10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(mark one)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

Commission File Number: 1-10499

NORTHWESTERN CORPORATION

Delaware	46-0172280
(State 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 filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

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

Common Stock, Par Value $0.01

36,265,149 shares outstanding at October 21, 2011

1

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets — September 30, 2011 and December 31, 2010	4
	Condensed Consolidated Statements of Income — Three and Nine Months Ended September 30, 2011 and 2010	5
	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2011 and 2010	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	47
Item 4.	Controls and Procedures	48
PART II. OTHER INFORMATION		49
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 6.	Exhibits	53
SIGNATURES		54

2

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Quarterly Report, relating to management's current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:

• potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, as well as adverse determinations by regulators, could have a material adverse effect on our liquidity, results of operations and financial condition;

• we have capitalized approximately $19.5 million in preliminary survey and investigative costs related to our proposed Mountain States Transmission Intertie (MSTI) transmission project. If our efforts to complete MSTI are not successful we may have to write-off all or a portion of these costs which could have a material adverse effect on our results of operations;

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

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

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

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

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our other reports on Form 10-Q, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

We undertake no obligation, to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent annual and periodic reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

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

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PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	September 30, 2011			December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	5,994		$	6,234
Restricted cash	11,674			12,862
Accounts receivable, net	107,112			143,304
Inventories	72,047			50,701
Regulatory assets	44,790			59,993
Deferred income taxes	19,593			24,052
Other	7,804			5,908
Total current assets	269,014			303,054
Property, plant, and equipment, net	2,170,928			2,117,977
Goodwill	355,128			355,128
Regulatory assets	225,757			222,341
Other noncurrent assets	40,997			39,169
Total assets	$	3,061,824		$	3,037,669
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,348		$	1,276
Current maturities of long-term debt	3,792			6,578
Short-term borrowings	112,993			—
Accounts payable	59,117			75,042
Accrued expenses	229,427			203,900
Regulatory liabilities	19,836			17,173
Total current liabilities	426,513			303,969
Long-term capital leases	33,271			34,288
Long-term debt	905,034			1,061,780
Deferred income taxes	262,660			232,709
Noncurrent regulatory liabilities	262,890			251,133
Other noncurrent liabilities	333,247			333,443
Total liabilities	2,223,615			2,217,322
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,827,577 and 36,264,686 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	398			398
Treasury stock at cost	(90,258		)	(90,427		)
Paid-in capital	816,151			813,878
Retained earnings	107,494			87,984
Accumulated other comprehensive income	4,424			8,514
Total shareholders' equity	838,209			820,347
Total liabilities and shareholders' equity	$	3,061,824		$	3,037,669

See Notes to Condensed Consolidated Financial Statements

4

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenues
Electric	$	206,613		$	203,585		$	602,024		$	592,262
Gas	37,067			36,963			230,971			225,882
Other	361			270			1,112			906
Total Revenues	244,041			240,818			834,107			819,050
Operating Expenses
Cost of sales	98,045			105,922			370,523			390,685
Operating, general and administrative	66,332			58,437			203,254			173,871
Property and other taxes	22,605			20,535			68,551			68,487
Depreciation	25,181			22,825			75,562			68,697
Total Operating Expenses	212,163			207,719			717,890			701,740
Operating Income	31,878			33,099			116,217			117,310
Interest Expense, net	(16,694		)	(16,306		)	(50,737		)	(49,413		)
Other Income	346			2,315			2,257			4,921
Income Before Income Taxes	15,530			19,108			67,737			72,818
Income Tax Expense	(635		)	(4,729		)	(9,297		)	(18,030		)
Net Income	$	14,895		$	14,379		$	58,440		$	54,788
Average Common Shares Outstanding	36,262			36,196			36,254			36,181
Basic Earnings per Average Common Share	$	0.41		$	0.40		$	1.61		$	1.51
Diluted Earnings per Average Common Share	$	0.41		$	0.40		$	1.60		$	1.51
Dividends Declared per Average Common Share	$	0.36		$	0.34		$	1.08		$	1.02

See Notes to Condensed Consolidated Financial Statements

5

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2011			2010
OPERATING ACTIVITIES:
Net Income	$	58,440		$	54,788
Items not affecting cash:
Depreciation	75,562			68,697
Amortization of debt issue costs, discount and deferred hedge gain	914			1,428
Amortization of restricted stock	1,649			1,264
Equity portion of allowance for funds used during construction	(960		)	(4,597		)
Loss on disposition of assets	850			716
Deferred income taxes	31,310			31,213
Changes in current assets and liabilities:
Restricted cash	1,188			2,241
Accounts receivable	36,192			45,117
Inventories	(21,346		)	(17,391		)
Other current assets	(1,896		)	6,021
Accounts payable	(12,808		)	(31,371		)
Accrued expenses	37,018			41,108
Regulatory assets	5,539			(8,247		)
Regulatory liabilities	2,663			(12,551		)
Other noncurrent assets	(3,451		)	10,923
Other noncurrent liabilities	(359		)	(1,049		)
Cash provided by operating activities	210,505			188,310
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(124,484		)	(178,147		)
Proceeds from sale of assets	209			69
Cash used in investing activities	(124,275		)	(178,078		)
FINANCING ACTIVITIES:
Treasury stock activity	169			(127		)
Dividends on common stock	(38,930		)	(36,728		)
Issuance of long term-debt	—			225,000
Repayments on long-term debt	(6,586		)	(231,141		)
Line of credit borrowings	80,000			554,000
Line of credit repayments	(233,000		)	(511,000		)
Issuances of short-term borrowings, net	112,993			—
Financing costs	(1,116		)	(8,019		)
Cash used in financing activities	(86,470		)	(8,015		)
(Decrease) Increase in Cash and Cash Equivalents	(240		)	2,217
Cash and Cash Equivalents, beginning of period	6,234			4,344
Cash and Cash Equivalents, end of period	$	5,994		$	6,561
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	18			1,000
Interest	28,950			31,637
Significant non-cash transactions:
Capital expenditures included in accounts payable	4,314			4,416

See Notes to Condensed Consolidated Financial Statements

6

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

(1) Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 665,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to September 30, 2011, have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2010.

Variable Interest Entities

A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.

Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $422.1 million through 2024.

(2) New Accounting Standards

Accounting Standards Issued

In May 2011, the Financial Accounting Standards Board (FASB) issued accounting guidance related to fair value measurement, which amends current guidance to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. The amendments generally represent clarification of how the concepts of highest and best use and valuation premise in a fair value measurement are relevant only when measuring the fair value of

7

nonfinancial assets and are not relevant when measuring the fair value of financial assets or of liabilities. In addition, the guidance expanded the disclosures for the unobservable inputs for Level 3 fair value measurements, requiring quantitative information to be disclosed related to (1) the valuation processes used, (2) the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, and (3) use of a nonfinancial asset in a way that differs from the asset’s highest and best use. This revised guidance is effective for interim and annual periods beginning after December 15, 2011 and early application is prohibited. We do not expect this pronouncement to have a material effect on our consolidated financial statements.

In June 2011, the FASB issued an accounting pronouncement that provides new guidance on the presentation of comprehensive income in financial statements. Entities are required to present total comprehensive income either in a single, continuous statement of comprehensive income or in two separate, but consecutive, statements. Under the single-statement approach, entities must include the components of net income, a total for net income, the components of other comprehensive income and a total for comprehensive income. Under the two-statement approach, entities must report an income statement and, immediately following, a statement of other comprehensive income. Under either method, entities must display adjustments for items reclassified from other comprehensive income to net income in both net income and other comprehensive income. The guidance eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The provisions of this pronouncement are effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. This guidance concerns disclosure only and will not have a material effect on our consolidated financial statements.

Accounting Standards Adopted

There have been no new accounting pronouncements or changes in accounting pronouncements adopted during the nine months ended September 30, 2011 that are of significance, or potential significance, to us.

(3) Income Taxes

Our effective tax rate was 4.1% and 13.7% for the three and nine months ended September 30, 2011 as compared with 24.7% and 24.8% for the three and nine months ended September 30, 2010. The following table summarizes the significant components of the income tax expense:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Income Before Income Taxes	$	15,530		$	19,108		$	67,737		$	72,818
Income tax calculated at 35% Federal statutory rate	(5,435		)	(6,687		)	(23,707		)	(25,485		)
Permanent or flow through adjustments:
Flow-through repairs deductions	3,243			2,341			8,745			6,902
Flow-through of state bonus depreciation deduction	1,170			—			4,452			—
Recognition of state NOL benefit/valuation allowance release	—			—			2,402			2,178
State income tax & other, net	387			(383		)	(1,189		)	(1,625		)
	$	4,800		$	1,958		$	14,410		$	7,455
Income tax expense	$	(635	)	$	(4,729	)	$	(9,297	)	$	(18,030	)

Our effective tax rate differs from the federal tax rate of 35% primarily due to repairs and state tax bonus depreciation deductions. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues we record deferred income taxes and establish related regulatory assets and liabilities.

8

In addition we maintain a valuation allowance against certain state net operating loss (NOL) carryforwards based on our forecast of taxable income and our estimate that a portion of these NOL carryforwards will more likely than not expire before we can use them. The nine months ended September 30, 2011 includes a $2.4 million favorable state NOL carryforward utilization benefit due to 2010 taxable income being higher than our original estimate. By comparison, we had recognized a $2.2 million valuation allowance release for the nine months ended September 30, 2010 based on our forecast of 2010 taxable income at that time. We reversed this benefit during the fourth quarter of 2010 after the law extending bonus depreciation was implemented.

Uncertain Tax Positions

We have unrecognized tax benefits of approximately $131.4 million as of September 30, 2011, including approximately $79.8 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitations within the next twelve months.

The Internal Revenue Service (IRS) issued guidance during the third quarter of 2011 providing a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. We are evaluating whether or not we want to elect the safe harbor method, which may result in a change in related repairs deductions and unrecognized tax benefits.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the nine months ended September 30, 2011, we have not recognized expense for interest or penalties, and do not have any amounts accrued at September 30, 2011 and December 31, 2010, respectively, for the payment of interest and penalties.

Our federal tax returns from 2000 forward remain subject to examination by the IRS.

(4) Goodwill

There were no changes in our goodwill during the nine months ended September 30, 2011. Goodwill by segment is as follows for both September 30, 2011 and December 31, 2010 (in thousands):

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

(5) Other Comprehensive Income

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income	$	14,895		$	14,379		$	58,440		$	54,788
Other comprehensive income (loss), net of tax:
Reclassification of net gains on hedging instruments from OCI to net income	(183		)	(297		)	(777		)	(891		)
Foreign currency translation	(168		)	62			(99		)	35
Comprehensive income	$	14,544		$	14,144		$	57,564		$	53,932

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(6) Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a large portion of our electric and natural gas supply requirements within the Montana market. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

Objectives and Strategies for Using Derivatives

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts, such as fixed-price forward purchase and sales contracts. The objective of these transactions is to fix the price for a portion of anticipated energy purchases to supply our customers. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide price stability for consumers; therefore, these commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to most of our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Financial Statements at September 30, 2011 and December 31, 2010. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

Mark-to-Market Accounting

Certain contracts for the purchase of natural gas associated with our gas utility operations do not qualify for NPNS. These are typically forward purchase contracts for natural gas where we lock in a fixed price, settle the contracts financially and do not take physical delivery of the natural gas. We use the mark-to-market method of accounting for these derivative contracts as we do not elect hedge accounting. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements; therefore, we record a regulatory asset or liability based on changes in market value.

The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 7.

10

Mark-to-Market Transactions	Balance Sheet Location	September 30, 2011		December 31, 2010
Natural gas net derivative liability	Accrued Expenses	$	20,057	$	29,712

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

	Unrealized gain (loss) recognized in Regulatory Assets					Unrealized gain (loss) recognized in Regulatory Assets
	Three Months Ended					Nine Months Ended
Derivatives Subject to Regulatory Deferral	September 30, 2011		September 30, 2010			September 30, 2011		September 30, 2010
Natural gas	$	1,840	$	(3,161	)	$	9,655	$	(12,862	)

Credit Risk

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

We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

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

The following table presents, as of September 30, 2011, the aggregate fair value of forward purchase contracts that do not qualify for NPNS that contain credit risk-related contingent features. If the credit risk-related contingent features underlying these agreements were triggered as of September 30, 2011, the collateral posting requirements would be as follows (in thousands):

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral
Credit rating	$	10,306	$	—	$	10,306

Interest Rate Swaps Designated as Cash Flow Hedges

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

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We have used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in Accumulated Other Comprehensive Income (AOCI). We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these derivative instruments on the Financial Statements (in thousands):

	Location of gain reclassified from AOCI to Income	Nine months ended September 30, 2011
Amount of gain reclassified from AOCI	Interest Expense	$	891

Approximately $7.8 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of September 30, 2011, and we expect to reclassify approximately $1.2 million from AOCI into interest expense during the next twelve months. These gains relate to swaps previously terminated, and we have no current interest rate swaps outstanding.

(7) Fair Value Measurements

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

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

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

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

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

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. There were no transfers between levels for the periods presented. See Note 6 for further discussion.

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September 30, 2011	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
Restricted cash	$	11,213	$	—		$	—	$	—	$	11,213
Rabbi trust investments	7,003		—			—		—		7,003
Derivative liability (1)	—		(20,057		)	—		—		(20,057		)
Total	$	18,216	$	(20,057	)	$	—	$	—	$	(1,841	)
December 31, 2010
Restricted Cash	$	12,297	$	—		$	—	$	—	$	12,297
Rabbi trust investments	5,495		—			—		—		5,495
Derivative asset (1)	—		1,620			—		—		1,620
Derivative liability (1)	—		(31,332		)	—		—		(31,332		)
Net derivative liability	—		(29,712		)	—		—		(29,712		)
Total	$	17,792	$	(29,712	)	$	—	$	—	$	(11,920	)

_________________________

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

We present our derivative assets and liabilities on a net basis in the Condensed Consolidated Balance Sheets. The table above disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required and classifies each individual asset or liability within the appropriate level in the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts. These gross balances are intended solely to provide information on sources of inputs to fair value and do not represent our actual credit exposure or net economic exposure. Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices.

Restricted cash represents amounts held in money market mutual funds. Rabbi trust assets represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Fair value for the commodity derivatives was determined using internal models based on quoted forward commodity prices. We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The fair value measurement of liabilities also reflects the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Consideration of our own credit risk did not have a material impact on our fair value measurements.

Financial Instruments

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

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt (including current portion)	$	908,826	$	1,050,621	$	1,068,358	$	1,137,148

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Short-term borrowings consist of commercial paper and is not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is necessarily required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

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

(8) Financing Activities

On February 8, 2011, we entered into a commercial paper program under which we may issue unsecured commercial paper notes on a private placement basis up to a maximum aggregate amount outstanding at any time of $250 million to provide an alternative financing source for our short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Commercial paper issuances are supported by available capacity under our unsecured revolving line of credit.

On June 30, 2011, we amended and restated our unsecured revolving line of credit scheduled to expire on June 30, 2012. The amended facility extends the term to June 30, 2016, and increases the aggregate principal amount available under the facility by $50 million to $300 million. The facility also has an accordion feature that allows us to increase the size of the facility up to $350 million with the consent of the lenders. The amended facility does not amortize and borrowings will bear interest based on a credit ratings grid. The 'spread' or 'margin' ranges from 0.88% to 1.75% over the London Interbank Offered Rate (LIBOR). Based on our unsecured credit ratings on the closing date of the agreement, the applicable spread was 1.25%. A total of eight banks participate in the new facility, with no one bank providing more than 17% of the total availability. The amended facility contains covenants substantially similar to the previous facility.

(9) Regulatory Matters

South Dakota Natural Gas Rate Case

In June 2011, we filed a request with the South Dakota Public Utilities Commission (SDPUC) for a natural gas distribution revenue increase of $4.1 million. This request was based on a return on equity of 10.9%, an equity ratio of 56.0% and a rate base of $67.5 million. Approximately $1.4 million of the requested increase relates to annual estimated manufactured gas plant remediation costs. In the event remediation costs are lower than estimated during the time period, the difference would be subject to a refund to customers. Accordingly, while gross margin and operating expenses will fluctuate based on actual results, this portion of the rate request would have no impact on operating income. We expect to complete this rate case and implement new rates by December 31, 2011.

Wind Generation

In April 2011, we executed an agreement to purchase a wind project in Judith Basin County in Montana to be developed and constructed by Spion Kop Wind, LLC, a wholly-owned subsidiary of Compass Wind, LLC (Compass) that would provide approximately 40 MW of capacity, with an estimated cost for the total project of approximately $86 million. We filed an application for pre-approval with the Montana Public Service Commission (MPSC) during the second quarter of 2011 to include the project in regulated rate base as an electric supply resource. Both the energy and associated renewable energy credits would be placed into the electric supply portfolio to meet future customer loads and renewable portfolio standards obligations. If the MPSC fails to grant approval on or before April 1, 2012, then either party may terminate this agreement. Material construction would not commence until we receive a favorable ruling from the MPSC. Assuming MPSC approval by April 1, 2012, commercial operation is projected to begin by the end of 2012. The MPSC established a procedural schedule, with a hearing scheduled to begin on December 14, 2011.

Montana Distribution System Infrastructure Project (DSIP)

In March 2011, the MPSC approved a request for an accounting order to defer certain incremental operating and maintenance expenses up to $16.9 million for 2011 and 2012 and amortize over a five-year period beginning in 2013 associated with the phase-in portion of the DSIP. We expect incremental expenses related to the DSIP project to be approximately $7.2 million and $9.7 million, respectively in 2011 and 2012. As of September 30, 2011 we have deferred incremental expenses of

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approximately $2.3 million. In addition, we are currently projecting capital expenditures under the DSIP to be approximately $287 million over a seven-year time span beginning in 2011. As of September 30, 2011, we have incurred approximately $8.5 million of DSIP-related capital expenditures. Based on our current forecast, along with the MPSC's recent approval of the accounting order, we anticipate providing the MPSC an informational technical plan on October 31, 2011, and believe that DSIP-related expenses will be recovered in base rates through annual or biennial general rate cases.

Dave Gates Generating Station at Mill Creek (formerly Mill Creek Generating Station) (DGGS)

On December 31, 2010, we completed construction of DGGS, a 150 MW natural gas fired facility and began commercial operations on January 1, 2011. The facility provides regulating resources (in place of previously contracted ancillary services) to balance our transmission system in Montana to maintain reliability and enable wind power to be integrated into the network to meet renewable energy portfolio needs. Total project costs through September 30, 2011 were approximately $183 million.

In October 2010, the Federal Energy Regulatory Commission (FERC) approved interim rates to reflect the estimated cost of service under Schedule 3 (Regulation and Frequency Response) of the Open Access Transmission Tariff (OATT). In November 2010, the MPSC approved interim rates based on the originally estimated construction costs of $202 million. The interim rates under both orders became effective beginning January 1, 2011. The respective interim rates are subject to refund plus interest pending final resolution in both jurisdictions.

On March 31, 2011, we made a compliance filing with the MPSC that will be used to conduct a final cost review and establish final rates. As a result of the lower than estimated construction costs and estimated impact of the flow-through of accelerated state tax depreciation, we also reduced our interim rate request, which the MPSC authorized to take effect beginning May 1, 2011. A procedural schedule has been established setting a hearing on the matter starting November 9, 2011. Discovery is currently in process.

During March 2011, we began settlement discussions with FERC Staff and large customers receiving service under Schedule 3 of the OATT. Settlement discussions have not been successful. During June 2011, FERC issued an order establishing a procedural schedule with a hearing scheduled for January 23, 2012 and an initial decision by May 4, 2012. Discovery is currently in process.

