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 March 31, 2012
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

36,390,258 shares outstanding at April 20, 2012

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 — March 31, 2012 and December 31, 2011	4
	Condensed Consolidated Statements of Income and Comprehensive Income — Three Months Ended March 31, 2012 and 2011	5
	Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2012 and 2011	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	36
PART II. OTHER INFORMATION		37
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 4.	Mine Safety Disclosures	41
Item 5.	Other Information	41
Item 6.	Exhibits	42
SIGNATURES		43

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 effect on our liquidity, results of operations and financial condition;

• we have capitalized approximately $22.3 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 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)

	March 31, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	7,792		$	5,928
Restricted cash	9,035			12,716
Accounts receivable, net	131,512			147,151
Inventories	41,676			59,532
Regulatory assets	40,925			48,900
Deferred income taxes	24,619			6,522
Other	8,297			9,450
Total current assets	263,856			290,199
Property, plant, and equipment, net	2,230,788			2,213,267
Goodwill	355,128			355,128
Regulatory assets	321,448			308,804
Other noncurrent assets	46,151			43,040
Total assets	$	3,217,371		$	3,210,438
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,538		$	1,370
Current maturities of long-term debt	—			3,792
Short-term borrowings	112,978			166,934
Accounts payable	52,396			76,735
Accrued expenses	215,935			193,939
Regulatory liabilities	32,390			33,184
Total current liabilities	415,237			475,954
Long-term capital leases	32,784			32,918
Long-term debt	905,055			905,049
Deferred income taxes	320,698			282,406
Noncurrent regulatory liabilities	270,594			265,987
Other noncurrent liabilities	393,301			389,012
Total liabilities	2,337,669			2,351,326
Commitments and Contingencies (Note 12)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,967,749 and 36,385,268 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	399			398
Treasury stock at cost	(90,198		)	(90,273		)
Paid-in capital	818,554			816,700
Retained earnings	147,316			128,631
Accumulated other comprehensive income	3,631			3,656
Total shareholders' equity	879,702			859,112
Total liabilities and shareholders' equity	$	3,217,371		$	3,210,438

See Notes to Condensed Consolidated Financial Statements

4

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended March 31,
	2012			2011
Revenues
Electric	$	207,055		$	208,622
Gas	101,746			129,212
Other	299			426
Total Revenues	309,100			338,260
Operating Expenses
Cost of sales	138,396			162,071
Operating, general and administrative	65,573			67,383
Property and other taxes	23,665			25,396
Depreciation	26,433			25,315
Total Operating Expenses	254,067			280,165
Operating Income	55,033			58,095
Interest Expense, net	(15,962		)	(17,147		)
Other Income	984			805
Income Before Income Taxes	40,055			41,753
Income Tax Expense	(8,012		)	(9,178		)
Net Income	32,043			32,575
Other comprehensive (loss) income, net of tax:
Reclassification of net gains on derivative instruments	(183		)	(297		)
Postretirement medical liability adjustment	205			—
Foreign currency translation	(47		)	51
Total Other Comprehensive Loss	(25		)	(246		)
Comprehensive Income	$	32,018		$	32,329
Average Common Shares Outstanding	36,328			36,242
Basic Earnings per Average Common Share	$	0.88		$	0.90
Diluted Earnings per Average Common Share	$	0.88		$	0.89
Dividends Declared per Average Common Share	$	0.37		$	0.36

See Notes to Condensed Consolidated Financial Statements

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NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Three Months Ended March 31,
	2012			2011
OPERATING ACTIVITIES:
Net Income	$	32,043		$	32,575
Items not affecting cash:
Depreciation	26,433			25,315
Amortization of debt issue costs, discount and deferred hedge gain	90			398
Amortization of restricted stock	1,075			560
Equity portion of allowance for funds used during construction	(930		)	(261		)
Gain on disposition of assets	(56		)	—
Deferred income taxes	20,195			19,596
Changes in current assets and liabilities:
Restricted cash	3,681			266
Accounts receivable	15,639			(1,421		)
Inventories	17,856			23,848
Other current assets	1,153			(2,765		)
Accounts payable	(16,099		)	(17,369		)
Accrued expenses	19,812			26,490
Regulatory assets	6,718			6,123
Regulatory liabilities	(794		)	6,014
Other noncurrent assets	(13,717		)	(2,751		)
Other noncurrent liabilities	6,826			5,462
Cash provided by operating activities	119,925			122,080
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(47,107		)	(37,580		)
Proceeds from sale of assets	80			—
Cash used in investing activities	(47,027		)	(37,580		)
FINANCING ACTIVITIES:
Treasury stock activity	75			55
Dividends on common stock	(13,358		)	(12,975		)
Repayments on long-term debt	(3,795		)	(3,623		)
Line of credit borrowings	—			80,000
Line of credit repayments	—			(233,000		)
(Repayments) issuances of short-term borrowings, net	(53,956		)	85,989
Cash used in financing activities	(71,034		)	(83,554		)
Increase in Cash and Cash Equivalents	1,864			946
Cash and Cash Equivalents, beginning of period	5,928			6,234
Cash and Cash Equivalents, end of period	$	7,792		$	7,180
Supplemental Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	(335		)	—
Interest	8,806			9,584
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	5,823			1,695

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 668,300 customers in Montana, South Dakota and Nebraska.

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 March 31, 2012, 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, 2011.

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 $408.6 million through 2024.

(2) New Accounting Standards

Accounting Standards Issued

There have been no new accounting pronouncements or changes in accounting pronouncements issued during the three months ended March 31, 2012 that are of significance, or potential significance, to us.

