NORTHWESTERN CORP (Form: 10-Q, Received: 07/29/2010 06:01:01)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

[Missing Graphic Reference]

FORM 10-Q

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

For the quarterly period ended June 30, 2010

OR

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

For the transition period from to

Commission File Number: 1-10499

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NORTHWESTERN CORPORATION

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)
Registrant’s telephone number, including area code: 605-978-2900

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

Common Stock, Par Value $0.01

36,181,695 shares outstanding at July 23, 2010

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		5
Item 1 .	Financial Statements (Unaudited)	5
	Condensed Consolidated Balance Sheets — June 30, 2010 and December 31, 2009	5
	Condensed Consolidated Statements of Income — Three and Six Months Ended June 30, 2010 and 2009	6
	Condensed Consolidated Statements of Cash Flows – Six Months Ended June 30, 2010 and 2009	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2 .	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
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 6.	Exhibits	48
SIGNATURES		49

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference 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:

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

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

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

·	adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.

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

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. 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 other reports on Form 10-Q, 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.

PART 1. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)


	June 30, 2010			December 31, 2009
ASSETS
Current Assets:
Cash and cash equivalents	$	6,149		$	4,344
Restricted cash	14,812			13,608
Accounts receivable, net	91,985			143,759
Inventories	42,065			47,305
Regulatory assets	54,960			40,509
Deferred income taxes	3,929			1,239
Prepaid and other	11,196			14,063
Total current assets	225,096			264,827
Property, Plant, and Equipment, Net	2,033,932			1,964,121
Goodwill	355,128			355,128
Regulatory assets	183,133			182,382
Other noncurrent assets	34,660			28,674
Total assets	$	2,831,949		$	2,795,132
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,237		$	1,197
Current maturities of long-term debt	6,353			6,123
Accounts payable	54,462			92,923
Accrued expenses	186,832			165,127
Regulatory liabilities	20,219			29,622
Total current liabilities	269,103			294,992
Long-term capital leases	34,952			35,570
Long-term debt	997,706			981,296
Deferred income taxes	184,009			161,188
Noncurrent regulatory liabilities	245,838			238,332
Other noncurrent liabilities	292,453			296,730
Total liabilities	2,024,061			2,008,108
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,741,036 and 36,181,190, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	397			395
Treasury stock at cost	(90,140		)	(90,228		)
Paid-in capital	813,007			807,527
Retained earnings	75,520			59,605
Accumulated other comprehensive income	9,104			9,725
Total shareholders' equity	807,888			787,024
Total liabilities and shareholders' equity	$	2,831,949		$	2,795,132

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Revenues
Electric	$	184,838		$	173,463		$	388,677		$	381,450
Gas	58,900			61,330			188,919			220,133
Other	321			920			636			5,033
Total Revenues	244,059			235,713			578,232			606,616
Operating Expenses
Cost of sales	111,936			106,840			284,763			314,850
Operating, general and administrative	57,126			60,898			115,434			126,317
Property and other taxes	24,984			18,246			47,952			42,535
Depreciation	22,997			22,260			45,872			44,982
Total Operating Expenses	217,043			208,244			494,021			528,684
Operating Income	27,016			27,469			84,211			77,932
Interest Expense, net	(16,057		)	(18,002		)	(33,107		)	(33,136		)
Other Income	1,853			198			2,606			789
Income Before Income Taxes	12,812			9,665			53,710			45,585
Income Tax Expense	(1,121		)	(3,567		)	(13,301		)	(16,674		)
Net Income	$	11,691		$	6,098		$	40,409		$	28,911
Average Common Shares Outstanding	36,179			35,940			36,174			35,937
Basic Earnings per Average Common Share	$	0.32		$	0.17		$	1.12		$	0.80
Diluted Earnings per Average Common Share	$	0.32		$	0.17		$	1.11		$	0.80
Dividends Declared per Average Common Share	$	0.34		$	0.335		$	0.68		$	0.67

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2010			2009
OPERATING ACTIVITIES :
Net Income	$	40,409		$	28,911
Items not affecting cash:
Depreciation	45,872			44,982
Amortization of debt issue costs, discount and deferred hedge gain	1,030			1,122
Amortization of restricted stock	861			1,164
Equity portion of allowance for funds used during construction	(2,585		)	(275		)
Loss (gain) on sale of assets	628			(223		)
Deferred income taxes	20,131			17,858
Changes in current assets and liabilities:
Restricted cash	(1,204		)	(1,913		)
Accounts receivable	51,774			57,710
Inventories	5,240			23,391
Other current assets	2,874			(1,846		)
Accounts payable	(29,005		)	(39,097		)
Accrued expenses	12,147			(9,867		)
Regulatory assets	(4,901		)	963
Regulatory liabilities	(9,403		)	(2,341		)
Other noncurrent assets	6,059			11,387
Other noncurrent liabilities	(7,469		)	(46,395		)
Cash provided by operating activities	132,458			85,531
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(116,233		)	(46,986		)
Proceeds from sale of assets	—			326
Cash used in investing activities	(116,233		)	(46,660		)
FINANCING ACTIVITIES:
Treasury stock activity	88			—
Dividends on common stock	(24,494		)	(24,079		)
Issuance of long-term debt	225,000			249,833
Repayment of long-term debt	(228,403		)	(135,011		)
Line of credit borrowings	402,000			237,000
Line of credit repayments	(382,000		)	(345,000		)
Financing costs	(6,611		)	(9,943		)
Cash used in financing activities	(14,420		)	(27,200		)
Increase in Cash and Cash Equivalents	1,805			11,671
Cash and Cash Equivalents, beginning of period	4,344			11,292
Cash and Cash Equivalents, end of period	$	6,149		$	22,963
Supplemental Cash Flow Information:
Cash paid during the period for:
Income Taxes	—			2
Interest	22,086			20,305
Significant non-cash transactions:
Capital expenditures included in accounts payable	2,788			2,284

See Notes to Condensed Consolidated Financial Statements

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

(1) Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 661,000 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 generated and distributed electricity and distributed natural gas in Montana since 2002.

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 Condensed Consolidated Financial Statements (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, 2010, have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

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 the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2009.

(2) New Accounting Standards

Accounting Standards Issued

There have been no new recent accounting pronouncements or changes in accounting pronouncements during the three months ended June 30, 2010, that are of significance, or potential significance, to us.

Accounting Standards Adopted

In June 2009, the Financial Accounting Standards Board (FASB) amended the accounting for variable interest entities, which was effective for us beginning January 1, 2010. This revised guidance 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. The statement includes the following significant provisions:

requires an entity to qualitatively assess the determination of the primary beneficiary of a variable interest entity (VIE) based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,

·	requires an ongoing reconsideration of the primary beneficiary instead of only upon certain triggering events,

·	amends the events that trigger a reassessment of whether an entity is a VIE, and

for an entity that is the primary beneficiary of a VIE, requires separate balance sheet presentation of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

We are required to consolidate VIEs if we are the primary beneficiary, which means we have a controlling financial interest. Certain long-term power purchase and tolling contracts may be considered variable interests. We have various long-term power purchase contracts with other utilities and certain qualifying facility (QF) plants. We have evaluated our inventory of long-term power purchase and tolling contracts under this guidance. We identified one QF contract that may constitute a VIE. The power purchase agreement was entered into in 1984 with a 35 megawatt coal-fired QF to purchase substantially all of the plant’s output over a substantial portion of its estimated useful life. We absorb a portion of the plant’s variability through the energy payment portion of the contract price. After making exhaustive efforts, we were unable to obtain the information from the plant necessary to determine whether it is a VIE or whether we are the primary beneficiary. The contract with the plant contains no provision which legally obligates the project to release this information to us. We have continued to account for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $455.4 million through 2025.

(3) Income Taxes

Our effective tax rate for the three months ended June 30, 2010 and 2009 was approximately 8.7% and 36.9%, respectively. The reduction in the effective tax rate versus the statutory rate in 2010 is primarily due to:

·	the release of $2.2 million in valuation allowance against certain state net operating loss (NOL) carryforwards, and

·	a tax benefit of $1.2 million recognized for repair costs, due to flow-through regulatory treatment.

Realization of our deferred tax assets is dependent upon, among other things, our ability to generate taxable income in the future. As of December 31, 2009, we had a valuation allowance of approximately $6.4 million against certain state NOL carryforwards based on our best estimate of what would be realized. If unused, a substantial portion of our state NOL carryforwards will expire at the end of 2010. Based on our current projections, we estimate we will generate enough taxable income to release an additional $2.1 million of our valuation allowance through the remainder of 2010.

Uncertain Tax Positions

We have unrecognized tax benefits of approximately $124.3 million as of June 30, 2010, including approximately $85.2 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, 2010, we have not recognized expense for interest or penalties, and do not have any amounts accrued at June 30, 2010 and December 31, 2009, respectively, for the payment of interest and penalties.

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

(4) Goodwill

There were no changes in our goodwill during the six months ended June 30, 2010. Goodwill by segment is as follows for both June 30, 2010 and December 31, 2009 (in thousands):


Electric	$	241,100
Natural gas	114,028
	$	355,128

( 5) Other Comprehensive Income

The following table displays the components of Accumulated Other Comprehensive Income (AOCI), which is included in Shareholders’ Equity on the Condensed Consolidated Balance Sheets (in thousands).

