2021

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 als o 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. ~~The fin al arbitration panel award is pending confirmation by~~On June 15, 2010, the Montana district court ~~which held a hearing on April 9, 2010 and asked the parties to submit proposed orders by May 7, 2010. If~~ confirmed the final arbitration panel award ~~will require us~~and denied CELP’s motion to ~~refile~~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. ~~CELP continues to dispute the results of the arbitration award, and due to the uncertainty around the resolution we~~In addition, settlement discussions concerning these claims are ~~currently unable to predict the outcome of this matter.~~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.

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The Gonzales Action was first filed on December 18, 1999, against MPC (NOR acquired MPC in 2002) and was stayed due to the ~~Chapter~~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~~t he 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~~f iled an appeal to the Supreme Court of the State of Montana with respect to ~~t hese~~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. ~~In addition,~~

The parties have agreed to settle the Gonzales Action and have executed a settlement ~~discussions concerning these~~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, ~~are ongoing.~~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~~investig ation 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~~Twenty-two lawsuits ~~have been filed~~ against NorthWestern ~~to date~~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 ~~been made. Our total available~~approximately $150 million of insurance coverage ~~is approximately $150 million~~available for known and potential claims. We have paid our ~~deductible~~self-insured retention under these policies, and our insurance ~~carrier has~~carriers have assumed the defense and handling of the existing and ~~anticipated~~potential future lawsuits and ~~claims.~~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.~~s ought. 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.

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In October 2009, the parties reached a global settlement, which ~~must be approved~~was subject to approval by the U.S. District Court in Montana and the Delaware Bankruptcy Court. ~~In November 2009,~~On February 23, 2010, the ~~parties submitted documentation concerning~~Delaware Bankruptcy Court approved the ~~settlement to~~settlement. On May 20, 2010, the U.S. District Court in Montana for its approval. Approval of the settlement by the U.S. District Court in Montana is still pending. In February 2010, the parties submitted documentation concerning the settlement to the Delaware Bankruptcy Court, which approved the settlement on February 23, 2010. Aconducted a fairness hearing concerning the proposed settlement ~~is scheduled for May 2010 with~~and approved the ~~U.S. District Court in Montana.~~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. ~~S ierra~~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. On October 13, 2009,~~complaint to the Eighth Circuit Court of Appeals (Court of Appeals). The United States Department of Justice (USDOJ) filed ~~a motion seeking a 30-day extension of the time to file~~ an amicus brief in support of the Sierra Club’s ~~position. The Court of Appeals granted this motion, as well as our subsequ ent joint motion with~~position and the Sierra Club, extending the timeline. In accordance with the revised briefing schedule, the Sierra Club filed its brief on October 14, 2009, the USDOJ filed its amicus brief on November 24, 2009, we filed our brief on December 24, 2009 (the state of South Dakota served an amicus brief in support of our position on December 30, 2009), and on January 22, 2010, the Sierra Club filed its reply brief. Additionally, on March 15, 2010, we filed correspondence with the court submitting recent supplemental authority in support of our positions, to which the Sierra Club and USDOJ also submitted replies.position. Appellate briefing has concluded, and the Court of Appeals held oral arguments ~~are scheduled for~~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.

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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 ~~March 31,~~June 30, 2010 include:

·	Improvement in net income of approximately ~~$5.9~~$5.6 million as compared with 2009, due primarily to income tax benefits and reduced operating , general and administrative ~~expenses;~~expense, which offset an increase in property tax expense; and

~~Improvement in operating cash flows~~Issuance of ~~approximately $41.2~~$161 million ~~due~~of Montana First Mortgage Bonds and $64 million of South Dakota First Mortgage Bonds at 5.01% to ~~lower contributions to~~refinance our ~~qualified pension plans in 2010.~~5.875% $225 million first mortgage bonds.

RESULTS OF OPERATIONS

Our consolidated results include the results of our reportable business ~~units constituting each of our business segments.~~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~~suppl ement 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. ~~Industrial electric distribution volumes were down approximately 12% for the first quarter of 2010 as compared with 2009, resulting in a $1.4 million reduction to gross margin.~~ 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.

