 and December 31, 2008. 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.

Certain contracts for the physical purchase of natural gas associated with our regulated gas utilities do not qualify for NPNS. These are typically forward purchase contracts for natural gas where we lock in a fixed price; however the contracts are settled financially and we do not take physical delivery of the natural gas. We use the mark-to-market method of accounting for these derivative contracts as we do not elect hedge accounting. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements therefore we apply SFAS No. 71, Accounting for the Effects of Certain Types of Regulations and record a regulatory asset or liability based on changes in market value.

The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 8.

The following table represents the net change in fair value for these derivatives (in thousands):

We are exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties.

We enter into commodity master arrangements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are : Western Systems Power Pool agreements (WSPP) – standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements (NAESB) – standardized physical gas contracts.

Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, it would be in violation of these provisions, and the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.

The following table presents, as of June 30, 2009, the aggregate fair value of forward purchase contracts that do not qualify as normal purchases in a net liability position with credit risk-related contingent features, collateral posted, and the aggregate amount of additional collateral that we would be required to post with counterparties, if the credit risk-related contingent features underlying these agreements were triggered on June 30, 2009 (in thousands):

If we enter into contracts to hedge the variability of cash flows related to forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. The relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods in which earnings are affected by the variability of the cash flows of the related hedged item. Any ineffective portion of all hedges would be recognized in current-period earnings. Cash flows related to these contracts are classified in the same category as the transaction being hedged.

We have used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. 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 AOCI. We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these derivative instruments on the Financial Statements:

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. These gains relate to swaps previously terminated, and we have no current interest rate swaps outstanding.

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. SFAS No. 157 establishes a three-level fair value hierarchy and requires fair value disclosures based upon this hierarchy. In addition, FSP 157-2, Effective Date of SFAS No. 157, deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities, was effective beginning with the first quarter of 2009. This FSP had no impact on our disclosures for the second quarter of 2009 and will be applied prospectively as applicable.

We present our derivative assets and liabilities on a net basis in the Condensed Consolidated Balance Sheets. The table below disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required by SFAS No. 157, and classifies each individual asset or liability within the appropriate level in the fair

value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts. These gross balances are intended solely to provide information on sources of inputs to fair value and do not represent our actual credit exposure or net economic exposure. Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices. 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 are not included in the fair values by source table as they are not recorded at fair value. See Note 7 for further discussion.

June 30, 2009	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
	(in thousands)
Cash equivalents	$	9,000	$	—		$	—	$	—	$	9,000
Restricted cash		15,483		—			—		—		15,483
Derivative asset (1)		—		127			—		—		127
Derivative liability (1)		—		(32,106	)		—		—		(32,106	)
Net derivative position		—		(31,979	)		—		—		(31,979	)
Total	$	24,483	$	(31,979	)	$	—	$	—	$	(7,496	)

Cash equivalents and restricted cash represent amounts held in money market mutual funds. Fair value for the commodity derivatives was determined using internal models based on quoted forward commodity prices. We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). SFAS No. 157 also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Consideration of our own credit risk did not have a material impact on our fair value measurements.

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, Disclosures About Fair Value of Financial Instruments. The estimated fair-value amounts have been determined using available market information and appropriate valuation methodologies. However, considerable judgment is necessarily required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

We used the following methods and assumptions to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

The fair value estimates presented herein are based on pertinent information available to us as of June 30, 2009.

The estimated fair value of financial instruments is summarized as follows (in thousands):

In March 2009, we issued $250 million of Montana First Mortgage Bonds at a fixed interest rate of 6.34% maturing April 1, 2019, which were discounted to yield 6.349%. The bonds are secured by our Montana electric and natural gas assets. The bonds were issued in a transaction exempt from registration under the Securities Act of 1933, as amended. We are obligated to offer to exchange these bonds for a like series of bonds registered under the Securities Act of 1933 by the end of 2009. We used the proceeds to redeem our $100 million Colstrip Lease Holdings LLC term loan, repay outstanding borrowings on our revolving credit facility, repay other outstanding debt obligations of $31.7 million related to Colstrip Unit 4, fund a portion of the costs of the Mill Creek generation project, and fund future capital expenditures.

On June 30, 2009, we amended and restated our unsecured revolving line of credit scheduled to expire on November 1, 2009. The amended facility extends the term to June 30, 2012, and increases the aggregate principal amount available under the facility by $50 million to $250 million. The amended facility does not amortize and borrowings will bear interest based on a credit ratings grid. The ‘spread’ or ‘margin’ ranges from 2.25% to 4.0% over the London Interbank Offered Rate (LIBOR). On the closing date of the agreement, the applicable spread was 3.0%. A total of nine banks participate in the new facility, with no one bank providing more than 14% of the total availability. The amended facility contains covenants substantially similar to the previous facility.

In January 2009, as a result of a 2008 Montana Public Service Commission (MPSC) order, we placed our joint ownership interest in Colstrip Unit 4, which had previously been an unregulated asset, into utility rate base at a value of $407 million. The order included a capital structure of 50% equity and 50% debt, an authorized return on equity of 10% and cost of debt of 6.5%, which are set for 34 years, based on the estimated useful life of the plant. Our interest in Colstrip Unit 4 is expected to supply approximately 13% of our Montana base-load requirements through 2010 and approximately 25% thereafter (upon expiration of an existing power sale agreement). The generation related costs and return on rate base related to Colstrip Unit 4, including the cost of any replacement power purchased during outages, will be included in our annual electric supply tracker filing for inclusion in customer rates.

In August 2008, we filed a request with the MPSC for advanced approval to construct a 150 megawatt natural gas fired facility. The Mill Creek Generating Station, estimated to cost approximately $202 million, will provide regulating resources to balance our transmission system in Montana to maintain reliability and enable additional wind power to be integrated onto the network to meet future renewable energy portfolio needs. In May 2009, the MPSC issued an order granting approval to construct the facility, authorizing a return on equity of 10.25% and cost of debt of 6.5%, with a capital structure of 50% equity and 50% debt. In addition, the MPSC determined the $81 million cost for the turbines is prudent, with the remainder of the project costs to be submitted to the MPSC for review and approval once construction of the facility is complete. Construction began in June 2009, and the plant is scheduled to be operational by December 31, 2010. As of June 30, 2009, we have capitalized approximately $2.7 million in construction work in process related to this project.

We have completed our compliance audit under the compliance monitoring and enforcement program of the Western Electricity Coordinating Council (WECC), a regional electric reliability organization. WECC has responsibility for monitoring and enforcing compliance with mandatory reliability standards within the U.S. established by the North American Electric Reliability Corporation (NERC). In connection with the compliance audit, WECC found no violations of the applicable standards. Prior to the audit we identified violations and submitted 18 mitigation plans to WECC, and have submitted one additional plan since completion of the audit. We have completed 13 of these plans, which were resolved without penalties. We anticipate resolving the remaining violations during the third quarter of 2009.

MSTI is a proposed 500kV transmission line from southwestern Montana to southeastern Idaho. In January 2009, we filed a request with the Federal Energy Regulatory Commission (FERC) seeking negotiated rates for the proposed MSTI project. The request was not for specific rates rather it was for confirmation from the FERC that MSTI satisfies the FERC’s negotiated rate criteria. As a transmission export project in a region that lacks a regional transmission organization, MSTI has no readily available regional tariff through which it can recover its costs and thereby mitigate project development risk. The request was based on a rate approach that FERC had approved for similar projects in the region, which would provide us with the flexibility to meet market demand from primarily new renewable generation resources in Montana and to insulate our native load customers from the costs and risks of the project. FERC issued an order in May 2009 denying our request for negotiated rates, and encouraged us to meet our needs by pursuing the MSTI project on a cost-of-service basis by requesting appropriate waivers under our Open Access Transmission Tariff.