Accounting Standards Adopted

In May 2011, the Financial Accounting Standards Board (FASB) issued guidance related to fair value measurement, which

7

amends current guidance to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. 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 was effective during the first quarter of 2012. The adoption of this standard did not have a material effect on our financial statement disclosures.

In June 2011, the FASB issued 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. We adopted this standard during the first quarter of 2012 and present net income and other comprehensive income in one continuous statement. The adoption of this standard did not have a material effect on our financial statement disclosures.

(3) Income Taxes

Our effective tax rate was 20% for the three months ended March 31, 2012 as compared with 22% for the three months ended March 31, 2011. The following table summarizes the significant differences from the federal statutory rate, which resulted in reduced income tax expense (in thousands):

	Three Months Ended March 31,
	2012			2011
Income Before Income Taxes	$	40,055		$	41,753
Income tax calculated at 35% federal statutory rate	(14,019		)	(14,614		)
Permanent or flow through adjustments:
Flow-through repairs deductions	5,571			3,982
Flow-through of state bonus depreciation deduction	1,371			2,603
Recognition of state net operating loss benefit/valuation allowance release	—			847
State income tax & other, net	(935		)	(1,996		)
	$	6,007		$	5,436
Income tax expense	$	(8,012	)	$	(9,178	)

Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions and state tax benefit of 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.

Uncertain Tax Positions

We have unrecognized tax benefits of approximately $132.6 million as of March 31, 2012, including approximately $79.6 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.

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Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the three months ended March 31, 2012, we have not recognized expense for interest or penalties, and do not have any amounts accrued at March 31, 2012 and December 31, 2011, 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 three months ended March 31, 2012. Goodwill by segment is as follows for both March 31, 2012 and December 31, 2011 (in thousands):

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

(5) Comprehensive Income (Loss)

The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):

	Three Months Ended March 31, 2012
	Before-Tax Amount			Tax (Expense) Benefit			Net-of-Tax Amount
Foreign currency translation adjustment	$	(47	)	$	—		$	(47	)
Reclassification of net gains on derivative instruments to net income	(297		)	114			(183		)
Pension and postretirement medical liability adjustment	333			(128		)	205
Other comprehensive loss	$	(11	)	$	(14	)	$	(25	)

	Three Months Ended March 31, 2011
	Before-Tax Amount			Tax (Expense) Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	51		$	—	$	51
Reclassification of net gains on derivative instruments to net income	(297		)	—		(297		)
Other comprehensive loss	$	(246	)	$	—	$	(246	)

Balances by classification included within accumulated other comprehensive income (AOCI) on the Condensed Consolidated Balance Sheets are as follows (in thousands):

	March 31, 2012			December 31, 2011
Foreign currency translation	$	373		$	420
Derivative instruments designated as cash flow hedges	4,792			4,975
Pension and postretirement medical plans	(1,534		)	(1,739		)
Accumulated other comprehensive income	3,631			3,656

(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

9

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. 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 March 31, 2012 and December 31, 2011. 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	March 31, 2012		December 31, 2011
Natural gas net derivative liability	Accrued Expenses	$	19,056	$	20,312

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

	Unrealized gain recognized in Regulatory Assets
	Three Months Ended
Derivatives Subject to Regulatory Deferral	March 31, 2012		March 31, 2011
Natural gas	$	1,256	$	3,090

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 March 31, 2012, 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 March 31, 2012, the collateral posting requirements would be as follows (in thousands):

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral
Credit rating	$	7,191	$	—	$	7,191

Interest Rate Swaps Designated as Cash Flow Hedges

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

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

11

	Location of gain reclassified from AOCI to Income	Three months ended March 31, 2012 and 2011
Amount of gain reclassified from AOCI	Interest Expense	$	297

Approximately $7.8 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of March 31, 2012, 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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	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
March 31, 2012	(in thousands)
Restricted cash	$	8,645	$	—		$	—	$	—	$	8,645
Rabbi trust investments	10,017		—			—		—		10,017
Derivative liability (1)	—		(19,056		)	—		—		(19,056		)
Total	$	18,662	$	(19,056	)	$	—	$	—	$	(394	)
December 31, 2011
Restricted cash	$	12,292	$	—		$	—	$	—	$	12,292
Rabbi trust investments	8,049		—			—		—		8,049
Derivative liability (1)	—		(20,312		)	—		—		(20,312		)
Net derivative liability	—		(20,312		)	—		—		(20,312		)
Total	$	20,341	$	(20,312	)	$	—	$	—	$	29

_________________________

(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):

	March 31, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt (including current portion)	$	905,055	$	1,042,436	$	908,841	$	1,070,539

Short-term borrowings consist of commercial paper and are 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

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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. These are significant other observable inputs, or level 2 inputs, in the fair value heirarchy.

(8) Regulatory Matters

Dave Gates Generating Station at Mill Creek (DGGS)

Our regulatory filings seeking approval of rates related to DGGS are based on approximately 80% of our revenues related to the facility being subject to the jurisdiction of the Montana Public Service Commission (MPSC) and approximately 20% being subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Intervenors in both jurisdictions have been challenging our proposed allocation methodology. In March 2012, the MPSC issued a final order in review of our previously submitted required compliance filing. The MPSC found that the total project costs incurred were prudent and established final rates. As a result of the lower than estimated construction costs and impact of the flow-through of accelerated state tax depreciation, the final rates are lower than our 2011 interim rates. The amount we over collected of approximately $6.2 million will be refunded to customers over a one-year period beginning in May 2012. The MPSC's final order approves using our proposed cost allocation methodology on a temporary basis, and requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers.