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OVERALL CONSOLIDATED RESULTS

Three Months Ended ~~March 31,~~June 30, 2010 Compared with the Three Months Ended ~~March 31,~~June 30, 2009

Three Months Ended March 31,
2010 2009 Change % Change
(in millions)
Operating Revenues
Electric
$ 203.8 $ 208.0 $ (4.2 ) (2.0 )%
Natural Gas
130.0 158.8 (28.8 ) (18.1 )
Other
0.3 4.6 (4.3 ) (93.5 )
Eliminations
— (0.5 ) 0.5 100.0
$ 334.1 $ 370.9 $ (36.8 ) (9.9 )%

	Three Months Ended March 31,									Three Months Ended June 30,
	2010		2009		Change			% Change		2010			2009			Change			% Change
	(in millions)									(in millions)
Cost of Sales
Operating Revenues
Electric	$	91.0	$	94.8	$	(3.8	)	(4.0	)%	$	184.8	$		173.5		$	11.3		6.5	%
Natural Gas	81.8		108.9		(27.1		)	(24.9	)	58.9		61.3				(2.4		)	(3.9	)
Other	—		4.3		(4.3		)	(100.0	)	0.3		1.3				(1.0		)	(76.9	)
Eliminations										—		(0.4			)	0.4			100.0
	$	172.8	$	208.0	$	(35.2	)	(16.9	)%	$	244.0	$		235.7		$	8.3		3.5	%

	Three Months Ended March 31,										Three Months Ended June 30,
	2010		2009			Change			% Change		2010		2009		Change			% Change
	(in millions)										(in millions)
Gross Margin
Cost of Sales
Electric	$	112.8	$	113.2		$	(0.4	)	(0.4	)%	$	82.3	$	71.7	$	10.6		14.8	%
Natural Gas	48.2		49.9			(1.7		)	(3.4	)	29.6		32.8		(3.2		)	(9.8	)
Other	0.3		0.3			—			—		—		2.3		(2.3		)	(100.0	)
Eliminations	—		(0.5		)	0.5			100.0
	$	161.3	$	162.9		$	(1.6	)	(1.0	)%	$	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 ~~$161.3~~$132.1 million for the three months ended ~~March 31,~~June 30, 2010, ~~a decrease~~an increase of ~~$1.6~~$3.2 million, or ~~1.0%~~2.5%, from gross margin in 2009. Primary components of this change include the following:

Gross Margin
2010 vs. 2009
(in millions)
Electric and natural gas volumes $ (3.4 )
Transmission capacity (0.4 )
Commercial natural gas contract minimum usage requirement 0.6
Reclamation settlement 0.5
Operating expenses recovered in supply trackers 0.3
Other 0.8
Decrease in Consolidated Gross Margin $ (1.6 )

	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 ~~$1.6~~$3.2 million ~~decline~~increase was primarily due to an increase in property taxes recoverable through a ~~decrease~~tracker as compared with 2009, a loss recorded in ~~electric volumes from lower industrial demand relating~~2009 on a capacity contract, higher revenues for operating expenses recovered in supply trackers primarily related to ~~the weak economic climate~~customer efficiency programs, improved transmission capacity revenues, and ~~lower~~higher natural gas volumes from ~~warmer winter weather~~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. ~~These decreases~~

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.

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.

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~~met. Partially offsetting this increase was higher QF related supply costs due to higher prices and ~~a settlement~~volumes, lower electric and natural gas volumes due to ~~recover previously incurred reclamation costs associated with the coal supply at Colstrip.~~unfavorable we ather and lower average wholesale prices.