Through September 30, 2011, we have deferred revenue of approximately $8.2 million associated with DGGS due to lower than estimated construction costs, the estimated impact of the flow-through of accelerated state tax depreciation, our current estimate of operating expenses as compared to amounts included in our interim rate requests, and uncertainty related to the allocation of costs between the MPSC and FERC jurisdictions. Our filings are based on approximately 80% of our revenues related to the facility being subject to the MPSC's jurisdiction and approximately 20% being subject to FERC's jurisdiction. There is significant uncertainty related to the ultimate resolution of cost allocations between the two jurisdictions, which could result in an inability to fully recover our costs, as well as requiring us to refund more interim revenues than our current estimate.

Mountain States Transmission Intertie Project

We have been involved in an open season process for our proposed MSTI line. Under our original timeline, we anticipated completing the open season process by the end of 2010. During 2010, a lawsuit was filed against the Montana Department of Environmental Quality (MDEQ) by Jefferson County, Montana, regarding the County's ability to be more involved in the siting and routing of MSTI. On September 8, 2010, the Montana District Court agreed with Jefferson County and (i) required the MDEQ to consult with Jefferson County in the preparation of the environmental impact statement (EIS) concerning the project and (ii) enjoined the MDEQ from releasing the draft EIS until that consultation occurs. In January 2011, MDEQ appealed the decision to the Montana Supreme Court. In February 2011, we also appealed the decision to the Montana Supreme Court. Oral arguments occurred before the Montana Supreme Court on August 2, 2011 and we anticipate receiving a decision by the end of 2011. In addition to this lawsuit, due to general economic conditions, lack of clarity around federal legislation on renewables and uncertainty in the California renewable standards, we have extended the open season process for the proposed MSTI line until at least the second quarter of 2012.

Construction on MSTI would not commence until all local, state and federal permits/regulatory requirements are met and there are sufficient contracts with credit-worthy shippers to support financing. We have successfully completed a path rating process for MSTI with the Western Electricity Coordinating Council (WECC), which is independent of the siting process. This process established a path rating for MSTI of 1,500 MW southbound and 1,100 MW northbound on the transmission facility. In September 2011, the proposed MSTI line received 'Phase 3' status, which means the study is concluded, the path rating has been established, and that from a regional planning alternative, MSTI could be constructed with the approved rating. Phase 3

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would conclude when the project is placed into service. The rating was affirmed for all of the potential alternative routes, including a 'common corridor' approach to what has been termed the 'northern route alternative' that may allow MSTI to more closely parallel an existing 500kV transmission line.

Due to the uncertainty surrounding the project, certain aspects are scaleable and thus can be built out to more closely match the timing and needs of new generation and loads. To avoid excessive risk for us, it is critical to reduce regulatory uncertainty before making large capital investments and/or commitments. We are also contemplating a strategic partner to own up to 50% of MSTI, however there can be no assurance that we will enter into such a partnership.

Through September 30, 2011, we have capitalized approximately $19.5 million of preliminary survey and investigative costs associated with the MSTI transmission project. As we continue to develop MSTI, costs will continue to increase. If our efforts to complete MSTI are not successful we may have to write-off all or a portion of these costs, which could have a material adverse effect on our results of operations.

FERC Order No. 1000

In July 2011, the FERC issued a Final Rule - Order No. 1000 which amends the transmission planning and cost allocation requirements established in Order No. 890. With respect to transmission planning,  Order No. 1000: (1) requires that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan; (2) requires that each public utility transmission provider amend its OATT to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; (3) removes from Commission-approved tariffs and agreements a federal right of first refusal for certain new transmission facilities; and (4) improves coordination between neighboring transmission planning regions.  Further,  Order No. 1000 requires that each public utility transmission provider must participate in a regional transmission planning process that has: (1) a regional cost allocation method for the cost of new transmission facilities selected in a regional transmission plan for purposes of cost allocation; and (2) an interregional cost allocation method for the cost of certain new transmission facilities that are located in two or more neighboring transmission planning regions and are jointly evaluated by the regions in the interregional transmission coordination procedures required by Order No. 1000. We are reviewing Order No. 1000 and participating in our regional transmission planning processes to develop and implement the requirements to comply with the Order.  The impacts of Order No. 1000, if any, cannot be predicted at this time.

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(10) Segment Information

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

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

Three Months Ended
September 30, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	206,613		$	37,067		$	361		$	—	$	244,041
Cost of sales	85,221			12,824			—			—		98,045
Gross margin	121,392			24,243			361			—		145,996
Operating, general and administrative	45,607			19,979			746			—		66,332
Property and other taxes	16,894			5,708			3			—		22,605
Depreciation	20,465			4,708			8			—		25,181
Operating income (loss)	38,426			(6,152		)	(396		)	—		31,878
Interest expense	(13,661		)	(2,711		)	(322		)	—		(16,694		)
Other income	86			232			28			—		346
Income tax (expense) benefit	(3,407		)	3,016			(244		)	—		(635		)
Net income (loss)	$	21,444		$	(5,615	)	$	(934	)	$	—	$	14,895
Total assets	$	2,157,225		$	891,989		$	12,610		$	—	$	3,061,824
Capital expenditures	$	44,318		$	8,309		$	—		$	—	$	52,627

Three Months Ended
September 30, 2010	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	203,585		$	36,963		$	270		$	—	$	240,818
Cost of sales	92,691			13,231			—			—		105,922
Gross margin	110,894			23,732			270			—		134,896
Operating, general and administrative	42,331			17,429			(1,323		)	—		58,437
Property and other taxes	15,569			5,041			(75		)	—		20,535
Depreciation	18,439			4,378			8			—		22,825
Operating income (loss)	34,555			(3,116		)	1,660			—		33,099
Interest expense	(12,202		)	(3,116		)	(988		)	—		(16,306		)
Other income	2,109			179			27			—		2,315
Income tax (expense) benefit	(6,551		)	3,543			(1,721		)	—		(4,729		)
Net income (loss)	$	17,911		$	(2,510	)	$	(1,022	)	$	—	14,379
Total assets	$	2,040,612		$	845,116		$	13,646		$	—	$	2,899,374
Capital expenditures	$	50,552		$	11,362		$	—		$	—	$	61,914

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Nine Months Ended
September 30, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	602,024		$	230,971		$	1,112		$	—	$	834,107
Cost of sales	246,592			123,931			—			—		370,523
Gross margin	355,432			107,040			1,112			—		463,584
Operating, general and administrative	140,267			60,651			2,336			—		203,254
Property and other taxes	50,937			17,606			8			—		68,551
Depreciation	61,205			14,332			25			—		75,562
Operating income (loss)	103,023			14,451			(1,257		)	—		116,217
Interest expense	(40,877		)	(8,105		)	(1,755		)	—		(50,737		)
Other income	1,425			751			81			—		2,257
Income tax (expense) benefit	(10,998		)	(1,228		)	2,929			—		(9,297		)
Net income (loss)	$	52,573		$	5,869		$	(2	)	$	—	$	58,440
Total assets	$	2,157,225		$	891,989		$	12,610		$	—	$	3,061,824
Capital expenditures	$	99,168		$	25,316		$	—		$	—	$	124,484

Nine Months Ended
September 30, 2010	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	592,262		$	225,882		$	906		$	—	$	819,050
Cost of sales	266,052			124,633			—			—		390,685
Gross margin	326,210			101,249			906			—		428,365
Operating, general and administrative	124,220			52,455			(2,804		)	—		173,871
Property and other taxes	50,625			17,853			9			—		68,487
Depreciation	55,562			13,110			25			—		68,697
Operating income	95,803			17,831			3,676			—		117,310
Interest expense	(37,309		)	(9,717		)	(2,387		)	—		(49,413		)
Other income	4,515			326			80			—		4,921
Income tax (expense) benefit	(17,490		)	(1,041		)	501			—		(18,030		)
Net income	$	45,519		$	7,399		$	1,870		$	—	$	54,788
Total assets	$	2,040,612		$	845,116		$	13,646		$	—	$	2,899,374
Capital expenditures	$	150,104		$	28,043		$	—		$	—	$	178,147

(11) Earnings Per Share

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

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

	Three Months Ended
	September 30, 2011	September 30, 2010
Basic computation	36,262,246	36,195,583
Dilutive effect of
Restricted stock and performance share awards (1)	248,775	116,624
Diluted computation	36,511,021	36,312,207

	Nine Months Ended
	September 30, 2011	September 30, 2010
Basic computation	36,254,159	36,181,238
Dilutive effect of
Restricted stock and performance share awards (1)	245,500	114,896
Diluted computation	36,499,659	36,296,134

_________________________

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

(12) Employee Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
	2011			2010			2011			2010
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,549		$	2,340		$	109		$	120
Interest cost	6,099			6,023			337			450
Expected return on plan assets	(7,616		)	(7,459		)	(296		)	(297		)
Amortization of prior service cost	62			62			(500		)	(488		)
Recognized actuarial loss	629			34			165			247
Net Periodic Benefit Cost (Income)	$	1,723		$	1,000		$	(185	)	$	32

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	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
	2011			2010			2011			2010
Components of Net Periodic Benefit Cost (Income)
Service cost	$	7,649		$	7,021		$	328		$	362
Interest cost	18,296			18,068			1,011			1,352
Expected return on plan assets	(22,847		)	(22,379		)	(889		)	(890		)
Amortization of prior service cost	185			185			(1,499		)	(1,464		)
Recognized actuarial loss	1,887			104			494			738
Net Periodic Benefit Cost (Income)	$	5,170		$	2,999		$	(555	)	$	98

(13) Commitments and Contingencies

ENVIRONMENTAL LIABILITIES AND REGULATION

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

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

Our liability for environmental remediation obligations is estimated to range between $29.3 to $38.9 million, primarily for manufactured gas plants discussed below. As of September 30, 2011, we have a reserve of approximately $32.2 million. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. Over time, as specific laws are implemented and we gain experience in operating under them, a portion of the costs related to such laws will become determinable, and we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material adverse effect on our consolidated financial position or ongoing operations.

Manufactured Gas Plants - Approximately $27.1 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. Our current reserve for remediation costs at this site is approximately $13.4 million, and we estimate that approximately $8.9 million of this amount will be incurred during the next five years.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. During 2006, the NDEQ released to us the Phase II Limited Subsurface Assessments performed by the NDEQ's environmental consulting firm for Kearney and Grand Island. In February 2011, NDEQ completed an Abbreviated Preliminary Assessment and Site Investigation Report for Grand Island, which recommended additional ground water testing. Our reserve estimate includes assumptions for additional ground water testing. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action

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at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to excess regulated pollutants in the groundwater. Voluntary soil and coal tar removals were conducted in the past at the Butte and Helena locations in accordance with MDEQ requirements. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the conditions at these sites; however, additional groundwater monitoring will be necessary. Monitoring of groundwater at the Helena site is ongoing and will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site or if any additional actions beyond monitored natural attenuation will be required.

Global Climate Change - There are national and international efforts to adopt measures related to global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide. These efforts include legislative proposals and U.S. Environmental Protection Agency (EPA) regulations at the federal level, actions at the state level, as well as litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their GHG emissions. We have joint ownership interests in four electric generating plants, all of which are coal fired and operated by other companies. We have undivided interests in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

While numerous bills have been introduced in Congress that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA is regulating GHG emissions under its existing authority pursuant to the Clean Air Act. For example, the EPA promulgated regulations requiring major sources in the United States to begin collecting and reporting information regarding their GHG emissions. Certain of our facilities began collecting such data on January 1, 2010 and submitted their first annual reports to the EPA by its September 30, 2011 deadline. For petroleum and natural gas facilities, data collection began on January 1, 2011, with the first annual report due on March 31, 2012.

In June 2010, the EPA also adopted rules that make certain “stationary sources,” such as power plants, subject to permitting requirements for their GHG emissions. Sources that emit more than 100,000 tons of greenhouse gases per year are now required to obtain permits for those emissions even if they are not otherwise required to obtain a new or modified permit. Such permits may require the installation and operation of “best available control technology” to control GHG emissions.

Also, in December 2010, the EPA entered into an agreement to settle litigation brought by states and environmental groups whereby the EPA agreed to issue New Source Performance Standards for GHG emissions from certain new and modified electric generating units and “emissions guidelines” for existing units over the next two years. Pursuant to this settlement agreement, the EPA agreed to issue proposed rules by September 2011 and final rules by May 2012. The EPA, however, did not meet the September deadline for issuing a proposed rule. It is uncertain whether the EPA still expects to meet the May 2012 deadline for issuing a final rule.

On June 20, 2011, the U.S. Supreme Court issued a decision that bars state and private parties from bringing federal common law nuisance actions against electrical utility companies based on their alleged contribution to climate change. The Supreme Court's decision did not, however, address state law claims. This decision is expected to affect other pending federal climate change litigation, including a case brought by individuals alleging public nuisance claims against a variety of companies that emit GHGs and seeking compensation for damages suffered in the wake of Hurricane Katrina. The plaintiffs in that case, which was previously dismissed, re-filed their lawsuit in May 2011. Although we are not a defendant in any of these proceedings, additional litigation in federal and state courts over these issues is continuing.

Physical impacts of climate change present potential risks for severe weather, such as floods and tornadoes, in the locations where we operate or have interests. Furthermore, requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance, increase our costs of procuring electricity in the marketplace or curtail the demand for fossil fuels such as oil and gas. In addition, we believe future legislation and regulations that affect GHG emissions from power plants are likely, although technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. We cannot predict with any certainty whether these risks will have a material impact on our operations.

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Coal Combustion Residuals (CCRs) - In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and scrubber wastes. Under one approach, the EPA would regulate CCRs as a hazardous waste under Subtitle C of RCRA. This approach would have significant impacts on coal-fired plants, and would require plants to retrofit their operations to comply with hazardous waste requirements from the generation of CCRs and associated waste waters through transportation and disposal. This could also have a negative impact on the beneficial use of CCRs and the current markets associated with such use. The second approach would regulate CCRs as a solid waste under Subtitle D of RCRA. This approach would only affect disposal, most significantly any wet disposal, of CCRs. We cannot predict at this time the final requirements of the EPA's CCR regulations and what impact, if any, they would have on us, but the costs could be significant.

Water Intakes - Section 316(b) of the Federal Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. Permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA takes action to address several court decisions that rejected portions of previous rules and confirmed that EPA has discretion to consider costs relative to benefits in developing cooling water intake structure regulations. In March 2011, EPA proposed rules to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. When final rules are issued and implemented, additional capital and/or increased operating costs may be incurred. The costs of complying with any such final water intake standards are not currently determinable, but could be significant.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures

EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants where we have joint ownership.

The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule requires the use of Best Available Retrofit Technology (BART) for certain electric generating units to achieve emissions reductions from designated sources that are deemed to contribute to visibility impairment in Class I air quality areas.

In May 2011, the EPA issued a proposed rule setting forth Maximum Achievable Control Technology (MACT) standards for hazardous air pollutant emissions from electric generating units that among other things, seek to set stringent emission limits for acid gases, mercury, and other hazardous air pollutants. EPA is under a consent decree deadline to issue the final MACT standards by mid-November 2011. Given the potential for legal challenges and regulatory uncertainties associated with EPA's final rule, it is not possible to fully assess the impact of this rulemaking.

On July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under the CSAPR, the first phase of the nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions reductions would commence in 2012 with further reductions effective in 2014. On October 7, 2011, EPA announced that it was proposing technical corrections to CSAPR that increase the allowances allocated to certain facilities and have the effect of allowing unlimited interstate trading of allowances between 2012 and 2014. Numerous challenges to CSAPR have been filed with the EPA and in Federal court and we cannot predict the outcome of such challenges. Regardless of the outcome, CSAPR only applies to power plants within the eastern half of the United States, and, thus is only applicable to one plant in which we have an ownership interest, the Neal 4 plant located in Iowa. We do not expect CSAPR to affect any of the other plants in which we have an ownership interest.

We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are subject to the Clean Air Visibility Rule and would be subject to the EPA's proposed rules, as discussed below.

South Dakota. The South Dakota Department of Environment and Natural Resources (DENR) determined that the Big Stone Plant, of which we have a 23.4% ownership, is subject to the Clean Air Visibility Rule. South Dakota DENR submitted its revised State Implementation Plan (SIP) and associated implementation rules to the EPA on September 19, 2011. Under the SIP, the Big Stone Plant must install and operate a new BART compliant air quality control system (AQCS) to reduce emissions as expeditiously as practicable, but no later than five years after the EPA's approval of South Dakota's SIP. We expect EPA approval of the SIP in the first half of 2012, however such approval cannot be guaranteed and we cannot predict the timing of any such approval with certainty. We will not incur any significant costs unless the EPA approves the SIP or issues a federal implementation plan in its place. Although studies and evaluations are continuing, the current project cost for the AQCS is estimated to be approximately $490 million (our share is 23.4%).

Our incremental capital expenditure projections include amounts related to our share of the BART technologies at Big

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Stone based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process. The SDPUC has historically allowed timely recovery of the costs of environmental improvements; however, there is no precedent on a project of this size.

Based on the proposed MACT rule, it appears that Big Stone would meet the proposed requirements by installing the AQCS system and using mercury control technology such as activated carbon injection. Mercury emissions monitoring equipment installation is already installed at Big Stone, but its operation has been put on hold pending additional regulatory direction.

North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, of which we have 10% ownership, to reduce its NOx emissions. On February 23, 2010, the North Dakota Department of Health (NDDOH) issued a construction permit to Coyote Station requiring installation of control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 12-month rolling average basis. The control equipment must be installed by July 1, 2018 and compliance with the limit must be beginning on July 1, 2019. Subsequent to issuance of the construction permit, the NDDOH entered into further negotiations with the EPA on regional haze plan implementation. As part of those negotiations, Coyote agreed to accept a NOx emission limit of 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown, beginning on July 1, 2018. The current estimate of the total cost of the project is approximately $6.0 million (our share is 10%).

Iowa. The Neal 4 generating facility, of which we have an 8.7% ownership, is installing a scrubber, a baghouse and a selective non-catalytic reduction system to comply with the CSAPR and the MACT standards. These improvements are expected to result in compliance with the regional haze provisions of the Clean Air Act. The Neal 4 owners are currently evaluating the plant's ability to meet the CSAPR standards on the timeframe required by EPA. Capital expenditures for such equipment are currently estimated to be approximately $270 million (our share is 8.7%). The plant began incurring such costs in 2011 and the costs will be spread over the next three years. Our incremental capital expenditure projections include amounts related to our share of the emission control equipment at Neal 4 based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process.

Montana. The Colstrip facility is currently controlling emissions of mercury under regulations issued by the State of Montana and has been since January 2010. The owners do not believe additional equipment will be necessary to meet the MACT standards for mercury. Additionally, the Colstrip facility anticipates meeting the expected standards for acid gases without additional costs. However, Colstrip may have to install additional controls to further reduce particulate matter to meet MACT standards. The Colstrip owners are continuing to determine what may be required and while it is not possible to predict costs at this time, the costs of additional controls could be significant. In November 2010, Colstrip Unit 4 received a request from the EPA to provide further analysis regarding why Colstrip Unit 4 is not a BART eligible unit under the regional haze rule. The plant operator completed a high level analysis of various control options to reduce emissions of SO2 and particulate matter and submitted that analysis to EPA in January 2011. The analysis shows that these units are well controlled, any incremental reductions would not be cost effective and further analysis is not warranted. The plant operator also concluded that further analysis for NOx was not justified as controls at Colstrip Unit 4 were installed and the EPA previously agreed that such controls would satisfy BART for NOx control. The plant operator informed us that the EPA verbally indicated that it does not agree with all of the plant operator's conclusions and will be requesting additional information. The EPA is under a consent decree to take final action on Montana's regional haze implementation plan no later than June 29, 2012. The costs of complying with any final regional haze standards in Montana are not currently determinable, but could be significant.

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.

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LEGAL PROCEEDINGS

Colstrip Energy Limited Partnership

In December 2006 and June 2007, the MPSC issued orders relating to certain QF long-term 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.