Based on the MPSC's final order we recognized revenue of approximately $2.7 million during the three months ended March 31, 2012 that we had previously deferred pending outcome of the allocation uncertainty.

A FERC hearing regarding DGGS rates is scheduled for June 11, 2012 and an initial decision is scheduled to be issued on September 24, 2012. We continue to bill customers interim rates which have been effective since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC.

Through March 31, 2012, we have deferred revenue of approximately $1.9 million associated with DGGS due to lower than estimated construction costs, our current estimate of operating expenses as compared to amounts included in our interim rate requests, and uncertainty related to the FERC's ultimate treatment of our cost allocation methodology. This uncertainty could result in an inability to fully recover our costs, as well as requiring us to refund more interim revenues than our current estimate.

Wind Generation

In February 2012, the MPSC approved our application for pre-approval 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. The approval includes an authorized rate of return of 7.4%, which was computed using a 10% return on equity, a 5% estimated cost of debt and a capital structure consisting of 52% debt and 48% equity. The approval also includes a performance condition that would reduce our revenue requirement if the average production failed to meet a minimum threshold for the first three years. We do not believe this performance condition will have a significant impact. Construction has commenced and commercial operation is projected to begin by December 31, 2012. Both the energy and associated renewable energy credits would be placed into our electric supply portfolio to meet future customer loads and renewable portfolio standards obligations.

Battle Creek Filing

In March 2012, we submitted an application with the MPSC to place our majority interest in the Battle Creek Field natural gas production fields and gathering system acquired in 2010 in regulated natural gas rate base. The application reflects a joint stipulation between us and the Montana Consumer Counsel (MCC) of a 10% return on equity and a capital structure consisting of 52% debt and 48% equity. Since November 2010, the cost of service for the natural gas produced, including a return on our investment has been included in our natural gas supply tracker on an interim basis. Pending MPSC approval, the corresponding

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amounts included in the natural gas supply tracker are subject to refund and through March 31, 2012, we have deferred revenue of approximately $1.8 million based on the difference between our cost of service and current natural gas market prices.

Montana Electric and Natural Gas Tracker Filings

Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas supply procurement activities were prudent. During March 2012, the MPSC found that our natural gas supply costs through the period ended June 30, 2011 were prudently incurred. During April 2012, the MPSC found that our electric supply costs through the period ended June 30, 2011 were prudently incurred.

(9) 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
March 31, 2012	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	207,055		$	101,746		$	299		$	—	$	309,100
Cost of sales	82,979			55,417			—			—		138,396
Gross margin	124,076			46,329			299			—		170,704
Operating, general and administrative	45,357			19,288			928			—		65,573
Property and other taxes	17,538			6,124			3			—		23,665
Depreciation	21,569			4,856			8			—		26,433
Operating income (loss)	39,612			16,061			(640		)	—		55,033
Interest expense	(13,667		)	(2,067		)	(228		)	—		(15,962		)
Other income	612			345			27			—		984
Income tax expense	(3,174		)	(3,590		)	(1,248		)	—		(8,012		)
Net income (loss)	$	23,383		$	10,749		$	(2,089	)	$	—	$	32,043
Total assets	$	2,266,842		$	938,335		$	12,194		$	—	$	3,217,371
Capital expenditures	$	24,856		$	22,251		$	—		$	—	$	47,107

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Three Months Ended
March 31, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	208,622		$	129,212		$	426		$	—	$	338,260
Cost of sales	84,446			77,625			—			—		162,071
Gross margin	124,176			51,587			426			—		176,189
Operating, general and administrative	45,286			21,448			649			—		67,383
Property and other taxes	18,741			6,652			3			—		25,396
Depreciation	20,354			4,953			8			—		25,315
Operating income (loss)	39,795			18,534			(234		)	—		58,095
Interest expense	(13,527		)	(2,665		)	(955		)	—		(17,147		)
Other income	615			164			26			—		805
Income tax expense	(3,921		)	(4,570		)	(687		)	—		(9,178		)
Net income (loss)	22,962			11,463			(1,850		)	—		32,575
Total assets	$	2,123,470		$	880,688		$	12,281		$	—	$	3,016,439
Capital expenditures	$	26,094		$	11,486		$	—		$	—	$	37,580

(10) Earnings Per Share

Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing net income 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
	March 31, 2012	March 31, 2011
Basic computation	36,328,360	36,241,904
Dilutive effect of
Restricted stock and performance share awards (1)	171,933	221,966
Diluted computation	36,500,293	36,463,870

______________________

(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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(11) 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 March 31,
	2012			2011			2012			2011
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,024		$	2,782		$	123		$	126
Interest cost	5,935			6,087			285			327
Expected return on plan assets	(7,506		)	(7,535		)	(257		)	(296		)
Amortization of prior service cost	62			62			(500		)	(488		)
Recognized actuarial loss	2,105			592			184			122
Net Periodic Benefit Cost (Income)	$	3,620		$	1,988		$	(165	)	$	(209	)

(12) 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, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, 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 $28.3 million to $37.5 million, primarily for manufactured gas plants discussed below. As of March 31, 2012, we have a reserve of approximately $31.3 million, which has not been discounted. 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 effect on our consolidated financial position or ongoing operations.

Manufactured Gas Plants - Approximately $25.9 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 (DENR). Our current reserve for remediation costs at this site is approximately $11.8 million, and we estimate that approximately $9.1 million of this amount will be incurred during the next five years.