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Net income	$	11,691		$	6,098		$	40,409		$	28,911
Other comprehensive income, net of tax:
Reclassification of net gains on hedging instruments from OCI to net income		(297	)		(297	)		(594	)		(594	)
Foreign currency translation		(91	)		141			(27	)		92
Comprehensive income	$	11,303		$	5,942		$	39,788		$	28,409

(6) Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

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 a significant risk due to our lack of ownership of natural gas reserves and our reliance on market purchases to fulfill a portion of our electric supply requirements 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.

Objectives and Strategies for Using Derivatives

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 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 our derivative transactions are only 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.

Accounting for Derivative Instruments

We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. 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 both at the time of designation and on an ongoing basis. 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.

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) 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, 2010 and December 31, 2009. 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.

Mark-to-Market Accounting

Certain contracts for the purchase of natural gas associated with our gas utility operations 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 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 7.

Mark-to-Market Transactions	Balance Sheet Location	June 30, 2010		December 31, 2009

Natural gas net derivative liability	Accrued Expenses	$	33,362	$	23,661

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

	Unrealized gain (loss) recognized in Regulatory Assets
	Three Months Ended				Six Months Ended
Derivatives Subject to Regulatory Deferral	June 30, 2010		June 30, 2009		June 30, 2010			June 30, 2009

Natural gas	$	3,548	$	9,334	$	(9,701	)	$	(2,823	)

Credit Risk

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: (1) Western Systems Power Pool agreements – standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

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, 2010, 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, 2010 (in thousands):

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral

Credit rating	$	26,550	$	—	$	26,550

Interest Rate Swaps Designated as Cash Flow Hedges

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 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 (in thousands):

Cash Flow Hedges	Amount of Gain Remaining in AOCI as of June 30, 2010		Location of Gain Reclassified from AOCI to Income		Amount of Gain Reclassified from AOCI into Income during the six months ended June 30, 2010

Interest rate contracts	$	9,870		Interest Expense	$	594

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.

(7) Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.

A fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs has been established by the applicable accounting guidance. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

·	Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;

·	Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and

·	Level 3 – Significant inputs that are generally not observable from market activity.

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. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. 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 6 for further discussion.

June 30, 2010	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)
Restricted cash	$	14,201	$	—		$	—	$	—	$	14,201
Rabbi trust investments		4,571		—			—		—		4,571
Derivative asset (1)		—		667			—		—		667
Derivative liability (1)		—		(34,029	)		—		—		(34,029	)
Net derivative position		—		(33,362	)		—		—		(33,362	)
Total	$	18,772	$	(33,362	)	$	—	$	—	$	(14,590	)

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

We present our derivative assets and liabilities on a net basis in the Condensed Consolidated Balance Sheets. The table above disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required 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.

Restricted cash represents amounts held in money market mutual funds. Rabbi trust assets represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. 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). The fair value measurement of liabilities also reflects 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.

Financial Instruments

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

	June 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
Liabilities:
Long-term debt (including current portion)	$	1,004,059	$	1,093,230	$	987,419	$	1,034,122

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 determined fair values for debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows.

(8) Financing Activities

On May 27, 2010 we issued $161 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.01% maturing in May 1, 2025. We also issued $64 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.01% maturing May 1, 2025. The bonds are secured by our electric and natural gas assets in the respective jurisdictions. The bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. We used the proceeds to redeem our 5.875%, $225 million Senior Secured Notes due 2014.

(9) Regulatory Matters

Montana General Rate Case

In October 2009, we filed a request with the Montana Public Service Commission (MPSC) for an annual electric transmission and distribution revenue increase of $15.5 million, and an annual natural gas transmission, storage and distribution revenue increase of $2.0 million. The request was based on a 2008 test period, a return on equity of 10.9%, an equity ratio of 49.45% and rate base of $632.2 million and $256.6 million for electric and natural gas, respectively.

A hearing is scheduled for September 2010 and we expect the MPSC to issue a final order during the fourth quarter of 2010. In July 2010, the MPSC voted to approve an interim rate increase of $12.4 million and $1.4 million for electric and natural gas, respectively, subject to refund. Interim rates went into effect on July 8, 2010. If final approved rates are lower than the interim amounts approved by the MPSC, we are required to refund the difference to customers, with interest. Interveners have filed testimony contesting various issues in the case and proposing electric and natural gas rate decreases. Since we cannot estimate the outcome, we expect to defer recognition of associated revenues until we receive a final order from the MPSC.

Montana Electric and Natural Gas Supply Trackers

Rates for our Montana electric and natural gas supply are set by the MPSC. Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas energy supply procurement activities were prudent. If the MPSC subsequently determines that a procurement activity was imprudent, then it may disallow such costs.

In April 2010, the MPSC issued a final order approving our purchased power costs for the 2008 and 2009 annual filings, as well as approving a stipulation between us and the Montana Consumer Counsel related to those periods where we agreed to remove approximately $183,000 in labor costs and calculated lost revenues from the tracker.

In June 2010, we filed our 2010 annual electric supply tracker, and received an interim order from the MPSC approving recovery of costs pending review.

Our 2009 and 2010 annual natural gas cost tracker filings are currently pending review by the MPSC. The MPSC issued interim orders for each cost tracking period, approving recovery of our projected gas costs pending its review. A procedural schedule has been established.

Mill Creek Generating Station

In August 2008, we filed a request with the MPSC for advanced approval to construct a 150 megawatt (MW) 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 wind power to be integrated onto the network to meet 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 a preliminary 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, 2010, we have capitalized approximately $147.2 million in construction work in process related to this project.

Our Federal Energy Regulatory Commission (FERC) Open Access Transmission Tariff (OATT) allows for pass-through of ancillary costs to our customers, including the regulating reserve service described above to be provided by the Mill Creek Generating Station under Schedule 3 (Regulation and Frequency Response). We submitted a filing to the FERC related to this project in April 2010 and have requested an effective date for the change in rates of January 1, 2011 in order to reflect the cost of service for the Mill Creek Generating Station under the OATT in Schedule 3. The filing is currently pending at FERC. We expect to file with the MPSC during the third quarter of 2010 a request for interim rates based on the estimated Mill Creek Generating Station construction costs. These rates are expected to be effective beginning January 1, 2011, and would replace the current contracted costs for ancillary services.

Transmission Investment Projects

We are conducting open season processes for the proposed Mountain States Transmission Intertie (MSTI) and Collector Project to identify potential interest for new transmission capacity on these paths due to the changing nature of generation projects. The open seasons were initiated with an informational meeting for prospective bidders in March 2010. The open season process is designed to provide for a staged level of commitment by prospective users. Assuming sufficient interest, we would expect to make filings with FERC early in 2011. A lawsuit has been filed against the Montana Department of Environmental Quality by Jefferson County, Montana, regarding the County’s ability to be more involved in the siting and routing of MSTI. An initial hearing was held in June 2010 in Montana District Court, with further hearings scheduled in July 2010. This lawsuit could have an impact on the release of the draft environmental impact statement, and therefore, the timing and completion of the open season process. We have capitalized approximately $14.1 million of preliminary survey and investigative costs associated with these proposed transmission projects. We discuss these transmission investment opportunities further in the “Overview” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2009.

(10) Segment Information

Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other. While it is not considered a business unit, other primarily consists of a remaining unregulated natural gas capacity contract, the wind down of our captive insurance subsidiary and our unallocated corporate costs.

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

Three Months Ended
June 30, 2010	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	184,838		$	58,900		$	321		$	—	$	244,059
Cost of sales	82,296			29,640			—			—		111,936
Gross margin	102,542			29,260			321			—		132,123
Operating, general and administrative	41,873			17,133			(1,880		)	—		57,126
Property and other taxes	18,281			6,659			44			—		24,984
Depreciation	18,620			4,369			8			—		22,997
Operating income	23,768			1,099			2,149			—		27,016
Interest expense	(11,915		)	(3,456		)	(686)			—		(16,057		)
Other income (expense)	1,949			(123		)	27			—		1,853
Income tax (expense) benefit	(4,405		)	1,155			2,129			—		(1,121		)
Net income (loss)	$	9,397		$	(1,325	)	$	3,619		$	—	$	11,691
Total assets	$	1,986,414		$	831,338		$	14,197		$	—	$	2,831,949
Capital expenditures	$	47,303		$	11,134		$	—		$	—	$	58,437

Three Months Ended
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

Six Months Ended
June 30, 2010	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	388,677		$	188,919		$	636		$	—	$	578,232
Cost of sales	173,361			111,402			—			—		284,763
Gross margin	215,316			77,517			636			—		293,469
Operating, general and administrative	81,889			35,026			(1,481		)	—		115,434
Property and other taxes	35,055			12,812			85			—		47,952
Depreciation	37,124			8,731			17			—		45,872
Operating income	61,248			20,948			2,015			—		84,211
Interest expense	(25,107		)	(6,602		)	(1,398		)	—		(33,107		)
Other income	2,406			147			53			—		2,606
Income tax (expense) benefit	(10,939		)	(4,584		)	2,222			—		(13,301		)
Net income	$	27,608		$	9,909		$	2,892		$	—	$	40,409
Total assets	$	1,986,414		$	831,338		$	14,197		$	—	$	2,831,949
Capital expenditures	$	99,553		$	16,680		$	—		$	—	$	116,233

Six Months Ended
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

(11) Earnings Per Share

Basic earnings per share is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested restricted shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. 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 stock and performance share awards.