On June 30, 2008, the Montana district court granted both a motion by the MPSC to bifurcate, having the effect of separating the issues between contract/tort claims against us and the administrative appeal of the MPSC's orders and a motion by us to refer the claims against us to arbitration. The order also stayed the appellate decision pending a decision in the arbitration proceedings. Arbitration was held in June 2009 and the arbitration panel entered its interim award in August 2009, holding that although NorthWestern failed to use certain data inputs required by the power purchase agreement, CELP was entitled to neither damages for contract years 2004-2005 or 2005-2006, nor to recalculation of the underlying MPSC filings for those years, effectively finalizing CELP's contract rates for those years. We requested clarification from the arbitration panel as to its intent regarding the applicable rates.

On November 2, 2009, we received the final award from the arbitration panelwhich confirmed that the filed rates for 2004-2005 and 2005-2006 are not required to be recalculated. In affirming its interim award, the arbitration panel also denied CELP's request for attorney fees, holding that each party would be responsible for its own fees.

On June 15, 2010, the Montana district court confirmed the final arbitration panel award and denied CELP's motion to vacate, modify or correct the award. CELP appealed the decision to the Montana Supreme Court (MSC). In May 2011, the MSC affirmed the Montana district court's order and the arbitration award.

Meanwhile, on October 31, 2010, NorthWestern filed with the MPSC, consistent with the direction of the arbitration panel, for a determination of the inputs that will be used to calculate contract rates for periods subsequent to June 30, 2006. The MPSC has not yet ruled on our filing. On June 30, 2011, CELP submitted another demand for arbitration, seeking clarification from the same panel regarding the panel's intent as to the implementation of its award in Contract Years 17 (July 2005 - June 2006) and 18 (July 2006 - June 2007). Based on our current assumptions (including current discount rates), if CELP prevailed entirely, we could be required to increase our QF liability by approximately $24 million. If we prevailed entirely, we could reduce our QF liability by up to $25 million. Due to the uncertainty around resolution of this matter, we currently are unable to predict its outcome. In addition, settlement discussions concerning these claims are ongoing.

Gonzales

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

The Gonzales Action was first filed on December 18, 1999, against MPC (NOR acquired MPC in 2002) and was stayed due to the chapter 11 bankruptcy filing of NOR. On August 10, 2005, the Bankruptcy Court approved a Bankruptcy Settlement Stipulation which permitted the Gonzales Action to proceed, assigned to plaintiffs NOR's interest in MPC's insurance policies (to the extent applicable to the allegations made by plaintiffs), released NOR from any and all obligations to the plaintiffs

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concerning such claims, and preserved plaintiffs' right to pursue claims arising after November 1, 2004, relating to the adjustment of workers' compensation claims. To date, no insurance carrier has indicated that coverage is available for any of the claims.

We and Putnam and Associates have agreed to settle the Gonzales Action and have executed a settlement agreement which remains subject to the approval of the Montana State Court. We paid the settlement agreement amount of $2.5 million to the Clerk of the Montana State Court in full satisfaction of all Gonzales Action claims. The Clerk of the Montana State Court will hold these funds pending final Montana State Court approval of the settlement, which could happen in early 2012.

Bozeman Explosion

On March 5, 2009, a natural gas explosion occurred in downtown Bozeman, Montana, resulting in one fatality, the destruction of or damage to six buildings and the businesses in them, and lesser damage to other nearby properties and businesses. Thirty-three lawsuits have been filed against NorthWestern in the District Court of Gallatin County, Montana, and a number of additional claims not currently in litigation also have been made against us. We have approximately $150 million of insurance coverage available for known and potential claims arising from the explosion. We tendered our self-insured retention under those policies to our insurance carriers, who accepted the tender and assumed the defense and handling of the existing and potential additional lawsuits and claims arising from the incident.

Settlements have been reached in 24 of the 33 cases filed to date, including the sole wrongful death case, and we have settled most of the additional claims that were not in litigation. There are nine remaining property damage and business loss cases pending, none of which is likely to be tried before the fall of 2012. While we cannot predict an outcome in those cases, we are continuing to vigorously defend them. A small number of additional pending claims not in litigation are being handled by our primary insurance carrier. We believe the possibility of any loss in excess of our self-insured retention on the remaining lawsuits and claims is remote.

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 665,000 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, 2010.

Regulatory Matters

Rate cases are a key component of our earnings growth and achieving our financial objectives. In June 2011, we filed a request with the SDPUC for a natural gas distribution revenue increase of $4.1 million. This request was based on a return on equity of 10.9%, an equity ratio of 56.0% and a rate base of $67.5 million. Approximately $1.4 million of the requested increase relates to annual estimated manufactured gas plant remediation costs. In the event remediation costs are lower than estimated during the time period, the difference would be subject to a refund to customers. Accordingly, while gross margin and operating expenses will fluctuate based on actual results, this portion of the rate request would have no impact on operating income. We expect to complete this rate case and implement new rates by December 31, 2011.

Supply Investments

Wind Generation

In April 2011, we executed an agreement to purchase a wind project in Judith Basin County in Montana to be developed and constructed by Spion Kop Wind, LLC, a wholly-owned subsidiary of Compass that would provide approximately 40 MW of capacity, with an estimated cost for the total project of approximately $86 million. We filed an application for pre-approval with the MPSC during the second quarter of 2011 to include the project in regulated rate base as an electric supply resource. Both the energy and associated renewable energy credits would be placed into the electric supply portfolio to meet future customer loads and renewable portfolio standards obligations. If the MPSC fails to grant approval on or before April 1, 2012, then either party may terminate this agreement. Material construction would not commence until we receive a favorable ruling from the MPSC. Assuming MPSC approval by April 1, 2012, commercial operation is projected to begin by the end of 2012. The MPSC established a procedural schedule, with a hearing scheduled to begin on December 14, 2011.

Dave Gates Generating Station at Mill Creek

On March 19, 2011, our Vice President of Wholesale Operations, David G. Gates, was tragically killed in a private plane crash. On March 26, 2011 our Board of Directors renamed the Mill Creek Generating Station as the Dave Gates Generating Station at Mill Creek (DGGS) to posthumously recognize Gates’ significant contributions to the company. On December 31, 2010, we completed construction of DGGS, a 150 MW natural gas fired facility and began commercial operations on January 1, 2011. The facility provides regulating resources (in place of previously contracted ancillary services) to balance our transmission system in Montana to maintain reliability and enable wind power to be integrated into the network to meet renewable energy portfolio needs.

In October 2010, the FERC approved interim rates to reflect the estimated cost of service under Schedule 3 of the OATT. In November 2010, the MPSC approved interim rates based on the originally estimated construction costs of $202 million. The interim rates under both orders became effective beginning January 1, 2011. The respective interim rates are subject to refund plus interest pending final resolution in both jurisdictions.

On March 31, 2011, we made a compliance filing with the MPSC that will be used to conduct a final cost review and establish final rates. As a result of the lower than estimated construction costs and estimated impact of the flow-through of accelerated state tax depreciation, we also reduced our interim rate request, which the MPSC authorized to take effect beginning May 1, 2011. A procedural schedule has been established setting a hearing on the matter starting November 9, 2011. Discovery is currently in process.

During March 2011, we began settlement discussions with FERC Staff and large customers receiving service under Schedule 3 of the OATT. Due to the complexity of the case, settlement discussions have not been successful. During June 2011, FERC issued an order establishing a procedural schedule with a hearing scheduled for January 23, 2012 and an initial

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decision by May 4, 2012. Discovery is currently in process.

Through September 30, 2011, we have deferred revenue of approximately $8.2 million associated with DGGS, primarily due to lower than estimated construction costs, the estimated impact of the flow-through of accelerated state tax depreciation, our current estimate of operating expenses as compared to amounts included in our interim rate requests, and uncertainty related to the allocation of costs between the MPSC and FERC jurisdictions. Our filings are based on approximately 80% of our revenues related to the facility being subject to the MPSC's jurisdiction and approximately 20% being subject to FERC's jurisdiction. There is significant uncertainty related to the ultimate resolution of cost allocations between the two jurisdictions, which could result in an inability to fully recover our costs, as well as requiring us to refund more interim revenues than our current estimate.

RESULTS OF OPERATIONS

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

Non-GAAP Financial Measure

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

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is primarily affected by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

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OVERALL CONSOLIDATED RESULTS

Three Months Ended September 30,2011 Compared with the Three Months Ended September 30,2010

	Three Months Ended September 30,
	2011		2010		Change		% Change
	(dollars in millions)
Operating Revenues
Electric	$	206.6	$	203.6	$	3.0	1.5	%
Natural Gas	37.0		36.9		0.1		0.3
Other	0.4		0.3		0.1		33.3
	$	244.0	$	240.8	$	3.2	1.3	%

	Three Months Ended September 30,
	2011		2010		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	85.2	$	92.7	$	(7.5	)	(8.1	)%
Natural Gas	12.8		13.2		(0.4		)	(3.0	)
	$	98.0	$	105.9	$	(7.9	)	(7.5	)%

	Three Months Ended September 30,
	2011		2010		Change		% Change
	(dollars in millions)
Gross Margin
Electric	$	121.4	$	110.9	$	10.5	9.5	%
Natural Gas	24.2		23.7		0.5		2.1
Other	0.4		0.3		0.1		33.3
	$	146.0	$	134.9	$	11.1	8.2	%

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Consolidated gross margin was $146.0 million for the three months ended September 30, 2011, an increase of $11.1 million, or 8.2%, from gross margin in 2010. Primary components of this change include the following:

	Gross Margin 2011 vs. 2010
	(in millions)
DGGS interim rates	$	6.8
Electric retail volumes	2.9
Expiration of a power sales agreement	1.5
Operating expenses recovered in a tracker	1.3
Montana property tax tracker	0.2
Gas production	0.2
Transmission capacity	(1.0		)
Natural gas retail volumes	(0.3		)
Montana natural gas rate decrease	(0.2		)
Other	(0.3		)
Increase in Consolidated Gross Margin	$	11.1

This $11.1 million increase in gross margin includes the following:

• DGGS revenues based on our current estimate of final resolution of applicable rate proceedings as discussed above in the "Summary" section. DGGS rates charged to Montana retail customers are based on total Montana retail volumes and will fluctuate quarterly due to the cyclical nature of our business;

• An increase in electric retail volumes due primarily to warmer summer weather and, to a lesser extent, customer growth;

• The expiration in December 2010 of a power sales agreement related to Colstrip Unit 4;

• Higher revenues for operating expenses recovered in supply trackers, primarily related to customer efficiency programs;

• An increase in Montana property taxes included in a tracker as compared to the same period in 2010; and

• Gas production margin from the Battle Creek Field.

These increases were partly offset by the following:

• Lower transmission capacity revenues due to a combination of hydro conditions and other factors that decreased demand;

• A decrease in natural gas retail volumes; and

• A decrease in Montana natural gas transmission and distribution rates implemented in January 2011.

	Three Months Ended September 30,
	2011		2010		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	66.3	$	58.5	$	7.8	13.3	%
Property and other taxes	22.6		20.5		2.1		10.2
Depreciation	25.2		22.8		2.4		10.5
	$	114.1	$	101.8	$	12.3	12.1	%

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Consolidated operating, general and administrative expenses were $66.3 million for the three months ended September 30, 2011, as compared with $58.5 million for the three months ended September 30, 2010. Primary components of this change include the following:

	Operating, General & Administrative Expenses
	2011 vs. 2010
	(in millions)
Self insurance reserves	$	5.2
Operating expenses recovered in supply trackers	1.3
DGGS operating costs	1.2
Plant operator costs	0.9
Operating and maintenance	0.4
Labor	(0.6		)
Other	(0.6		)
Increase in Operating, General & Administrative Expenses	$	7.8

The increase in operating, general and administrative expenses of $7.8 million was primarily due to the following:

• Higher insurance reserves, which includes an increase of $2.3 million due to a dispute with a former employee and the inclusion in our third quarter 2010 results of a $2.0 million insurance recovery. In addition, insurance reserves increased approximately $0.9 million primarily related to workers compensation claims and general liability matters;

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

• The operations of DGGS in 2011;

• Higher plant operator costs at Colstrip Unit 4 and to a lesser extent at Big Stone and Neal, primarily due to maintenance; and

• Higher operating and maintenance costs primarily from an $0.8 million write-off of an abandoned gas transmission project due to the pursuit of a more cost effective solution.

This increase was offset in part by lower labor costs due to more time spent on capital projects, which reduces expense.

In March 2011, the MPSC approved a request for an accounting order to defer and amortize certain incremental operating and maintenance expenses up to $16.9 million for 2011 and 2012 over a five-year period beginning in 2013 associated with the phase-in portion of the DSIP. As of September 30, 2011 we have deferred incremental expenses of approximately $2.3 million.

Property and other taxes was $22.6 million for the three months ended September 30, 2011, as compared with $20.5 million in the third quarter of 2010. This increase was due primarily to plant additions, including the addition of DGGS.

Depreciation expense was $25.2 million for the three months ended September 30, 2011, as compared with $22.8 million in the third quarter of 2010. This increase was primarily due to plant additions, including DGGS.

Consolidated operating income for the three months ended September 30, 2011 was $31.9 million, as compared with $33.1 million in the third quarter of 2010. This decrease was primarily due to higher operating expenses offset in part by an increase in gross margin discussed above.

Consolidated interest expense for the three months ended September 30, 2011 was $16.7 million, as compared with $16.3 million in the third quarter of 2010. This increase was primarily due to lower capitalization of Allowance for Funds Used During Construction (AFUDC) as DGGS began operating in January 2011, offset in part by lower rates on debt outstanding.

Consolidated other income for the three months ended September 30, 2011 was $0.3 million, as compared with $2.3 million in the third quarter of 2010. This decrease was primarily due to lower capitalization of AFUDC as DGGS began operating in January 2011.

30

We had a consolidated income tax expense for the three months ended September 30, 2011 of $0.6 million, as compared with $4.7 million in the same period of 2010. We currently expect our effective tax rate to range between 13% - 16% for 2011. The following table summarizes the significant differences from the Federal statutory rate, which result in reduced income tax expense:

	Three Months Ended September 30,
	(in millions)
	2011			2010
Income Before Income Taxes	$	15.5		$	19.1
Income tax calculated at 35% Federal statutory rate	(5.4		)	(6.7		)
Permanent or flow through adjustments:
Flow-through repairs deductions	3.2			2.3
Flow-through of state bonus depreciation deduction	1.2			—
State income tax & other, net	0.4			(0.4		)
	$	4.8		$	1.9
Income tax expense	$	(0.6	)	$	(4.8	)

Our effective tax rate differs from the federal tax rate of 35% primarily due to repairs and state tax bonus depreciation deductions. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues we record deferred income taxes and establish related regulatory assets and liabilities. We recognized a state tax bonus depreciation related benefit of $1.2 million for the three months ended September 30, 2011, related to DGGS (which contributed to our reduced interim rate request as discussed above in the "Regulatory Matters" section) and other qualifying additions. By comparison, we did not recognize any state tax bonus depreciation benefits until the fourth quarter of 2010, after the Small Business Jobs Act of 2010 was signed into law. Based on guidance from the IRS, we believe DGGS will qualify for a 50% bonus depreciation deduction in 2011.

This act provides a bonus depreciation deduction ranging from 50%-100% for qualified property acquired or constructed and placed into service during 2010 through 2012. We expect to recognize additional bonus depreciation related benefits through 2012.

In addition, the IRS issued guidance during the third quarter of 2011 providing a safe harbor method for determining the tax treatment of repairs costs for electric transmission and distribution property. We are evaluating whether or not we want to elect the safe harbor method, which may result in a change in related repairs deductions and unrecognized tax benefits.

Consolidated net income for the three months ended September 30, 2011 was $14.9 million as compared with $14.4 million for the same period in 2010. This increase was primarily due to lower income tax expense offset in part by lower operating income, higher interest expense, and lower other income as discussed above.

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Nine Months Ended September 30,2011 Compared with the Nine Months Ended September 30,2010

	Nine Months Ended September 30,
	2011		2010		Change		% Change
	(dollars in millions)
Operating Revenues
Electric	$	602.0	$	592.3	$	9.7	1.6	%
Natural Gas	230.9		225.9		5.0		2.2
Other	1.1		0.9		0.2		22.2
	$	834.0	$	819.1	$	14.9	1.8	%

	Nine Months Ended September 30,
	2011		2010		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	246.6	$	266.1	$	(19.5	)	(7.3	)%
Natural Gas	123.9		124.6		(0.7		)	(0.6	)
	$	370.5	$	390.7	$	(20.2	)	(5.2	)%

	Nine Months Ended September 30,
	2011		2010		Change		% Change
	(dollars in millions)
Gross Margin
Electric	$	355.4	$	326.2	$	29.2	9.0	%
Natural Gas	107.0		101.3		5.7		5.6
Other	1.1		0.9		0.2		22.2
	$	463.5	$	428.4	$	35.1	8.2	%

Consolidated gross margin was $463.5 million for the nine months ended September 30, 2011, an increase of $35.1 million or 8.2%, from gross margin in the same period of 2010. Primary components of this change include the following:

	Gross Margin 2011 vs. 2010
	(in millions)
DGGS interim rates	$	20.8
Electric and natural gas retail volumes	10.7
Expiration of a power sales agreement	4.5
Montana electric rate increase	3.4
Gas production	1.7
Operating expenses recovered in a tracker	1.6
Montana property tax tracker	(3.3		)
Transmission capacity	(2.6		)
Settlement received during 2010	(1.0		)
South Dakota wholesale electric	(0.8		)
Montana natural gas rate decrease	(0.7		)
Other	0.8
Increase in Consolidated Gross Margin	$	35.1

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This $35.1 million increase in gross margin includes the following:

• DGGS revenues based on our current estimate of final resolution of applicable rate proceedings. We estimate that gross margin will be positively impacted by approximately $6.0 million for the remainder of 2011 as compared to 2010 due to the inclusion of DGGS in rates;

• An increase in electric and natural gas retail volumes due primarily to colder winter weather and warmer summer weather;

• The expiration in December 2010 of a power sales agreement related to Colstrip Unit 4;

• An increase in Montana electric transmission and distribution rates implemented in July 2010;

• Gas production margin from the Battle Creek Field: and

• Higher revenues for operating expenses recovered in supply trackers, primarily related to customer efficiency programs.

These increases were partly offset by the following:

• A decrease in Montana property taxes included in a tracker as compared to the same period in 2010;

• Lower transmission capacity revenues due to decreased demand and favorable hydro conditions;

• Higher cost of sales because 2010 results included a settlement related to coal supply costs at Colstrip;

• Lower wholesale electric sales in South Dakota from lower plant utilization due to market conditions and scheduled maintenance; and

• A decrease in Montana natural gas transmission and distribution rates implemented in January 2011.

	Nine Months Ended September 30,
	2011		2010		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	203.3	$	173.9	$	29.4	16.9	%
Property and other taxes	68.5		68.5		—		—
Depreciation	75.6		68.7		6.9		10.0
	$	347.4	$	311.1	$	36.3	11.7	%

Consolidated operating, general and administrative expenses were $203.3 million for the nine months ended September 30, 2011, as compared with $173.9 million for the nine months ended September 30, 2010. Primary components of this change include the following:

	Operating, General & Administrative Expenses
	2011 vs. 2010
	(in millions)
Self insurance reserves	$	9.3
Operating and maintenance	5.7
Labor	4.9
DGGS operating costs	3.3
Plant operator costs	2.4
Operating expenses recovered in supply trackers	1.6
Pension	1.0
Other	1.2
Increase in Operating, General & Administrative Expenses	$	29.4

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The increase in operating, general and administrative expenses of $29.4 million was primarily due to the following:

• Higher insurance reserves, which includes an increase of $2.3 million due to a dispute with a former employee and the inclusion in our third quarter results of a favorable arbitration decision and insurance recoveries totaling $5.4 million. In addition, insurance reserves increased approximately $1.6 million primarily related to workers compensation claims and general liability matters;

• Increased operating and maintenance costs primarily due to accelerated maintenance to enhance system reliability and performance, as well as an $0.8 million write-off of an abandoned gas transmission project due to the pursuit of a more cost effective solution;

• Increased labor costs due primarily to compensation increases and a larger number of employees, offset in part by more time spent on capital projects, which reduces expense;

• The operations of DGGS in 2011. We estimate the operations of DGGS will increase operating, general and administrative expenses by approximately $1.9 million for the remainder of 2011 as compared to 2010;

• Higher plant operator costs primarily at Colstrip Unit 4 and to a lesser extent at Neal due to scheduled maintenance;

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

• Higher pension expense, however, based on current assumptions we expect the annual pension expense for 2011 to be comparable with 2010 due to the regulatory treatment of our Montana pension plan.