We are planning to conduct a second open season process by the end of 2009 to identify potential interest for new transmission capacity on this path due to the changing nature of generation projects. The results of the open season will be used to size the project according to customer demand. The open season process will also ensure that the projects have sufficient contracts with credit-worthy shippers to support financing. As of June 30, 2009, we have capitalized approximately $7.6 million of preliminary survey and investigative costs associated with this project.

We operate regulated electric and regulated natural gas business units, which are considered reportable business segments under SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. The remainder of our operations are presented as other. While it is not considered a business unit, other primarily consists of our remaining unregulated natural gas operations, the wind down of our captive insurance subsidiary and our unallocated corporate costs. As discussed in Note 10, the operations of our joint ownership interest in Colstrip Unit 4 were unregulated through December 31, 2008, and are included in regulated operations beginning January 1, 2009, due to an MPSC rate order. We have not revised the 2008 segment presentation due to the nature of the transfer of the asset from unregulated to the regulated business.

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
June 30, 2009	Electric			Gas			Other			Eliminations			Total
Operating revenues	$	173,463		$	61,330		$	1,306		$	(386	)	$	235,713
Cost of sales	71,623			32,842			2,375			—			106,840
Gross margin	101,840			28,488			(1,069		)	(386		)	128,873
Operating, general and administrative	44,763			19,290			(2,769		)	(386		)	60,898
Property and other taxes	13,065			5,150			31			—			18,246
Depreciation	17,951			4,301			8			—			22,260
Operating income (loss)	26,061			(253		)	1,661			—			27,469
Interest expense	(13,757		)	(3,317		)	(928		)	—			(18,002		)
Other income (expense)	182			(12		)	28			—			198
Income tax (expense) benefit	(4,789		)	1,353			(131		)	—			(3,567		)
Net income (loss)	$	7,697		$	(2,229	)	$	630		$	—			6,098
Total assets	$	1,907,466		$	795,842		$	16,662		$	—		$	2,719,970
Capital expenditures	$	23,574		$	4,903		$	—		$	—		$	28,477

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

Six Months Ended	Regulated
June 30, 2009	Electric			Gas			Other			Eliminations			Total
Operating revenues	$	381,450		$	220,133		$	5,957		$	(924	)	$	606,616
Cost of sales	166,372			141,779			6,699			—			314,850
Gross margin	215,078			78,354			(742		)	(924		)	291,766
Operating, general and administrative	87,741			41,105			(1,605		)	(924		)	126,317
Property and other taxes	31,082			11,378			75			—			42,535
Depreciation	36,342			8,623			17			—			44,982
Operating income	59,913			17,248			771			—			77,932
Interest expense	(24,907		)	(6,385		)	(1,844		)	—			(33,136		)
Other income	473			255			61			—			789
Income tax (expense) benefit	(12,855		)	(4,123		)	304			—			(16,674		)
Net income (loss)	$	22,624		$	6,995		$	(708	)	$	—			28,911
Total assets	$	1,907,466		$	795,842		$	16,662		$	—		$	2,719,970
Capital expenditures	$	38,420		$	8,566		$	—		$	—		$	46,986

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

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 shares were to vest. Common stock equivalent shares are calculated using the treasury stock method. Performance share awards are included in diluted weighted-average number of shares outstanding based upon what would be issued if the end of the reporting period was the end of the performance period of the award.

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:

Net periodic benefit cost for our pension and other postretirement plans consists of the following (in thousands):

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
	2009			2008			2009			2008
Components of Net Periodic Benefit Cost
Service cost	$	2,154		$	2,033		$	364		$	132
Interest cost	5,772			5,712			954			573
Expected return on plan assets	(4,653		)	(6,851		)	(178		)	(369		)
Amortization of prior service cost	62			63			—			—
Recognized actuarial loss (gain)	2,038			(268		)	292			(193		)
Net Periodic Benefit Cost	$	5,373		$	689		$	1,432		$	143

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
	2009			2008			2009			2008
Components of Net Periodic Benefit Cost
Service cost	$	4,135		$	4,203		$	497		$	282
Interest cost	11,853			11,438			1,575			1,184
Expected return on plan assets	(11,192		)	(13,607		)	(497		)	(658		)
Amortization of prior service cost	123			123			—			—
Recognized actuarial loss (gain)	2,038			(409		)	138			(300		)
Net Periodic Benefit Cost	$	6,957		$	1,748		$	1,713		$	508

Due to the significant decline in equity markets, we experienced plan asset market losses in 2008 in excess of 30%. This decline in plan assets, which has significantly increased our pension expense, is reflected in the increase in net periodic benefit cost above as an actuarial loss due to the use of asset smoothing. This smoothing allows the use of asset averaging, including expected returns, for a 24-month period in the determination of funding requirements. Pension costs in Montana are included in expense on a pay as you go (cash funding) basis. The MPSC authorized the recognition of pension costs based on an average of the annual funding to be made over an 8-year

period for the calendar years 2005 through 2012, therefore our pension expense differs from the net periodic benefit cost for our Montana plan.

During the first half of 2009, we contributed approximately $63.2 million to our pension plans. Our plan funding estimates are based on achieving an 8.0% return on assets. While this is a long-term assumption, our funding requirements are determined annually based on many variables, including actual plan asset returns. Our return on plan assets has been approximately 6.0% during the first half of 2009. The overall market has continued to be volatile during 2009, and if asset returns are below our assumption of 8.0% for 2009, we will likely need to increase our funding estimates.

Our liability for environmental remediation obligations is estimated to range between $22.5 million to $43.8 million. As of June 30, 2009, we have a reserve of approximately $31.7 million. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. Over time, as specific laws are implemented and we gain experience in operating under them, a portion of the costs related to such laws will become determinable, and we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, we do not expect these costs to have a material adverse effect on our consolidated financial position or ongoing operations. There can be no assurance, however, of regulatory recovery.

We maintain insurance coverage for environmental related exposure, and are currently seeking insurance recoveries. Approximately 90% of these anticipated recoveries relate to previously incurred Montana generation related environmental remediation costs, while approximately 10% of the anticipated recoveries relate to previously incurred costs and estimated future costs for other Montana matters. We received insurance proceeds of approximately $3.9 million in July 2009. The settlement agreement related to the insurance proceeds was executed in June 2009 with 30 day payment terms. As collectability was reasonably assured, we recorded a receivable in June 2009 and the portion related to previously incurred Montana generation related costs was recognized as a reduction to operating expenses, while 10% of the proceeds was recorded as a liability that may be returned to customers pending regulatory review. We anticipate receiving additional proceeds of $1.4 million during the third quarter of 2009.

Manufactured Gas Plants - Approximately $26.5 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. Our current reserve for remediation costs at this site is approximately $13.0 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 conducted limited additional site investigation, assessment and monitoring work at Kearney and Grand Island. 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 excess 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 conditions 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 is ongoing and 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 or if any additional actions beyond monitored natural attenuation will be required.

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 in 2009. Our remaining obligation to the State of Montana related to this site is approximately $0.6 million, which will be solely funded through the transfer of land and water rights associated with the former Milltown Dam operations to the State of Montana.

Coal-Fired Plants- We have a joint ownership interest in four electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. In addition, a significant portion of the electric supply we procure in the market is generated by coal-fired plants.

Global Climate Change - 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 U.S. Supreme Court decision holding that the Environmental Protection Agency (EPA) relied on improper factors in deciding not to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. In April 2009, the EPA issued a proposed finding that greenhouse gas emissions endanger the public health and welfare. The EPA’s proposed finding indicated that the current and projected levels of six greenhouse gas emissions – carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride contribute to climate change. The proposed findings were not accompanied by proposed regulations, and it is uncertain whether the EPA will finalize the endangerment finding before proposing regulations or whether it will propose regulations more quickly. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations.

Specifically, coal-fired plants have come under scrutiny due to their emissions of carbon dioxide. There is a gap between proposed emissions reduction levels and the current capabilities of technology, as there is no currently available commercial scale technology that would achieve the proposed reduction levels. Such technology may not be available within a timeframe consistent with the implementation of climate change legislation or at all. To the extent that such technology does become available, we can provide no assurance that it will be suitable or cost-effective for installation at the generation facilities in which we have a joint interest.