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

	Three Months Ended
	June 30, 2010	June 30, 2009
Basic computation	36,179,133	35,940,008
Dilutive effect of
Restricted stock and performance share awards (1)	143,728	379,617

Diluted computation	36,322,861	36,319,625
	Six Months Ended
	June 30, 2010	June 30, 2009
Basic computation	36,173,947	35,936,960
Dilutive effect of
Restricted stock and performance share awards (1)	141,995	379,617

Diluted computation	36,315,942	36,316,577

(1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

(12) Employee Benefit Plans

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,
	2010			2009			2010			2009
Components of Net Periodic Benefit Cost
Service cost	$	2,348		$	2,154		$	121		$	364
Interest cost	6,026			5,772			511			954
Expected return on plan assets	(7,567		)	(4,653		)	(297		)	(178		)
Amortization of prior service cost	62			62			(535		)	—
Recognized actuarial loss (gain)	70			2,038			(4		)	292
Net Periodic Benefit Cost	$	939		$	5,373		$	(204	)	$	1,432

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
	2010			2009			2010			2009
Components of Net Periodic Benefit Cost
Service cost	$	4,681		$	4,135		$	242		$	497
Interest cost	12,045			11,853			902			1,575
Expected return on plan assets	(14,920		)	(11,192		)	(593		)	(497		)
Amortization of prior service cost	123			123			(976		)	—
Recognized actuarial loss	70			2,038			492			138
Net Periodic Benefit Cost	$	1,999		$	6,957		$	67		$	1,713

We experienced plan asset market gains during 2009 in excess of 20%, and plan asset market losses during 2008 in excess of 30%. This volatility in return on plan assets is reflected in the change 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. During the first half of 2010 and 2009 we contributed approximately $10.0 million and $63.2 million, respectively, to our pension plans. The decrease in other postretirement benefits net periodic benefit cost for the three and six months ended June 30, 2010 as compared with 2009 is due to a plan amendment.

(13) Commitments and Contingencies

ENVIRONMENTAL LIABILITIES

The operation of electric generating, transmission and distribution facilities, and gas transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, and protection of natural resources. We continuously monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are promulgated, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs become fixed and reliably determinable.

Our liability for environmental remediation obligations is estimated to range between $22.4 million to $44.1 million. As of June 30, 2010, we have a reserve of approximately $31.5 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.

Global Climate Change

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.

Specifically, coal-fired plants have come under scrutiny due to their emissions of carbon dioxide, and in September 2009, the U.S. Court of Appeals for the Second Circuit reversed a federal district court’s decision and ruled that several states and public interest groups could sue five electric utility companies under federal common law for allegedly causing a public nuisance as a result of their emissions of greenhouse gases. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed a federal district court and ruled that individuals damaged by Hurricane Katrina could sue a variety of companies that emit carbon dioxide, including electric utilities, for allegedly causing a public nuisance that contributed to their damages. In May 2010, due to a lack of quorum, the Court of Appeals for the Fifth Circuit dismissed its decision, which essentially reinstated the district court’s dismissal of the claim. The plaintiffs have not yet announced if they intend to seek Supreme Court review. Additional litigation in federal and state courts over these issues is continuing.

In addition to litigation during 2009, the Environmental Protection Agency (EPA) issued a finding that greenhouse gas emissions endanger the public health and welfare. The EPA’s 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. In a related matter, in June 2010, the EPA also adopted rules that would phase in requirements for all new or modified “stationary sources,” such as power plants, that emit 100,000 tons of greenhouse gases per year or modified sources that increase emissions by 75,000 tons per year to obtain permits incorporating the “best available control technology” for such emissions.

In September 2009, the EPA announced the adoption of the first comprehensive national system for reporting emissions of carbon dioxide and other greenhouse gases produced by major sources in the United States. The new reporting requirements will apply to suppliers of fossil fuel and industrial chemicals, manufacturers of motor vehicles and engines, as well as large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain of our facilities. The effective date for gathering the data is January 2010 with the first mandatory reporting due in March 2011.

National Legislation - In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, which would regulate greenhouse gas emissions by instituting a cap-and-trade-system. Climate change legislation is currently pending in the U.S. Senate with various proposals under consideration. Meanwhile, the EPA is beginning to implement regulatory actions under the Clean Air Act to address emission of greenhouse gases. Specifically, the EPA issued a proposed Transport Rule in July 2010 that would require significant reductions in sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions that cross state lines, which could impact our jointly owned plants that serve our South Dakota customers.

International Activities - Other nations have agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17% compared to 2005 levels.

State Activities - The Montana Governor’s office 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. Impacts include future capital expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures and the purchase of emission allowances from market sources. Our current capital expenditures projections do not include significant amounts related to environmental projects. We believe the cost of purchasing carbon emissions credits, or alternatively the proceeds from the sale of any excess carbon emissions credits would be included in our supply trackers and passed through to customers. 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.

In addition, 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. We believe future legislation and regulations that affect carbon dioxide emissions from power plants are likely, although technology to efficiently capture, remove and sequester carbon dioxide emissions is not presently available on a commercial scale.

Regional Haze and Visibility - The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule requires the use of Best Available Retrofit Technology (BART) for certain electric generating units to achieve emissions reductions from designated sources that are deemed to contribute to visibility impairment in Class I air quality areas. We have a 23.4% interest in Big Stone, a coal-fired power plant located in northeastern South Dakota, which is potentially subject to emission reduction requirements. The South Dakota Department of Environment and Natural Resources (DENR) recommended a Selective Catalytic Reduction technology for nitrogen oxide emission reduction and we estimate capital expenditures for the BART technologies based on the DENR proposal are approximately $200 - $300 million for Big Stone (our share is 23.4%). The DENR proposes to require that BART be installed and operating as expeditiously as practicable, but no later than five years from the EPA’s approval of the South Dakota Regional Haze State Implementation Plan, which is expected no later than January 15, 2011. If the emissions reduction technology is required, we will seek to recover these costs through the ratemaking process. The South Dakota Public Utilities Commission (SDPUC) has allowed timely recovery of the costs of environmental improvements; however, there is no precedent on a project of this size.

Clean Air Mercury Rule - In March 2005, the EPA issued the Clean Air Mercury Regulations (CAMR) to reduce the emissions of mercury from coal-fired facilities through a market-based cap-and-trade program. Although the U.S. Court of Appeals for the District of Columbia Circuit struck down CAMR, the state of Montana finalized its own mercury emission rules that require, by 2010, every coal-fired generating plant in Montana to achieve reductions more stringent than CAMR's 2018 requirements. Chemical injection technologies were installed at Colstrip during the fourth quarter of 2009 to meet these requirements. If the enhanced chemical injection technologies are not sufficient to meet the required levels of reduction, then adsorption/absorption technology with fabric filters would be required, which could represent a material cost. We are continuing to work with the other Colstrip owners to assess compliance with these reduction levels.

Manufactured Gas Plants

Approximately $26.3 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 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 DENR. Our current reserve for remediation costs at this site is approximately $12.6 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. In 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. 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.

Other

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

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

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

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

LEGAL PROCEEDINGS

Colstrip Energy Limited Partnership

In December 2006 and June 2007, the MPSC issued orders relating to certain QF rates for the period July 1, 2003 through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a QF with which we have a power purchase agreement through June 2024. 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, with the rates to be used in that formula derived from the annual MPSC QF rate review. CELP initially appealed the MPSC’s orders and then, in July 2007, filed a complaint against NorthWestern and the MPSC in Montana district court, which contested the MPSC’s orders. CELP disputed inputs into the underlying rates used in the formula, which initially are calculated by us and reviewed by the MPSC on an annual basis, to calculate energy and capacity payments for the contract years 2004-2005 and 2005-2006. CELP claimed that NorthWestern breached the power purchase agreement causing damages, which CELP asserted to be approximately $23 million for contract years 2004-2005 and 2005-2006. The parties stipulated that NorthWestern would not implement the final derived rates resulting from the MPSC orders, pending an ultimate decision on CELP's complaint. The Montana district court, on June 30, 2008, granted both a motion by the MPSC to bifurcate, having the effect of separating the issues between contract/tort claims against us and the administrative appeal of the MPSC’s orders and a motion by us to refer the claims against us to arbitration. The order also stayed the appellate decision pending a decision in the arbitration proceedings. Arbitration was held in June 2009 and the arbitration panel entered its interim award in August 2009, holding that although NorthWestern failed to use certain data inputs required by the power purchase agreement, CELP was entitled to neither damages for contract years 2004-2005 or 2005-2006, nor to recalculation of the underlying MPSC filings for those years, effectively finalizing CELP's contract rates for those years. We requested clarification from the arbitration panel as to its intent regarding the applicable rates. On November 2, 2009, we received the final award from the arbitration panel which confirmed that the filed rates for 2004-2005 and 2005-2006 are not required to be recalculated. In affirming its interim award, the arbitration panel also denied CELP’s request for attorney fees, holding that each party would be responsible for its own fees. On June 15, 2010, the Montana district court confirmed the final arbitration panel award and denied CELP’s motion to vacate, modify or correct the award. CELP has appealed the decision, and due to the uncertainty around resolution we are currently unable to predict the outcome of this matter. We are required to file with the MPSC by August 31, 2010 for a new determination of rates subsequent to June 30, 2006, using data inputs required by the power purchase agreement. In addition, settlement discussions concerning these claims are ongoing.