Property and other taxes remained flat for the nine months ended September 30, 2011, with an increase from plant additions, including the addition of DGGS, offset in part by lower actual 2010 property taxes than our initial estimate based on assessed property valuations and mill levy increases in Montana. We estimate the inclusion of DGGS will increase property and other taxes by approximately $0.8 million for the remainder of 2011 as compared to 2010.

Depreciation expense was $75.6 million for the nine months ended September 30, 2011 as compared with $68.7 million in the same period of 2010. This increase was primarily due to plant additions, including DGGS. We estimate the inclusion of DGGS will increase depreciation expense by approximately $1.4 million for the remainder of 2011 as compared to 2010.

Consolidated operating income for the nine months ended September 30, 2011 was $116.2 million, as compared with $117.3 million in the same period of 2010. This decrease was primarily due to higher operating expenses offset in part by an increase in gross margin discussed above.

Consolidated interest expense for the nine months ended September 30, 2011 was $50.7 million, as compared with $49.4 million in the same period of 2010. This increase was primarily due to lower capitalization of AFUDC as DGGS began operating in January 2011 offset in part by lower rates on debt outstanding.

Consolidated other income for the nine months ended September 30, 2011 was $2.3 million, as compared with $4.9 million in the same period of 2010. This decrease was primarily due to lower capitalization of AFUDC as DGGS began operating in January 2011.

Consolidated income tax expense for the nine months ended September 30, 2011 was $9.3 million as compared with a $18.0 million in the same period of 2010. The effective tax rate in 2011 was 13.7% as compared with 24.7% for the same period of 2010.

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The following table summarizes the significant differences from the Federal statutory rate, which result in reduced income tax expense:

	Nine Months Ended September 30,
	(in millions)
	2011			2010
Income Before Income Taxes	$	67.7		$	72.8
Income tax calculated at 35% Federal statutory rate	(23.7		)	(25.5		)
Permanent or flow through adjustments:
Flow-through repairs deductions	8.7			6.9
Flow-through of state bonus depreciation deduction	4.5			—
Recognition of state NOL benefit/valuation allowance release	2.4			2.2
State income tax & other, net	(1.2		)	(1.6		)
	$	14.4		$	7.5
Income tax expense	$	(9.3	)	$	(18.0	)

Our effective tax rate differs from the federal tax rate of 35% primarily due to the flow-through treatment of repairs and state tax bonus depreciation deductions as discussed above in the quarterly results section. We recognized repairs related tax benefits of $8.7 million and $6.9 million for the nine months ended September 30, 2011 and 2010, respectively. We recognized a state tax bonus depreciation related benefit of $4.5 million for the nine months ended September 30, 2011. By comparison, we did not recognize any state tax bonus depreciation benefits until the fourth quarter of 2010, as discussed in the quarterly results section above.

In addition, the nine months ended September 30, 2011 includes a $2.4 million favorable state NOL carryforward utilization benefit due to 2010 taxable income being higher than our original estimate. By comparison, we had recognized a $2.2 million valuation allowance release for the nine months ended September 30, 2010 based on our forecast of 2010 taxable income at that time. We reversed this benefit during the fourth quarter of 2010 after the law extending bonus tax depreciation was implemented.

Consolidated net income for the nine months ended September 30, 2011 was $58.4 million as compared with $54.8 million in the same period of 2010. This increase was primarily due to lower income tax expense offset in part by lower operating income, higher interest expense and lower other income as discussed above.

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ELECTRIC SEGMENT

Three Months Ended September 30,2011 Compared with the Three Months Ended September 30,2010

	Results
	2011		2010		Change			% Change
	(dollars in millions)
Retail revenue	$	189.2	$	173.0	$	16.2		9.4	%
Transmission	11.5		12.5		(1.0		)	(8.0	)
Wholesale	0.4		11.5		(11.1		)	(96.5	)
Regulatory amortization and other	5.5		6.6		(1.1		)	(16.7	)
Total Revenues	206.6		203.6		3.0			1.5
Total Cost of Sales	85.2		92.7		(7.5		)	(8.1	)
Gross Margin	$	121.4	$	110.9	$	10.5		9.5	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2011		2010		2011	2010	2011	2010
	(in thousands)
Retail Electric
Montana	$	58,531	$	51,731	552	523	271,073	269,750
South Dakota	12,858		12,441		150	149	48,664	48,464
Residential	71,389		64,172		702	672	319,737	318,214
Montana	79,634		73,345		840	828	61,623	61,125
South Dakota	18,076		17,372		250	248	12,054	11,911
Commercial	97,710		90,717		1,090	1,076	73,677	73,036
Industrial	8,961		8,612		718	694	73	71
Other	11,179		9,462		92	80	7,627	7,607
Total Retail Electric	$	189,239	$	172,963	2,602	2,522	401,114	398,928
Wholesale Electric
Montana	$	—	$	10,524	—	205	N/A	N/A
South Dakota	378		1,040		15	53	N/A	N/A
Total Wholesale Electric	$	378	$	11,564	15	258	—	—

	Degree Days			2011 as compared with:
Cooling Degree-Days	2011	2010	Historic Average	2010	Historic Average
Montana	308	195	260	58% warmer	18% warmer
South Dakota	753	748	639	1% warmer	18% warmer

	Degree Days			2011 as compared with:
Heating Degree-Days	2011	2010	Historic Average	2010	Historic Average
Montana	235	407	385	42% warmer	39% warmer
South Dakota	70	57	98	23% colder	29% warmer

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The following summarizes the components of the changes in electric margin for the three months ended September 30, 2011 and 2010:

	Gross Margin 2011 vs. 2010
	(in millions)
DGGS interim rates	$	6.8
Retail volumes	2.9
Expiration of a power sales agreement	1.5
Operating expenses recovered in supply trackers	1.0
Transmission capacity	(1.0		)
Other	(0.7		)
Increase in Gross Margin	$	10.5

The improvement in margin is primarily due to DGGS interim rates, as discussed above, an increase in retail volumes due primarily to warmer summer weather and to a lesser extent customer growth, the expiration in December 2010 of a power sales agreement related to Colstrip Unit 4, and higher revenues for operating expenses recovered in supply trackers primarily related to customer efficiency programs. These increases were offset in part by a decline in transmission capacity demand.

Demand for transmission capacity can fluctuate substantially from year to year based on weather and market conditions in states to the South and West. For example, increased availability of local natural gas fired generation due to low natural gas prices and increased generation in the Pacific Northwest due to favorable hydro conditions may make it more economically viable to utilize local generation rather than transmit electricity from Montana over our transmission lines.

Retail volumes increased from warmer weather and customer growth. Wholesale volumes decreased in South Dakota from lower plant utilization due to market conditions and scheduled maintenance. We no longer have Montana wholesale volumes due to the expiration of a remaining wholesale supply contract associated with Colstrip. Beginning January 1, 2011 these volumes are used to supply our retail demand.

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Nine Months Ended September 30,2011 Compared with the Nine Months Ended September 30,2010

	Results
	2011		2010		Change			% Change
	(dollars in millions)
Retail revenue	$	552.4	$	493.1	$	59.3		12.0	%
Transmission	32.3		35.0		(2.7		)	(7.7	)
Wholesale	1.5		34.5		(33.0		)	(95.7	)
Regulatory amortization and other	15.8		29.7		(13.9		)	(46.8	)
Total Revenues	602.0		592.3		9.7			1.6
Total Cost of Sales	246.6		266.1		(19.5		)	(7.3	)
Gross Margin	$	355.4	$	326.2	$	29.2		9.0	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2011		2010		2011	2010	2011	2010
	(in thousands)
Retail Electric
Montana	$	187,856	$	162,540	1,786	1,698	271,975	270,348
South Dakota	36,556		34,775		448	435	48,660	48,435
Residential	224,412		197,315		2,234	2,133	320,635	318,783
Montana	228,556		203,203		2,407	2,357	61,516	60,900
South Dakota	49,748		48,118		702	700	11,938	11,794
Commercial	278,304		251,321		3,109	3,057	73,454	72,694
Industrial	27,723		24,508		2,113	2,055	72	71
Other	21,936		20,002		150	145	5,953	6,011
Total Retail Electric	$	552,375	$	493,146	7,606	7,390	400,114	397,559
Wholesale Electric
Montana	$	—	$	30,689	—	597	N/A	N/A
South Dakota	1,507		3,796		88	182	N/A	N/A
Total Wholesale Electric	$	1,507	$	34,485	88	779	—	—

	Degree Days			2011 as compared with:
Cooling Degree-Days	2011	2010	Historic Average	2010	Historic Average
Montana	324	219	301	48% warmer	8% warmer
South Dakota	814	823	707	1% colder	15% warmer

	Degree Days			2011 as compared with:
Heating Degree-Days	2011	2010	Historic Average	2010	Historic Average
Montana	5,235	4,938	5,054	6% colder	4% colder
South Dakota	6,211	5,692	5,646	9% colder	10% colder

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The following summarizes the components of the changes in electric margin for the nine months ended September 30, 2011 and 2010:

	Gross Margin 2011 vs. 2010
	(in millions)
DGGS interim rates	$	20.8
Retail volumes	6.6
Expiration of a power sales agreement	4.5
Montana electric rate increase	3.4
Operating expenses recovered in supply trackers	0.7
Montana property tax tracker	(2.8		)
Transmission capacity	(2.6		)
Reclamation settlement received during 2010	(1.0		)
South Dakota wholesale	(0.8		)
Other	0.4
Increase in Gross Margin	$	29.2

The improvement in margin and the change in volumes are primarily due to the same reasons discussed above for the three months ended September 30, 2011. Margin was also impacted by the inclusion in the second quarter of 2010 of a settlement to recover previously incurred reclamation costs associated with the coal supply at Colstrip, which reduced cost of sales, and lower wholesale electric sales in South Dakota from lower plant utilization due to market conditions and scheduled maintenance.

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NATURAL GAS SEGMENT

Three Months Ended September 30,2011 Compared with the Three Months Ended September 30,2010

	Results
	2011		2010		Change			% Change
	(dollars in millions)
Retail revenue	$	23.7	$	25.4	$	(1.7	)	(6.7	)%
Wholesale and other	13.3		11.5		1.8			15.7
Total Revenues	37.0		36.9		0.1			0.3
Total Cost of Sales	12.8		13.2		(0.4		)	(3.0	)
Gross Margin	$	24.2	$	23.7	$	0.5		2.1	%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2011		2010		2011	2010	2011	2010
	(in thousands)
Retail Gas
Montana	$	10,151	$	11,391	790	940	157,491	156,925
South Dakota	1,717		1,714		121	120	37,167	36,844
Nebraska	2,204		2,136		155	157	36,175	36,121
Residential	14,072		15,241		1,066	1,217	230,833	229,890
Montana	6,020		6,476		525	582	22,024	21,920
South Dakota	1,462		1,557		199	198	5,854	5,810
Nebraska	1,883		1,875		289	299	4,528	4,488
Commercial	9,365		9,908		1,013	1,079	32,406	32,218
Industrial	136		160		13	16	275	282
Other	82		61		8	6	147	146
Total Retail Gas	$	23,655	$	25,370	2,100	2,318	263,661	262,536

	Degree Days			2011 as compared with:
Heating Degree-Days	2011	2010	Historic Average	2010	Historic Average
Montana	235	407	385	42% warmer	39% warmer
South Dakota	70	57	98	23% colder	29% warmer
Nebraska	49	26	49	88% colder	remained flat

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The following summarizes the components of the changes in natural gas margin for the three months ended September 30, 2011 and 2010:

	Gross Margin 2011 vs. 2010
	(in millions)
Montana property tax tracker	$	0.3
Operating expenses recovered in supply trackers	0.3
Gas production	0.2
Retail volumes	(0.3		)
Montana natural gas rate decrease	(0.2		)
Other	0.2
Increase in Gross Margin	$	0.5

This increase in margin was primarily due to an increase in Montana property taxes included in a tracker as compared to the same period in 2010, higher revenues for operating expenses recovered in supply trackers primarily related to customer efficiency programs, and gas production margin from the Battle Creek Field. These increases were offset in part by a decrease in retail volumes and a Montana natural gas rate decrease. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales. In addition, average natural gas supply prices decreased resulting in lower retail revenues and cost of sales in 2011 as compared with 2010, with no impact to gross margin.

Nine Months Ended September 30,2011 Compared with the Nine Months Ended September 30,2010

	Results
	2011		2010		Change			% Change
	(dollars in millions)
Retail revenue	$	199.4	$	189.4	$	10.0		5.3	%
Wholesale and other	31.5		36.5		(5.0		)	(13.7	)
Total Revenues	230.9		225.9		5.0			2.2
Total Cost of Sales	123.9		124.6		(0.7		)	(0.6	)
Gross Margin	$	107.0	$	101.3	$	5.7		5.6	%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2011		2010		2011	2010	2011	2010
	(in thousands)
Retail Gas
Montana	$	85,553	$	75,852	8,883	8,198	158,457	157,694
South Dakota	20,589		20,778		2,333	2,141	37,388	37,167
Nebraska	18,571		19,248		2,038	2,045	36,525	36,457
Residential	124,713		115,878		13,254	12,384	232,370	231,318
Montana	44,543		38,545		4,667	4,188	22,188	22,029
South Dakota	14,742		18,474		2,107	2,438	5,899	5,880
Nebraska	13,591		14,617		2,143	2,175	4,577	4,542
Commercial	72,876		71,636		8,917	8,801	32,664	32,451
Industrial	1,055		1,239		115	140	279	287
Other	763		625		93	80	146	146
Total Retail Gas	$	199,407	$	189,378	22,379	21,405	265,459	264,202

41

	Degree Days			2011 as compared with:
Heating Degree-Days	2011	2010	Historic Average	2010	Historic Average
Montana	5,235	4,938	5,054	6% colder	4% colder
South Dakota	6,211	5,692	5,646	9% colder	10% colder
Nebraska	4,847	4,767	4,643	2% colder	4% colder

The following summarizes the components of the changes in natural gas margin for the nine months ended September 30, 2011 and 2010:

	Gross Margin 2011 vs. 2010
	(in millions)
Retail volumes	$	4.1
Gas production	1.7
Operating expenses recovered in supply trackers	0.9
Montana natural gas rate decrease	(0.7		)
Montana property tax tracker	(0.5		)
Other	$	0.2
Increase in Gross Margin	$	5.7

This increase in margin was primarily due to increased retail volumes from colder winter and spring weather, gas production margin from the Battle Creek Field, and higher revenues for operating expenses recovered in supply trackers primarily related to customer efficiency programs. These increases were offset in part by a decrease in Montana natural gas rates and a decrease in Montana property taxes included in a tracker as compared to the same period in 2010.

Retail residential and commercial volumes increased in Montana primarily due to colder weather, while industrial volumes declined in Montana due to a lower number of customers and lower usage per customer. Retail residential volumes increased in South Dakota due to colder weather, while commercial volumes declined in South Dakota due primarily to lower usage for grain drying requirements during the first quarter of 2011 as compared with the same period of 2010.

LIQUIDITY AND CAPITAL RESOURCES

We utilize short-term borrowings, including our revolving credit facility and commercial paper program to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. As of September 30, 2011, our total net liquidity was approximately $192.8 million including $6.0 million of cash and $186.8 million of revolving credit facility availability. Revolving credit facility availability was $205.9 millionas of October 21, 2011.

The following table presents additional information about short term borrowings during the three months ended September 30, 2011 (in millions):

September 30, 2011	Short-term Borrowings
Amount outstanding	$	113.0
Weighted average interest rate	0.37		%
Daily average amount outstanding	$	84.3
Weighted average interest rate	0.37		%
Maximum amount outstanding	$	113.0

Factors Impacting our Liquidity

Supply Costs - Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas sales and transportation services typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our

42

existing revolver, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.

The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we usually under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms can have a significant effect on cash flows from operations and make year-to-year comparisons difficult.

As of September 30, 2011, we are under collected on our current Montana natural gas and electric trackers by approximately $4.1 million, as compared with an under collection of $14.1 million as of December 31, 2010, and an under collection of $0.6 million as of September 30, 2010.

Dodd-Frank– On July 21, 2010, President Obama signed into law new federal financial reform legislation, the Dodd-Frank Wall Street Reform and Consumer Protection Act. This financial reform legislation includes a provision that requires over-the-counter derivative transactions to be executed through an exchange or centrally cleared. Such clearing requirements would result in a significant change from our current practice of bilateral transactions and negotiated credit terms. An exemption to such clearing requirements is outlined in the legislation, and included in proposed regulations, for end users that enter into hedges to mitigate commercial risk. We expect to qualify under the end user exemption. At the same time, the legislation includes provisions under which the Commodity Futures Trading Commission (CFTC) may impose collateral requirements for transactions, including those that are used to hedge commercial risk. In addition, although the CFTC's proposed rules would not impose specific margin requirements on end users, the CFTC's proposed regulations would require swap dealers and major swap participants to have credit support arrangements with their end user counterparties. In addition, to the extent that our counterparties were banking entities, proposed rules issued by banking regulators would require the banking entities to calculate credit exposure limits for end user counterparties and collect margin when the credit exposure exceeds the limit.

Therefore, despite the end user exemption, concern remains that counterparties that do not qualify for the exemption will pass along the increased cost and margin requirements through higher prices and reductions in unsecured credit limits. We are unable to assess the impact of the financial reform legislation pending issuance of the final regulations implementing these provisions, which will not take effect until 60 days following publication of the applicable final rule.

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. Fitch Ratings (Fitch), Moody's Investors Service (Moody’s) and Standard and Poor’s Ratings Service (S&P) are independent credit-rating agencies that rate our debt securities. As of October 21, 2011, our current ratings with these agencies are as follows:

	Senior Secured Rating	Senior Unsecured Rating	Commercial Paper	Outlook
Fitch	A-	BBB+	N/A	Stable
Moody’s	A2	Baa1	Prime-2	Stable
S&P	A-	BBB	A-2	Stable

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and impact our trade credit availability. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

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Cash Flows

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

	Nine Months Ended September 30,
	2011			2010
Operating Activities
Net income	$	58.4		$	54.8
Non-cash adjustments to net income	109.3			98.7
Changes in working capital	46.6			24.9
Other	(3.8		)	9.9
	210.5			188.3
Investing Activities
Property, plant and equipment additions	(124.5		)	(178.1		)
Other	0.2			—
	(124.3		)	(178.1		)
Financing Activities
Net (repayment) borrowing of debt	(46.6		)	36.9
Dividends on common stock	(38.9		)	(36.8		)
Other	(0.9		)	(8.1		)
	(86.4		)	(8.0		)
Net (Decrease) Increase in Cash and Cash Equivalents	$	(0.2	)	$	2.2
Cash and Cash Equivalents, beginning of period	$	6.2		$	4.3
Cash and Cash Equivalents, end of period	$	6.0		$	6.5

Cash Provided by Operating Activities

As of September 30, 2011, cash and cash equivalents were $6.0 million as compared with $6.2 million at December 31, 2010 and $6.5 million at September 30, 2010. Cash provided by operating activities totaled $210.5 million for the nine months ended September 30, 2011 as compared with $188.3 million during the nine months ended September 30, 2010. This increase in operating cash flows is primarily due to improvements in the timing of collection of costs included in our supply and property tax trackers, as well as higher net income adjusted for higher non-cash depreciation.