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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, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of 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 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 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 regulations require that major sources in the United States collect and report information regarding their GHG emissions. The first required annual reports for electric generating facilities were submitted to the EPA in September 2011. The first annual reports for petroleum and natural gas facilities were submitted in March 2012.

In March 2012, the EPA proposed New Source Performance Standards that would limit carbon dioxide emissions from new electric generating units (EGUs). The proposed limits would not apply to existing or reconstructed EGUs. The proposed rule was part of an agreement to settle litigation brought by states, municipalities and environmental groups. The settlement required that the standards be proposed by July 2011 and finalized by May 2012. It is not clear if the final standards will be issued by the May deadline.

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. 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 may 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

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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. EPA has not yet issued a final CCR rule; however, at least one lawsuit has been filed to require EPA to do so. We cannot predict at this time the final requirements of any CCR regulations and what impact, if any, they would have on us, but the costs of complying with any such requirements 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 a rule to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. EPA has not yet issued a final rule; however, it is under a consent decree to do so by July 2012. When a final rule is 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 in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in such 'Class I' areas.

In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS), which was formerly the proposed Maximum Achievable Control Technology standards for hazardous air pollutant emissions from new and existing electric generating units. Among other things, these MATS standards set stringent emission limits for acid gases, mercury, and other hazardous air pollutants. Facilities that are subject to the MATS must come into compliance within three years after the effective date of the rule (or by 2015) unless a one year extension is granted on a case-by-case basis. Numerous challenges to the MATS standards have been filed with the EPA and in Federal court and we cannot predict the outcome of such challenges.

On July 7, 2011, the EPA finalized the 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, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions reductions would be required beginning in 2012. The CSAPR was to become effective on January 1, 2012; however, on December 30, 2011, a Federal court ordered that CSAPR be stayed until a hearing could be held on the numerous legal challenges brought against EPA regarding the rule. A hearing was held in April 2012 and a decision on CSAPR will be issued sometime thereafter. The Federal court that stayed the CSAPR ordered that the Clean Air Interstate Rule remain in effect while the CSAPR is stayed. Regardless of the outcome of the stay hearing, 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 or may become subject to various regulations that have been issued or proposed under the Clean Air Act, as discussed below.

South Dakota. The South Dakota DENR determined that the Big Stone Plant, of which we have a 23.4% ownership, is subject to the Regional Haze 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 SO2, NOx and particulate emissions as expeditiously as practicable, but no later than five years after the EPA's approval of South Dakota's SIP. The Administrator of EPA Region 8 signed the final rule approving the SIP in March 2012. The rule will be effective 30 days following its publication in the Federal Register. 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 South Dakota Public Utilities Commission (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 finalized MATS standards, it appears that Big Stone would meet the requirements by installing the AQCS system and using mercury control technology such as activated carbon injection. Mercury emissions monitoring equipment 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 begin 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 10.0%). In April 2012, the EPA published the final rule partially approving and partially disapproving the North Dakota Regional Haze SIP. Those portions of the final rule that were partially disapproved do not impact Coyote.

Iowa. The Neal 4 generating facility, of which we have an 8.7% ownership, is installing a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system to comply with national ambient air quality standards, the CSAPR and MATS standards. These improvements are also expected to result in compliance with the regional haze provisions of the Clean Air Act. 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. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is currently controlling emissions of mercury under regulations issued by the State of Montana, which are more strict than the Federal MATS standard, and has been since January 2010. The owners do not believe additional equipment will be necessary to meet the MATS standards for mercury. Additionally, the Colstrip facility anticipates meeting the expected MATS for acid gases without additional costs. However, Colstrip may have to install additional controls to further reduce particulate matter to meet MATS using particulate matter as a surrogate for non-mercury metals. 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 March 2012, EPA issued a proposed Federal Implementation Plan for Montana to address regional haze, which is expected to be finalized in 2012. As proposed, Colstrip does not have to improve removal efficiency for pollutants that contribute to regional haze including SO2, NOx and particulate matter.The plant operator has indicated there would be no additional costs to comply with the proposed Federal Implementation Plan.

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). The parties initially agreed to submit the matter without witnesses but following simultaneous submission of briefs in February 2012 and a hearing on March 1, 2012, the arbitration panel has requested further proceedings, including witness testimony at a hearing scheduled for July 30 through August 1, 2012. Based on our current assumptions (including current discount rates), if CELP prevailed entirely, we could be required to increase our QF liability by approximately $20 million. If we prevailed entirely, we could reduce our QF liability by up to $42 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.

Other Legal Proceedings

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 668,300 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, 2011.

Significant achievements during the three months ended March 31, 2012 include:

• Received a final order from the MPSC approving total project costs and establishing final rates for DGGS;

• Received approval from the MPSC for Spion Kop wind project in Montana; and

• Submitted an application with the MPSC to place our majority interest in the Battle Creek Field natural gas production fields and gathering system acquired in 2010 in regulated natural gas rate base.

Dave Gates Generating Station at Mill Creek

Our regulatory filings seeking approval of rates related to DGGS 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. Intervenors in both jurisdictions have been challenging our proposed allocation methodology. In March 2012, the MPSC issued a final order in review of our previously submitted required compliance filing. The MPSC found that the total project costs incurred were prudent and established final rates. As a result of the lower than estimated construction costs and impact of the flow-through of accelerated state tax depreciation, the final rates are lower than our 2011 interim rates. The amount we over collected of approximately $6.2 million will be refunded to customers over a one-year period beginning in May 2012. The MPSC's final order approves using our proposed cost allocation methodology on a temporary basis, and requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers.