Gonzales

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 (Montana State 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.

On September 30, 2009, the Montana State Court granted the plaintiffs’ motions to file a sixth amended complaint and partially granted the plaintiff’s motion for class certification. The Montana State Court excluded the fraud claims from its class certification. The new complaint seeks to hold us jointly and severally liable for the acts of MPC and NOR and alleges that we negligently/intentionally sabotaged plaintiffs’ ability to recover under the MPC insurance policies. Plaintiffs seek compensatory and punitive damages from all defendants. Due to the individual nature of the claims, we believe the class certification was improper under Montana law, and we continue to believe that the new complaint violates the bankruptcy stipulation. We have filed an appeal to the Supreme Court of the State of Montana with respect to these issues and intend to continue to defend the lawsuit vigorously. We also believe the sixth amended complaint violates the Bankruptcy Settlement Stipulation and have filed a motion with the Bankruptcy Court seeking enforcement of the Bankruptcy Settlement Stipulation. The motion before the Bankruptcy Court is pending.

The parties have agreed to settle the Gonzales Action and have executed a settlement agreement which is subject to the approval of the Montana State Court. If the court approves the settlement agreement, we will pay the plaintiffs an aggregate amount of $2.6 million in full satisfaction of all Gonzales Action claims, which has been accrued.

Maryland Street

On March 16, 2009, Monsignor John F. McCarthy, the duly appointed personal representative for the Estate of Father James C. McCarthy, filed a lawsuit against NorthWestern and one of our employees in the District Court of Butte-Silver Bow County, Montana for injuries that Fr. McCarthy received in an April 2007 natural gas explosion that destroyed his four-plex residence. The complaint alleges negligence and strict liability with respect to the maintenance and operation of the natural gas distribution system that served the residence. Fr. McCarthy died in November 2007, allegedly because of injuries sustained in the explosion. 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 continue vigorously defending against the lawsuit.

Bozeman Explosion

On March 5, 2009, a natural gas explosion occurred in downtown Bozeman, Montana. The explosion resulted in one fatality, the destruction of or damage to several buildings and the businesses in them, and damage to other nearby properties and businesses. Twenty-two lawsuits against NorthWestern are pending in the District Court of Gallatin County, Montana, and a number of additional claims not currently in litigation also are pending. We have approximately $150 million of insurance coverage available for known and potential claims. We have paid our self-insured retention under these policies, and our insurance carriers have assumed the defense and handling of the existing and potential future lawsuits and claims arising from the incident.

McGreevey Litigation

We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al., now pending in U.S. District Court in Montana. The lawsuit, which was filed by former shareholders of The Montana Power Company (most of whom became shareholders of Touch America Holdings, Inc. (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 Company L.L.C. (now Clark Fork and Blackfoot LLC), which plaintiffs claim is a successor to The Montana Power Company.

In October 2009, the parties reached a global settlement, which was subject to approval by the U.S. District Court in Montana and the Delaware Bankruptcy Court. On February 23, 2010, the Delaware Bankruptcy Court approved the settlement. On May 20, 2010, the U.S. District Court in Montana conducted a fairness hearing concerning the proposed settlement and approved the global settlement, but did not approve attorneys fees to the plaintiffs’ counsel. If the court approves the attorneys fees, it will enter a final judgment on the settlement, and, subject to any appeals of the final judgment, we will receive approximately $2.0 million from the Touch America bankruptcy estate and have no remaining exposure in the litigation.

Sierra Club

On June 10, 2008, Sierra Club filed a complaint in the U.S. District Court for the District of South Dakota (Northern Division) (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 the 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 the Defendants to remedy the alleged violations. Sierra Club also sought unspecified civil penalties, including a beneficial mitigation project. We believe these claims are 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 March 31, 2009, the South Dakota Federal District Court entered a Memorandum Opinion and Order granting Defendants’ Motion to Dismiss the Sierra Club Complaint. On July 30, 2009, Sierra Club appealed the South Dakota Federal District Court’s decision to dismiss the complaint to the Eighth Circuit Court of Appeals (Court of Appeals). The United States Department of Justice (USDOJ) filed an amicus brief in support of the Sierra Club’s position and the state of South Dakota served an amicus brief in support of our position. Appellate briefing has concluded, and the Court of Appeals held oral arguments on May 11, 2010. We cannot predict the outcome at this time.

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

OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 661,000 customers in Montana, South Dakota and Nebraska. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2009.

SUMMARY

Significant achievements during the three months ended June 30, 2010 include:

·	Improvement in net income of approximately $5.6 million as compared with 2009, due primarily to income tax benefits and reduced operating , general and administrative expense, which offset an increase in property tax expense; and

·	Issuance of $161 million of Montana First Mortgage Bonds and $64 million of South Dakota First Mortgage Bonds at 5.01% to refinance our 5.875% $225 million first mortgage bonds.

RESULTS OF OPERATIONS

Our consolidated results include the results of our reportable business segments, which are primarily engaged in the electric and natural gas business. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment.

Non-GAAP Financial Measure

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.

Outlook

The current weak economic conditions have resulted in weaker customer demand, among other things, and the outlook and timing of economic recovery remains uncertain. We expect to continue to experience relatively flat residential demand as well as reduced commercial and industrial demand during 2010. In addition, the weak economic climate has impacted demand for our transmission capacity. In response, we have taken steps to manage our operating, general and administrative expenses and will continue to manage our costs consistent with the impact to our margin.

OVERALL CONSOLIDATED RESULTS

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009

	Three Months Ended June 30,
	2010			2009			Change			% Change
	(in millions)
Operating Revenues
Electric	$	184.8	$		173.5		$	11.3		6.5	%
Natural Gas	58.9		61.3				(2.4		)	(3.9	)
Other	0.3		1.3				(1.0		)	(76.9	)
Eliminations	—		(0.4			)	0.4			100.0
	$	244.0	$		235.7		$	8.3		3.5	%

	Three Months Ended June 30,
	2010		2009		Change			% Change
	(in millions)
Cost of Sales
Electric	$	82.3	$	71.7	$	10.6		14.8	%
Natural Gas	29.6		32.8		(3.2		)	(9.8	)
Other	—		2.3		(2.3		)	(100.0	)
	$	111.9	$	106.8	$	5.1		4.8	%

	Three Months Ended June 30,
	2010		2009			Change		% Change
	(in millions)
Gross Margin
Electric	$	102.5	$	101.8		$	0.7	0.7	%
Natural Gas	29.3		28.5			0.8		2.8
Other	0.3		(1.0		)	1.3		130.0
Eliminations	—		(0.4		)	0.4		100.0
	$	132.1	$	128.9		$	3.2	2.5	%

Consolidated gross margin was $132.1 million for the three months ended June 30, 2010, an increase of $3.2 million, or 2.5%, from gross margin in 2009. Primary components of this change include the following:

	Gross Margin
	2010 vs. 2009
	(in millions)
Montana property tax tracker	$	3.5
Loss on capacity contract in 2009	1.2
Operating expenses recovered in supply trackers	0.9
Transmission capacity	0.6
Natural gas volumes	0.4
QF supply costs	(3.6		)
Other	0.2
Increase in Consolidated Gross Margin	$	3.2

This $3.2 million increase was primarily due to an increase in property taxes recoverable through a tracker as compared with 2009, a loss recorded in 2009 on a capacity contract, higher revenues for operating expenses recovered in supply trackers primarily related to customer efficiency programs, improved transmission capacity revenues, and higher natural gas volumes from colder spring weather. Partially offsetting this increase was higher QF related supply costs due to higher prices and volumes.

	Three Months Ended June 30,
	2010		2009		Change			% Change
	(in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	57.1	$	60.9	$	(3.8	)	(6.2	)%
Property and other taxes	25.0		18.2		6.8			37.4
Depreciation	23.0		22.3		0.7			3.1
	$	105.1	$	101.4	$	3.7		3.6	%

Consolidated operating, general and administrative expenses were $57.1 million for the three months ended June 30, 2010 as compared with $60.9 million for the three months ended June 30, 2009. Primary components of this change include the following:

	Operating, General & Administrative Expenses
	2010 vs. 2009
	(Millions of Dollars)
Postretirement health care	$	(1.5	)
Pension	(1.3		)
Jointly owned plant operations	(1.1		)
Legal and professional fees	(0.9		)
Bad debt expense	(0.5		)
Insurance recoveries and settlements	1.8
Operating expenses recovered in supply trackers	0.9
Other		(1.2	)
Decrease in Operating, General & Administrative Expenses	$	(3.8	)

The decrease in operating, general and administrative expenses of $3.8 million was primarily due to the following:

·	Lower postretirement health care costs due to a plan amendment during the fourth quarter of 2009. We expect postretirement health care costs to total approximately $1.5 million for the full year 2010 as compared to approximately $5.7 million for the full year 2009;

·	Lower pension expense, however, based on current assumptions we expect the annual pension expense to be comparable with 2009 due to the regulatory treatment of our Montana pension plan;

·	Lower plant operations costs due to scheduled maintenance and an unplanned outage at Colstrip Unit 4 for a rotor repair in 2009;

·	Decreased legal and professional fees primarily related to outstanding litigation;

·	Lower bad debt expense based on lower average customer receivables;

·	Net decrease in insurance recoveries and settlements due to $4.4 million received in second quarter 2009 as compared with $2.6 million received in the second quarter 2010; and

·	Higher operating expenses recovered from customers through supply trackers primarily related to costs incurred for customer efficiency programs, which have no impact on operating income.