Cash Used in Investing Activities

Cash used in investing activities decreased by approximately $53.8 million as compared with the first nine months of 2010 due primarily to prior year additions related to the DGGS project.

Cash Used in Financing Activities

Cash used in financing activities totaled approximately $86.4 million during the nine months ended September 30, 2011 as compared with approximately $8.0 million during the nine months ended September 30, 2010. During the nine months ended September 30, 2011, net cash used in financing activities consisted of the net revolving credit facility repayments of $153.0 million, net issuance of commercial paper of $113.0 million, the repayment of long-term debt of $6.6 million and the payment of dividends of $38.9 million. During the nine months ended September 30, 2010, we received proceeds from the issuance of debt of $225.0 million, made debt repayments of $188.1 million, paid deferred financing costs of $8.1 million and paid dividends on common stock of $36.8 million.

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Financing Activities - On February 8, 2011, we entered into a commercial paper program under which we may issue unsecured commercial paper notes on a private placement basis up to a maximum aggregate amount outstanding at any time of $250 million to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Commercial paper issuances are supported by available capacity under our unsecured revolving line of credit.

On June 30, 2011, we amended and restated our unsecured revolving line of credit scheduled to expire on June 30, 2012. The amended facility extends the term to June 30, 2016, and increases the aggregate principal amount available under the facility by $50 million to $300 million. The facility also has an accordion feature that allows us to increase the size of the facility up to $350 million with the consent of the lenders. The amended facility does not amortize and borrowings will bear interest based on a credit ratings grid. The 'spread' or 'margin' ranges from 0.88% to 1.75% over the LIBOR. Based on our unsecured credit ratings on the closing date of the agreement, the applicable spread was 1.25%. A total of eight banks participate in the new facility, with no one bank providing more than 17% of the total availability. The amended facility contains covenants substantially similar to the previous facility.

Sources and Uses of Funds

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

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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 September 30, 2011. See our Annual Report on Form 10-K for the year ended December 31, 2010 for additional discussion.

	Total		2011		2012		2013		2014		2015		Thereafter
	(in thousands)
Long-term debt	$	908,826	$	—	$	3,792	$	—	$	—	$	—	$	905,034
Capital leases	34,618		331		1,370		1,468		1,582		1,705		28,162
Short-term borrowings	112,993		112,993		—		—		—		—		—
Future minimum operating lease payments	4,271		501		1,930		999		430		173		238
Estimated pension and other postretirement obligations (1)	57,772		972		15,400		13,800		13,800		13,800		N/A
Qualifying facilities (2)	1,284,828		16,145		67,111		69,816		72,354		74,135		985,267
Supply and capacity contracts (3)	1,510,217		91,618		266,412		214,454		141,126		103,590		693,017
Contractual interest payments on debt (4)	488,829		16,867		51,116		50,999		50,999		50,782		268,066
Total Commitments (5)	$	4,402,354	$	239,427	$	407,131	$	351,536	$	280,291	$	244,185	$	2,879,784

_________________________

(1) We have only estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. These estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.

(2) The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $167 per MWH through 2029. Our estimated gross contractual obligation related to the QFs is approximately $1.3 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.0 billion.

(3) We have entered into various purchase commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 25 years.

(4) We have assumed a weighted average interest rate of 0.4% on outstanding short-term borrowing amounts through maturity.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s discussion and analysis of financial condition and results of operations is based on our condensed consolidated financial statements, which have been prepared in accordance with GAAP. 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 September 30, 2011, 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, 2010. 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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Interest Rate Risk

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing primarily fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit facility. The revolving credit facility bears interest at the lower of prime or available rates tied to the LIBOR plus a credit spread, ranging from 0.88% to 1.75% over LIBOR. To more cost effectively meet short-term cash requirements, we established a program where we may issue commercial paper; which is supported by our revolving credit facility. Since commercial paper terms are short-term, we are subject to interest rate risk. As of September 30, 2011, we had approximately $113.0 million of commercial paper outstanding and no borrowings on our revolving credit facility. A 1% increase in interest rates would increase our annual interest expense by approximately $1.1 million.

Commodity Price Risk

We are exposed to commodity price risk due to our reliance on market purchases to fulfill a large portion of our electric and natural gas supply requirements within the Montana market. We also participate in the wholesale electric market to balance our supply of power from our own generating resources, primarily in South Dakota. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

As part of our overall strategy for fulfilling our electric and natural gas supply requirements, we employ the use of market purchases, including forward purchase and sales contracts. These types of contracts are included in our supply portfolios and in some instances, are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. These contracts are part of an overall portfolio approach intended to provide price stability for consumers. As a regulated utility, our exposure to market risk caused by changes in commodity prices is substantially mitigated because these commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by applicable state regulatory commissions.

Counterparty Credit Risk

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

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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 is 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 most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

We are subject to extensive and changing 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.

The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of our costs incurred in a historical test year. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs.

For example, in our regulatory filings related to DGGS, we proposed an allocation of approximately 80% of costs to retail customers subject to the MPSC's jurisdiction and approximately 20% allocated to wholesale customers subject to FERC's jurisdiction. There is significant uncertainty related to the ultimate resolution of cost allocations between the two jurisdictions, which could result in an inability to fully recover our costs, as well as requiring us to refund more interim revenues than our current estimate.

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 North American Electric Reliability Corporation (NERC) functions for which we have registered in both the Midwest Reliability Organization for our South Dakota operations and the WECC for our Montana operations. The FERC can impose penalties for violation of FERC statutes, rules and orders of $1 million per violation per day. In addition, more than 120 electric reliability standards are mandatory and subject to potential financial penalties by NERC or FERC for violations. If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.

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. In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act, which is intended to improve regulation of financial markets was signed into law. Certain provisions of the Act relating to derivatives could result in increased capital and/or collateral requirements. Despite certain exemptions in the law, we will not know if we qualify for the exemptions until the rule making has been completed, and, even if we qualify for the exemptions, concern remains that counterparties that do not qualify for the exemption will pass along the increased cost and margin requirements through higher prices and reductions in unsecured credit limits. We are unable to assess the impact of the financial reform legislation pending issuance of the final regulations implementing these provisions.

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, protection of natural resources and wildlife, solid waste disposal, coal ash and other environmental considerations. We believe that we are in compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations; however, possible future developments, including the promulgation of more stringent environmental laws and regulations, and the timing of future enforcement proceedings that may be taken by environmental authorities could affect the costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures.

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There are national and international efforts to adopt measures related to global climate change and the contribution of emissions of GHGs including, most significantly, carbon dioxide. These efforts include legislative proposals and agency regulations at the federal level, actions at the state level, as well as litigation relating to GHG emissions. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of carbon dioxide and other GHGs 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.

Our plans for future expansion through capital improvements to current assets and transmission grid expansion 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, which includes investment in capital improvements and additions to modernize existing infrastructure, generation investments and transmission capacity expansion. The age of our existing assets may result in them being more costly to maintain and susceptible to outages in spite of diligent efforts by us to properly maintain these assets through inspection, scheduled maintenance and capital investment. The failure of such assets could result in increased expenses which may not be fully recoverable from customers and/or a reduction in revenue.

The completion of generation investments and transmission projects are subject to many construction and development risks, including, but not limited to, risks related to financing, regulatory recovery, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. Construction of new transmission facilities required to support future growth is subject to certain additional risks, including but not limited to: (i) our ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on terms that are acceptable to us; (ii) potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; (iii) inability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us; and (iv) insufficient customer throughput commitments. In addition, there are projects proposed by other parties that may result in direct competition to our proposed transmission expansion.

As of September 30, 2011, we have capitalized approximately $19.5 million in preliminary survey and investigative costs related to MSTI. If we are unable to complete the development and ultimate construction of MSTI or decide to delay or cancel construction for any reason, including failure to receive necessary regulatory approvals and/or siting or environmental permits, we may not be able to recover our investment. Even if MSTI is completed, the total costs may be higher than estimated and there is no assurance that we will be able to recover such costs from customers. If our efforts to complete MSTI are not successful we may have to write-off all or a portion of these costs, which could have a material adverse effect on our results of operations. See Note 9 - Regulatory Matters to the Condensed Consolidated Financial Statements for further discussion of this project.

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

Our proposed capital investment projects are based on assumptions regarding future growth and resulting power demand that may not be realized. This planning process must look many years into the future in order to accommodate the long lead times associated with the permitting and construction of new generation facilities. Inherent risk exists in predicting demand this

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far into the future as these future loads are dependent on many uncertain factors, including regional economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. We may increase our transmission and/or baseload capacity and have excess capacity if anticipated growth levels are not realized. The resulting excess capacity could exceed our obligation to serve retail customers or demand for transmission capacity and, as a result, may not be recoverable from customers.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions. We are also impacted by market conditions outside of our service territories related to demand for transmission capacity and wholesale electric pricing.

Our revenues, results of operations and financial condition are impacted by customer growth and usage, which can be impacted by population growth as well as by economic factors. 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. While our service territories have been less impacted than other parts of the country, residential customer consumption patterns may change and our revenues may be negatively impacted. Our commercial and industrial customers have been impacted by the economic downturn, resulting in a decline in their consumption of electricity. Additionally, our customers may voluntarily reduce their consumption of electricity in response to increases in prices, decreases in their disposable income or individual energy conservation efforts. In addition, demand for our Montana transmission capacity and wholesale supply fluctuate with regional demand, fuel prices and contracted capacity and are dependent on market conditions. The timing and extent of the recovery of the economy cannot be predicted.

Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs.

Inherent in our natural gas distribution activities are a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.

To the extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we would not recover some of 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 contractual 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 not recover some of our costs, which could adversely impact our results of operations.

We currently procure almost all of our 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 favorable 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. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as 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.

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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 in 2002 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 owned and jointly owned electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves risks, which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal for our electric generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity and operational issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error, catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences affecting the electric generating facilities; and operational changes necessitated by environmental legislation or regulation. The loss of a major electric generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, could adversely affect our results of operations and liquidity.

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

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

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Our business is dependent on our ability to successfully access capital markets on favorable terms. Limits on our access to capital may adversely impact our ability to execute our business plan or pursue improvements that we would otherwise rely on for future growth.

Our cash requirements are driven by the capital-intensive nature of our business. 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 and commercial paper market 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, access the commercial paper market 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 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, including through the commercial paper markets. Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our results of operations.

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+ from S&P and Baa1 from Moody's.

ITEM 6.                      EXHIBITS

(a)Exhibits

Exhibit 31.1—Certification of chief executive officer.

Exhibit 31.2—Certification of chief financial officer.

Exhibit 32.1—Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2—Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 101.INS—XBRL Instance Document

Exhibit 101.SCH—XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL—XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF—XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB—XBRL Taxonomy Label Linkbase Document

Exhibit 101.PRE—XBRL Taxonomy Extension Presentation Linkbase Document

53

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:	October 26, 2011	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

54

EXHIBIT INDEX

Exhibit Number	Description
*31.1	Certification of chief executive officer.
*31.2	Certification of chief financial officer.
*32.1	Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema Document
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB	XBRL Taxonomy Label Linkbase Document
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

_________________________

* Filed herewith

55

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert C. Rowe, certify that:

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

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

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

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

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

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

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

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

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

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

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

October 26, 2011

/s/ ROBERT C. ROWE

Robert C. Rowe

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Brian B. Bird, certify that:

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

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

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

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

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

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

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

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

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

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

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

October 26, 2011

/s/ BRIAN B. BIRD

Brian B. Bird

Vice President, Chief Financial Officer and Treasurer

EX-32.1

EXHIBIT 32.1

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

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

In connection with the Quarterly Report of NorthWestern Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert C. Rowe, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

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

October 26, 2011	/s/ ROBERT C. ROWE
	Robert C. Rowe
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

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

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

In connection with the Quarterly Report of NorthWestern Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brian B. Bird, Vice President, Chief Financial Officer and Treasurer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

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

October 26, 2011	/s/ BRIAN B. BIRD
	Brian B. Bird
	Vice President, Chief Financial Officer and Treasurer

XML

CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL (USD $)	Sep. 30, 2011
Common stock, par value	$ 0.01
Common stock, shares authorized	200,000,000
Common stock, shares issued	39,827,577
Common stock, shares outstanding	36,264,686
Preferred stock, par value	$ 0.01
Preferred stock, shares authorized	50,000,000
Preferred stock, shares issued	0

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenues
Electric	$ 206,613	$ 203,585	$ 602,024	$ 592,262
Gas	37,067	36,963	230,971	225,882
Other	361	270	1,112	906
Total Revenues	244,041	240,818	834,107	819,050
Operating Expenses
Cost of sales	98,045	105,922	370,523	390,685
Operating, general and administrative	66,332	58,437	203,254	173,871
Property and other taxes	22,605	20,535	68,551	68,487
Depreciation	25,181	22,825	75,562	68,697
Total Operating Expenses	212,163	207,719	717,890	701,740
Operating Income	31,878	33,099	116,217	117,310
Interest Expense, net	(16,694)	(16,306)	(50,737)	(49,413)
Other Income	346	2,315	2,257	4,921
Income Before Income Taxes	15,530	19,108	67,737	72,818
Income Tax Expense	(635)	(4,729)	(9,297)	(18,030)
Net Income	$ 14,895	$ 14,379	$ 58,440	$ 54,788
Weighted Average Number of Shares Outstanding, Basic	36,262,246	36,195,583	36,254,159	36,181,238
Basic Earnings per Average Common Share (in dollars per share)	$ 0.41	$ 0.40	$ 1.61	$ 1.51
Diluted Earnings per Average Common Share (in dollars per share)	$ 0.41	$ 0.40	$ 1.60	$ 1.51
Dividends Declared per Average Common Share (in dollars per share)	$ 0.36	$ 0.34	$ 1.08	$ 1.02

XML

Risk Management and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments [Table Text Block]

The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 7.

Mark-to-Market Transactions	Balance Sheet Location	September 30, 2011		December 31, 2010
Natural gas net derivative liability	Accrued Expenses	$	20,057	$	29,712

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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

	Unrealized gain (loss) recognized in Regulatory Assets					Unrealized gain (loss) recognized in Regulatory Assets
	Three Months Ended					Nine Months Ended
Derivatives Subject to Regulatory Deferral	September 30, 2011		September 30, 2010			September 30, 2011		September 30, 2010
Natural gas	$	1,840	$	(3,161	)	$	9,655	$	(12,862	)

Schedule of Price Risk Derivatives [Table Text Block]

The following table presents, as of September 30, 2011, the aggregate fair value of forward purchase contracts that do not qualify for NPNS that contain credit risk-related contingent features. If the credit risk-related contingent features underlying these agreements were triggered as of September 30, 2011, the collateral posting requirements would be as follows (in thousands):

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral
Credit rating	$	10,306	$	—	$	10,306

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following table shows the effect of these derivative instruments on the Financial Statements (in thousands):

	Location of gain reclassified from AOCI to Income	Nine months ended September 30, 2011
Amount of gain reclassified from AOCI	Interest Expense	$	891

XML

DOCUMENT AND ENTITY INFORMATION	9 Months Ended
	Sep. 30, 2011	Oct. 21, 2011
Entity Information [Line Items]
Entity Registrant Name	NORTHWESTERN CORPORATION
Entity Central Index Key	0000073088
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		36,265,149
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

XML

Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Schedule of Weighted Average Number of Shares [Table Text Block]

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

	Three Months Ended
	September 30, 2011	September 30, 2010
Basic computation	36,262,246	36,195,583
Dilutive effect of
Restricted stock and performance share awards (1)	248,775	116,624
Diluted computation	36,511,021	36,312,207

	Nine Months Ended
	September 30, 2011	September 30, 2010
Basic computation	36,254,159	36,181,238
Dilutive effect of
Restricted stock and performance share awards (1)	245,500	114,896
Diluted computation	36,499,659	36,296,134

_________________________

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

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Fair Value Measurements

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

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

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

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

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

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. There were no transfers between levels for the periods presented. See Note 6 for further discussion.

September 30, 2011	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
Restricted cash	$	11,213	$	—		$	—	$	—	$	11,213
Rabbi trust investments	7,003		—			—		—		7,003
Derivative liability (1)	—		(20,057		)	—		—		(20,057		)
Total	$	18,216	$	(20,057	)	$	—	$	—	$	(1,841	)
December 31, 2010
Restricted Cash	$	12,297	$	—		$	—	$	—	$	12,297
Rabbi trust investments	5,495		—			—		—		5,495
Derivative asset (1)	—		1,620			—		—		1,620
Derivative liability (1)	—		(31,332		)	—		—		(31,332		)
Net derivative liability	—		(29,712		)	—		—		(29,712		)
Total	$	17,792	$	(29,712	)	$	—	$	—	$	(11,920	)

_________________________

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

We present our derivative assets and liabilities on a net basis in the Condensed Consolidated Balance Sheets. The table above disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required and classifies each individual asset or liability within the appropriate level in the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts. These gross balances are intended solely to provide information on sources of inputs to fair value and do not represent our actual credit exposure or net economic exposure. Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices.

Restricted cash represents amounts held in money market mutual funds. Rabbi trust assets represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Fair value for the commodity derivatives was determined using internal models based on quoted forward commodity prices. We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The fair value measurement of liabilities also reflects the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Consideration of our own credit risk did not have a material impact on our fair value measurements.