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	Three Months Ended March 31,									Six Months Ended June 30,
	2010		2009		Change			% Change		2010		2009		Change			% Change
	(in millions)									(in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	58.3	$	65.4	$	(7.1	)	(10.9	)%	$	115.4	$	126.3	$	(10.9	)	(8.6	)%
Property and other taxes	23.0		24.3		(1.3		)	(5.3	)	48.0		42.5		5.5			12.9
Depreciation	22.9		22.7		0.2			0.9		45.9		45.0		0.9			2.0
	$	104.2	$	112.4	$	(8.2	)	(7.3	)%	$	209.3	$	213.8	$	(4.5	)	(2.1	)%

Consolidated operating, general and administrative expenses were ~~$58.3~~$115.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2010 as compared with ~~$65.4~~$126.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2009. Primary components of this change include the following:

	Operating, General & Administrative Expenses			Operating, General & Administrative Expenses
	2010 vs. 2009			2010 vs. 2009
	(Millions of Dollars)			(Millions of Dollars)
Insurance reserves	$	(3.0	)	$	(2.9	)
Compensation	(2.2		)	(2.3		)
Postretirement health care				(2.0		)
Pension	(0.6		)	(1.9		)
Postretirement health care	(0.5		)
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	0.3			1.2
Other	(1.1		)	(3.0		)
Decrease in Operating, General & Administrative Expenses	$	(7.1	)	$	(10.9	)

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Cash Provided by Operating Activities

As of ~~March 31,~~June 30, 2010, cash and cash equivalents were ~~$7.1~~$6.1 million as compared with $4.3 million at December 31, 2009 and ~~$83.2~~$23.0 million at ~~March 31,~~June 30, 2009. Cash provided by operating activities totaled ~~$106.3~~$132.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2010 as compared with ~~$65.1~~$85.5 million during the ~~three~~six months ended ~~March 31,~~June 30, 2009. This increase in operating cash flows is primarily related to a decrease in contributions ~~of $43.2 million~~ to our qualified pension plans ~~during~~of $53.2 million as compared with the ~~first quarter of~~same period in 2009.

Cash Used in Investing Activities

Cash used in investing activities increased by approximately ~~$39.6~~$69.6 million as compared with the ~~first quarter of~~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) Provided by~~Used in Financing Activities

Cash used in financing activities totaled approximately ~~$45.7~~$14.4 million induring the ~~first quarter of~~six months ended June 30, 2010 as compared with ~~cash provided by financing activities of approximately $25.0~~$27.2 million during ~~the three months ended March 31,~~ 2009. During the ~~first quarter~~six months ended June 30, 2010 we received proceeds from the issuance of ~~2010 we~~debt of $225.0 million, made debt repayments of ~~$33.4~~$208.4 million, paid deferred financing costs of $6.6 million and paid dividends on common stock of ~~$12.2~~$24.5 million. During the ~~first quarter of~~six months ended June 30, 2009 we ~~issued~~received net proceeds from the issuance of debt of ~~$250.0~~$249.8 million, made net debt repayments of ~~$211.3~~$243.0 million, paid deferred financing costs of $9.9 million and paid dividends on common stock of ~~$12.0~~$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 ~~curre nt~~current liquidity and capital resource requirements, and we may defer capital expenditures as necessary.

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Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of ~~March 31,~~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		Total		2010		2011		2012		2013		2014		Thereafter
	(in thousands)														(in thousands)
Long-term Debt	$	954,044	$	2,733	$	6,578	$	39,792	$	—	$	225,000	$	679,941	$	1,004,059	$	2,733	$	6,578	$	89,792	$	—	$	—	$	904,956
Capital Leases	36,479		907		1,282		1,372		1,468		1,582		29,868		36,189		619		1,282		1,370		1,468		1,582		29,868
Future minimum operating lease payments	3,581		1,146		1,161		765		157		134		218		3,728		762		1,254		888		262		230		332
Estimated Pension and Other Postretirement Obligations (1)	50,064		12,864		13,800		13,800		4,800		4,800		N/A		39,109		1,909		13,800		13,800		4,800		4,800		N/A
Qualifying Facilities (2)	1,381,946		47,940		65,323		67,111		69,816		72,354		1,059,402		1,366,296		32,290		65,323		67,111		69,816		72,354		1,059,402
Supply and Capacity Contracts (3)	1,653,336		270,354		240,775		186,692		162,476		119,869		673,170		1,569,021		182,835		243,281		186,878		162,763		119,869		673,395
Other Purchase Obligations (4)	44,946		44,946		—		—		—		—		—		22,714		22,714		—		—		—		—		—
Contractual interest payments on debt (5)	508,637		45,321		54,230		53,223		52,512		52,512		250,839		603,441		27,099		53,917		52,093		50,566		50,566		369,200
Total Commitments (6)	$	4,633,033	$	426,211	$	383,149	$	362,755	$	291,229	$	476,251	$	2,693,438	$	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 ~~megawatt hour~~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 ~~$1.1~~$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 ~~3.25%~~2.75% on an estimated revolving line of credit balance of ~~$36.0~~$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.