Property and other taxes were $25.0 million for the three months ended June 30, 2010 as compared with $18.2 million in the second quarter of 2009. This increase was primarily due to plant additions related to the Mill Creek Generating Station and higher assessed property valuations in Montana.

Depreciation expense was $23.0 million for the three months ended June 30, 2010 as compared with $22.3 million in the second quarter of 2009. This increase was primarily due to plant additions.

Consolidated operating income for the three months ended June 30, 2010 was $27.0 million, as compared with $27.5 million in the second quarter of 2009. This decrease was primarily due to higher property and other taxes, which were partly offset by the increase in gross margin and decrease in operating, general and administrative expenses discussed above.

Consolidated interest expense for the three months ended June 30, 2010 was $16.1 million, a decrease of $1.9 million, or 10.6%, from 2009. This decrease was primarily due to $1.0 million capitalized for the debt portion of allowance for funds used during construction (AFUDC), primarily related to the Mill Creek Generating Station. We expect to capitalize approximately $2.5 million of AFUDC related to the Mill Creek Generating Station through the remainder of the year.

Consolidated other income for the three months ended June 30, 2010 was $1.9 million, as compared with $0.2 million in the second quarter of 2009. This includes approximately $1.6 million capitalized for the equity portion of AFUDC, primarily related to the Mill Creek Generating Station. We expect to capitalize approximately $4.0 million of AFUDC related to the Mill Creek Generating Station through the remainder of the year.

Consolidated income tax expense for the three months ended June 30, 2010 was $1.1 million as compared with $3.6 million for the second quarter of 2009. The effective tax rate in 2010 was 8.7% as compared with 36.9% for the same period of 2009. The reduction in the effective income tax rate versus the statutory rate in 2010 is primarily due to:

·	the release of $2.2 million in valuation allowance against certain state net operating loss (NOL) carryforwards, and

·	a tax benefit of $1.2 million recognized for repair costs, due to flow-through regulatory treatment.

We received approval of a tax accounting method change for repair costs during September 2009. Our effective tax rate for the year ended December 31, 2009 of 17.2% reflected the impact of the tax accounting method change for repairs for both 2009 and 2008, which impacts the comparability of the income tax benefit for 2010 as compared with 2009. In addition, as we did not receive approval of the tax accounting method change until the third quarter of 2009, quarterly income tax expense during 2010 will not be comparable with 2009.

While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2014, based on our projected taxable income and anticipated use of consolidated NOL carryforwards.

Consolidated net income for the three months ended June 30, 2010 was $11.7 million as compared with $6.1 million for the second quarter of 2009. This increase was primarily due to lower interest and income tax expense and higher other income, offset in part by lower operating income as discussed above.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009

	Six Months Ended June 30,
	2010			2009			Change			% Change
	(in millions)
Operating Revenues
Electric	$	388.7	$		381.5		$	7.2		1.9	%
Natural Gas	188.9		220.1				(31.2		)	(14.2	)
Other	0.7		5.9				(5.2		)	(88.1	)
Eliminations	—		(0.9			)	0.9			100.0
	$	578.3	$		606.6		$	(28.3	)	(4.7	)%

	Six Months Ended June 30,
	2010		2009		Change			% Change
	(in millions)
Cost of Sales
Electric	$	173.4	$	166.4	$	7.0		4.2	%
Natural Gas	111.4		141.7		(30.3		)	(21.4	)
Other	—		6.7		(6.7		)	(100.0	)
	$	284.8	$	314.8	$	(30.0	)	(9.5	)%

	Six Months Ended June 30,
	2010		2009			Change			% Change
	(in millions)
Gross Margin
Electric	$	215.3	$	215.1		$	0.2		0.1	%
Natural Gas	77.5		78.4			(0.9		)	(1.1	)
Other	0.7		(0.8		)	1.5			187.5
Eliminations	—		(0.9		)	0.9			100.0
	$	293.5	$	291.8		$	1.7		0.6	%

Consolidated gross margin was $293.5 million for the six months ended June 30, 2010, an increase of $1.7 million, or 0.6%, from gross margin in 2009. Primary components of this change include the following:

	Gross Margin
	2010 vs. 2009
	(in millions)
Montana property tax tracker	$	4.4
Loss on capacity contract in 2009	1.2
Operating expenses recovered in supply trackers	1.2
Reclamation settlement	1.0
QF supply costs	(3.6		)
Electric and natural gas volumes	(2.7		)
Wholesale electric	(0.6		)
Other	0.8
Increase in Consolidated Gross Margin	$	1.7

This $1.7 million increase was primarily due to an increase in property taxes recoverable through a tracker as compared with 2009. Also contributing to the increase was a loss recorded in 2009 on a capacity contract, higher revenues for operating expenses recovered in supply trackers, primarily related to customer efficiency programs, decreased cost of sales due to a settlement to recover previously incurred reclamation costs associated with the coal supply at Colstrip, and the recognition of revenues associated with a natural gas contract with minimum usage requirements that were not met. Partially offsetting this increase was higher QF related supply costs due to higher prices and volumes, lower electric and natural gas volumes due to unfavorable weather and lower average wholesale prices.

	Six Months Ended June 30,
	2010		2009		Change			% Change
	(in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	115.4	$	126.3	$	(10.9	)	(8.6	)%
Property and other taxes	48.0		42.5		5.5			12.9
Depreciation	45.9		45.0		0.9			2.0
	$	209.3	$	213.8	$	(4.5	)	(2.1	)%

Consolidated operating, general and administrative expenses were $115.4 million for the six months ended June 30, 2010 as compared with $126.3 million for the six months ended June 30, 2009. Primary components of this change include the following:

	Operating, General & Administrative Expenses
	2010 vs. 2009
	(Millions of Dollars)
Insurance reserves	$	(2.9	)
Compensation	(2.3		)
Postretirement health care	(2.0		)
Pension	(1.9		)
Jointly owned plant operations	(0.9		)
Bad debt expense	(0.8		)
Legal and professional fees	(0.4		)
Insurance recoveries and settlements	2.1
Operating expenses recovered in supply trackers	1.2
Other	(3.0		)
Decrease in Operating, General & Administrative Expenses	$	(10.9	)

The decrease in operating, general and administrative expenses of $10.9 million was primarily due to the following:

·	Lower insurance reserves due to claims incurred in the prior year and a favorable arbitration decision in the first quarter of 2010;

·	Decreased compensation costs primarily from a combination of lower headcount, more time spent by employees on capital projects rather than maintenance projects (which are expensed), and lower severance costs;

·	Lower postretirement health care costs due to a plan amendment during the fourth quarter of 2009;

·	Lower pension expense, however, based on current assumptions we expect the annual pension expense to be comparable with 2009 due to the regulatory treatment of our Montana pension plan;

·	Lower plant operations costs due to scheduled maintenance and an unplanned outage at Colstrip Unit 4 for a rotor repair in 2009;

·	Lower bad debt expense based on lower average customer receivables;

·	Decreased legal and professional fees primarily related to outstanding litigation;

·	Net decrease in insurance recoveries and settlements due to $4.7 million received during the first six months of 2009 as compared with $2.6 million received during the first six months of 2010; and

·	Higher operating expenses recovered from customers through supply trackers primarily related to costs incurred for customer efficiency programs, which have no impact on operating income.

Property and other taxes were $48.0 million for the six months ended June 30, 2010 as compared with $42.5 million in the same period of 2009. This increase was primarily due to plant additions related to the Mill Creek Generating Station and higher assessed property valuations in Montana.

Depreciation expense was $45.9 million for the six months ended June 30, 2010 as compared with $45.0 million in the same period of 2009. This increase was primarily due to plant additions.

Consolidated operating income for the six months ended June 30, 2010 was $84.2 million, as compared with $77.9 million in the same period of 2009. The increase was primarily due to the $4.5 million decrease in operating expenses and the $1.7 million increase in gross margin discussed above.

Consolidated interest expense remained flat for the six months ended June 30, 2010 compared with the same period in 2009, with an increase in expense due primarily to increased debt outstanding offset by $1.8 million capitalized for the debt portion of AFUDC, primarily related to the Mill Creek Generating Station.

Consolidated other income for the six months ended June 30, 2010 was $2.6 million, as compared with $0.8 million in the same period of 2009. This includes an increase of approximately $2.3 million capitalized for the equity portion of AFUDC, primarily related to the Mill Creek Generating Station.

Consolidated income tax expense for the six months ended June 30, 2010 was $13.3 million as compared with $16.7 million in the same period of 2009. The effective tax rate in 2010 was 24.8% as compared with 36.6% for the same period of 2009, and we expect our effective tax rate for 2010 to be approximately 25%. The reduction in effective tax rate versus the statutory rate in 2010 is primarily due to the release of valuation allowance discussed above, and a tax benefit of $4.6 million recognized for repair costs.

Consolidated net income for the six months ended June 30, 2010 was $40.4 million as compared with $28.9 million in the same period of 2009. The increase was primarily due to higher operating income, higher other income, and lower income tax expense as discussed above.