Financial Instruments

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

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt (including current portion)	$	908,826	$	1,050,621	$	1,068,358	$	1,137,148

Short-term borrowings consist of commercial paper and is not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is necessarily required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

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

XML

Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2011

Compensation and Retirement Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
	2011			2010			2011			2010
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,549		$	2,340		$	109		$	120
Interest cost	6,099			6,023			337			450
Expected return on plan assets	(7,616		)	(7,459		)	(296		)	(297		)
Amortization of prior service cost	62			62			(500		)	(488		)
Recognized actuarial loss	629			34			165			247
Net Periodic Benefit Cost (Income)	$	1,723		$	1,000		$	(185	)	$	32

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
	2011			2010			2011			2010
Components of Net Periodic Benefit Cost (Income)
Service cost	$	7,649		$	7,021		$	328		$	362
Interest cost	18,296			18,068			1,011			1,352
Expected return on plan assets	(22,847		)	(22,379		)	(889		)	(890		)
Amortization of prior service cost	185			185			(1,499		)	(1,464		)
Recognized actuarial loss	1,887			104			494			738
Net Periodic Benefit Cost (Income)	$	5,170		$	2,999		$	(555	)	$	98

XML

Segment Information (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Segment Reporting Information [Line Items]
Operating revenues	$ 244,041	$ 240,818	$ 834,107	$ 819,050
Cost of sales	98,045	105,922	370,523	390,685
Gross margin	145,996	134,896	463,584	428,365
Operating, general, and administrative	66,332	58,437	203,254	173,871
Property and other taxes	22,605	20,535	68,551	68,487
Depreciation	25,181	22,825	75,562	68,697
Operating Income	31,878	33,099	116,217	117,310
Interest expense	(16,694)	(16,306)	(50,737)	(49,413)
Other income	346	2,315	2,257	4,921
Income tax (expense) benefit	(635)	(4,729)	(9,297)	(18,030)
Net Income	14,895	14,379	58,440	54,788
Total assets	3,061,824	2,899,374	3,061,824	2,899,374	3,037,669
Capital expenditures	52,627	61,914	124,484	178,147
Electric Domestic Regulated [Member]
Segment Reporting Information [Line Items]
Operating revenues	206,613	203,585	602,024	592,262
Cost of sales	85,221	92,691	246,592	266,052
Gross margin	121,392	110,894	355,432	326,210
Operating, general, and administrative	45,607	42,331	140,267	124,220
Property and other taxes	16,894	15,569	50,937	50,625
Depreciation	20,465	18,439	61,205	55,562
Operating Income	38,426	34,555	103,023	95,803
Interest expense	(13,661)	(12,202)	(40,877)	(37,309)
Other income	86	2,109	1,425	4,515
Income tax (expense) benefit	(3,407)	(6,551)	(10,998)	(17,490)
Net Income	21,444	17,911	52,573	45,519
Total assets	2,157,225	2,040,612	2,157,225	2,040,612
Capital expenditures	44,318	50,552	99,168	150,104
Gas Domestic Regulated [Member]
Segment Reporting Information [Line Items]
Operating revenues	37,067	36,963	230,971	225,882
Cost of sales	12,824	13,231	123,931	124,633
Gross margin	24,243	23,732	107,040	101,249
Operating, general, and administrative	19,979	17,429	60,651	52,455
Property and other taxes	5,708	5,041	17,606	17,853
Depreciation	4,708	4,378	14,332	13,110
Operating Income	(6,152)	(3,116)	14,451	17,831
Interest expense	(2,711)	(3,116)	(8,105)	(9,717)
Other income	232	179	751	326
Income tax (expense) benefit	3,016	3,543	(1,228)	(1,041)
Net Income	(5,615)	(2,510)	5,869	7,399
Total assets	891,989	845,116	891,989	845,116
Capital expenditures	8,309	11,362	25,316	28,043
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	361	270	1,112	906
Cost of sales	0	0	0	0
Gross margin	361	270	1,112	906
Operating, general, and administrative	746	(1,323)	2,336	(2,804)
Property and other taxes	3	(75)	8	9
Depreciation	8	8	25	25
Operating Income	(396)	1,660	(1,257)	3,676
Interest expense	(322)	(988)	(1,755)	(2,387)
Other income	28	27	81	80
Income tax (expense) benefit	(244)	(1,721)	2,929	501
Net Income	(934)	(1,022)	(2)	1,870
Total assets	12,610	13,646	12,610	13,646
Capital expenditures	0	0	0	0
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Cost of sales	0	0	0	0
Gross margin	0	0	0	0
Operating, general, and administrative	0	0	0	0
Property and other taxes	0	0	0	0
Depreciation	0	0	0	0
Operating Income	0	0	0	0
Interest expense	0	0	0	0
Other income	0	0	0	0
Income tax (expense) benefit	0	0	0	0
Net Income	0	0	0	0
Total assets	0	0	0	0
Capital expenditures	$ 0	$ 0	$ 0	$ 0

XML

Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Financial data for the business segments are as follows (in thousands):

Three Months Ended
September 30, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	206,613		$	37,067		$	361		$	—	$	244,041
Cost of sales	85,221			12,824			—			—		98,045
Gross margin	121,392			24,243			361			—		145,996
Operating, general and administrative	45,607			19,979			746			—		66,332
Property and other taxes	16,894			5,708			3			—		22,605
Depreciation	20,465			4,708			8			—		25,181
Operating income (loss)	38,426			(6,152		)	(396		)	—		31,878
Interest expense	(13,661		)	(2,711		)	(322		)	—		(16,694		)
Other income	86			232			28			—		346
Income tax (expense) benefit	(3,407		)	3,016			(244		)	—		(635		)
Net income (loss)	$	21,444		$	(5,615	)	$	(934	)	$	—	$	14,895
Total assets	$	2,157,225		$	891,989		$	12,610		$	—	$	3,061,824
Capital expenditures	$	44,318		$	8,309		$	—		$	—	$	52,627

Three Months Ended
September 30, 2010	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	203,585		$	36,963		$	270		$	—	$	240,818
Cost of sales	92,691			13,231			—			—		105,922
Gross margin	110,894			23,732			270			—		134,896
Operating, general and administrative	42,331			17,429			(1,323		)	—		58,437
Property and other taxes	15,569			5,041			(75		)	—		20,535
Depreciation	18,439			4,378			8			—		22,825
Operating income (loss)	34,555			(3,116		)	1,660			—		33,099
Interest expense	(12,202		)	(3,116		)	(988		)	—		(16,306		)
Other income	2,109			179			27			—		2,315
Income tax (expense) benefit	(6,551		)	3,543			(1,721		)	—		(4,729		)
Net income (loss)	$	17,911		$	(2,510	)	$	(1,022	)	$	—	14,379
Total assets	$	2,040,612		$	845,116		$	13,646		$	—	$	2,899,374
Capital expenditures	$	50,552		$	11,362		$	—		$	—	$	61,914

Nine Months Ended
September 30, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	602,024		$	230,971		$	1,112		$	—	$	834,107
Cost of sales	246,592			123,931			—			—		370,523
Gross margin	355,432			107,040			1,112			—		463,584
Operating, general and administrative	140,267			60,651			2,336			—		203,254
Property and other taxes	50,937			17,606			8			—		68,551
Depreciation	61,205			14,332			25			—		75,562
Operating income (loss)	103,023			14,451			(1,257		)	—		116,217
Interest expense	(40,877		)	(8,105		)	(1,755		)	—		(50,737		)
Other income	1,425			751			81			—		2,257
Income tax (expense) benefit	(10,998		)	(1,228		)	2,929			—		(9,297		)
Net income (loss)	$	52,573		$	5,869		$	(2	)	$	—	$	58,440
Total assets	$	2,157,225		$	891,989		$	12,610		$	—	$	3,061,824
Capital expenditures	$	99,168		$	25,316		$	—		$	—	$	124,484

Nine Months Ended
September 30, 2010	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	592,262		$	225,882		$	906		$	—	$	819,050
Cost of sales	266,052			124,633			—			—		390,685
Gross margin	326,210			101,249			906			—		428,365
Operating, general and administrative	124,220			52,455			(2,804		)	—		173,871
Property and other taxes	50,625			17,853			9			—		68,487
Depreciation	55,562			13,110			25			—		68,697
Operating income	95,803			17,831			3,676			—		117,310
Interest expense	(37,309		)	(9,717		)	(2,387		)	—		(49,413		)
Other income	4,515			326			80			—		4,921
Income tax (expense) benefit	(17,490		)	(1,041		)	501			—		(18,030		)
Net income	$	45,519		$	7,399		$	1,870		$	—	$	54,788
Total assets	$	2,040,612		$	845,116		$	13,646		$	—	$	2,899,374
Capital expenditures	$	150,104		$	28,043		$	—		$	—	$	178,147

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2011

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Employee Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
	2011			2010			2011			2010
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,549		$	2,340		$	109		$	120
Interest cost	6,099			6,023			337			450
Expected return on plan assets	(7,616		)	(7,459		)	(296		)	(297		)
Amortization of prior service cost	62			62			(500		)	(488		)
Recognized actuarial loss	629			34			165			247
Net Periodic Benefit Cost (Income)	$	1,723		$	1,000		$	(185	)	$	32

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
	2011			2010			2011			2010
Components of Net Periodic Benefit Cost (Income)
Service cost	$	7,649		$	7,021		$	328		$	362
Interest cost	18,296			18,068			1,011			1,352
Expected return on plan assets	(22,847		)	(22,379		)	(889		)	(890		)
Amortization of prior service cost	185			185			(1,499		)	(1,464		)
Recognized actuarial loss	1,887			104			494			738
Net Periodic Benefit Cost (Income)	$	5,170		$	2,999		$	(555	)	$	98

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Income Taxes

9 Months Ended

Sep. 30, 2011

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

Our effective tax rate was 4.1% and 13.7% for the three and nine months ended September 30, 2011 as compared with 24.7% and 24.8% for the three and nine months ended September 30, 2010. The following table summarizes the significant components of the income tax expense:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Income Before Income Taxes	$	15,530		$	19,108		$	67,737		$	72,818
Income tax calculated at 35% Federal statutory rate	(5,435		)	(6,687		)	(23,707		)	(25,485		)
Permanent or flow through adjustments:
Flow-through repairs deductions	3,243			2,341			8,745			6,902
Flow-through of state bonus depreciation deduction	1,170			—			4,452			—
Recognition of state NOL benefit/valuation allowance release	—			—			2,402			2,178
State income tax & other, net	387			(383		)	(1,189		)	(1,625		)
	$	4,800		$	1,958		$	14,410		$	7,455
Income tax expense	$	(635	)	$	(4,729	)	$	(9,297	)	$	(18,030	)

Our effective tax rate differs from the federal tax rate of 35% primarily due to repairs and state tax bonus depreciation deductions. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues we record deferred income taxes and establish related regulatory assets and liabilities.

In addition we maintain a valuation allowance against certain state net operating loss (NOL) carryforwards based on our forecast of taxable income and our estimate that a portion of these NOL carryforwards will more likely than not expire before we can use them. The nine months ended September 30, 2011 includes a $2.4 million favorable state NOL carryforward utilization benefit due to 2010 taxable income being higher than our original estimate. By comparison, we had recognized a $2.2 million valuation allowance release for the nine months ended September 30, 2010 based on our forecast of 2010 taxable income at that time. We reversed this benefit during the fourth quarter of 2010 after the law extending bonus depreciation was implemented.

Uncertain Tax Positions

We have unrecognized tax benefits of approximately $131.4 million as of September 30, 2011, including approximately $79.8 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitations within the next twelve months.

The Internal Revenue Service (IRS) issued guidance during the third quarter of 2011 providing a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. We are evaluating whether or not we want to elect the safe harbor method, which may result in a change in related repairs deductions and unrecognized tax benefits.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the nine months ended September 30, 2011, we have not recognized expense for interest or penalties, and do not have any amounts accrued at September 30, 2011 and December 31, 2010, respectively, for the payment of interest and penalties.

Our federal tax returns from 2000 forward remain subject to examination by the IRS.

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Fair Value Measurements Fair Value Finanical Insruments (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Carrying Value	$ 908,826	$ 1,068,358
Long-term Debt, Fair Value	$ 1,050,621	$ 1,137,148

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Regulatory Matters

9 Months Ended

Sep. 30, 2011

Regulated Operations [Abstract]

Public Utilities Disclosure [Text Block]

Regulatory Matters

South Dakota Natural Gas Rate Case

In June 2011, we filed a request with the South Dakota Public Utilities Commission (SDPUC) for a natural gas distribution revenue increase of $4.1 million. This request was based on a return on equity of 10.9%, an equity ratio of 56.0% and a rate base of $67.5 million. Approximately $1.4 million of the requested increase relates to annual estimated manufactured gas plant remediation costs. In the event remediation costs are lower than estimated during the time period, the difference would be subject to a refund to customers. Accordingly, while gross margin and operating expenses will fluctuate based on actual results, this portion of the rate request would have no impact on operating income. We expect to complete this rate case and implement new rates by December 31, 2011.

Wind Generation

In April 2011, we executed an agreement to purchase a wind project in Judith Basin County in Montana to be developed and constructed by Spion Kop Wind, LLC, a wholly-owned subsidiary of Compass Wind, LLC (Compass) that would provide approximately 40 MW of capacity, with an estimated cost for the total project of approximately $86 million. We filed an application for pre-approval with the Montana Public Service Commission (MPSC) during the second quarter of 2011 to include the project in regulated rate base as an electric supply resource. Both the energy and associated renewable energy credits would be placed into the electric supply portfolio to meet future customer loads and renewable portfolio standards obligations. If the MPSC fails to grant approval on or before April 1, 2012, then either party may terminate this agreement. Material construction would not commence until we receive a favorable ruling from the MPSC. Assuming MPSC approval by April 1, 2012, commercial operation is projected to begin by the end of 2012. The MPSC established a procedural schedule, with a hearing scheduled to begin on December 14, 2011.

Montana Distribution System Infrastructure Project (DSIP)

In March 2011, the MPSC approved a request for an accounting order to defer certain incremental operating and maintenance expenses up to $16.9 million for 2011 and 2012 and amortize over a five-year period beginning in 2013 associated with the phase-in portion of the DSIP. We expect incremental expenses related to the DSIP project to be approximately $7.2 million and $9.7 million, respectively in 2011 and 2012. As of September 30, 2011 we have deferred incremental expenses of approximately $2.3 million. In addition, we are currently projecting capital expenditures under the DSIP to be approximately $287 million over a seven-year time span beginning in 2011. As of September 30, 2011, we have incurred approximately $8.5 million of DSIP-related capital expenditures. Based on our current forecast, along with the MPSC's recent approval of the accounting order, we anticipate providing the MPSC an informational technical plan on October 31, 2011, and believe that DSIP-related expenses will be recovered in base rates through annual or biennial general rate cases.

Dave Gates Generating Station at Mill Creek (formerly Mill Creek Generating Station) (DGGS)

On December 31, 2010, we completed construction of DGGS, a 150 MW natural gas fired facility and began commercial operations on January 1, 2011. The facility provides regulating resources (in place of previously contracted ancillary services) to balance our transmission system in Montana to maintain reliability and enable wind power to be integrated into the network to meet renewable energy portfolio needs. Total project costs through September 30, 2011 were approximately $183 million.

In October 2010, the Federal Energy Regulatory Commission (FERC) approved interim rates to reflect the estimated cost of service under Schedule 3 (Regulation and Frequency Response) of the Open Access Transmission Tariff (OATT). In November 2010, the MPSC approved interim rates based on the originally estimated construction costs of $202 million. The interim rates under both orders became effective beginning January 1, 2011. The respective interim rates are subject to refund plus interest pending final resolution in both jurisdictions.

On March 31, 2011, we made a compliance filing with the MPSC that will be used to conduct a final cost review and establish final rates. As a result of the lower than estimated construction costs and estimated impact of the flow-through of accelerated state tax depreciation, we also reduced our interim rate request, which the MPSC authorized to take effect beginning May 1, 2011. A procedural schedule has been established setting a hearing on the matter starting November 9, 2011. Discovery is currently in process.

During March 2011, we began settlement discussions with FERC Staff and large customers receiving service under Schedule 3 of the OATT. Settlement discussions have not been successful. During June 2011, FERC issued an order establishing a procedural schedule with a hearing scheduled for January 23, 2012 and an initial decision by May 4, 2012. Discovery is currently in process.

Through September 30, 2011, we have deferred revenue of approximately $8.2 million associated with DGGS due to lower than estimated construction costs, the estimated impact of the flow-through of accelerated state tax depreciation, our current estimate of operating expenses as compared to amounts included in our interim rate requests, and uncertainty related to the allocation of costs between the MPSC and FERC jurisdictions. Our filings are based on approximately 80% of our revenues related to the facility being subject to the MPSC's jurisdiction and approximately 20% being subject to FERC's jurisdiction. There is significant uncertainty related to the ultimate resolution of cost allocations between the two jurisdictions, which could result in an inability to fully recover our costs, as well as requiring us to refund more interim revenues than our current estimate.

Mountain States Transmission Intertie Project

We have been involved in an open season process for our proposed MSTI line. Under our original timeline, we anticipated completing the open season process by the end of 2010. During 2010, a lawsuit was filed against the Montana Department of Environmental Quality (MDEQ) by Jefferson County, Montana, regarding the County's ability to be more involved in the siting and routing of MSTI. On September 8, 2010, the Montana District Court agreed with Jefferson County and (i) required the MDEQ to consult with Jefferson County in the preparation of the environmental impact statement (EIS) concerning the project and (ii) enjoined the MDEQ from releasing the draft EIS until that consultation occurs. In January 2011, MDEQ appealed the decision to the Montana Supreme Court. In February 2011, we also appealed the decision to the Montana Supreme Court. Oral arguments occurred before the Montana Supreme Court on August 2, 2011 and we anticipate receiving a decision by the end of 2011. In addition to this lawsuit, due to general economic conditions, lack of clarity around federal legislation on renewables and uncertainty in the California renewable standards, we have extended the open season process for the proposed MSTI line until at least the second quarter of 2012.

Construction on MSTI would not commence until all local, state and federal permits/regulatory requirements are met and there are sufficient contracts with credit-worthy shippers to support financing. We have successfully completed a path rating process for MSTI with the Western Electricity Coordinating Council (WECC), which is independent of the siting process. This process established a path rating for MSTI of 1,500 MW southbound and 1,100 MW northbound on the transmission facility. In September 2011, the proposed MSTI line received 'Phase 3' status, which means the study is concluded, the path rating has been established, and that from a regional planning alternative, MSTI could be constructed with the approved rating. Phase 3 would conclude when the project is placed into service. The rating was affirmed for all of the potential alternative routes, including a 'common corridor' approach to what has been termed the 'northern route alternative' that may allow MSTI to more closely parallel an existing 500kV transmission line.

Due to the uncertainty surrounding the project, certain aspects are scaleable and thus can be built out to more closely match the timing and needs of new generation and loads. To avoid excessive risk for us, it is critical to reduce regulatory uncertainty before making large capital investments and/or commitments. We are also contemplating a strategic partner to own up to 50% of MSTI, however there can be no assurance that we will enter into such a partnership.

Through September 30, 2011, we have capitalized approximately $19.5 million of preliminary survey and investigative costs associated with the MSTI transmission project. As we continue to develop MSTI, costs will continue to increase. If our efforts to complete MSTI are not successful we may have to write-off all or a portion of these costs, which could have a material adverse effect on our results of operations.

FERC Order No. 1000

In July 2011, the FERC issued a Final Rule - Order No. 1000 which amends the transmission planning and cost allocation requirements established in Order No. 890. With respect to transmission planning,  Order No. 1000: (1) requires that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan; (2) requires that each public utility transmission provider amend its OATT to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; (3) removes from Commission-approved tariffs and agreements a federal right of first refusal for certain new transmission facilities; and (4) improves coordination between neighboring transmission planning regions.  Further,  Order No. 1000 requires that each public utility transmission provider must participate in a regional transmission planning process that has: (1) a regional cost allocation method for the cost of new transmission facilities selected in a regional transmission plan for purposes of cost allocation; and (2) an interregional cost allocation method for the cost of certain new transmission facilities that are located in two or more neighboring transmission planning regions and are jointly evaluated by the regions in the interregional transmission coordination procedures required by Order No. 1000. We are reviewing Order No. 1000 and participating in our regional transmission planning processes to develop and implement the requirements to comply with the Order.  The impacts of Order No. 1000, if any, cannot be predicted at this time.

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Nature of Operations and Basis of Consolidation (Policies)

9 Months Ended

Sep. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation, Variable Interest Entity [Policy Text Block]

Variable Interest Entities

A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.

Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $422.1 million through 2024.