Based on the MPSC's final order we recognized revenue of approximately $2.7 million during the three months ended March 31, 2012 that we had previously deferred pending outcome of the allocation uncertainty. In addition, we expect DGGS related margin to increase by approximately $4.5 million for the full year of 2012 as compared to 2011 because we flowed through the state related benefit of bonus depreciation to customers during 2011.

A FERC hearing regarding DGGS rates is scheduled for June 11, 2012 and an initial decision is scheduled to be issued on September 24, 2012. We continue to bill customers interim rates which have been effective since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC.

Through March 31, 2012, we have deferred revenue of approximately $1.9 million associated with DGGS due to lower than estimated construction costs, our current estimate of operating expenses as compared to amounts included in our interim rate requests, and uncertainty related to the FERC's ultimate treatment of our cost allocation methodology. This uncertainty could result in an inability to fully recover our costs, as well as requiring us to refund more interim revenues than our current estimate.

DGGS, which began commercial operation on January 1, 2011, was shut down on January 31, 2012 after problems were discovered in the power turbines of two of the generation units. Similar problems were subsequently found in the third unit. We expect two of the three units to be returned to service by April 30, 2012 using either the original turbines after servicing by their supplier Pratt & Whitney Power Systems (PWPS) or turbines on loan from PWPS. We are coordinating with PWPS to investigate the root cause of the problem, which is expected to take several months. When the root cause of the problem is determined, the units may require modification or further service. However, in that event, we anticipate that work will be performed in a manner that will not require DGGS to be taken completely off-line. We expect the turbine repair costs will be covered under the manufacturer's warranty. We are also, however, incurring incremental costs for contracts with third parties for replacement regulation service. During the first quarter of 2012, our incremental costs for replacement regulation service totaled approximately $0.5 million. We have been actively managing our contracted service in an effort to reduce these costs as much as possible as DGGS is brought back into service. We believe the incremental contracted costs for regulation service are recoverable from customers through our normal course of business; however, there can be no assurance that the MPSC and/or FERC will allow us full recovery of such costs.

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Wind Generation

In February 2012, the MPSC approved our application for pre-approval 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. The approval includes an authorized rate of return of 7.4%, which was computed using a 10.0% return on equity, a 5.0% estimated cost of debt and a capital structure consisting of 52% debt and 48% equity. The approval also includes a performance condition that would reduce our revenue requirement if the average production failed to meet a minimum threshold for the first three years. We do not believe this performance condition will have a significant impact. Construction has commenced and commercial operation is projected to begin by December 31, 2012. Both the energy and associated renewable energy credits would be placed into our electric supply portfolio to meet future customer loads and renewable portfolio standards obligations.

Battle Creek

In March 2012, we submitted an application with the MPSC to place our majority interest in the Battle Creek Field natural gas production fields and gathering system acquired in 2010 in regulated natural gas rate base. The application reflects a joint stipulation between us and the MCC of a 10.0% return on equity and a capital structure consisting of 52% debt and 48% equity. Since November 2010, the cost of service for the natural gas produced, including a return on our investment has been included in our natural gas supply tracker on an interim basis. Pending MPSC approval, the corresponding amounts included in the natural gas supply tracker are subject to refund and through March 31, 2012, we have deferred revenue of approximately $1.8 million based on the difference between our cost of service and current natural gas market prices.

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 March 31,2012 Compared with the Three Months Ended March 31,2011

	Three Months Ended March 31,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	207.1	$	208.6	$	(1.5	)	(0.7	)%
Natural Gas	101.7		129.2		(27.5		)	(21.3	)
Other	0.3		0.4		(0.1		)	(25.0	)
	$	309.1	$	338.2	$	(29.1	)	(8.6	)%

	Three Months Ended March 31,
	2012		2011		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	83.0	$	84.4	$	(1.4	)	(1.7	)%
Natural Gas	55.4		77.6		(22.2		)	(28.6	)
	$	138.4	$	162.0	$	(23.6	)	(14.6	)%

	Three Months Ended March 31,
	2012		2011		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	124.1	$	124.2	$	(0.1	)	(0.1	)%
Natural Gas	46.3		51.6		(5.3		)	(10.3	)
Other	0.3		0.4		(0.1		)	(25.0	)
	$	170.7	$	176.2	$	(5.5	)	(3.1	)%

Primary components of the change in gross margin include the following:

	Gross Margin 2012 vs. 2011
	(in millions)
Electric and natural gas retail volumes	$	(8.2	)
Montana property tax tracker	(1.3		)
Gas production	(0.7		)
Operating expenses recovered in energy supply trackers	(0.3		)
DGGS	4.5
South Dakota natural gas rate increase	0.6
Other	(0.1		)
Decrease in Consolidated Gross Margin	$	(5.5	)

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This $5.5 million decrease in gross margin includes the following:

• A decrease in electric and natural gas retail volumes due primarily to warmer winter weather;

• A decrease in Montana property taxes included in a tracker as compared to the same period in 2011;

• A decrease in gas production margin from lower market prices; and

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

These decreases were partly offset by the following:

• Higher DGGS related revenues, including approximately $2.7 million that we had deferred in prior periods pending outcome of allocation uncertainty in Montana; and

• An increase in South Dakota natural gas rates.