Although no federal laws currently limit greenhouse gas emissions, in June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, a bill introduced by Rep. Henry Waxman and Rep. Edward Markey and popularly known as the Waxman-Markey bill. The bill would regulate greenhouse gas emissions by instituting a cap-and-trade-system, in which an economy-wide cap on U.S. greenhouse gas emissions would be established starting in 2012 with a cap 3% below the baseline 2005 level. The cap would steeply decline over time until in 2050 it reaches 83% below the baseline level. Emission allowances, which are rights to emit greenhouse gases, would be both allocated for free and auctioned. In addition, the draft legislation contains a renewable energy standard of 25% by the year 2025 and an energy efficiency mandate for electric and natural gas utilities, as well as other requirements. Although the Waxman-Markey bill is widely viewed as the most probable climate change bill to be enacted into law, the prospects for passage of a similar bill by the U.S. Senate are uncertain.

In addition, Montana has joined the Western Regional Climate Initiative (WCI) and is expected to participate in any greenhouse gas emission control regulations that are adopted by the WCI. The WCI, which has a goal of reducing carbon dioxide emissions 15% below the 2005 levels by 2020, currently is developing greenhouse gas emission allocations, offsets, and reporting recommendations. While we cannot predict the impact of any legislation

until final, 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 and / or our customers could be significant. We are proactively involved in analyzing the impacts of current legislative efforts on our customers and shareholders and are participating in public policy forums related to these issues.

Clean Air Act - 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.

Clean Air Mercury Rule- The state of Montana has issued mercury regulation rules that would require every coal-fired generating plant in the state to reduce emissions of mercury by 2010. The joint owners of Colstrip Unit 4 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 these 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 additional cost.

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:

Magten Settlement - In July 2008, the U.S. Bankruptcy Court for the District of Delaware (Bankruptcy Court) approved a global settlement agreement between NorthWestern, Magten Asset Management (Magten), Law Debenture Trust Company of New York (Law Debenture) and the committee concerning NorthWestern’s plan of reorganization (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 (Plan), as discussed below in the following paragraph. This settlement resolves the last significant claim from the bankruptcy case. The parties to the appeal have submitted all appellate briefs, and the Ad Hoc Committee has requested oral argument on the appeal. The appeal remains pending before The United States District Court of Delaware, which has not yet decided the request for oral argument.

Disputed Claims Reserve - In July 2008, we obtained Bankruptcy Court approval for the purchase of the remaining shares in the disputed claims reserve established by the Plan. The motion allowed unsecured creditors and

debt holders in Class 7 and Class 9 to elect to receive their surplus distribution in stock or cash. We repurchased 1.1 million shares from the disputed claims reserve for those claimants who elected a cash payment. In October 2008, we filed a motion requesting the Bankruptcy Court to determine the disputed claims reserve is taxable as a grantor trust. The Internal Revenue Service (IRS) filed an objection to the motion; however we have reached an agreement in principle with the IRS and the Plan Committee to settle this matter. If the matter is resolved as contemplated, it would not have a material impact on our financial position, results of operations or cash flows. We anticipate finalizing a settlement agreement and seeking Bankruptcy Court approval by the end of the third quarter of 2009. Upon resolution of this motion, we expect to distribute the remaining cash and shares in the disputed claims reserve to eligible claimants.

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. (Touch America) 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 were 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 sought, among other things, the avoidance of the transfer of assets from CFB to us, declaration that the assets were fraudulently transferred and were not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets, and the return of such assets to CFB. We were dismissed from this lawsuit by the U.S. District Court in Montana in February 2009.

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 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, 2008, 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 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 established by the Plan, we have limited exposure to the plaintiffs for damages arising from the McGreevey claims. In January 2009, the U.S. District Court in Montana held a status conference and issued a bench ruling asking all parties to submit memorandum discussing the party’s willingness to enter into a global settlement of the matter. We responded noting our position that all matters are resolved against NorthWestern as discussed above and noted that we are willing to work with the other parties and the Court. The Court-ordered mediation and settlement discussions are ongoing. We continue to vigorously defend against all allegations.

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. 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 of reorganization, 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. 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. On July 17, 2009, the Montana Supreme Court reclassified the case for decision by the full court, instead of the initial panel of five justices. 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.

On June 10, 2008, Sierra Club filed a complaint in the U.S. District Court for the District of South Dakota (Northern Division) (South Dakota Federal District Court) against us and two other co-owners (the Defendants) of Big Stone Generating Station (Big Stone). The complaint alleged 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 alleged 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. Sierra Club alleged that Defendants’ actions have contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. Sierra Club sought 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. Sierra Club also sought unspecified civil penalties, including a beneficial mitigation project. We believed that these claims were without merit and that Big Stone was and is being operated in compliance with the Clean Air Act and the South Dakota SIP.

The Defendants filed a Motion to Dismiss the Sierra Club complaint on August 12, 2008, based on certain of the claims being barred by statute of limitations and the remaining claims being an impermissible collateral attack on valid Clean Air Permits issued by the state of South Dakota. On September 22, 2008, the Sierra Club filed its response. Additionally on September 22, 2008, the Sierra Club sent a Notice of Intent to Sue for additional violations of the Clean Air Act at Big Stone, which are similar in nature and seek the same remedies as the June 2008 complaint. On March 31, 2009, the South Dakota Federal District Court entered a Memorandum Opinion and Order granting Defendants’ Motion to Dismiss the Sierra Club Complaint. Sierra Club filed a motion for reconsideration of the dismissal, which was denied in July 2009. The appeal period for Sierra Club will run for 30 days from this denial.

In December 2006, the MPSC issued an order finalizing certain QF rates for the periods July 1, 2003 through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a QF 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 to be approximately $23 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 Montana district court granted our motions to enforce the contractual arbitration provision and to stay all discovery and proceedings against us, pending the decision of the required contract arbitration. The Montana 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. Arbitration was held in June 2009 and briefs are due to the arbitration panel by July 31, 2009. We believe that we will prevail in the arbitration and intend to vigorously defend our positions.

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. 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 U.S. District Court for the District of Columbia in January 2008 seeking relief from the orders issued by the MMS and affirmed by the IBLA. An agreement to settle this dispute was finalized in the second quarter of 2009. Our portion of the settlement was approximately $1.5 million, which we previously accrued.

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 $3.5 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 and approximately $300,000 in cash. On September 5, 2008, Blue Dot and its subsidiaries filed a petition for protection under Chapter 7 of the Bankruptcy Code in United States Bankruptcy Court for the District of Delaware. 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, results of operations or cash flows.

On March 5, 2009, a natural gas explosion occurred in downtown Bozeman, Montana. The explosion resulted in one fatality, the destruction of three buildings (and the several places of business located within the destroyed buildings), and ancillary damage to nearby buildings and vehicles. Our investigation of this incident is ongoing. While litigation has not been commenced with respect to this incident, claims have been made against NorthWestern. We have paid our deductible and tendered the defense of any claims which may arise out of this incident to our insurance carrier. Our total available insurance coverage is approximately $150 million.

On March 16, 2009, Monsignor John F. McCarthy, as the duly appointed personal representative for the estate of Father James C. McCarthy, filed a complaint in the Montana Second Judicial District Court, Butte-Silver Bow County against us, one of our employees and other unknown individuals and entities. The complaint arises out of an April 2007 natural gas explosion and alleges negligence and strict liability with respect to the maintenance and operation of the natural gas distribution system that served Fr. McCarthy’s residence. The explosion destroyed a four-plex residence and nearby properties sustained damages. Fr. McCarthy died in November 2007. The plaintiff seeks unspecified compensatory and punitive damages and other equitable relief, costs and attorney’s fees. The investigation of this incident is ongoing, and while we cannot predict an outcome, we intend to vigorously defend against this complaint. We have filed a notice of removal to remove the case from Montana state court to the Butte Division of the U.S. District Court for the District of Montana (Montana Federal District Court), but the Montana Federal District Court remanded the case to the Montana state court.