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Segment Information

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

Segment Information

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

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

Three Months Ended
September 30, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	206,613		$	37,067		$	361		$	—	$	244,041
Cost of sales	85,221			12,824			—			—		98,045
Gross margin	121,392			24,243			361			—		145,996
Operating, general and administrative	45,607			19,979			746			—		66,332
Property and other taxes	16,894			5,708			3			—		22,605
Depreciation	20,465			4,708			8			—		25,181
Operating income (loss)	38,426			(6,152		)	(396		)	—		31,878
Interest expense	(13,661		)	(2,711		)	(322		)	—		(16,694		)
Other income	86			232			28			—		346
Income tax (expense) benefit	(3,407		)	3,016			(244		)	—		(635		)
Net income (loss)	$	21,444		$	(5,615	)	$	(934	)	$	—	$	14,895
Total assets	$	2,157,225		$	891,989		$	12,610		$	—	$	3,061,824
Capital expenditures	$	44,318		$	8,309		$	—		$	—	$	52,627

Three Months Ended
September 30, 2010	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	203,585		$	36,963		$	270		$	—	$	240,818
Cost of sales	92,691			13,231			—			—		105,922
Gross margin	110,894			23,732			270			—		134,896
Operating, general and administrative	42,331			17,429			(1,323		)	—		58,437
Property and other taxes	15,569			5,041			(75		)	—		20,535
Depreciation	18,439			4,378			8			—		22,825
Operating income (loss)	34,555			(3,116		)	1,660			—		33,099
Interest expense	(12,202		)	(3,116		)	(988		)	—		(16,306		)
Other income	2,109			179			27			—		2,315
Income tax (expense) benefit	(6,551		)	3,543			(1,721		)	—		(4,729		)
Net income (loss)	$	17,911		$	(2,510	)	$	(1,022	)	$	—	14,379
Total assets	$	2,040,612		$	845,116		$	13,646		$	—	$	2,899,374
Capital expenditures	$	50,552		$	11,362		$	—		$	—	$	61,914

Nine Months Ended
September 30, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	602,024		$	230,971		$	1,112		$	—	$	834,107
Cost of sales	246,592			123,931			—			—		370,523
Gross margin	355,432			107,040			1,112			—		463,584
Operating, general and administrative	140,267			60,651			2,336			—		203,254
Property and other taxes	50,937			17,606			8			—		68,551
Depreciation	61,205			14,332			25			—		75,562
Operating income (loss)	103,023			14,451			(1,257		)	—		116,217
Interest expense	(40,877		)	(8,105		)	(1,755		)	—		(50,737		)
Other income	1,425			751			81			—		2,257
Income tax (expense) benefit	(10,998		)	(1,228		)	2,929			—		(9,297		)
Net income (loss)	$	52,573		$	5,869		$	(2	)	$	—	$	58,440
Total assets	$	2,157,225		$	891,989		$	12,610		$	—	$	3,061,824
Capital expenditures	$	99,168		$	25,316		$	—		$	—	$	124,484

Nine Months Ended
September 30, 2010	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	592,262		$	225,882		$	906		$	—	$	819,050
Cost of sales	266,052			124,633			—			—		390,685
Gross margin	326,210			101,249			906			—		428,365
Operating, general and administrative	124,220			52,455			(2,804		)	—		173,871
Property and other taxes	50,625			17,853			9			—		68,487
Depreciation	55,562			13,110			25			—		68,697
Operating income	95,803			17,831			3,676			—		117,310
Interest expense	(37,309		)	(9,717		)	(2,387		)	—		(49,413		)
Other income	4,515			326			80			—		4,921
Income tax (expense) benefit	(17,490		)	(1,041		)	501			—		(18,030		)
Net income	$	45,519		$	7,399		$	1,870		$	—	$	54,788
Total assets	$	2,040,612		$	845,116		$	13,646		$	—	$	2,899,374
Capital expenditures	$	150,104		$	28,043		$	—		$	—	$	178,147

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Other Comprehensive Income (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Statement of Income and Comprehensive Income [Abstract]
Net Income	$ 14,895	$ 14,379	$ 58,440	$ 54,788
Other Comprehensive Income (loss), Net of Tax [Abstract]
Reclassification of net gains on hedging instruments from OCI to net income	(183)	(297)	(777)	(891)
Foreign currency translation	(168)	62	(99)	35
Comprehensive Income	$ 14,544	$ 14,144	$ 57,564	$ 53,932

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Financing Activities

9 Months Ended

Sep. 30, 2011

Financing Activities [Abstract]

Debt Disclosure [Text Block]

Financing Activities

On February 8, 2011, we entered into a commercial paper program under which we may issue unsecured commercial paper notes on a private placement basis up to a maximum aggregate amount outstanding at any time of $250 million to provide an alternative financing source for our short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Commercial paper issuances are supported by available capacity under our unsecured revolving line of credit.

On June 30, 2011, we amended and restated our unsecured revolving line of credit scheduled to expire on June 30, 2012. The amended facility extends the term to June 30, 2016, and increases the aggregate principal amount available under the facility by $50 million to $300 million. The facility also has an accordion feature that allows us to increase the size of the facility up to $350 million with the consent of the lenders. The amended facility does not amortize and borrowings will bear interest based on a credit ratings grid. The 'spread' or 'margin' ranges from 0.88% to 1.75% over the London Interbank Offered Rate (LIBOR). Based on our unsecured credit ratings on the closing date of the agreement, the applicable spread was 1.25%. A total of eight banks participate in the new facility, with no one bank providing more than 17% of the total availability. The amended facility contains covenants substantially similar to the previous facility.

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Nature of Operations and Basis of Consolidation

9 Months Ended

Sep. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 665,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to September 30, 2011, have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2010.

Variable Interest Entities

A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.

Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $422.1 million through 2024.

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Goodwill

9 Months Ended

Sep. 30, 2011

Goodwill [Abstract]

Goodwill Disclosure [Text Block]

Goodwill

There were no changes in our goodwill during the nine months ended September 30, 2011. Goodwill by segment is as follows for both September 30, 2011 and December 31, 2010 (in thousands):

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

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Employee Benefit Plans Net Periodic Benefit Cost (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Pension Plans, Defined Benefit [Member]
Components of Net Periodic Benefit Cost [Abstract]
Service cost	$ 2,549	$ 2,340	$ 7,649	$ 7,021
Interest cost	6,099	6,023	18,296	18,068
Expected return on plan assets	(7,616)	(7,459)	(22,847)	(22,379)
Amortization of prior service cost	62	62	185	185
Recognized actuarial loss	629	34	1,887	104
Net Periodic Benefit Cost (Income)	1,723	1,000	5,170	2,999
Other Pension Plans, Postretirement or Supplemental Plans, Defined Benefit [Member]
Components of Net Periodic Benefit Cost [Abstract]
Service cost	109	120	328	362
Interest cost	337	450	1,011	1,352
Expected return on plan assets	(296)	(297)	(889)	(890)
Amortization of prior service cost	(500)	(488)	(1,499)	(1,464)
Recognized actuarial loss	165	247	494	738
Net Periodic Benefit Cost (Income)	$ (185)	$ 32	$ (555)	$ 98

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Goodwill (Details) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Goodwill [Line Items]
Goodwill	$ 355,128	$ 355,128
Goodwill, Period Increase (Decrease)	0
Electric Domestic Regulated [Member]
Goodwill [Line Items]
Goodwill	241,100	241,100
Gas Domestic Regulated [Member]
Goodwill [Line Items]
Goodwill	$ 114,028	$ 114,028

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Other Comprehensive Income

9 Months Ended

Sep. 30, 2011

Statement of Income and Comprehensive Income [Abstract]

Comprehensive Income Note [Text Block]

Other Comprehensive Income

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income	$	14,895		$	14,379		$	58,440		$	54,788
Other comprehensive income (loss), net of tax:
Reclassification of net gains on hedging instruments from OCI to net income	(183		)	(297		)	(777		)	(891		)
Foreign currency translation	(168		)	62			(99		)	35
Comprehensive income	$	14,544		$	14,144		$	57,564		$	53,932

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Commitments and Contingencies Legal Proceedings (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Increase [Member] | Colstrip Energy Limited Partnership (CELP) [Member]
Loss Contingencies [Line Items]
Estimated Litigation Settlement	$ 24
Decrease [Member] | Colstrip Energy Limited Partnership (CELP) [Member]
Loss Contingencies [Line Items]
Estimated Litigation Settlement	25
Colstrip Energy Limited Partnership (CELP) [Member]
Loss Contingencies [Line Items]
Loss Contingency Allegation	23
Gonzales Action [Member]
Loss Contingencies [Line Items]
Payments for Legal Settlements	2.5
Bozeman Explosion [Member]
Loss Contingencies [Line Items]
Insurance Coverage For Available Claims	$ 150
Number Of Buildings	6
Total Cases FIled To Date	33
Cases Settlements Have Been Reached	24
Total Remaining Property Damage And Business Loss Cases Pending	9

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Nature of Operations and Basis of Consolidation (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011 customers
Number Of Customers	665,000
Estimated Aggregate Gross Contractual Payments	$ 422.1

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Risk Management and Hedging Activities (Details) (USD $) In Thousands			3 Months Ended		9 Months Ended					9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Commodity Contract [Member] Forward Contracts [Member]	Sep. 30, 2010 Commodity Contract [Member] Forward Contracts [Member]	Sep. 30, 2011 Commodity Contract [Member] Forward Contracts [Member]	Sep. 30, 2010 Commodity Contract [Member] Forward Contracts [Member]	Sep. 30, 2011 Commodity Contract [Member] Forward Contracts [Member] Not Designated as Hedging Instrument [Member] Accrued Liabilities [Member]	Dec. 31, 2010 Commodity Contract [Member] Forward Contracts [Member] Not Designated as Hedging Instrument [Member] Accrued Liabilities [Member]	Sep. 30, 2011 Interest Rate Swap [Member]	Sep. 30, 2011 Interest Rate Swap [Member] Interest Expense [Member]
Derivative [Line Items]
Physical Purchase And Sale of Gas And Electricity At Fixed Prices	$ 0	$ 0
Natural gas net derivative liability							20,057	29,712
Derivative, Gain (Loss) on Derivative, Net			1,840	(3,161)	9,655	(12,862)
Derivative, Net Liability Position, Aggregate Fair Value			10,306		10,306
Collateral Already Posted, Aggregate Fair Value			0		0
Additional Collateral, Aggregate Fair Value			10,306		10,306
Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss)										891
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	7,792
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months									1,200
Interest Rate Cash Flow Hedge Derivative at Fair Value, Net	$ 0	$ 0

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Commitments and Contingencies Environmental (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Environmental Remediation Obligation Minimum	$ 29.3
Environmental Remediation Obligation Maximum	38.9
Accrual for Environmental Loss Contingencies	32.2
Manufactured Gas Plants [Member]
Accrual for Environmental Loss Contingencies	27.1
Manufactured Gas Plants [Member] | Aberdeen South Dakota Site [Member]
Accrual for Environmental Loss Contingencies	13.4
Environmental Remediation Obligation Next 5 years	8.9
Clean Air Act and Emission Control Equipment | Big Stone Generating Facility [Member] | Jointly Owned Electricity Generation Plant [Member]
Environmental Obligation Capital Expenditure Estimated	490.0
Jointly Owned Utility Plant Ownership Percentage	23.40%
Clean Air Act and Emission Control Equipment | Coyote Generating Facility [Member] | Jointly Owned Electricity Generation Plant [Member]
Environmental Obligation Capital Expenditure Estimated	6.0
Jointly Owned Utility Plant Ownership Percentage	10.00%
Clean Air Act and Emission Control Equipment | Neal 4 Generating Facility [Member] | Jointly Owned Electricity Generation Plant [Member]
Environmental Obligation Capital Expenditure Estimated	$ 270.0
Jointly Owned Utility Plant Ownership Percentage	8.70%
Site Contingency, Time Frame of Disbursements	scheduled to commence in 2011 and be spread over the next three years.

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Income Taxes Tax Reconciliation (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Tax Disclosure [Abstract]
Income Before Income Taxes	$ 15,530	$ 19,108	$ 67,737	$ 72,818
Income tax calculated at 35% Federal statutory rate	(5,435)	(6,687)	(23,707)	(25,485)
Permanents or flow through adjustments:
Flow through repair deduction	3,243	2,341	8,745	6,902
Flow through of state bonus depreciation deduction	1,170	0	4,452	0
Recognition of state NOL benefit/Valuation allowance release	0	0	2,402	2,178
State income tax & other, net	387	(383)	(1,189)	(1,625)
Total adjustments	4,800	1,958	14,410	7,455
Income tax expense	$ (635)	$ (4,729)	$ (9,297)	$ (18,030)

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

Commitments and Contingencies

ENVIRONMENTAL LIABILITIES AND REGULATION

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

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

Our liability for environmental remediation obligations is estimated to range between $29.3 to $38.9 million, primarily for manufactured gas plants discussed below. As of September 30, 2011, we have a reserve of approximately $32.2 million. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. Over time, as specific laws are implemented and we gain experience in operating under them, a portion of the costs related to such laws will become determinable, and we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material adverse effect on our consolidated financial position or ongoing operations.

Manufactured Gas Plants - Approximately $27.1 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. Our current reserve for remediation costs at this site is approximately $13.4 million, and we estimate that approximately $8.9 million of this amount will be incurred during the next five years.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. During 2006, the NDEQ released to us the Phase II Limited Subsurface Assessments performed by the NDEQ's environmental consulting firm for Kearney and Grand Island. In February 2011, NDEQ completed an Abbreviated Preliminary Assessment and Site Investigation Report for Grand Island, which recommended additional ground water testing. Our reserve estimate includes assumptions for additional ground water testing. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to excess regulated pollutants in the groundwater. Voluntary soil and coal tar removals were conducted in the past at the Butte and Helena locations in accordance with MDEQ requirements. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the conditions at these sites; however, additional groundwater monitoring will be necessary. Monitoring of groundwater at the Helena site is ongoing and will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site or if any additional actions beyond monitored natural attenuation will be required.

Global Climate Change - There are national and international efforts to adopt measures related to global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide. These efforts include legislative proposals and U.S. Environmental Protection Agency (EPA) regulations at the federal level, actions at the state level, as well as litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their GHG emissions. We have joint ownership interests in four electric generating plants, all of which are coal fired and operated by other companies. We have undivided interests in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

While numerous bills have been introduced in Congress that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA is regulating GHG emissions under its existing authority pursuant to the Clean Air Act. For example, the EPA promulgated regulations requiring major sources in the United States to begin collecting and reporting information regarding their GHG emissions. Certain of our facilities began collecting such data on January 1, 2010 and submitted their first annual reports to the EPA by its September 30, 2011 deadline. For petroleum and natural gas facilities, data collection began on January 1, 2011, with the first annual report due on March 31, 2012.

In June 2010, the EPA also adopted rules that make certain “stationary sources,” such as power plants, subject to permitting requirements for their GHG emissions. Sources that emit more than 100,000 tons of greenhouse gases per year are now required to obtain permits for those emissions even if they are not otherwise required to obtain a new or modified permit. Such permits may require the installation and operation of “best available control technology” to control GHG emissions.

Also, in December 2010, the EPA entered into an agreement to settle litigation brought by states and environmental groups whereby the EPA agreed to issue New Source Performance Standards for GHG emissions from certain new and modified electric generating units and “emissions guidelines” for existing units over the next two years. Pursuant to this settlement agreement, the EPA agreed to issue proposed rules by September 2011 and final rules by May 2012. The EPA, however, did not meet the September deadline for issuing a proposed rule. It is uncertain whether the EPA still expects to meet the May 2012 deadline for issuing a final rule.

On June 20, 2011, the U.S. Supreme Court issued a decision that bars state and private parties from bringing federal common law nuisance actions against electrical utility companies based on their alleged contribution to climate change. The Supreme Court's decision did not, however, address state law claims. This decision is expected to affect other pending federal climate change litigation, including a case brought by individuals alleging public nuisance claims against a variety of companies that emit GHGs and seeking compensation for damages suffered in the wake of Hurricane Katrina. The plaintiffs in that case, which was previously dismissed, re-filed their lawsuit in May 2011. Although we are not a defendant in any of these proceedings, additional litigation in federal and state courts over these issues is continuing.

Physical impacts of climate change present potential risks for severe weather, such as floods and tornadoes, in the locations where we operate or have interests. Furthermore, requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance, increase our costs of procuring electricity in the marketplace or curtail the demand for fossil fuels such as oil and gas. In addition, we believe future legislation and regulations that affect GHG emissions from power plants are likely, although technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. We cannot predict with any certainty whether these risks will have a material impact on our operations.

Coal Combustion Residuals (CCRs) - In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and scrubber wastes. Under one approach, the EPA would regulate CCRs as a hazardous waste under Subtitle C of RCRA. This approach would have significant impacts on coal-fired plants, and would require plants to retrofit their operations to comply with hazardous waste requirements from the generation of CCRs and associated waste waters through transportation and disposal. This could also have a negative impact on the beneficial use of CCRs and the current markets associated with such use. The second approach would regulate CCRs as a solid waste under Subtitle D of RCRA. This approach would only affect disposal, most significantly any wet disposal, of CCRs. We cannot predict at this time the final requirements of the EPA's CCR regulations and what impact, if any, they would have on us, but the costs could be significant.

Water Intakes - Section 316(b) of the Federal Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. Permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA takes action to address several court decisions that rejected portions of previous rules and confirmed that EPA has discretion to consider costs relative to benefits in developing cooling water intake structure regulations. In March 2011, EPA proposed rules to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. When final rules are issued and implemented, additional capital and/or increased operating costs may be incurred. The costs of complying with any such final water intake standards are not currently determinable, but could be significant.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures

EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants where we have joint ownership.

The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule requires the use of Best Available Retrofit Technology (BART) for certain electric generating units to achieve emissions reductions from designated sources that are deemed to contribute to visibility impairment in Class I air quality areas.

In May 2011, the EPA issued a proposed rule setting forth Maximum Achievable Control Technology (MACT) standards for hazardous air pollutant emissions from electric generating units that among other things, seek to set stringent emission limits for acid gases, mercury, and other hazardous air pollutants. EPA is under a consent decree deadline to issue the final MACT standards by mid-November 2011. Given the potential for legal challenges and regulatory uncertainties associated with EPA's final rule, it is not possible to fully assess the impact of this rulemaking.

On July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under the CSAPR, the first phase of the nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions reductions would commence in 2012 with further reductions effective in 2014. On October 7, 2011, EPA announced that it was proposing technical corrections to CSAPR that increase the allowances allocated to certain facilities and have the effect of allowing unlimited interstate trading of allowances between 2012 and 2014. Numerous challenges to CSAPR have been filed with the EPA and in Federal court and we cannot predict the outcome of such challenges. Regardless of the outcome, CSAPR only applies to power plants within the eastern half of the United States, and, thus is only applicable to one plant in which we have an ownership interest, the Neal 4 plant located in Iowa. We do not expect CSAPR to affect any of the other plants in which we have an ownership interest.

We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are subject to the Clean Air Visibility Rule and would be subject to the EPA's proposed rules, as discussed below.

South Dakota. The South Dakota Department of Environment and Natural Resources (DENR) determined that the Big Stone Plant, of which we have a 23.4% ownership, is subject to the Clean Air Visibility Rule. South Dakota DENR submitted its revised State Implementation Plan (SIP) and associated implementation rules to the EPA on September 19, 2011. Under the SIP, the Big Stone Plant must install and operate a new BART compliant air quality control system (AQCS) to reduce emissions as expeditiously as practicable, but no later than five years after the EPA's approval of South Dakota's SIP. We expect EPA approval of the SIP in the first half of 2012, however such approval cannot be guaranteed and we cannot predict the timing of any such approval with certainty. We will not incur any significant costs unless the EPA approves the SIP or issues a federal implementation plan in its place. Although studies and evaluations are continuing, the current project cost for the AQCS is estimated to be approximately $490 million (our share is 23.4%).

Our incremental capital expenditure projections include amounts related to our share of the BART technologies at Big Stone based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process. The SDPUC has historically allowed timely recovery of the costs of environmental improvements; however, there is no precedent on a project of this size.

Based on the proposed MACT rule, it appears that Big Stone would meet the proposed requirements by installing the AQCS system and using mercury control technology such as activated carbon injection. Mercury emissions monitoring equipment installation is already installed at Big Stone, but its operation has been put on hold pending additional regulatory direction.

North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, of which we have 10% ownership, to reduce its NOx emissions. On February 23, 2010, the North Dakota Department of Health (NDDOH) issued a construction permit to Coyote Station requiring installation of control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 12-month rolling average basis. The control equipment must be installed by July 1, 2018 and compliance with the limit must be beginning on July 1, 2019. Subsequent to issuance of the construction permit, the NDDOH entered into further negotiations with the EPA on regional haze plan implementation. As part of those negotiations, Coyote agreed to accept a NOx emission limit of 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown, beginning on July 1, 2018. The current estimate of the total cost of the project is approximately $6.0 million (our share is 10%).

Iowa. The Neal 4 generating facility, of which we have an 8.7% ownership, is installing a scrubber, a baghouse and a selective non-catalytic reduction system to comply with the CSAPR and the MACT standards. These improvements are expected to result in compliance with the regional haze provisions of the Clean Air Act. The Neal 4 owners are currently evaluating the plant's ability to meet the CSAPR standards on the timeframe required by EPA. Capital expenditures for such equipment are currently estimated to be approximately $270 million (our share is 8.7%). The plant began incurring such costs in 2011 and the costs will be spread over the next three years. Our incremental capital expenditure projections include amounts related to our share of the emission control equipment at Neal 4 based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process.