	Three Months Ended March 31,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	65.6	$	67.4	$	(1.8	)	(2.7	)%
Property and other taxes	23.7		25.4		(1.7		)	(6.7	)
Depreciation	26.4		25.3		1.1			4.3
	$	115.7	$	118.1	$	(2.4	)	(2.0	)%

Consolidated operating, general and administrative expenses were $65.6 million for the three months ended March 31, 2012, as compared with $67.4 million for the three months ended March 31, 2011. Primary components of the change include the following:

	Operating, General & Administrative Expenses
	2012 vs. 2011
	(in millions)
Operating and maintenance	$	(1.8	)
Operating expenses recovered in energy supply trackers	(0.3		)
Other	0.3
Decrease in Operating, General & Administrative Expenses	$	(1.8	)

The decrease in operating, general and administrative expenses of $1.8 million was primarily due to timing related proactive line maintenance as compared to the same period in 2011. We expect these costs to be higher for the remainder of the year. Lower operating expenses primarily related to costs incurred for customer efficiency programs, which are recovered from customers through energy supply trackers and have no impact on operating income, also contributed to the decrease in operating, general and administrative expenses.

Property and other taxes was $23.7 million for the three months ended March 31, 2012, as compared with $25.4 million in the first quarter of 2011. This decrease was due primarily to lower actual 2011 property taxes than our initial estimate based on assessed property valuations and mill levy increases in Montana, offset in part by plant additions. We estimate property taxes throughout each year and update to the actual expense when we receive our Montana property tax bills in November.

Depreciation expense was $26.4 million for the three months ended March 31, 2012, as compared with $25.3 million in the first quarter of 2011. This increase was primarily due to plant additions.

Consolidated operating income for the three months ended March 31, 2012 was $55.0 million, as compared with $58.1 million in the first quarter of 2011. This decrease was primarily due to a decrease in gross margin offset in part by lower operating expenses as discussed above.

Consolidated interest expense for the three months ended March 31, 2012 was $16.0 million, as compared with $17.1

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million in the first quarter of 2011. This decrease was primarily due to lower interest rates on debt outstanding.

Consolidated other income for the three months ended March 31, 2012 was $1.0 million, as compared with $0.8 million in the first quarter of 2011. The increase was primarily due to higher capitalization of allowance for funds used during construction.

We had a consolidated income tax expense for the three months ended March 31, 2012 of $8.0 million, as compared with $9.2 million in the same period of 2011. This decrease is primarily due to lower taxable income and higher repairs deductions.

Consolidated net income for the three months ended March 31, 2012 was $32.0 million as compared with $32.6 million for the same period in 2011. This decrease was primarily due to lower operating income offset in part by lower interest expense, higher other income, and lower income tax expense as discussed above.

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ELECTRIC SEGMENT

Three Months Ended March 31,2012 Compared with the Three Months Ended March 31,2011

	Results
	2012		2011		Change			% Change
	(dollars in millions)
Retail revenue	$	192.0	$	196.2	$	(4.2	)	(2.1	)%
Transmission	11.1		10.9		0.2			1.8
Wholesale	0.9		0.3		0.6			200.0
Regulatory amortization and other	3.1		1.2		1.9			158.3
Total Revenues	207.1		208.6		(1.5		)	(0.7	)
Total Cost of Sales	83.0		84.4		(1.4		)	(1.7	)
Gross Margin	$	124.1	$	124.2	$	(0.1	)	(0.1	)%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Electric
Montana	$	72,137	$	75,663	671	731	274,164	272,526
South Dakota	12,986		13,393		160	179	48,840	48,705
Residential	85,123		89,056		831	910	323,004	321,231
Montana	75,696		77,133		794	820	62,010	61,459
South Dakota	16,916		16,309		235	238	11,954	11,789
Commercial	92,612		93,442		1,029	1,058	73,964	73,248
Industrial	9,637		9,183		730	692	73	72
Other	4,581		4,520		23	24	4,511	4,620
Total Retail Electric	$	191,953	$	196,201	2,613	2,684	401,552	399,171
Total Wholesale Electric	$	869	$	309	53	31	—	—

	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	3,039	3,490	3,319	13% warmer	8% warmer
South Dakota	3,417	4,569	4,103	25% warmer	17% warmer

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The following summarizes the components of the changes in electric gross margin for the three months ended March 31, 2012 and 2011:

	Gross Margin 2012 vs. 2011
	(in millions)
Retail volumes	$	(4.2	)
Montana property tax tracker	(0.8		)
DGGS	4.5
Operating expenses recovered in energy supply trackers	0.3
Other	0.1
Decrease in Gross Margin	$	(0.1	)

Gross margin remained relatively flat, with a decrease in retail volumes during the three months ended March 31, 2012 due primarily to warmer winter weather and a decrease in Montana property taxes included in a tracker as compared to the same period in 2011, offset by higher revenue from DGGS rates, as discussed above, and higher revenues for operating expenses recovered in energy supply trackers primarily related to customer efficiency programs.

Retail volumes decreased from warmer winter weather, which were offset in part by an increase in customers. Wholesale volumes increased from higher plant utilization in 2012. Lower plant utilization in 2011 was due to the combination of market conditions and scheduled maintenance.