3340

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 ~~March 31,~~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.

3441

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Interest Rate Risk

~~We utilize various risk management instruments to reduce our exposure to market interest~~Interest rate ~~changes. These~~ 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 ~~March 31,~~June 30, 2010, the applicable spread was ~~3.0%~~2.75%, resulting in a borrowing rate of ~~3.25%~~3.10%. Based upon amounts outstanding as of ~~March 31,~~June 30, 2010, a 1% increase in the LIBOR would increase our annual interest expense by approximately ~~$3.6~~$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 ~~electric~~ supply ~~portfolio~~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,~~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.~~mechanisms and are recoverable from customers subject to prudence reviews by applicable sta te 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.

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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 ~~three~~six months ended ~~March 31,~~June 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

3643

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note ~~12,~~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~~impac ted by market conditions in states to the South and West of our service ~~terri tory,~~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 (NPSC).~~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~~ad verse 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 ~~WECC~~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.

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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 ~~u s~~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 ~~two~~a federal ~~courts~~court of appeal ~~have~~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~~emiss ions 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.

~~We are subject to physical and financial risks associated with climate change.~~

Physical risks from climate change could include changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. Our customers' energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, our customers' energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in additional electric generation assets, transmission and other infrastructure to serve increased loads. Decreased energy use due to weather changes could result in decreased revenues. Extreme weather conditions in general increase the stress on our system. Weather condit ions outside of our service territories could have an impact on our results of operations through impacts to the market prices for supply and transmission capacity. We purchase and sell electric and natural gas supply depending upon system needs and market opportunities. 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. We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region's economic health, it also may impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on greenhouse gases or additional environmental regulation, would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

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~~t ransmission 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~~ve ntures 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 ~~March 31,~~June 30, 2010, we have capitalized approximately ~~$119.8~~$147.2 million in construction work in process associated with the Mill Creek Generating Station and ~~$12.3~~$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~~failu re 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.

~~Seasonal~~Weather and weather patterns, including normal seasonal and quarterly fluctuations of ~~our business~~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 ~~positi on~~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 impact s 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 ~~10.1— Waiver~~4.1—Twenty-ninth Supplemental Indenture, dated as of May 1, 2010, among NorthWestern Corporation and ~~Release~~The Bank of ~~Miggie E. Cramblit executed January 5,~~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 January 5, 2010, Commission File No.1-10499).~~

Exhibit 10.2— Consulting agreement with Miggie E. Cramblit, executed January 6, 2010 (incorporated by reference to Exhibit 10.2 of NorthWestern Corporation's Current Report on Form 8-K, dated January 5, 2010, Commission File No.1-10499).

~~Exhibit 10.3—NorthWestern Energy 2010 Annual Incentive Plan (incorporated by reference to Exhibit 99.1~~ of NorthWestern Corporation’s Current Report on Form 8-K, dated ~~February 12,~~April 26, 2010, Commission File No. 1-10499).

Exhibit ~~10.4— Form of~~10.2—Purchase Agreement, dated April 26, 2010, among NorthWestern Corporation ~~Long-Term Performance Incentive Restricted Stock Award Agreement~~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 ~~99.2~~10.2 of NorthWestern Corporation’s Current Report on ~~Form~~form 8-K, dated ~~February 12,~~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 pursuant to Section 302 of the Sarbanes Oxley Act of 2002.~~officer.