ELECTRIC SEGMENT

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009

	Results
	2010		2009		Change			% Change
	(in millions)
Retail revenue	$	149.7	$	151.1	$	(1.4	)	(0.9	)%
Transmission	11.0		10.3		0.7			6.8
Wholesale	11.9		10.6		1.3			12.3
Regulatory amortization and other	12.2		1.5		10.7			713.3
Total Revenues	184.8		173.5		11.3			6.5
Total Cost of Sales	82.3		71.7		10.6			14.8
Gross Margin	$	102.5	$	101.8	$	0.7		0.7	%

	Revenues					Megawatt Hours (MWH)		Avg. Customer Counts
	2010		2009			2010	2009	2010	2009
	(in thousands)
Retail Electric
Montana	$	47,213		$	47,366	496	488	270,369	268,627
South Dakota	9,489			9,496		110	108	48,419	48,181
Residential	56,702			56,862		606	596	318,788	316,808
Montana	63,640			64,402		741	749	60,777	60,316
South Dakota	14,938			14,748		213	202	11,848	11,701
Commercial	78,578			79,150		954	951	72,625	72,017
Industrial	8,129			8,267		684	702	71	72
Other	6,335			6,840		41	49	5,805	5,843
Total Retail Electric	$	149,744		$	151,119	2,285	2,298	397,289	394,740
Wholesale Electric
Montana	$	10,231		$	9,068	188	96	N/A	N/A
South Dakota	1,678			1,485		90	58	N/A	N/A
Total Wholesale Electric	$	11,909		$	10,553	278	154	N/A	N/A

	2010 as compared to:
Cooling Degree Days	2009	Historic Average
Montana	20% colder	41% colder
South Dakota	70% warmer	4% warmer

The following summarizes the components of the changes in electric margin for the three months ended June 30, 2010 and 2009:

	Gross Margin
	2010 vs. 2009
	(Millions of Dollars)
Montana property tax tracker	$	3.4
Transmission capacity	0.7
Operating expenses recovered in supply tracker	0.5
QF supply costs	(3.6		)
Other	(0.1		)
Increase in Gross Margin	$	0.7

The increase in margin is due largely to an increase in property taxes recoverable in a tracker as compared to the same period in 2009. Also contributing to the increase was higher demand to transmit energy for others across our lines, and higher revenues for operating expenses recovered from customers through the supply trackers, primarily related to customer efficiency programs. Partially offsetting this increase was higher QF related supply costs due to higher prices and volumes. The increase in regulatory amortization is due to deferred costs primarily related to electric supply and property taxes that have been approved for recovery in our revenues but not yet billed to customers.

Retail residential and commercial volumes increased from customer growth, which was offset by a decline in commercial and industrial volumes in Montana due primarily to the weaker economy. Wholesale volumes increased due to higher plant availability. In addition, while cooling degree days may fluctuate significantly during the second quarter, our customer usage is not highly sensitive to these changes between heating and cooling seasons.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009

	Results
	2010		2009		Change			% Change
	(in millions)
Retail revenue	$	320.2	$	331.6	$	(11.4	)	(3.4	)%
Transmission	22.5		22.3		0.2			0.9
Wholesale	23.0		21.7		1.3			6.0
Regulatory amortization and other	23.0		5.9		17.1			289.8
Total Revenues	388.7		381.5		7.2			1.9
Total Cost of Sales	173.4		166.4		7.0			4.2
Gross Margin	$	215.3	$	215.1	$	0.2		0.1	%

	Revenues					Megawatt Hours (MWH)		Avg. Customer Counts
	2010		2009			2010	2009	2010	2009
	(in thousands)
Retail Electric
Montana	$	110,809		$	113,460	1,176	1,166	270,648	268,815
South Dakota	22,334			23,042		286	280	48,421	48,188
Residential	133,143			136,502		1,462	1,446	319,069	317,003
Montana	129,858			133,294		1,529	1,545	60,788	60,260
South Dakota	30,746			31,421		451	430	11,735	11,588
Commercial	160,604			164,715		1,980	1,975	72,523	71,848
Industrial	15,896			19,213		1,360	1,467	71	72
Other	10,540			11,151		65	73	5,212	5,242
Total Retail Electric	$	320,183		$	331,581	4,867	4,961	396,875	394,165
Wholesale Electric
Montana	$	20,165		$	18,890	392	299	N/A	N/A
South Dakota	2,755			2,793		129	98,	N/A	N/A
Total Wholesale Electric	$	22,920		$	21,683	521	397	N/A	N/A

	2010 as compared to:
Cooling Degree Days	2009	Historic Average
Montana	20% colder	41% colder
South Dakota	70% warmer	4% warmer

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, 2010.

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, 2010 and are summarized for the six months ended June 30, 2010 as compared with 2009 as follows:

	Gross Margin
	2010 vs. 2009
	(Millions of Dollars)
Montana property tax tracker	$	4.5
Operating expenses recovered in supply tracker	1.2
Reclamation settlement	1.0
QF supply costs	(3.6		)
Retail volumes	(1.7		)
South Dakota wholesale	(0.6		)
Other		(0.6	)
Increase in Gross Margin	$	0.2

Retail volumes were impacted by decreases in industrial demand relating to the weak economic climate. Wholesale volumes increased due to higher plant availability.

NATURAL GAS SEGMENT

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009

	Results
	2010		2009		Change			% Change
	(in millions)
Retail revenue	$	45.6	$	50.4	$	(4.8	)	(9.5	)%
Wholesale and other	13.3		10.9		2.4			22.0
Total Revenues	58.9		61.3		(2.4		)	(3.9	)
Total Cost of Sales	29.6		32.8		(3.2		)	(9.8	)
Gross Margin	$	29.3	$	28.5	$	0.8		2.8	%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2010		2009		2010	2009	2010	2009
	(in thousands)
Retail Gas
Montana	$	19,841	$	21,150	2,303	2,133	157,867	157,045
South Dakota	4,513		5,744		454	550	37,081	36,571
Nebraska	4,279		5,016		439	502	36,375	36,259
Residential	28,633		31,910		3,196	3,185	231,323	229,875
Montana	9,656		10,143		1,124	1,049	22,077	22,009
South Dakota	3,649		4,331		507	574	5,867	5,796
Nebraska	3,236		3,649		509	565	4,531	4,496
Commercial	16,541		18,123		2,140	2,188	32,475	32,301
Industrial	253		212		30	22	288	295
Other	173		193		23	22	146	142
Total Retail Gas	$	45,600	$	50,438	5,389	5,417	264,232	262,613

	2010 as compared with:
Heating Degree-Days	2009	Historic Average
Montana	11% colder	5% colder
South Dakota	23% warmer	20% warmer
Nebraska	10% warmer	10% warmer

The following summarizes the components of the changes in natural gas margin for the three months ended June 30, 2010 and 2009:

	Gross Margin
	2010 vs. 2009
	(Millions of Dollars)
Colder weather in Montana	$	0.5
Operating expenses recovered in supply tracker	0.4
Other	(0.1		)
Increase in Gross Margin	$	0.8

This increase in margin is primarily due to colder spring weather impacting our residential volumes in Montana. Also contributing to the increase was higher operating expenses recovered from customers through the supply tracker related to customer efficiency programs. In addition, average natural gas supply prices decreased resulting in lower retail revenues and cost of sales in 2010 as compared with 2009, with no impact to gross margin.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009

	Results
	2010		2009		Change			% Change
	(in millions)
Retail revenue	$	164.0	$	194.9	$	(30.9	)	(15.9	)%
Wholesale and other	24.9		25.2		(0.3		)	(1.2	)
Total Revenues	188.9		220.1		(31.2		)	(14.2	)
Total Cost of Sales	111.4		141.7		(30.3		)	(21.4	)
Gross Margin	$	77.5	$	78.4	$	(0.9	)	(1.1	)%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2010		2009		2010	2009	2010	2009
	(in thousands)
Retail Gas
Montana	$	64,460	$	76,674	7,256	7,516	158,080	157,220
South Dakota	19,064		24,433		2,021	2,127	37,328	36,838
Nebraska	17,112		20,459		1,888	1,817	36,625	36,536
Residential	100,636		121,566		11,165	11,460	232,033	230,594
Montana	32,069		38,413		3,607	3,785	22,083	22,027
South Dakota	16,917		18,627		2,239	2,070	5,915	5,841
Nebraska	12,742		14,592		1,864	1,796	4,568	4,539
Commercial	61,728		71,632		7,710	7,651	32,566	32,407
Industrial	1,079		1,015		125	102	290	297
Other	564		669		74	74	146	142
Total Retail Gas	$	164,007	$	194,882	19,074	19,287	265,035	263,440

	2010 as compared with:
Heating Degree-Days	2009	Historic Average
Montana	Remained flat	3% warmer
South Dakota	4% warmer	1% colder
Nebraska	5% colder	3% colder

Average natural gas supply prices decreased resulting in lower retail revenues and cost of sales in 2010 as compared with 2009, with no impact to gross margin. The following summarizes the components of the changes in natural gas margin for the six months ended June 30, 2010 and 2009:

	Gross Margin
	2010 vs. 2009
	(Millions of Dollars)
Warmer winter weather	$	(1.0	)
Other	0.1
Decrease in Gross Margin	$	(0.9	)

The decline in margin and volumes is primarily due to warmer winter weather in Montana during the first quarter of 2010 offset in part by colder spring weather in Montana during the second quarter of 2010.