We are a defendant – along with our predecessor entities the Montana Power Company (MPC) and pre-bankruptcy NorthWestern Corporation (NOR) – in an action (Gonzales Action) pending in the Montana Second Judicial District Court, Butte-Silver Bow County (Gonzales Court), alleging fraud, constructive fraud and violations of the Unfair Claim Settlement Practices Act all arising out of the adjustment of workers’ compensation claims. Putnam and Associates, the third party administrator of such workers’ compensation claims, also is a defendant.

The Gonzales Action was first filed on December 18, 1999, against MPC (NOR acquired MPC in 2002) and was stayed due to the chapter 11 bankruptcy filing of NOR. On August 10, 2005, the Bankruptcy Court approved a “Bankruptcy Settlement Stipulation” which permitted the Gonzales Action to proceed, assigned to plaintiffs NOR’s interest in MPC’s insurance policies (to the extent applicable to the allegations made by plaintiffs), released NOR from any and all obligations to the plaintiffs concerning such claims, and preserved plaintiffs’ right to pursue claims arising after November 1, 2004, relating to the adjustment of workers’ compensation claims. To date, no insurance carrier has indicated that coverage is available for any of the claims.

Currently pending before the Gonzales Court are the plaintiffs’ motions to file a sixth amended complaint and a motion for class certification. These motions were filed on July 2, 2009. The new complaint seeks to hold us jointly and severally liable for the acts of MPC and NOR. Plaintiffs seek compensatory and punitive damages from all defendants. Due to the pending class certification issue, our exposure cannot be determined; however, we believe the new complaint violates the bankruptcy stipulation and intend to defend the lawsuit vigorously.

REC Advanced Silicon Materials LLC (REC) is a large transmission customer which manufactures polysilicon and silane gas for the photovoltaic and electronics industries. REC purchases services from us pursuant to our Open Access Transmission Tariff. REC brought an action against us in June 2009, in the Montana Second Judicial District Court, Butte-Silver Bow County, which alleges breach of contract and negligence. REC claims we failed to properly maintain a substation, which resulted in an outage for approximately three hours and disrupted REC’s production operations for several days. REC alleges damage claims of approximately $1.25 million. We are still evaluating our potential liability and the extent and validity of REC’s damage claims. We cannot currently predict the impact or resolution of this litigation.

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 other 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

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 656,000 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, 2008.

In January 2009, as a result of a 2008 MPSC order, we placed our joint ownership interest in Colstrip Unit 4, which had previously been an unregulated asset, into utility rate base at a value of $407 million. The order included a capital structure of 50% equity and 50% debt, an authorized return on equity of 10% and cost of debt of 6.5%, which are set for 34 years based on the estimated useful life of the plant. Our interest in Colstrip Unit 4 is expected to supply approximately 13% of our base-load requirements through 2010 and approximately 25% thereafter (upon expiration of an existing power sale agreement) and will help provide rate stability for our customers. The generation related costs and return on rate base related to Colstrip Unit 4 will be included in our annual electric supply tracker filing for inclusion in customer rates. We are currently experiencing an unplanned outage at Colstrip Unit 4 for a rotor repair, which we expect to extend into the fourth quarter of 2009. We do not expect this to have an impact on our electric margins due to the regulatory treatment of our supply costs; however, we expect operating expenses to increase by approximately $1.3 million for rotor repair costs.

The current weak economic conditions will likely result in weaker customer demand, higher bad debt expense and greater risk of defaults by our counterparties, among other things. While customer counts increased, retail residential and commercial electric volumes were relatively flat and industrial volumes were down 9% for the second quarter of 2009 as compared with the same quarter of 2008. This volume reduction, while due in part to energy efficiency measures, is also largely due to weak economic conditions, particularly for commercial and industrial customers. Our margins are minimally impacted by changes in industrial demand due to our rate structure. The weak economy also contributed to a 20% decrease in transmission capacity revenues. We expect to continue to experience relatively flat residential demand as well as reduced commercial and industrial demand during the remainder of 2009. In addition, states to our South and West have experienced more significant declines in the demand for power due to the current economic conditions. This, in addition to other factors discussed in the results of operations of our regulated electric segment, has decreased demand for our transmission capacity during the second quarter of 2009, and we expect the trend to continue through the end of 2009.

Our consolidated results include the results of our business units constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment.

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Gross Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of Gross Margin is intended to supplement investors’ understanding of our operating performance. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Our Gross Margin measure may not be comparable to other companies’ Gross Margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Three Months Ended June 30, 2009 Compared with the Three Months Ended June 30, 2008

	Three Months Ended June 30,
	2009				2008			Change			% Change
	(in millions)
Operating Revenues
Regulated Electric	$	173.5		$		179.0		$	(5.5	)	(3.1	)%
Regulated Natural Gas	61.3			80.5				(19.2		)	(23.9	)
Unregulated Electric	—			16.5				(16.5		)	(100.0	)
Other	1.3			8.7				(7.4		)	(85.1	)
Eliminations	(0.4		)	(8.2			)	7.8			95.1
	$	235.7		$		276.5		$	(40.8	)	(14.8	)%

	Three Months Ended June 30,
	2009		2008				Change						% Change
	(in millions)
Cost of Sales
Regulated Electric	$	71.7	$		87.2			$		(15.5		)		(17.8		)%
Regulated Natural Gas	32.8		49.9				(17.1				)		(34.3		)
Unregulated Electric	—		11.6				(11.6				)		(100.0		)
Other	2.3		8.4				(6.1				)		(72.6		)
Eliminations	—		(7.8			)	7.8						100.0
	$	106.8	$	149.3			$		(42.5		)		(28.5		)%

	Three Months Ended June 30,
	2009			2008			Change			% Change
	(in millions)
Gross Margin
Regulated Electric	$	101.8		$	91.8		$	10.0		10.9	%
Regulated Natural Gas	28.5			30.6			(2.1		)	(6.9	)
Unregulated Electric	—			4.9			(4.9		)	(100.0	)
Other	(1.0		)	0.3			(1.3		)	(433.3	)
Eliminations	(0.4		)	(0.4		)	—			—
	$	128.9		$	127.2		$	1.7		1.3	%

Consolidated gross margin was $128.9 million for the three months ended June 30, 2009, an increase of $1.7 million, or 1.3%, from gross margin in the same period of 2008. Primary components of the change include the following:

This improvement was substantially due to the transfer of our interest in Colstrip Unit 4 to Montana utility rate base and represents our return on rate base. Prior to the transfer of Colstrip Unit 4, all of our Montana electric supply costs were based on power purchase agreements, which are passed through to customers at actual cost with no return component. Results of operations of this plant were reflected in our unregulated electric segment through December 31, 2008, which impacts the comparability of our segmented results. This increase in consolidated margin was offset by lower transmission volumes with less demand to transmit energy for others across our lines, a decrease in wholesale margin due to lower sales at lower average prices, and a weather-related decrease in regulated gas volumes.

In addition, our “other” segment includes a capacity contract through October 2013 that was primarily used to serve one customer. This customer terminated their supply contract with us and we recognized a $1.2 million loss on the contract based on our release of the capacity through October 2010 and our estimate of the market value for capacity during the remaining term. Our remaining exposure is approximately $1.2 million related to this contract.