Montana. The Colstrip facility is currently controlling emissions of mercury under regulations issued by the State of Montana and has been since January 2010. The owners do not believe additional equipment will be necessary to meet the MACT standards for mercury. Additionally, the Colstrip facility anticipates meeting the expected standards for acid gases without additional costs. However, Colstrip may have to install additional controls to further reduce particulate matter to meet MACT standards. The Colstrip owners are continuing to determine what may be required and while it is not possible to predict costs at this time, the costs of additional controls could be significant. In November 2010, Colstrip Unit 4 received a request from the EPA to provide further analysis regarding why Colstrip Unit 4 is not a BART eligible unit under the regional haze rule. The plant operator completed a high level analysis of various control options to reduce emissions of SO2 and particulate matter and submitted that analysis to EPA in January 2011. The analysis shows that these units are well controlled, any incremental reductions would not be cost effective and further analysis is not warranted. The plant operator also concluded that further analysis for NOx was not justified as controls at Colstrip Unit 4 were installed and the EPA previously agreed that such controls would satisfy BART for NOx control. The plant operator informed us that the EPA verbally indicated that it does not agree with all of the plant operator's conclusions and will be requesting additional information. The EPA is under a consent decree to take final action on Montana's regional haze implementation plan no later than June 29, 2012. The costs of complying with any final regional haze standards in Montana are not currently determinable, but could be significant.

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 long-term 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.

On June 30, 2008, the Montana district court granted both a motion by the MPSC to bifurcate, having the effect of separating the issues between contract/tort claims against us and the administrative appeal of the MPSC's orders and a motion by us to refer the claims against us to arbitration. The order also stayed the appellate decision pending a decision in the arbitration proceedings. Arbitration was held in June 2009 and the arbitration panel entered its interim award in August 2009, holding that although NorthWestern failed to use certain data inputs required by the power purchase agreement, CELP was entitled to neither damages for contract years 2004-2005 or 2005-2006, nor to recalculation of the underlying MPSC filings for those years, effectively finalizing CELP's contract rates for those years. We requested clarification from the arbitration panel as to its intent regarding the applicable rates.

On November 2, 2009, we received the final award from the arbitration panelwhich confirmed that the filed rates for 2004-2005 and 2005-2006 are not required to be recalculated. In affirming its interim award, the arbitration panel also denied CELP's request for attorney fees, holding that each party would be responsible for its own fees.

On June 15, 2010, the Montana district court confirmed the final arbitration panel award and denied CELP's motion to vacate, modify or correct the award. CELP appealed the decision to the Montana Supreme Court (MSC). In May 2011, the MSC affirmed the Montana district court's order and the arbitration award.

Meanwhile, on October 31, 2010, NorthWestern filed with the MPSC, consistent with the direction of the arbitration panel, for a determination of the inputs that will be used to calculate contract rates for periods subsequent to June 30, 2006. The MPSC has not yet ruled on our filing. On June 30, 2011, CELP submitted another demand for arbitration, seeking clarification from the same panel regarding the panel's intent as to the implementation of its award in Contract Years 17 (July 2005 - June 2006) and 18 (July 2006 - June 2007). Based on our current assumptions (including current discount rates), if CELP prevailed entirely, we could be required to increase our QF liability by approximately $24 million. If we prevailed entirely, we could reduce our QF liability by up to $25 million. Due to the uncertainty around resolution of this matter, we currently are unable to predict its outcome. In addition, settlement discussions concerning these claims are ongoing.

Gonzales

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

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

We and Putnam and Associates have agreed to settle the Gonzales Action and have executed a settlement agreement which remains subject to the approval of the Montana State Court. We paid the settlement agreement amount of $2.5 million to the Clerk of the Montana State Court in full satisfaction of all Gonzales Action claims. The Clerk of the Montana State Court will hold these funds pending final Montana State Court approval of the settlement, which could happen in early 2012.

Bozeman Explosion

On March 5, 2009, a natural gas explosion occurred in downtown Bozeman, Montana, resulting in one fatality, the destruction of or damage to six buildings and the businesses in them, and lesser damage to other nearby properties and businesses. Thirty-three lawsuits have been filed against NorthWestern in the District Court of Gallatin County, Montana, and a number of additional claims not currently in litigation also have been made against us. We have approximately $150 million of insurance coverage available for known and potential claims arising from the explosion. We tendered our self-insured retention under those policies to our insurance carriers, who accepted the tender and assumed the defense and handling of the existing and potential additional lawsuits and claims arising from the incident.

Settlements have been reached in 24 of the 33 cases filed to date, including the sole wrongful death case, and we have settled most of the additional claims that were not in litigation. There are nine remaining property damage and business loss cases pending, none of which is likely to be tried before the fall of 2012. While we cannot predict an outcome in those cases, we are continuing to vigorously defend them. A small number of additional pending claims not in litigation are being handled by our primary insurance carrier. We believe the possibility of any loss in excess of our self-insured retention on the remaining lawsuits and claims is remote.

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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Risk Management and Hedging Activities

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a large portion of our electric and natural gas supply requirements within the Montana market. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

Objectives and Strategies for Using Derivatives

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts, such as fixed-price forward purchase and sales contracts. The objective of these transactions is to fix the price for a portion of anticipated energy purchases to supply our customers. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide price stability for consumers; therefore, these commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to most of our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Financial Statements at September 30, 2011 and December 31, 2010. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

Mark-to-Market Accounting

Certain contracts for the purchase of natural gas associated with our gas utility operations do not qualify for NPNS. These are typically forward purchase contracts for natural gas where we lock in a fixed price, settle the contracts financially and do not take physical delivery of the natural gas. We use the mark-to-market method of accounting for these derivative contracts as we do not elect hedge accounting. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements; therefore, we record a regulatory asset or liability based on changes in market value.

The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 7.

Mark-to-Market Transactions	Balance Sheet Location	September 30, 2011		December 31, 2010
Natural gas net derivative liability	Accrued Expenses	$	20,057	$	29,712

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

	Unrealized gain (loss) recognized in Regulatory Assets					Unrealized gain (loss) recognized in Regulatory Assets
	Three Months Ended					Nine Months Ended
Derivatives Subject to Regulatory Deferral	September 30, 2011		September 30, 2010			September 30, 2011		September 30, 2010
Natural gas	$	1,840	$	(3,161	)	$	9,655	$	(12,862	)

Credit Risk

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

We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

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

The following table presents, as of September 30, 2011, the aggregate fair value of forward purchase contracts that do not qualify for NPNS that contain credit risk-related contingent features. If the credit risk-related contingent features underlying these agreements were triggered as of September 30, 2011, the collateral posting requirements would be as follows (in thousands):

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral
Credit rating	$	10,306	$	—	$	10,306

Interest Rate Swaps Designated as Cash Flow Hedges

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

We have used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in Accumulated Other Comprehensive Income (AOCI). We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these derivative instruments on the Financial Statements (in thousands):

	Location of gain reclassified from AOCI to Income	Nine months ended September 30, 2011
Amount of gain reclassified from AOCI	Interest Expense	$	891

Approximately $7.8 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of September 30, 2011, and we expect to reclassify approximately $1.2 million from AOCI into interest expense during the next twelve months. These gains relate to swaps previously terminated, and we have no current interest rate swaps outstanding.

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Goodwill (Tables)

9 Months Ended

Sep. 30, 2011

Goodwill [Abstract]

Schedule of Goodwill [Table Text Block]

Goodwill by segment is as follows for both September 30, 2011 and December 31, 2010 (in thousands):

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

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Earnings Per Share (Details)	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Weighted Average Number of Shares Outstanding, Basic	36,262,246		36,195,583		36,254,159		36,181,238
Restricted Stock And Performance Share Awards	248,775	[1]	116,624	[1]	245,500	[1]	114,896	[1]
Weighted Average Number of Shares Outstanding, Diluted	36,511,021		36,312,207		36,499,659		36,296,134

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

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Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Income Tax Contingency [Line Items]
Income Tax Reconciliation, State Net Operating Loss Carry Forward Utilization Benefit and Valuation Allowance Release	$ 0	$ 0	$ 2,402	$ 2,178
Unrecognized Tax Benefits	131,351		131,351
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	79,799		79,799
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense			0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 0		$ 0		$ 0
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Effective Income Tax Rate, Continuing Operations	4.10%	24.70%	13.70%	24.80%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate			35.00%
Years remaining subject to examination by the Internal Revenue Service			from 2000 forward

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
OPERATING ACTIVITIES:
Net Income	$ 58,440	$ 54,788
Items not affecting cash:
Depreciation	75,562	68,697
Amortization of debt issue costs, discount and deferred hedge gain	914	1,428
Amortization of restricted stock	1,649	1,264
Equity portion of allowance for funds used during construction	(960)	(4,597)
Loss on disposition of assets	850	716
Deferred income taxes	31,310	31,213
Changes in current assets and liabilities:
Restricted cash	1,188	2,241
Accounts receivable	36,192	45,117
Inventories	(21,346)	(17,391)
Other current assets	(1,896)	6,021
Accounts payable	(12,808)	(31,371)
Accrued expenses	37,018	41,108
Regulatory assets	5,539	(8,247)
Regulatory liabilities	2,663	(12,551)
Other noncurrent assets	(3,451)	10,923
Other noncurrent liabilities	(359)	(1,049)
Cash provided by operating activities	210,505	188,310
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(124,484)	(178,147)
Proceeds from sale of assets	209	69
Cash used in investing activities	(124,275)	(178,078)
FINANCING ACTIVITIES:
Treasury stock activity	169	(127)
Dividends on common stock	(38,930)	(36,728)
Issuance of long-term debt	0	225,000
Repayment on long-term debt	(6,586)	(231,141)
Line of credit borrowings	80,000	554,000
Line of credit repayments	(233,000)	(511,000)
Issuances of short-term borrowings, net	112,993	0
Financing costs	(1,116)	(8,019)
Cash used in financing activities	(86,470)	(8,015)
(Decrease) Increase in Cash and Cash Equivalents	(240)	2,217
Cash and Cash Equivalents, beginning of period	6,234	4,344
Cash and Cash Equivalents, end of period	5,994	6,561
Cash paid during the period for:
Income taxes	18	1,000
Interest	28,950	31,637
Significant non-cash transactions:
Capital expenditures included in accounts payable	$ 4,314	$ 4,416

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Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2011

Statement of Income and Comprehensive Income [Abstract]

Schedule of Comprehensive Income (Loss) [Table Text Block]

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income	$	14,895		$	14,379		$	58,440		$	54,788
Other comprehensive income (loss), net of tax:
Reclassification of net gains on hedging instruments from OCI to net income	(183		)	(297		)	(777		)	(891		)
Foreign currency translation	(168		)	62			(99		)	35
Comprehensive income	$	14,544		$	14,144		$	57,564		$	53,932

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

September 30, 2011	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
Restricted cash	$	11,213	$	—		$	—	$	—	$	11,213
Rabbi trust investments	7,003		—			—		—		7,003
Derivative liability (1)	—		(20,057		)	—		—		(20,057		)
Total	$	18,216	$	(20,057	)	$	—	$	—	$	(1,841	)
December 31, 2010
Restricted Cash	$	12,297	$	—		$	—	$	—	$	12,297
Rabbi trust investments	5,495		—			—		—		5,495
Derivative asset (1)	—		1,620			—		—		1,620
Derivative liability (1)	—		(31,332		)	—		—		(31,332		)
Net derivative liability	—		(29,712		)	—		—		(29,712		)
Total	$	17,792	$	(29,712	)	$	—	$	—	$	(11,920	)

_________________________

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

Fair Value Financial Instruments [Table Text Block]

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

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt (including current portion)	$	908,826	$	1,050,621	$	1,068,358	$	1,137,148

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New Accounting Standards

9 Months Ended

Sep. 30, 2011

New Accounting Pronouncement or Change in Accounting Principle, Current Period Disclosures [Abstract]

New Accounting Pronouncements [Text Block]

New Accounting Standards

Accounting Standards Issued

In May 2011, the Financial Accounting Standards Board (FASB) issued accounting guidance related to fair value measurement, which amends current guidance to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. The amendments generally represent clarification of how the concepts of highest and best use and valuation premise in a fair value measurement are relevant only when measuring the fair value of nonfinancial assets and are not relevant when measuring the fair value of financial assets or of liabilities. In addition, the guidance expanded the disclosures for the unobservable inputs for Level 3 fair value measurements, requiring quantitative information to be disclosed related to (1) the valuation processes used, (2) the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, and (3) use of a nonfinancial asset in a way that differs from the asset’s highest and best use. This revised guidance is effective for interim and annual periods beginning after December 15, 2011 and early application is prohibited. We do not expect this pronouncement to have a material effect on our consolidated financial statements.

In June 2011, the FASB issued an accounting pronouncement that provides new guidance on the presentation of comprehensive income in financial statements. Entities are required to present total comprehensive income either in a single, continuous statement of comprehensive income or in two separate, but consecutive, statements. Under the single-statement approach, entities must include the components of net income, a total for net income, the components of other comprehensive income and a total for comprehensive income. Under the two-statement approach, entities must report an income statement and, immediately following, a statement of other comprehensive income. Under either method, entities must display adjustments for items reclassified from other comprehensive income to net income in both net income and other comprehensive income. The guidance eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The provisions of this pronouncement are effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. This guidance concerns disclosure only and will not have a material effect on our consolidated financial statements.

Accounting Standards Adopted

There have been no new accounting pronouncements or changes in accounting pronouncements adopted during the nine months ended September 30, 2011 that are of significance, or potential significance, to us.

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Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

Earnings Per Share

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

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

	Three Months Ended
	September 30, 2011	September 30, 2010
Basic computation	36,262,246	36,195,583
Dilutive effect of
Restricted stock and performance share awards (1)	248,775	116,624
Diluted computation	36,511,021	36,312,207

	Nine Months Ended
	September 30, 2011	September 30, 2010
Basic computation	36,254,159	36,181,238
Dilutive effect of
Restricted stock and performance share awards (1)	245,500	114,896
Diluted computation	36,499,659	36,296,134

_________________________

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

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Fair Value Measurements Fair Value Recurring Basis (Details) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Dec. 31, 2010 Fair Value, Measurements, Recurring [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 1 [Member]		Dec. 31, 2010 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 1 [Member]		Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member]		Dec. 31, 2010 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member]		Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 3 [Member]		Dec. 31, 2010 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 3 [Member]		Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Netting and Collateral [Member]		Dec. 31, 2010 Fair Value, Measurements, Recurring [Member] Netting and Collateral [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Level 1 to level 2 Transfers, Amount	$ 0
Fair Value, Level 2 to level 1 Transfers, Amount	0
Restricted Cash		11,213		12,297		11,213		12,297		0		0		0		0		0		0
Rabbi Trust Investments		7,003		5,495		7,003		5,495		0		0		0		0		0		0
Derivative Asset				1,620	[1]			0	[1]			1,620	[1]			0	[1]			0	[1]
Derivative Liability		(20,057)	[1]	(31,332)	[1]	0	[1]	0	[1]	(20,057)	[1]	(31,332)	[1]	0	[1]	0	[1]	0	[1]	0	[1]
Net derivative liability				(29,712)				0				(29,712)				0				0
Total		$ (1,841)		$ (11,920)		$ 18,216		$ 17,792		$ (20,057)		$ (29,712)		$ 0		$ 0		$ 0		$ 0

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

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The following table summarizes the significant components of the income tax expense:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Income Before Income Taxes	$	15,530		$	19,108		$	67,737		$	72,818
Income tax calculated at 35% Federal statutory rate	(5,435		)	(6,687		)	(23,707		)	(25,485		)
Permanent or flow through adjustments:
Flow-through repairs deductions	3,243			2,341			8,745			6,902
Flow-through of state bonus depreciation deduction	1,170			—			4,452			—
Recognition of state NOL benefit/valuation allowance release	—			—			2,402			2,178
State income tax & other, net	387			(383		)	(1,189		)	(1,625		)
	$	4,800		$	1,958		$	14,410		$	7,455
Income tax expense	$	(635	)	$	(4,729	)	$	(9,297	)	$	(18,030	)

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CONDENSED CONSOLIDATED BALANCE SHEET (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 5,994	$ 6,234
Restricted cash	11,674	12,862
Accounts receivable, net	107,112	143,304
Inventories	72,047	50,701
Regulatory assets	44,790	59,993
Deferred income taxes	19,593	24,052
Other	7,804	5,908
Total current assets	269,014	303,054
Property, plant, and equipment, net	2,170,928	2,117,977
Goodwill	355,128	355,128
Regulatory assets	225,757	222,341
Other noncurrent assets	40,997	39,169
Total assets	3,061,824	3,037,669
Current Liabilities:
Current maturities of capital leases	1,348	1,276
Current maturities of long-term debt	3,792	6,578
Short-term borrowings	112,993	0
Accounts payable	59,117	75,042
Accrued expenses	229,427	203,900
Regulatory liabilities	19,836	17,173
Total current liabilities	426,513	303,969
Long-term capital leases	33,271	34,288
Long-term debt	905,034	1,061,780
Deferred income taxes	262,660	232,709
Noncurrent regulatory liabilities	262,890	251,133
Other noncurrent liabilities	333,247	333,443
Total liabilities	2,223,615	2,217,322
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,827,577 and 36,264,686, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	398	398
Treasury stock at cost	(90,258)	(90,427)
Paid-in capital	816,151	813,878
Retained earnings	107,494	87,984
Accumulated other comprehensive income	4,424	8,514
Total shareholders' equity	838,209	820,347
Total liabilities and shareholders' equity	$ 3,061,824	$ 3,037,669

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Financing Activities (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Line of Credit Facility [Line Items]
Line of Credit Facility, Increase, Additional Borrowings	$ 50
Line of Credit Facility, Current Borrowing Capacity	300
Line of Credit Facility, Maximum Borrowing Capacity	350
Line of Credit Facility, Interest Rate, Stated Percentage Rate Range, Minimum	0.88%
Line of Credit Facility, Interest Rate, Stated Percentage Rate Range, Maximum	1.75%
Line of Credit, Description Of Variable Rate Basis	LIBOR
Line of Credit Facility, Basis Spread on Variable Rate	1.25%
Maximum Borrowing Percentage Per Institution	17.00%
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Commercial Paper Maximum Aggregate Carrying Amount Outstanding	$ 250
Commpercial Paper Maximum Maturities in Days	270

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Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended			9 Months Ended
	Sep. 30, 2011 South Dakota Rate Case [Member]	Sep. 30, 2011 Wind Generation [Member] watts	Sep. 30, 2011 Montana Distribution System Infrastructure Project [Member]	Dec. 31, 2012 Montana Distribution System Infrastructure Project [Member]	Dec. 31, 2011 Montana Distribution System Infrastructure Project [Member]	Sep. 30, 2011 Montana Distribution System Infrastructure Project [Member] Deferred Project Costs [Member]	Sep. 30, 2011 Dave Gates Generating Station [Member]	Sep. 30, 2011 Mountain States Transmission [Member]
Request Natural Gas Distribution Revenue Increase	$ 4.1
Rate Of Return On Equity For Base Rate	10.90%
Capitalized Structure Percentage Of Equity	56.00%
Rate Base, Natural Gas Distribution	67.5
Estimated Environmental Remediation Costs	1.4
Megawatts of Capacity		40
Estimated Construction Costs		86					202
Deferred Incremental Operating And Maintenence Costs Maximum Amount			16.9
Estimated Incremental Project Costs				9.7	7.2
Deferred costs						2.3
Projected Capital Expenditures			287
Payments for Capital Improvements			8.5
Total Project Costs Incurred to Date							183
Percentage Of Revenue Based On MPSC							80.00%
Percentage Of Revenues Based On FERC							20.00%
Deferred Revenue							8.2
Comtemplated Strategic Partner, Ownership Percentage, Maximum								50.00%
Capitalized Costs Relating to Preliminary Survey And Investigation								$ 19.5