LIQUIDITY AND CAPITAL RESOURCES

We utilize our revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. As of June 30, 2010 , our total net liquidity was approximately $169.6 million, including $6.1 million of cash and $163.5 million of revolving credit facility availability. Revolver availability was $171.5 million as of July 23, 2010.

Factors Impacting our Liquidity

Financing Activities - On May 27, 2010 we issued $161 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.01% maturing May 1, 2025. We also issued $64 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.01% maturing May 1, 2025. We used the proceeds to redeem our 5.875%, $225 million Senior Secured Notes due 2014.

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, 2010, we are over collected on our current Montana natural gas and electric trackers by approximately $1.3 million, as compared with an under collection of $19.8 million as of December 31, 2009, and an over collection of $21.3 million as of June 30, 2009.

Growth Capital Expenditures – In July 2009, we began construction of the Mill Creek Generating Station, a 150 MW natural gas fired facility, estimated to cost $202 million. During the six months ended June 30, 2010, we capitalized approximately $57.8 million in construction work in process related to this project. We expect to spend an additional $25 million on this project during the remainder of 2010.

Credit Ratings

Fitch Ratings (Fitch), Moody’s Investors Service (Moody’s) and Standard and Poor’s Rating Group (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of July 23, 2010, our current ratings with these agencies are as follows:

	Senior Secured Rating	Senior Unsecured Rating	Outlook
Fitch	A-	BBB+	Stable
Moody’s	A3	Baa2	Positive
S&P	A-	BBB	Stable

(1)	Fitch upgraded our senior secured and senior unsecured credit rating on April 15, 2010, from BBB+ to A- and BBB to BBB+, 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 impact 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.

Cash Flows

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

	Six Months Ended June 30,
	2010			2009
Operating Activities
Net income	$	40.4		$	28.9
Non-cash adjustments to net income	65.9			64.6
Changes in working capital	27.5			27.0
Other	(1.4		)	(35.0		)
	132.4			85.5

Investing Activities
Property, plant and equipment additions	(116.2		)	(46.9		)
Sale of assets	—			0.3
	(116.2		)	(46.6		)

Financing Activities
Net borrowing of debt	16.7			6.8
Dividends on common stock	(24.5		)	(24.1		)
Other	(6.6		)	(9.9		)
	(14.4		)	(27.2		)

Net Increase in Cash and Cash Equivalents	$	1.8		$	11.7
Cash and Cash Equivalents, beginning of period	$	4.3		$	11.3
Cash and Cash Equivalents, end of period	$	6.1		$	23.0

Cash Provided by Operating Activities

As of June 30, 2010, cash and cash equivalents were $6.1 million as compared with $4.3 million at December 31, 2009 and $23.0 million at June 30, 2009. Cash provided by operating activities totaled $132.4 million for the six months ended June 30, 2010 as compared with $85.5 million during the six months ended June 30, 2009. This increase in operating cash flows is primarily related to a decrease in contributions to our qualified pension plans of $53.2 million as compared with the same period in 2009.

Cash Used in Investing Activities

Cash used in investing activities increased by approximately $69.6 million as compared with the six months ended June 30, 2009 due primarily to increased property, plant and equipment additions related to the Mill Creek Generating Station project as discussed above.

Cash Used in Financing Activities

Cash used in financing activities totaled approximately $14.4 million during the six months ended June 30, 2010 as compared with $27.2 million during 2009. During the six months ended June 30, 2010 we received proceeds from the issuance of debt of $225.0 million, made debt repayments of $208.4 million, paid deferred financing costs of $6.6 million and paid dividends on common stock of $24.5 million. During the six months ended June 30, 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.

Sources and Uses of Funds

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.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of June 30, 2010. See our Annual Report on Form 10-K for the year ended December 31, 2009 for additional discussion.

	Total		2010		2011		2012		2013		2014		Thereafter
	(in thousands)
Long-term Debt	$	1,004,059	$	2,733	$	6,578	$	89,792	$	—	$	—	$	904,956
Capital Leases	36,189		619		1,282		1,370		1,468		1,582		29,868
Future minimum operating lease payments	3,728		762		1,254		888		262		230		332
Estimated Pension and Other Postretirement Obligations (1)	39,109		1,909		13,800		13,800		4,800		4,800		N/A
Qualifying Facilities (2)	1,366,296		32,290		65,323		67,111		69,816		72,354		1,059,402
Supply and Capacity Contracts (3)	1,569,021		182,835		243,281		186,878		162,763		119,869		673,395
Other Purchase Obligations (4)	22,714		22,714		—		—		—		—		—
Contractual interest payments on debt (5)	603,441		27,099		53,917		52,093		50,566		50,566		369,200
Total Commitments (6)	$	4,644,557	$	270,961	$	385,435	$	411,932	$	289,675	$	249,401	$	3,037,153

(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. These estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.

(2) The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $167 per MWH through 2029. 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 $1.0 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.

(4) This represents contractual purchase obligations related to Mill Creek Generating Station construction project.

(5) Contractual interest payments include our revolving credit facility, which has a variable interest rate. We have assumed an average interest rate of 2.75% on an estimated revolving line of credit balance of $86.0 million through maturity in June 2012.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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, 2010, there have been no significant changes with regard to the critical accounting policies disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2009. The policies disclosed included the accounting for the following: goodwill and long-lived assets, qualifying facilities liability, revenue recognition, regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Interest Rate Risk

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing primarily fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. 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, 2010, the applicable spread was 2.75%, resulting in a borrowing rate of 3.10%. Based upon amounts outstanding as of June 30, 2010, a 1% increase in the LIBOR would increase our annual interest expense by approximately $0.9 million.

Commodity Price Risk

Commodity price risk is a significant risk due to our lack of ownership of natural gas reserves and our reliance on market purchases to fulfill a large portion of our electric supply requirements within the Montana market. We also participate in the wholesale electric market to balance our supply of power from our own generating resources, primarily in South Dakota. 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 electric and natural gas supply requirements, we employ the use of market purchases, including forward purchase and sales contracts. These types of contracts are included in our 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. As a regulated utility, our exposure to market risk caused by changes in commodity prices is substantially mitigated because these commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by applicable state regulatory commissions.

Counterparty Credit Risk

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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the six months ended June 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 13, Commitments and Contingencies, to the Financial Statements for information about legal proceedings.

ITEM 1A. RISK FACTORS

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our 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 has resulted in a decline in energy consumption and a decrease in customers’ ability 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, we have experienced declines in electric and natural gas usage per customer and lower electric transmission sales, due in part to the recession. In addition, demand for our Montana transmission capacity is impacted by market conditions in states to the South and West of our service territory, which have been more significantly impacted by the economic downturn.

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. 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 FERC, MPSC, SDPUC and Nebraska Public Service Commission. Regulations can affect allowed rates of return, recovery of costs and operating requirements. For example, in our 2008 proceeding related to Colstrip, 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. The outcome of our Montana electric and natural gas rate case filed in 2009 could have a significant impact on our liquidity and results of operations. The filing is based upon a 2008 test period, and we anticipate a final determination on the filing during the fourth quarter of 2010, which creates a delay between the timing of when such costs are incurred and when the costs are recovered from customers. This lag can adversely impact our cash flows. 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 FERC 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 Western Electricity Coordination Counsel 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, coal ash and other environmental considerations. We believe that we are in 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, 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.

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 and a federal court of appeal has reinstated nuisance claims against emitters of carbon dioxide, including several utility companies, alleging that such emissions contribute to global warming. 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.

Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including rate of return on plan assets, discount rates, other actuarial assumptions, and government regulation. Due to the unprecedented volatility in equity markets, we experienced plan asset market gains during 2009 in excess of 20%, and plan asset market losses during 2008 in excess of 30%. Without sustained growth in the plan assets over time and depending upon the other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.

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, is 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.

Our proposed capital investment projects are based on assumptions regarding future growth and resulting power demand that may not be realized. The timing and extent of the recovery of the economy, and its impact on demand cannot be predicted. Additionally, our customers may undertake further individual energy conservation measures, which could decrease the demand for electricity. We may increase our transmission and/or baseload capacity and have excess capacity if anticipated growth levels are not realized. The resulting excess capacity could exceed our obligation to serve retail customers or demand for transmission capacity and, as a result, may not be recoverable from customers.

The construction of new generation and expansion of our transmission system will require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support these projects. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with these projects, but we cannot be certain we will be able to successfully negotiate any such arrangement. Furthermore, joint ventures or joint ownership arrangements also present risks and uncertainties, including those associated with sharing control over the construction and operation of a facility and reliance on the other party’s financial or operational strength.

We have filed for and received advanced approval from the MPSC to construct the Mill Creek Generating Station. The MPSC determined the cost of the gas turbines is prudent, with the remainder of the project costs to be submitted for review upon completion of construction. A portion of these future costs could potentially be deemed imprudent, which we would not be able to recover from customers.

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. As of June 30, 2010, we have capitalized approximately $147.2 million in construction work in process associated with the Mill Creek Generating Station and $14.1 million in preliminary survey and investigative costs associated with transmission projects.

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 a previous stipulation with the MPSC and other parties, 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 obligation.