	Three Months Ended June 30,
	2009		2008		Change				% Change
	(in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	60.9	$	53.9	$		7.0		13.0	%
Property and other taxes	18.2		20.5		(2.3			)	(11.2	)
Depreciation	22.3		21.2		1.1				5.2
	$	101.4	$	95.6	$	5.8			6.1	%

Consolidated operating, general and administrative expenses were $60.9 million for the three months ended June 30, 2009 as compared with $53.9 million for the same period of 2008. Primary components of this change include the following:

The increase in operating, general and administrative expenses was primarily due to the following:

Our Montana pension costs are included in expense on a pay as you go (cash funding) basis. We received a revised pension accounting order from the MPSC in 2008, which based our Montana pension expense on an average of our funding requirements for calendar years 2005 through 2012. This expense is currently estimated at approximately $30.6 million annually. Our estimate is based on achieving an 8.0% return on assets. While this is a long-term assumption, our funding requirements are determined annually based on many variables, including actual plan asset returns. Our return on plan assets for the first half of 2009 was approximately 6.0%. The overall market has continued to be volatile during 2009, and if asset returns are below our assumption of 8.0% for 2009, we will likely need to increase our funding estimates, which could result in higher pension expense.

Property and other taxes were $18.2 million for the three months ended June 30, 2009 as compared with $20.5 million in the same period of 2008. The decrease was due to lower assessed property valuations.

Depreciation expense was $22.3 million for the three months ended June 30, 2009 as compared with $21.2 million in the same period of 2008. The increase was primarily due to plant additions.

Consolidated operating income for the three months ended June 30, 2009 was $27.5 million, as compared with $31.5 million in the same period of 2008. The decrease was primarily due to higher operating expenses partly offset by the $1.7 million increase in gross margin discussed above.

Consolidated interest expense for the three months ended June 30, 2009 was $18.0 million, an increase of $2.2 million, or 13.9%, from the second quarter of 2008. This increase was primarily due to increased debt outstanding.

Consolidated income tax expense for the three months ended June 30, 2009 was $3.6 million as compared with $6.0 million in the same period of 2008. Our effective tax rate for 2009 was 37.1% as compared to 38.7% for 2008.

Consolidated net income for the three months ended June 30, 2009 was $6.1 million as compared with $9.5 million for the same period of 2008. The decrease was primarily due to lower operating income and higher interest expense partly offset by lower income tax expense as discussed above.

Six Months Ended June 30, 2009 Compared with the Six Months Ended June 30, 2008

	Six Months Ended June 30,
	2009				2008			Change			% Change
	(in millions)
Operating Revenues
Regulated Electric	$	381.5		$		375.6		$	5.9		1.6	%
Regulated Natural Gas	220.1			252.2				(32.1		)	(12.7	)
Unregulated Electric	—			37.0				(37.0		)	(100.0	)
Other	5.9			16.5				(10.6		)	(64.2	)
Eliminations	(0.9		)	(18.8			)	17.9			95.2
	$	606.6		$		662.5		$	(55.9	)	(8.4	)%

	Six Months Ended June 30,
	2009		2008				Change						% Change
	(in millions)
Cost of Sales
Regulated Electric	$	166.4	$		190.3			$		(23.9		)		(12.6		)%
Regulated Natural Gas	141.7		171.2				(29.5				)		(17.2		)
Unregulated Electric	—		18.7				(18.7				)		(100.0		)
Other	6.7		16.1				(9.4				)		(58.4		)
Eliminations	—		(17.8			)	17.8						100.0
	$	314.8	$	378.5			$		(63.7		)		(16.8		)%

	Six Months Ended June 30,
	2009			2008			Change			% Change
	(in millions)
Gross Margin
Regulated Electric	$	215.1		$	185.3		$	29.8		16.1	%
Regulated Natural Gas	78.4			81.0			(2.6		)	(3.2	)
Unregulated Electric	—			18.3			(18.3		)	(100.0	)
Other	(0.8		)	0.4			(1.2		)	(300.0	)
Eliminations	(0.9		)	(1.0		)	0.1			10.0
	$	291.8		$	284.0		$	7.8		2.7	%

Consolidated gross margin was $291.8 million for the six months ended June 30, 2009, an increase of $7.8 million, or 2.7%, from gross margin in the same period of 2008. The improvement in margin is primarily due to the reasons discussed above for the three months ended June 30, 2009, and are summarized for the six months ended June 30, 2009 as compared with the same period in 2008 as follows:

	Six Months Ended June 30,
	2009		2008		Change				% Change
	(in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	126.3	$	113.9	$		12.4		10.9	%
Property and other taxes	42.5		44.2		(1.7			)	(3.8	)
Depreciation	45.0		42.3		2.7				6.4
	$	213.8	$	200.4	$	13.4			6.7	%

Consolidated operating, general and administrative expenses were $126.3 million for the six months ended June 30, 2009 as compared with $113.9 million for the six months ended June 30, 2008. Primary components of this change include the following:

The increase in operating, general and administrative expenses of $12.4 million was primarily due to the following:

Property and other taxes were $42.5 million for the six months ended June 30, 2009 as compared with $44.2 million in the same period of 2008. The decrease was due to lower assessed property valuations.

Depreciation expense was $45.0 million for the six months ended June 30, 2009 as compared with $42.3 million in the same period of 2008. The increase was primarily due to plant additions.

Consolidated operating income for the six months ended June 30, 2009 was $77.9 million, as compared with $83.6 million in the same period of 2008. The decrease was primarily due to higher operating expenses partly offset by the $7.8 million increase in gross margin discussed above.

Consolidated interest expense for the six months ended June 30, 2009 was $33.1 million, an increase of $1.3 million, or 4.1%, from the same period of 2008. This increase was primarily due to increased debt outstanding.

Consolidated income tax expense for the six months ended June 30, 2009 was $16.7 million as compared with $19.2 million in the same period of 2008. Our effective tax rate for 2009 was 36.6% as compared to 36.8% for 2008.

Consolidated net income for the six months ended June 30, 2009 was $28.9 million as compared with $33.0 million for the same period of 2008. The decrease was primarily due to lower operating income and higher interest expense partly offset by lower income tax expense as discussed above.

Three Months Ended June 30, 2009 Compared with the Three Months Ended June 30, 2008

	Results
	2009			2008				Change			% Change
	(in millions)
Retail revenue	$		151.1	$	166.0			$	(14.9	)	(9.0	)%
Transmission	10.3			12.8				(2.5		)	(19.5	)
Wholesale	10.6			3.8				6.8			178.9
Other	1.5			(3.6			)	5.1			141.7
Total Revenues	173.5			179.0				(5.5		)	(3.1	)
Total Cost of Sales	71.7			87.2				(15.5		)	(17.8	)
Gross Margin	$	101.8		$		91.8		$	10.0		10.9	%

	Revenues						Megawatt Hours (MWH)		Avg. Customer Counts
	2009		2008				2009	2008	2009	2008
	(in thousands)
Retail Electric
Montana	$	47,366		$	53,269		488	498	268,627	265,820
South Dakota	9,496			9,802			108	105	48,181	47,882
Residential	56,862			63,071			596	603	316,808	313,702
Montana	64,402			69,587			749	756	60,316	59,449
South Dakota	14,748			15,375			202	200	11,701	11,522
Commercial	79,150			84,962			951	956	72,017	70,971
Industrial	8,267			11,622			702	773	72	71
Other	6,840			6,351			49	38	5,843	5,559
Total Retail Electric	$	151,119		$	166,006		2,298	2,370	394,740	390,303
Wholesale Electric
Montana	$	9,068		$		—	96	—	N/A	N/A
South Dakota	1,485			3,780			58	82	N/A	N/A
Total Wholesale Electric	$	10,553		$		3,780	154	82	N/A	N/A

The following summarizes the components of the changes in regulated electric margin for the three months ended June 30, 2009 and 2008:

The improvement in electric margin is primarily due to the transfer of Colstrip Unit 4 to the regulated utility, which is reflected as an increase in retail revenue and a reduction to cost of sales. Revenues from the sales of the output of this plant were reflected in our unregulated electric segment through December 31, 2008, which impacts the comparability of the results of our regulated electric segment. We are continuing to fulfill prior third party power purchase agreements, which are reflected as an increase in Montana wholesale revenues and volumes above. Prior to the transfer of Colstrip Unit 4, all of our Montana electric supply costs were based on power purchase agreements, which are passed through to customers at actual cost with no return component. In addition, the unregulated electric margin for the three months ended June 30, 2008 included an unrealized loss on a forward electric sales contract of $5.2 million. We are currently experiencing an unplanned outage at Colstrip Unit 4 for a rotor repair, which we expect to extend into the fourth quarter of 2009. We do not expect this to have an impact on our electric margin as replacement power is included in our supply tracking mechanism, and the remaining power purchase agreements for the output of this plant are unit-contingent, therefore we are not required to procure supply to fulfill these obligations.