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NATURAL GAS SEGMENT

Three Months Ended March 31,2012 Compared with the Three Months Ended March 31,2011

	Results
	2012		2011		Change			% Change
	(dollars in millions)
Retail revenue	$	95.6	$	121.0	$	(25.4	)	(21.0	)%
Wholesale and other	6.1		8.2		(2.1		)	(25.6	)
Total Revenues	101.7		129.2		(27.5		)	(21.3	)
Total Cost of Sales	55.4		77.6		(22.2		)	(28.6	)
Gross Margin	$	46.3	$	51.6	$	(5.3	)	(10.3	)%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Gas
Montana	$	41,839	$	51,100	4,983	5,638	159,886	159,029
South Dakota	10,363		13,306		1,256	1,599	38,098	37,712
Nebraska	9,421		11,486		1,141	1,382	36,918	36,949
Residential	61,623		75,892		7,380	8,619	234,902	233,690
Montana	21,050		26,438		2,524	2,915	22,427	22,273
South Dakota	6,653		9,302		1,051	1,332	6,001	5,954
Nebraska	5,415		8,242		829	1,287	4,639	4,636
Commercial	33,118		43,982		4,404	5,534	33,067	32,863
Industrial	443		691		54	78	277	282
Other	395		449		53	58	150	145
Total Retail Gas	$	95,579	$	121,014	11,891	14,289	268,396	266,980

	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	3,039	3,490	3,319	13% warmer	8% warmer
South Dakota	3,417	4,569	4,103	25% warmer	17% warmer
Nebraska	2,949	3,573	3,410	17% warmer	14% warmer

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The following summarizes the components of the changes in natural gas gross margin for the three months ended March 31, 2012 and 2011:

	Gross Margin 2012 vs. 2011
	(in millions)
Retail volumes	$	(4.0	)
Gas production	(0.7		)
Operating expenses recovered in energy supply trackers	(0.6		)
Montana property tax tracker	(0.5		)
South Dakota rate increase	0.6
Other	(0.1		)
Decrease in Gross Margin	$	(5.3	)

This decrease in gross margin and volumes during the three months ended March 31, 2012 was primarily due to warmer winter weather, a decrease in gas production margin from lower market prices, lower revenues for operating expenses recovered in energy supply trackers primarily related to customer efficiency programs, and a decrease in Montana property taxes included in a tracker as compared to the same period in 2011. These decreases were offset in part by an increase in South Dakota natural gas rates. 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 in 2012 resulting in lower retail revenues and cost of sales as compared with 2011, with no impact to gross margin.

LIQUIDITY AND CAPITAL RESOURCES

We issue debt securities to refinance retiring maturities, reduce short-term debt, fund construction programs and for other general corporate purposes. Short-term liquidity is provided by internal cash flows, the sale of commercial paper and use of our revolving credit facility. We utilize our short-term borrowings and / or revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. Short-term borrowings may also be used to temporarily fund utility capital requirements. As of March 31, 2012, our total net liquidity was approximately $184.8 million including $7.8 million of cash and $177.0 million of revolving credit facility availability. Revolving credit facility availability was $190.0 millionas of April 20, 2012.

The following table presents additional information about short term borrowings during the three months ended March 31, 2012 (in millions):

Amount outstanding	$	113.0
Daily average amount outstanding	$	126.5
Maximum amount outstanding	$	166.9

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 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.

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As of March 31, 2012, we are under collected on our current Montana natural gas and electric trackers by approximately $4.9 million, as compared with an under collection of $14.7 million as of December 31, 2011, and an under collection of $2.7 million as of March 31, 2011.

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.

Credit Ratings

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. 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. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of April 20, 2012, our current ratings with these agencies are as follows:

	Senior Secured Rating	Senior Unsecured Rating	Commercial Paper	Outlook
Fitch	A-	BBB+	F2	Positive
Moody’s	A2	Baa1	Prime-2	Stable
S&P	A-	BBB	A-2	Stable

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):

	Three Months Ended March 31,
	2012			2011
Operating Activities
Net income	$	32.0		$	32.6
Non-cash adjustments to net income	46.8			45.6
Changes in working capital	48.0			41.2
Other	(6.9		)	2.7
	119.9			122.1
Investing Activities
Property, plant and equipment additions	(47.1		)	(37.6		)
Other	0.1			—
	(47.0		)	(37.6		)
Financing Activities
Net repayment of debt	(57.7		)	(70.6		)
Dividends on common stock	(13.4		)	(13.0		)
Other	0.1			0.1
	(71.0		)	(83.5		)
Net Increase in Cash and Cash Equivalents	$	1.9		$	1.0
Cash and Cash Equivalents, beginning of period	$	5.9		$	6.2
Cash and Cash Equivalents, end of period	$	7.8		$	7.2

Cash Provided by Operating Activities

As of March 31, 2012, cash and cash equivalents were $7.8 million as compared with $5.9 million at December 31, 2011 and $7.2 million at March 31, 2011. Cash provided by operating activities totaled $119.9 million for the three months ended March 31, 2012 as compared with $122.1 million during the three months ended March 31, 2011. This decrease in operating cash flows is primarily due to timing of contributions to our qualified pension plans compared with the same period in 2011 and increased expenditures related to the DSIP implementation offset in part by improvements in the collection of our supply costs.

Cash Used in Investing Activities

Cash used in investing activities increased by approximately $9.4 million as compared with the first three months of 2011. Plant additions during the first quarter of 2012 include supply related capital expenditures of approximately $17.6 million, primarily related to the 60 MW peaking facility in South Dakota, and DSIP capital expenditures of approximately $2.9 million.

Cash Used in Financing Activities

Cash used in financing activities totaled approximately $71.0 million during the three months ended March 31, 2012 as compared with approximately $83.5 million during the three months ended March 31, 2011. During the three months ended March 31, 2012, net cash used in financing activities consisted of net repayments of commercial paper of $54.0 million, the repayment of long-term debt of $3.8 million and the payment of dividends of $13.4 million. During the three months ended March 31, 2011, net cash used in financing activities consisted of net revolving credit facility repayments of $153.0 million, net issuance of commercial paper of $86.0 million, the repayment of long-term debt of $3.6 million and the payment of dividends of $13.0 million.