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

4148

SIGNATURES

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

		Northwestern Corporation
Date: ~~April 23,~~July 29, 2010	By:	/s/ BRIAN B. BIRD
		Brian B. Bird
		Chief Financial Officer
		Duly Authorized Officer and Principal Financial Officer

4249

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		~~Waiver~~Purchase Agreement, dated April 26, 2010, among NorthWestern Corporation and ~~Release~~the purchasers named therein to the issuance of ~~Miggie E. Cramblit executed January 5, 2010~~$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 January 5, 2010, Commission File No.1-10499).~~
~~10.2~~		Consulting agreement with Miggie E. Cramblit, executed January 6, 2010 (incorporated by reference to Exhibit 10.2 of NorthWestern Corporation's Current Report on Form 8-K, dated January 5, 2010, Commission File No.1-10499).
~~10.3~~		~~NorthWestern Energy 2010 Annual Incentive Plan (incorporated by reference to Exhibit 99.1~~ of NorthWestern Corporation’s Current Report on Form 8-K, dated ~~February 12,~~April 26, 2010, Commission File No. 1-10499).
~~10.4~~10.2		~~Form of~~Purchase Agreement, dated April 26, 2010, among NorthWestern Corporation ~~Long-Term Performance Incentive Restricted Stock Award Agreement(incorporated~~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 ~~99.2~~10.2 of NorthWestern Corporation’s Current Report on ~~Form~~form 8-K, dated ~~February 12,~~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 pursuant to Section 302 of the Sarbanes Oxley Act of 2002.~~officer.
*31.2		Certification of chief financial ~~officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.~~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

4350

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

For the quarterly period ended ~~March 31,~~June 30, 2010

OR

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

Delaware		46-0172280
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
3010 W. 69th 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
~~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:

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		5
Item 1.	Financial Statements (Unaudited)	5
	Condensed Consolidated Balance Sheets — ~~March 31,~~June 30, 2010 and December 31, 2009	5
	Condensed Consolidated Statements of Income — Three and Six Months Ended ~~March 31,~~June 30, 2010 and 2009	6
	Condensed Consolidated Statements of Cash Flows – ~~Three~~Six Months Ended ~~March 31,~~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	24 25
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	35 42
Item 4.	Controls and Procedures	36 43
PART II. OTHER INFORMATION		37 44
Item 1.	Legal Proceedings	37 44
Item 1A.	Risk Factors	37 44
Item 6.	Exhibits	41 48
SIGNATURES		42 49


	March 31, 2010			December 31, 2009			June 30, 2010			December 31, 2009
ASSETS
Current Assets:
Cash and cash equivalents	$	7,128		$	4,344		$	6,149		$	4,344
Restricted cash	13,408			13,608			14,812			13,608
Accounts receivable, net	134,281			143,759			91,985			143,759
Inventories	28,136			47,305			42,065			47,305
Regulatory assets	53,194			40,509			54,960			40,509
Prepaid energy supply	3,411			2,535
Deferred income taxes	4,408			1,239			3,929			1,239
Other	8,457			11,528
Prepaid and other							11,196			14,063
Total current assets	252,423			264,827			225,096			264,827
Property, Plant, and Equipment, Net	1,996,483			1,964,121			2,033,932			1,964,121
Goodwill	355,128			355,128			355,128			355,128
Regulatory assets	180,300			182,382			183,133			182,382
Other noncurrent assets	30,303			28,674			34,660			28,674
Total assets	$	2,814,637		$	2,795,132		$	2,831,949		$	2,795,132
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,218		$	1,197		$	1,237		$	1,197
Current maturities of long-term debt	6,353			6,123			6,353			6,123
Accounts payable	69,073			92,923			54,462			92,923
Accrued expenses	199,926			165,127			186,832			165,127
Regulatory liabilities	26,903			29,622			20,219			29,622
Total current liabilities	303,473			294,992			269,103			294,992
Long-term capital leases	35,261			35,570			34,952			35,570
Long-term debt	947,691			981,296			997,706			981,296
Deferred income taxes	181,284			161,188			184,009			161,188
Noncurrent regulatory liabilities	242,178			238,332			245,838			238,332
Other noncurrent liabilities	300,957			296,730			292,453			296,730
Total liabilities	2,010,844			2,008,108			2,024,061			2,008,108
Commitments and Contingencies (Note 12)
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,568,881 and 36,007,017, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	396			395
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	(90,203		)	(90,228		)	(90,140		)	(90,228		)
Paid-in capital	808,017			807,527			813,007			807,527
Retained earnings	76,092			59,605			75,520			59,605
Accumulated other comprehensive income	9,491			9,725			9,104			9,725
Total shareholders' equity	803,793			787,024			807,888			787,024
Total liabilities and shareholders' equity	$	2,814,637		$	2,795,132		$	2,831,949		$	2,795,132