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 electric 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 electric generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, 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.

There is also a concern that the physical risks of climate change could include changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate. Extreme weather conditions creating high energy demand on our own and/or other systems may raise market prices as we buy short-term energy to serve our own system. Severe weather impacts our service territories, primarily through thunderstorms, tornadoes and snow or ice storms. To the extent the frequency of extreme weather events increase, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our ability to provide electricity to customers, as well as increase the price they pay for energy. In addition, extreme weather may exacerbate the risks to physical infrastructure. We may not recover all costs related to mitigating these physical and financial risks.

We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.

A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms and increase our borrowing costs.

Our secured credit ratings are also tied to our ability to invest in unregulated ventures due to an existing stipulation with the MPSC and MCC, which establishes diminishing limits for such investment at certain credit rating levels. The stipulation does not limit investment in unregulated ventures so long as we maintain credit ratings on a secured basis of at least BBB+ (S&P) and Baa1 (Moody’s). For a further discussion of how a lack of liquidity and access to adequate capital could affect our operations, please see the Risk Factor above, “Economic conditions and instability in the financial markets could negatively impact our business.”

ITEM 6. EXHIBITS

(a) Exhibits

Exhibit 4.1—Twenty-ninth Supplemental Indenture, dated as of May 1, 2010, among NorthWestern Corporation and The Bank of New York Mellon and Ming Ryan, as trustees.

Exhibit 4.2—Ninth Supplemental Indenture, dated as of May 1, 2010, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993.

Exhibit 10.1—Purchase Agreement, dated April 26, 2010, among NorthWestern Corporation and the purchasers named therein to the issuance of $161,000,000 aggregate principal amount of 5.01% First Mortgage Bonds due 2025 (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated April 26, 2010, Commission File No. 1-10499).

Exhibit 10.2—Purchase Agreement, dated April 26, 2010, among NorthWestern Corporation and the purchasers relating to the issuance of $64,000,000 aggregate principal amount of 5.01% First Mortgage Bonds due 2025 (incorporated by reference to Exhibit 10.2 of NorthWestern Corporation’s Current Report on form 8-K, dated April 26, 2010, Commission File No. 1-10499).

Exhibit 10.3—NorthWestern Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, as amended April 21, 2010.

Exhibit 10.4—NorthWestern Corporation 2009 Officers Deferred Compensation Plan, as amended April 21, 2010.

Exhibit 10.5—Offer letter by and between NorthWestern Corporation and Heather H. Grahame, executed May 12, 2010.

Exhibit 31.1—Certification of chief executive officer.

Exhibit 31.2—Certification of chief financial officer.

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.

Exhibit 101.INS—XBRL Instance Document

Exhibit 101.SCH—XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL—XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF—XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB—XBRL Taxonomy Label Linkbase Document

Exhibit 101.PRE—XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

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

		N orthwestern C orporation
Date: July 29, 2010	By:	/s/ BRIAN B. BIRD
		Brian B. Bird
		Chief Financial Officer
		Duly Authorized Officer and Principal Financial Officer

EXHIBIT INDEX

Exhibit Number		Description
*4.1		Twenty-ninth Supplemental Indenture, dated as of May 1, 2010, among NorthWestern Corporation and The Bank of New York Mellon and Ming Ryan, as trustees.
*4.2		Ninth Supplemental Indenture, dated as of May 1, 2010, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993.
10.1		Purchase Agreement, dated April 26, 2010, among NorthWestern Corporation and the purchasers named therein to the issuance of $161,000,000 aggregate principal amount of 5.01% First Mortgage Bonds due 2025 (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated April 26, 2010, Commission File No. 1-10499).
10.2		Purchase Agreement, dated April 26, 2010, among NorthWestern Corporation and the purchasers relating to the issuance of $64,000,000 aggregate principal amount of 5.01% First Mortgage Bonds due 2025 (incorporated by reference to Exhibit 10.2 of NorthWestern Corporation’s Current Report on form 8-K, dated April 26, 2010, Commission File No. 1-10499).
*10.3		NorthWestern Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, as amended April 21, 2010.
*10.4		Corporation 2009 Officers Deferred Compensation Plan, as amended April 21, 2010.
*10.5		Offer letter by and between NorthWestern Corporation and Heather H. Grahame, executed May 12, 2010.
*31.1		Certification of chief executive officer.
*31.2		Certification of chief financial officer.
*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.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Taxonomy Extension Schema Document
*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB		XBRL Taxonomy Label Linkbase Document
*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith

Series	Principal Amount Issued	Principal Amount Outstanding
2-7/8% Series due 1975	$40,000,000	NONE
3-1/8% Series due 1984	6,000,000	NONE
4-1/2% Series due 1989	15,000,000	NONE
8-1/4% Series due 1974	30,000,000	NONE
7-1/2% Series due 2001	25,000,000	NONE
8-5/8% Series due 2004	60,000,000	NONE
8-3/4% Series due 1981	30,000,000	NONE
9.60% Series due 2005	35,000,000	NONE
9.70% Series due 2005	65,000,000	NONE

9-7/8% Series due 2009	50,000,000	NONE
11-3/4% Series due 1993	75,000,000	NONE
10/10-1/8% Series due 2004/2014	80,000,000	NONE
8-1/8% Series due 2014	41,200,000	NONE
7.70% Series due 1999	55,000,000	NONE
8-1/4% Series due 2007	55,000,000	NONE
8.95% Series 2022	50,000,000	NONE
Secured Medium-Term Notes	68,000,000	NONE
7% Series due 2005	50,000,000	NONE
6-1/8% Series due 2023	90,205,000	NONE
5.90% Series due 2023	80,000,000	NONE
0% Series due 1999	210,321,007	NONE
7.30% Series due 2006	150,000,000	NONE
Collateral (2002) Series due 2006	280,000,000	NONE
Collateral (2004) Series A due 2009	90,000,000	NONE
Collateral (2004) Series B due 2011	72,000,000	NONE
Collateral (2004) Series C due 2014 (Twenty-sixth)	161,000,000	161,000,000
4.65% Series due 2023 (Twenty-seventh)……….	170,205,000	170,205,000
6.04% Series due 2016 (Twenty-eighth)…………	150,000,000	150,000,000
6.34% Series due 2019 (Twenty-ninth) ………….	250,000,000	250,000,000
5.71% Series due 2039 (Thirtieth) ………….	55,000,000	55,000,000

		Page
ARTICLE 1	DEFINITIONS	1
ARTICLE 2	Eligibility	4
2.1	Requirements for Participation	4
2.2	Enrollment Procedure	4
ARTICLE 3	Participants’ Deferrals	4
3.1	Deferral of Qualified Compensation	4
3.2	Irrevocability of Deferral Elections	5
ARTICLE 4	Deferred COMPENSATION ACCOUNTS	5
4.1	Deferred Compensation Accounts	5
4.2	Account Elections	5
4.3	Crediting of Deferred Compensation	5
4.4	Crediting of Earnings	6
4.5	Applicability of Account Values	6
4.6	Vesting of Deferred Compensation Accounts	6
4.7	Assignments, Etc. Prohibited	6
ARTICLE 5	Distribution Of Accounts	6
5.1	Distributions upon a Participant’s Separation from Service	6
5.2	Distributions upon a Participant’s Death	7
5.3	Election of Manner and Time of Distribution	7
5.4	Applicable Taxes	7
5.5	Nature and Sources of Benefit Payments	8
ARTICLE 6	Withdrawals From Accounts	8
6.1	Hardship Distributions from Accounts	8
6.2	Payment of Withdrawals	8
6.3	Effect of Withdrawals	9
6.4	Applicable Taxes	9
ARTICLE 7	Administrative Provisions	9
7.1	Administrator’s Duties and Powers	9
7.2	Limitations Upon Powers	9
7.3	Final Effect of Administrator Action	9
7.4	Delegation by Administrator	10

7.5	Indemnification by the Company; Liability Insurance	10
7.6	Recordkeeping	10
7.7	Statement to Participants	10
7.8	Inspection of Records	11
7.9	Identification of Fiduciaries	11
7.10	Procedure for Allocation of Fiduciary Responsibilities	11
7.11	Claims Procedure	11
7.12	Conflicting Claims	13
7.13	Service of Process	13
7.14	Fees	13
ARTICLE 8	Miscellaneous Provisions	13
8.1	Termination of the Plan	13
8.2	Limitation on Rights of Participants	13
8.3	Consolidation or Merger; Adoption of Plan by Other Companies	14
8.4	Errors and Misstatements	14
8.5	Payment on Behalf of Minor, Etc	14
8.6	Amendment of Plan	14
8.7	Governing Law	14
8.8	Pronouns and Plurality	15
8.9	Titles	15
8.10	References	15

Name of Primary Beneficiary	Social Security Number	Mailing Address	Percentage of Death Benefit
			%
			%

Name of Contingent Beneficiary	Social Security Number	Mailing Address	Percentage of Death Benefit
			%
			%

o Agreed to and accepted by: ________________________	Date: ______________________
o Declined by: _____________________________________	Date: ______________________

Date: July 29, 2010
/s/ ROBERT C. ROWE
Robert C. Rowe
President and Chief Executive Officer

Date: July29_, 2010
/s/ BRIAN B. BIRD
Brian B. Bird
Vice President, Chief Financial Officer and Treasurer