This improvement in electric margin due to the transfer of Colstrip Unit 4 was offset in part by lower transmission capacity revenues with less demand to transmit energy for others across our lines, a decrease in South Dakota wholesale margin due to lower sales at lower average prices, and higher QF related supply costs based on actual QF pricing and output. Retail residential volumes have remained relatively flat as compared with 2008 due to the weaker economy and efficiency measures. In addition, average electric supply prices decreased resulting in decreased retail revenues and cost of sales in 2009 as compared with 2008, with no impact to gross margin.

We have experienced decreases in transmission capacity revenues during the second quarter of 2009, and expect the trend to continue through the end of 2009. Demand for transmission capacity can fluctuate substantially from year to year based on weather and market conditions in states to the South and West. Those states have experienced declining demand for our transmission capacity due to: (i) reduced customer demand as a result of the economic downturn; (ii) increased availability of local natural gas fired generation due to low natural gas prices making it more economically viable than transmitting electricity from Montana; (iii) increased generation in the Pacific Northwest due to favorable hydro conditions; and (iv) to a lesser extent decreased availability of Montana generation to transmit due to the outage at Colstrip Unit 4.

Regulated wholesale electric volumes increased due to the 2009 transfer of Colstrip Unit 4 to the regulated utility. The increase in regulated wholesale electric volumes was offset in part by a decrease in South Dakota wholesale volumes from lower plant availability related to scheduled maintenance. We expect wholesale volumes for Montana to be reduced into the fourth quarter due to the outage at Colstrip Unit 4. While cooling degree days may fluctuate significantly during the second quarter, our customer usage is not highly sensitive to these changes between the heating and cooling seasons.

Six Months Ended June 30, 2009 Compared with the Six Months Ended June 30, 2008

	Results
	2009			2008				Change			% Change
	(in millions)
Retail revenue	$		331.6	$	347.3			$	(15.7	)	(4.5	)%
Transmission	22.3			23.9				(1.6		)	(6.7	)
Wholesale	21.7			5.8				15.9			274.1
Other	5.9			(1.4			)	7.3			521.4
Total Revenues	381.5			375.6				5.9			1.6
Total Cost of Sales	166.4			190.3				(23.9		)	(12.6	)
Gross Margin	$	215.1		$		185.3		$	29.8		16.1	%

	Revenues						MWHs		Avg. Customer Counts
	2009		2008				2009	2008	2009	2008
	(in thousands)
Retail Electric
Montana	$	113,460		$	120,563		1,166	1,167	268,815	265,962
South Dakota	23,042			22,433			280	264	48,188	47,895
Residential	136,502			142,996			1,446	1,431	317,003	313,857
Montana	133,294			139,439			1,545	1,555	60,260	59,299
South Dakota	31,421			31,059			430	422	11,588	11,427
Commercial	164,715			170,498			1,975	1,977	71,848	70,726
Industrial	19,213			23,112			1,467	1,534	72	71
Other	11,151			10,718			73	63	5,242	5,106
Total Retail Electric	$	331,581		$	347,324		4,961	5,005	394,165	389,760
Wholesale Electric
Montana	$	18,890		$		—	299	—	N/A	N/A
South Dakota	2,793			5,846			98	131	N/A	N/A
Wholesale Electric	$	21,683		$		5,846	397	131	N/A	N/A

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, 2009.

The improvement in margin and the change in volumes are primarily due to the same reasons discussed above for the three months ended June 30, 2009 and are summarized for the six months ended June 30, 2009 as compared with 2008 as follows:

Three Months Ended June 30, 2009 Compared with the Three Months Ended June 30, 2008

	Results
	2009		2008			Change				% Change
	(in millions)
Retail revenue	$	50.4	$		78.5	$		(28.1	)	(35.8	)%
Wholesale and other	10.9		2.0			8.9				445.0
Total Revenues	61.3		80.5			(19.2			)	(23.9	)
Total Cost of Sales	32.8		49.9			(17.1			)	(34.3	)
Gross Margin	$	28.5	$	30.6		$	(2.1		)	(6.9	)%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2009		2008		2009	2008	2009	2008
	(in thousands)
Retail Gas
Montana	$	21,150	$	33,953	2,133	2,523	157,045	155,546
South Dakota	5,744		8,100		550	589	36,571	36,498
Nebraska	5,016		6,979		502	526	36,259	36,344
Residential	31,910		49,032		3,185	3,638	229,875	228,388
Montana	10,143		16,671		1,049	1,234	22,009	21,770
South Dakota	4,331		6,243		574	542	5,796	5,760
Nebraska	3,649		5,946		565	596	4,496	4,519
Commercial	18,123		28,860		2,188	2,372	32,301	32,049
Industrial	212		249		22	16	295	305
Other	193		338		22	29	142	139
Total Retail Gas	$	50,438	$	78,479	5,417	6,055	262,613	260,881

The following summarizes the components of the changes in regulated natural gas margin for the three months ended June 30, 2009 and 2008:

The decline in margin and volumes is primarily due to warmer weather. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales. In addition, average natural gas supply prices decreased, resulting in decreased retail revenues and cost of sales in 2009 as compared with 2008, with no impact to gross margin.

Six Months Ended June 30, 2009 Compared with the Six Months Ended June 30, 2008

	Results
	2009		2008			Change				% Change
	(in millions)
Retail revenue	$	194.9	$		230.4	$		(35.5	)	(15.4	)%
Wholesale and other	25.2		21.8			3.4				15.6
Total Revenues	220.1		252.2			(32.1			)	(12.7	)
Total Cost of Sales	141.7		171.2			(29.5			)	(17.2	)
Gross Margin	$	78.4	$	81.0		$	(2.6		)	(3.2	)%

	Revenues				Dkt		Customer Counts
	2009		2008		2009	2008	2009	2008
	(in thousands)
Retail Gas
Montana	$	76,674	$	94,697	7,516	8,091	157,220	155,652
South Dakota	24,433		26,788		2,127	2,196	36,838	36,706
Nebraska	20,459		22,146		1,817	1,931	36,536	36,616
Residential	121,566		143,631		11,460	12,218	230,594	228,974
Montana	38,413		46,936		3,785	3,991	22,027	21,728
South Dakota	18,627		20,177		2,070	1,920	5,841	5,799
Nebraska	14,592		17,257		1,796	1,880	4,539	4,556
Commercial	71,632		84,370		7,651	7,791	32,407	32,083
Industrial	1,015		1,537		102	136	297	306
Other	669		843		74	82	142	139
Total Retail Gas	$	194,882	$	230,381	19,287	20,227	263,440	261,502

The following summarizes the components of the changes in regulated natural gas margin for the six months ended June 30, 2009 and 2008:

The decline in margin and volumes is primarily due to warmer weather in Montana and Nebraska. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

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 invest in our business and reduce borrowings. As of June 30, 2009, our total net liquidity was approximately $269.3 million, including $23.0 million of cash and $246.3 million of revolving credit facility availability. Revolver availability was $241.5 million as of July 24, 2009.

Financing Transactions - In March 2009, we received net proceeds of approximately $249.8 million from the issuance of Montana First Mortgage Bonds at a fixed interest rate of 6.34% maturing April 1, 2019. We used the proceeds to redeem our $100 million Colstrip Lease Holdings LLC term loan, repay outstanding borrowings on our revolving credit facility, repay other outstanding debt obligations of $31.7 million related to Colstrip Unit 4, fund a portion of the costs of the Mill Creek generation project, and fund future capital expenditures.