	Three Months Ended March 31,						Six Months Ended June 30,
	2010			2009			2010			2009
OPERATING ACTIVITIES:
Net Income	$	28,718		$	22,813		$	40,409		$	28,911
Items not affecting cash:
Depreciation	22,875			22,722			45,872			44,982
Amortization of debt issue costs, discount and deferred hedge gain	531			462			1,030			1,122
Amortization of restricted stock	490			598			861			1,164
Equity portion of allowance for funds used during construction	(848		)	(116		)	(2,585		)	(275		)
Gain on sale of assets	(78		)	(269		)
Loss (gain) on sale of assets							628			(223		)
Deferred income taxes	16,927			14,050			20,131			17,858
Changes in current assets and liabilities:
Restricted cash	200			(221		)	(1,204		)	(1,913		)
Accounts receivable	9,478			13,295			51,774			57,710
Inventories	19,169			35,812			5,240			23,391
Prepaid energy supply costs	(876		)	(1,285		)
Other current assets	3,090			4,095			2,874			(1,846		)
Accounts payable	(17,467		)	(28,620		)	(29,005		)	(39,097		)
Accrued expenses	21,693			12,067			12,147			(9,867		)
Regulatory assets	412			1,683			(4,901		)	963
Regulatory liabilities	(2,719		)	(5,531		)	(9,403		)	(2,341		)
Other noncurrent assets	809			7,671			6,059			11,387
Other noncurrent liabilities	3,866			(34,096		)	(7,469		)	(46,395		)
Cash provided by operating activities	106,270			65,130			132,458			85,531
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(57,796		)	(18,509		)	(116,233		)	(46,986		)
Proceeds from sale of assets	—			320			—			326
Cash used in investing activities	(57,796		)	(18,189		)	(116,233		)	(46,660		)
FINANCING ACTIVITIES:
Treasury stock activity	25			—			88			—
Dividends on common stock	(12,231		)	(12,039		)	(24,494		)	(24,079		)
Issuance of long-term debt	—			250,000			225,000			249,833
Repayment of long-term debt	(3,396		)	(103,309		)	(228,403		)	(135,011		)
Line of credit borrowings	201,000			237,000			402,000			237,000
Line of credit repayments	(231,000		)	(345,000		)	(382,000		)	(345,000		)
Financing costs	(88		)	(1,639		)	(6,611		)	(9,943		)
Cash (used in) provided by financing activities	(45,690		)	25,013
Cash used in financing activities							(14,420		)	(27,200		)
Increase in Cash and Cash Equivalents	2,784			71,954			1,805			11,671
Cash and Cash Equivalents, beginning of period	4,344			11,292			4,344			11,292
Cash and Cash Equivalents, end of period	$	7,128		$	83,246		$	6,149		$	22,963
Supplemental Cash Flow Information:
Cash paid during the period for:
Income Taxes	—			—			—			2
Interest	9,529			10,333			22,086			20,305
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	5,950			1,045
Capital expenditures included in accounts payable							2,788			2,284

	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

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

Natural gas net derivative liability	Accrued Expenses	$	36,910	$	23,661	Accrued Expenses	$	33,362	$	23,661

	Unrealized loss recognized in Regulatory Assets						Unrealized gain (loss) recognized in Regulatory Assets
	Three Months Ended						Three Months Ended				Six Months Ended
Derivatives Subject to Regulatory Deferral	March 31, 2010			March 31, 2009			June 30, 2010		June 30, 2009		June 30, 2010			June 30, 2009

Natural gas	$	(13,249	)	$	(12,157	)	$	3,548	$	9,334	$	(9,701	)	$	(2,823	)

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

Credit rating	$	31,117	$	5,000	$	26,117

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral

Credit rating	$	26,550	$	—	$	26,550

Cash Flow Hedges	Amount of Gain Remaining in AOCI as of March 31, 2010		Location of Gain Reclassified from AOCI to Income		Amount of Gain Reclassified from AOCI into Income during the three months ended March 31, 2010		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	$	10,167		Interest Expense	$	297	$	9,870		Interest Expense	$	594

March 31, 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
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)												(in thousands)
Restricted cash		12,883		—			—		—		12,883		$	14,201	$	—		$	—	$	—	$	14,201
Rabbi trust investments														4,571		—			—		—		4,571
Derivative asset (1)		—		603			—		—		603			—		667			—		—		667
Derivative liability (1)		—		(37,513	)		—		—		(37,513	)		—		(34,029	)		—		—		(34,029	)
Net derivative position		—		(36,910	)		—		—		(36,910	)		—		(33,362	)		—		—		(33,362	)
Total	$	12,883	$	(36,910	)	$	—	$	—	$	(24,027	)	$	18,772	$	(33,362	)	$	—	$	—	$	(14,590	)

	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,												Three Months Ended June 30,
	2010			2009			2010			2009			2010			2009			2010			2009
Components of Net Periodic Benefit Cost
Service cost	$	2,333		$	1,981		$	121		$	133		$	2,348		$	2,154		$	121		$	364
Interest cost	6,019			6,081			391			621			6,026			5,772			511			954
Expected return on plan assets	(7,353		)	(6,539		)	(296		)	(319		)	(7,567		)	(4,653		)	(297		)	(178		)
Amortization of prior service cost	61			61			(441		)	—			62			62			(535		)	—
Recognized actuarial gain	—			—			495			(154		)
Recognized actuarial loss (gain)													70			2,038			(4		)	292
Net Periodic Benefit Cost	$	1,060		$	1,584		$	270		$	281		$	939		$	5,373		$	(204	)	$	1,432

	Results									Results
	2010		2009		Change			% Change		2010		2009		Change			% Change
	(in millions)									(in millions)
Retail revenue	$	170.4	$	180.5	$	(10.1	)	(5.6	)%	$	149.7	$	151.1	$	(1.4	)	(0.9	)%
Transmission	11.5		11.9		(0.4		)	(3.4	)	11.0		10.3		0.7			6.8
Wholesale	11.0		11.1		(0.1		)	(0.9	)	11.9		10.6		1.3			12.3
Regulatory amortization and other	10.9		4.5		6.4			142.2		12.2		1.5		10.7			713.3
Total Revenues	203.8		208.0		(4.2		)	(2.0	)	184.8		173.5		11.3			6.5
Total Cost of Sales	91.0		94.8		(3.8		)	(4.0	)	82.3		71.7		10.6			14.8
Gross Margin	$	112.8	$	113.2	$	(0.4	)	(0.4	)%	$	102.5	$	101.8	$	0.7		0.7	%

	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

Three Months Ended
March 31, 2009	Electric			Gas			Other			Eliminations			Total
June 30, 2010																Electric			Gas			Other			Eliminations		Total
Operating revenues	$	207,987		$	158,803		$	4,651		$	(538	)	$	370,903		$	184,838		$	58,900		$	321		$	—	$	244,059
Cost of sales	94,748			108,938			4,324			—			208,010			82,296			29,640			—			—		111,936
Gross margin	113,239			49,865			327			(538		)	162,893			102,542			29,260			321			—		132,123
Operating, general and administrative	42,979			21,815			1,163			(538		)	65,419			41,873			17,133			(1,880		)	—		57,126
Property and other taxes	18,017			6,227			45			—			24,289			18,281			6,659			44			—		24,984
Depreciation	18,391			4,323			8			—			22,722			18,620			4,369			8			—		22,997
Operating income (loss)	33,852			17,500			(889		)	—			50,463
Operating income																23,768			1,099			2,149			—		27,016
Interest expense	(11,150		)	(3,068		)	(916		)	—			(15,134		)	(11,915		)	(3,456		)	(686)			—		(16,057		)
Other income	291			268			32			—			591
Other income (expense)																1,949			(123		)	27			—		1,853
Income tax (expense) benefit	(8,067		)	(5,475		)	435			—			(13,107		)	(4,405		)	1,155			2,129			—		(1,121		)
Net income (loss)	$	14,926		$	9,225		$	(1,338	)	$	—			22,813		$	9,397		$	(1,325	)	$	3,619		$	—	$	11,691
Total assets	$	1,956,083		$	824,058		$	11,708		$	—		$	2,791,849		$	1,986,414		$	831,338		$	14,197		$	—	$	2,831,949
Capital expenditures	$	14,846		$	3,663		$	—		$	—		$	18,509		$	47,303		$	11,134		$	—		$	—	$	58,437