On June 30, 2009, we amended and restated our unsecured revolving line of credit scheduled to expire on November 1, 2009. The amended facility extends the term to June 30, 2012, and increases the aggregate principal amount available under the facility by $50 million to $250 million. The amended facility does not amortize and borrowings will bear interest based on a credit ratings grid. The ‘spread’ or ‘margin’ ranges from 2.25% to 4.0% over the London Interbank Offered Rate (LIBOR). On the closing date of the agreement, the applicable spread was 3.0%. A total of nine banks participate in the new facility, with no one bank providing more than 14.0% of the total availability. The amended facility contains covenants substantially similar to the previous facility.

Supply Costs - 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 can have a significant effect on cash flow from operations and make year-to-year comparisons difficult.

As of June 30, 2009, we are over collected on our current Montana natural gas and electric trackers by approximately $21.3 million, as compared with an under collection of $10.5 million as of December 31, 2008, and an over collection of $35.7 million as of June 30, 2008. This over collection is primarily due to the volatility of commodity prices.

Pension Plan Contributions – During the first half of 2009, we made contributions of $63.2 million to our qualified pension plans. Based on the expected funded status of our plans and our available liquidity, we anticipate making additional contributions to our qualified pension plans during 2009 of approximately $20 million. These contributions are in addition to our minimum funding requirements for 2009, but will improve the funded status of our plans and reduce 2010 contribution requirements.

Fitch Investors Service (Fitch), Moody’s and Standard and Poor’s Rating Group (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of July 24, 2009, our current ratings with these agencies are as follows:

(1) Moody’s upgraded our senior secured and senior unsecured credit ratings on March 6, 2009, from Baa2 and Baa3, 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. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

	Six Months Ended June 30,
	2009			2008
Operating Activities
Net income	$	28.9		$	33.0
Non-cash adjustments to net income	64.6			73.0
Changes in working capital	27.0			27.0
Other	(35.0		)	(8.4		)
	85.5			124.6

Investing Activities
Property, plant and equipment additions	(46.9		)	(43.1		)
Sale of assets	0.3			—
	(46.6		)	(43.1		)

Financing Activities
Net borrowing (repayment) of debt	6.8			(42.9		)
Dividends on common stock	(24.1		)	(25.7		)
Other	(9.9		)	(1.5		)
	(27.2		)	(70.1		)

Net Increase in Cash and Cash Equivalents	$	11.7		$	11.4
Cash and Cash Equivalents, beginning of period	$	11.3		$	12.8
Cash and Cash Equivalents, end of period	$	23.0		$	24.2

As of June 30, 2009, cash and cash equivalents were $23.0 million as compared with $11.3 million at December 31, 2008 and $24.2 million at June 30, 2008. Cash provided by operating activities totaled $85.5 million for the six months ended June 30, 2009 as compared with $124.6 million during the six months ended June 30, 2008. This decrease in operating cash flows is primarily related to pension funding of $63.2 million, which was an increase of approximately $41.3 million as compared with the first half of 2008, and a $10.8 million prepayment of a power purchase agreement, offset by lower commodity prices reflected in the change in accounts receivable and accounts payable, as well as decreased cash outflows for natural gas storage injections.

Cash used in investing activities for the six months ended June 30, 2009, increased by approximately $3.5 million as compared with the same period in 2008 due to increased property, plant and equipment additions.

Cash used in financing activities totaled approximately $27.2 million during the six months ended June 30, 2009 as compared with $70.1 million during the six months ended June 30, 2008. During the first half of 2009 we received net proceeds from the issuance of debt of $249.8 million, made net debt repayments of $243.0 million, paid deferred financing costs of $9.9 million and paid dividends on common stock of $24.1 million. During the six months ended June 30, 2008 we made net debt repayments of $42.9 million and paid dividends on common stock of $25.7 million.

We require liquidity to support and grow our business and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, to repay debt and, from time to time, to repurchase common stock. We anticipate that our ongoing liquidity requirements will be satisfied through a combination of operating cash flows, borrowings, and as necessary, the issuance of debt or equity securities, consistent with our objective of maintaining a capital structure that will support a strong investment grade credit rating on a long-term basis. The amount of capital expenditures and dividends are subject to certain factors including the use of existing cash, cash equivalents and the receipt of cash from operations. A material adverse change in operations or available financing could impact our ability to fund our current liquidity and capital resource requirements, and we may defer capital expenditures as necessary.

The MPSC approved our Mill Creek Generating Station project during the second quarter of 2009. We estimate capital spending for this project will be between $80 and $100 million in 2009. In addition to the financing transactions completed during the first half of 2009, we plan to issue up to an additional $55 million of long-term debt securities in the second half of 2009 to finance a portion of this project.

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, 2009. See our Annual Report on Form 10-K for the year ended December 31, 2008 for additional discussion.

	Total			2009		2010		2011		2012		2013		Thereafter
	(in thousands)
Long-term Debt	$		868,979	$	2,592	$	6,123	$	6,578	$	3,792	$	—	$	849,894
Capital Leases	37,530			627		1,322		1,283		1,380		1,468		31,450
Future minimum operating lease payments	4,050			864		1,350		907		551		72		306
Estimated Pension and Other Postretirement Obligations (1)	130,420			1,870		41,450		29,600		27,900		29,600		N/A
Qualifying Facilities (2)	1,428,895			31,299		63,589		65,323		67,111		69,816		1,131,757
Supply and Capacity Contracts (3)	1,601,519			208,139		317,499		176,387		162,231		150,209		587,054
Contractual interest payments on debt (4)	450,186			29,438		50,288		49,902		49,489		49,371		221,698
Total Commitments (5)	$	4,521,579		$	274,829	$	481,621	$	329,980	$	312,454	$	300,536	$	2,822,159

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

(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 $1.4 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.1 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 19 years.

Management’s discussion and analysis of financial condition and results of operations is based on our condensed 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, 2009, 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, 2008. The policies disclosed included the accounting for the following: goodwill and long-lived assets, QF 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.

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.

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 revolving credit facility. The revolving credit facility bears interest at the lower of prime or available rates tied to the London Interbank Offered Rate (LIBOR) plus a credit spread, ranging from 2.25% to 4.0% over LIBOR. As of June 30, 2009, the applicable spread was 3.0%. There were no borrowings on our revolving credit facility as of June 30, 2009.

Commodity price risk is one of our most significant risks due to our lack of ownership of natural gas reserves and minimal ownership of regulated electric generation assets within the Montana market. Several factors influence price levels and volatility. 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 and natural gas supply portfolios 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.

Our “other” segment includes a pipeline capacity contract through October 2013 that was primarily used to serve natural gas supply to one customer. During the second quarter of 2009, this customer terminated their natural gas supply contract with us during their bankruptcy proceedings. As a result of the supply contract termination, we have excess capacity. We recognized a $1.2 million loss during the second quarter of 2009 based on our release of the excess capacity through October 2010 and our estimate of the market value for the excess capacity during the remaining term. Our remaining maximum exposure is approximately $1.2 million related to this contract. We have no other remaining capacity contracts outside of our regulated utility operations.

We are exposed to counterparty credit risk related to the ability of our counterparties to meet their contractual payment obligations, and the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price. We have risk management policies in place to limit our transactions to high quality counterparties, and continue to monitor closely the status of our counterparties, and will take action, as appropriate, to further manage this risk. This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and accumulated and reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.

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.

There have been no changes in our internal control over financial reporting during the three months ended June 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

See Note 14, Commitments and Contingencies, to the Condensed Consolidated Financial Statements for information about legal proceedings.

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

Economic conditions and instability in the financial markets could negatively impact our business.