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts		Revenues					Megawatt Hours (MWH)		Avg. Customer Counts
	2010		2009		2010	2009	2010	2009	2010		2009			2010	2009	2010	2009
	(in thousands)								(in thousands)
Retail Electric
Montana	$	63,596	$	66,094	680	679	270,923	269,003	$	47,213		$	47,366	496	488	270,369	268,627
South Dakota	12,845		13,547		176	171	48,422	48,194	9,489			9,496		110	108	48,419	48,181
Residential	76,441		79,641		856	850	319,345	317,197	56,702			56,862		606	596	318,788	316,808
Montana	66,218		68,892		788	796	60,799	60,202	63,640			64,402		741	749	60,777	60,316
South Dakota	15,808		16,673		238	228	11,622	11,475	14,938			14,748		213	202	11,848	11,701
Commercial	82,026		85,565		1,026	1,024	72,421	71,677	78,578			79,150		954	951	72,625	72,017
Industrial	7,767		10,947		676	765	71	72	8,129			8,267		684	702	71	72
Other	4,205		4,311		24	24	4,623	4,643	6,335			6,840		41	49	5,805	5,843
Total Retail Electric	$	170,439	$	180,464	2,582	2,663	396,460	393,589	$	149,744		$	151,119	2,285	2,298	397,289	394,740
Wholesale Electric
Montana	$	9,934	$	9,823	204	204	N/A	N/A	$	10,231		$	9,068	188	96	N/A	N/A
South Dakota	1,078		1,308		39	39	N/A	N/A	1,678			1,485		90	58	N/A	N/A
Total Wholesale Electric	$	11,012	$	11,131	243	243	N/A	N/A	$	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

	Revenues				Dekatherms (Dkt)		Customer Counts		Revenues				Dekatherms (Dkt)		Customer Counts
	2010		2009		2010	2009	2010	2009	2010		2009		2010	2009	2010	2009
	(in thousands)								(in thousands)
Retail Gas
Montana	$	44,620	$	55,524	4,954	5,383	158,294	157,395	$	19,841	$	21,150	2,303	2,133	157,867	157,045
South Dakota	14,551		18,690		1,567	1,577	37,574	37,105	4,513		5,744		454	550	37,081	36,571
Nebraska	12,833		15,443		1,448	1,316	36,875	36,813	4,279		5,016		439	502	36,375	36,259
Residential	72,004		89,657		7,969	8,276	232,743	231,313	28,633		31,910		3,196	3,185	231,323	229,875
Montana	22,413		28,271		2,484	2,735	22,090	22,046	9,656		10,143		1,124	1,049	22,077	22,009
South Dakota	13,268		14,296		1,732	1,497	5,962	5,887	3,649		4,331		507	574	5,867	5,796
Nebraska	9,506		10,942		1,355	1,231	4,606	4,582	3,236		3,649		509	565	4,531	4,496
Commercial	45,187		53,509		5,571	5,463	32,658	32,515	16,541		18,123		2,140	2,188	32,475	32,301
Industrial	826		803		94	79	292	299	253		212		30	22	288	295
Other	390		476		51	52	146	142	173		193		23	22	146	142
Total Retail Gas	$	118,407	$	144,445	13,685	13,870	265,839	264,269	$	45,600	$	50,438	5,389	5,417	264,232	262,613

	2010 as compared with:
Heating Degree-Days	2009	Historic Average
Montana	~~5% warmer~~11% colder	~~6% warmer~~5% colder
South Dakota	~~2% colder~~23% warmer	~~8% colder~~20% warmer
Nebraska	10% ~~colder~~warmer	~~7% colder~~10% warmer

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