Our operations are impacted by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity may result in a decline in energy consumption and an increase in customers’ inability to pay their accounts, which may adversely affect our liquidity, results of operations and future growth. While our territories have been less impacted than other parts of the country, during 2009 we have experienced declines in electric and natural gas usage per customer and lower electric transmission sales, due in part to the recession.

Access to the capital and credit markets, at a reasonable cost, is necessary for us to fund our operations, including capital requirements. We rely on a revolving credit facility for short-term liquidity needs due to the seasonality of our business, and on capital markets to raise capital for growth projects that are not otherwise provided by operating cash flows. Continued instability in the financial markets may increase the cost of capital, limit our ability to draw on our revolving credit facility and/or raise capital. If we are unable to obtain the liquidity needed to meet our business requirements on favorable terms, we may defer growth projects and/or capital expenditures.

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 liquidity and results of operations.

We are subject to regulation by federal and state governmental entities, including the Federal Energy Regulatory Commission, MPSC, South Dakota Public Utilities Commission and Nebraska Public Service Commission. Regulations can affect allowed rates of return, recovery of costs and operating requirements. Specifically, in our recent proceeding related to Colstrip Unit 4, the MPSC approved a 10% return on equity and 6.5% cost of debt for the expected 34-year life of the plant. 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 liquidity and results of operations.

We are also subject to the jurisdiction of NERC with regard to electric system reliability standards. We must comply with the standards and requirements established, which apply to the NERC functions for which we have registered in both the Midwest Reliability Organization for our South Dakota operations and the WECC for our Montana operations. To the extent we are deemed to not be compliant with these standards, we could be subject to fines or penalties.

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 U.S. Supreme Court decision holding that the EPA relied on improper factors in deciding not 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 to meet future requirements and obligations under environmental laws.

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 position 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 are required to procure our entire natural gas supply and a large portion of our Montana electric 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.

Poor investment performance of plan assets of our defined benefit pension and post-retirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.

We have two defined benefit pension plans that cover substantially all of our employees, and a post-retirement medical plan for our Montana employees. The costs of providing these plans are dependent upon a number of factors, including rate of return on plan assets, discount rates, other actuarial assumptions, and government regulation. While we have complied with the minimum funding requirements, our obligations for these plans exceed the value of plan assets. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. During 2008, we experienced plan asset losses in excess of

30%. Without sustained growth in the plan assets over time and depending upon the other factors noted above, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations may change significantly from projections, and could have a material impact on our liquidity and results of operations.

Our plans for future expansion through transmission grid expansion, the construction of power generation facilities and capital improvements to current assets involve substantial risks. Failure to adequately execute and manage significant construction plans, as well as the risk of recovering such costs, could materially impact our results of operations and liquidity.

We have proposed capital investment projects in excess of $1 billion. The completion of these projects, which are primarily investments in electric transmission projects and electric generation projects, are subject to many construction and development risks, including, but not limited to, risks related to financing, regulatory recovery, obtaining and complying with terms of permits, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. In addition, there are projects proposed by other parties that may result in direct competition to our proposed transmission expansion. Should our efforts be unsuccessful, we could be subject to additional costs, termination payments under committed contracts, and/or the write-off of investments in these projects. We have capitalized approximately $7.7 million of costs associated with these projects as of June 30, 2009.

Our obligation to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWh 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. In addition, we are subject to price escalation risk with one of our largest QF contracts.

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWh. 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. The anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility.

In addition, we are subject to price escalation risk with one of our largest QF contracts due to variable contract terms. In estimating our QF liability, we have estimated an annual escalation rate of 1.9% over the term of the contract (through June 2024). To the extent the annual escalation rate exceeds 1.9%, our results of operations and financial position could be adversely affected.

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 Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity and operational 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, and 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 position 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 to less than investment grade could adversely affect our liquidity, as counterparties 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.

On April 22, 2009, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

	VOTES FOR:		VOTES WITHHELD:
Stephen P. Adik		32,358,562		127,521
E. Linn Draper		32,220,593		265,490
Dana J. Dykhouse		32,366,843		119,241
Julia L. Johnson		32,089,967		396,117
Philip L. Maslowe		32,346,483		139,600
D. Louis Peoples		32,355,991		130,092
Robert C. Rowe		32,382,470		103,614

Exhibit 10.1— Amended and Restated Credit Agreement, dated as of June 30, 2009, among NorthWestern Corporation, as borrower, the several banks and other financial institutions or entities from time to time parties to the Agreement, as lenders, Banc of America Securities LLC, as lead arranger; JP Morgan Chase Bank, N.A., as syndication agent; Union Bank, N.A. and U.S. Bank National Association, as co-documentation agents; and Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated June 30, 2009, Commission File No. 1-10499)

Exhibit 10.2— Purchase Agreement, dated July 2, 2009, between NorthWestern Corporation and Pratt & Whitney Power Systems, Inc.

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.

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.

(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, 2009

OR

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

Delaware		46-0172280
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
3010 W. 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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.

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:

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		5
Item 1.	Financial Statements (Unaudited)	5
	Condensed Consolidated Balance Sheets — June 30, 2009 and December 31, 2008	5
	Condensed Consolidated Statements of Income — Three and Six Months Ended June 30, 2009 and 2008	6
	Condensed Consolidated Statements of Cash Flows – Six Months Ended June 30, 2009 and 2008	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
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	48
Item 6.	Exhibits	49
SIGNATURES		50


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

Mark-to-Market Transactions	Balance Sheet Location	June 30, 2009		December 31, 2008

Regulated natural gas net derivative liability	Accrued Expenses	$	31,979	$	29,156

	Unrealized gain (loss) recognized in Regulatory Assets
Derivatives Subject to Regulatory Deferral	Three Months Ended June 30, 2009		Six Months Ended June 30, 2009

Natural gas	$	9,334	$	(2,823	)

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral (1)		Contingent Collateral

Credit rating	$	31,044	$	500	$	30,544

Cash Flow Hedges	Amount of Gain Remaining in AOCI as of June 30, 2009		Location of Gain Reclassified from AOCI to Income		Amount of Gain Reclassified from AOCI into Income during the Six Months Ended June 30, 2009

Interest rate contracts	$	11,058		Interest Expense	$	594

	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
Liabilities:
Long-term debt (including current portion)	$	868,979	$	847,752	$	862,056	$	780,023

	Gross Margins
	2009 vs. 2008
	(Millions of Dollars)
Colstrip Unit 4	$	11.2
Regulated electric transmission volumes	(2.5		)
Regulated electric wholesale	(2.2		)
Regulated gas volumes	(2.0		)
Loss on capacity contract	(1.2		)
Other	(1.6		)
Increase in Consolidated Gross Margin	$	1.7

	Operating, General & Administrative Expenses
	2009 vs. 2008
	(Millions of Dollars)
Labor and benefits	$	3.0
Pension expense	2.9
Insurance recoveries	(1.7		)
Other	2.8
Increase in Operating, General & Administrative Expenses	$	7.0

	2009 as compared to:
Cooling Degree-Days	2008	Historic Average
Montana	9% colder	27% colder
South Dakota	132% warmer	38% colder

	2009 as compared with:
Heating Degree-Days	2008	Historic Average
Montana	15% warmer	5% warmer
South Dakota	2% warmer	7% colder
Nebraska	5% warmer	2% colder

	Senior Secured Rating	Senior Unsecured Rating	Outlook
Fitch	BBB+	BBB	Stable
Moody’s (1)	Baa1	Baa2	Positive
S&P	A- (MT) BBB+ (SD)	BBB	Stable

	FOR:	AGAINST:		ABSTAIN:
Votes	29,540,800		763,617		113,992

		NORTHWESTERN CORPORATION
Date: July 29, 2009	By:	/s/ BRIAN B. BIRD
		Brian B. Bird
		Chief Financial Officer
		Duly Authorized Officer and Principal Financial Officer

Exhibit Number		Description
*10.2		Purchase Agreement, dated July 2, 2009, between NorthWestern Corporation and Pratt & Whitney Power Systems, Inc.
*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.