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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, and to repay debt. We believe our cash flows from operations and existing borrowing capacity should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures (excluding strategic growth opportunities). 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. In addition, a material change in operations or available financing could impact our current liquidity and ability to fund capital resource requirements, and we may defer a portion of our planned capital expenditures as necessary.

We anticipate the need for equity financing as we proceed further with supply, transmission or a combination of other strategic growth investment opportunities. To fund our strategic growth opportunities we intend to utilize available cash flow, debt capacity that would allow us to maintain investment grade ratings, and based on current plans, issue equity financing of up to $100 million over the next three years. We plan to maintain a 50 - 55% debt to total capital ratio excluding capital leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70% of net income; however, there can be no assurance that we will be able to meet these targets.

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Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of March 31, 2012. See our Annual Report on Form 10-K for the year ended December 31, 2011 for additional discussion.

	Total		2012		2013		2014		2015		2016		Thereafter
	(in thousands)
Long-term debt	$	905,055	$	—	$	—	$	—	$	—	$	150,000	$	755,055
Capital leases	34,322		1,147		1,613		1,667		1,732		1,837		26,326
Short-term borrowings	112,978		112,978		—		—		—		—		—
Future minimum operating lease payments	3,630		1,487		1,113		540		199		77		214
Estimated pension and other postretirement obligations (1)	65,398		8,598		15,400		13,800		13,800		13,800		N/A
Qualifying facilities liability (2)	1,252,167		50,595		69,816		72,354		74,135		75,945		909,322
Supply and capacity contracts (3)	1,717,442		208,800		261,378		191,418		117,537		118,340		819,969
Contractual interest payments on debt (4)	514,563		42,459		51,073		51,073		51,073		50,819		268,066
Total Commitments (5)	$	4,605,555	$	426,064	$	400,393	$	330,852	$	258,476	$	410,818	$	2,778,952

_________________________

(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) Certain QFs require us to purchase minimum amounts of energy at prices ranging from $78 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these 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 20 years.

(4) We have assumed a weighted average interest rate of 0.45% 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 March 31, 2012, 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, 2011. 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 DISCLOSURES 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 March 31, 2012, 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. We monitor closely the status of our counterparties and 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.

During the quarter ended March 31, 2012, we implemented new income tax software to gain more utility specific functionality. The system changes are not being made in response to any material weakness in our internal controls. This software is specialized to the utility industry and provides us a more integrated process of reconciling our temporary and permanent tax differences to our financial statements. This implementation has resulted in certain changes to business processes and internal controls impacting financial reporting. We have taken steps to monitor and maintain appropriate internal control over financial reporting during this period of system change and will continue to evaluate the operating effectiveness of related controls during subsequent periods.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 12, 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 uncertainty related to the FERC's ultimate treatment of our cost allocation methodology, 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 Western Electricity Coordination Council 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 operating and financial results.

In addition, 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 not qualifying for the exemption will pass along the increased cost and margin requirements through higher prices and reductions in unsecured credit limits.

We are subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and additional 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; however, possible future developments, such as more stringent environmental laws and regulations, and the timing of future enforcement proceedings that may be taken by environmental authorities could affect our costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures.

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

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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 costs exceed our estimated environmental liabilities and/or we are not successful 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, new electric generation or natural gas reserves, 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 and natural gas 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 March 31, 2012, we have capitalized approximately $22.3 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 MSTI 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.

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 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

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from customers.

Our business could be adversely affected by union disputes and strikes or work stoppages by our bargaining unit employees.

Union contracts covering approximately 400 of our Montana employees expire at various dates throughout 2012, with the largest union contract, representing approximately 340 employees, expiring on April 30, 2012. We have been negotiating with this union and they are currently voting on our latest proposal. We expect to be notified of the voting results by April 30, 2012 and cannot predict the outcome of the vote. If our proposal is rejected, a strike or work stoppage could occur, which could adversely affect our results of operations.

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. For example, DGGS, which began commercial operation on January 1, 2011, was shut down on January 31, 2012 after problems were discovered in the power turbines of two of the generation units. Similar problems were subsequently found in the third unit. We have incurred incremental costs for contracts with third parties for replacement regulation service. To the extent that the repair costs are not covered by the manufacturer's warranty or the incremental contract costs are not fully recoverable from customers, our results of operations and financial position could be adversely affected.

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 some 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 fluctuates with regional demand, fuel prices and weather related conditions.

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.

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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.

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.

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.

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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.

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 includes 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.

Threats of terrorism and catastrophic events that could result from terrorism, cyber attacks, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may impact our operations

in unpredictable ways and could adversely affect our liquidity and results of operations.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, information technology systems and other infrastructure facilities and systems could be direct targets of, or indirectly affected by, such activities.

Terrorist acts or other similar events could harm our business by limiting our ability to generate, purchase or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure assets, and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. These events could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable

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ITEM 5.           OTHER INFORMATION

In June 2011, the FASB issued 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. We adopted this standard as of January 1, 2012 and present net income and other comprehensive income in one continuous statement. The table below reflects the retrospective application of this guidance for each of the three years ended December 31. The retrospective application did not have a material impact on our financial condition or results of operations.

	December 31,
	2011			2010			2009
Net Income	$	92,556		$	77,376		$	73,420
Other comprehensive income (loss), net of tax:
Reclassification of net gains on derivative instruments to net income, net of taxes of $458 for 2011	(4,302		)	(1,188		)	(1,188		)
Pension and postretirement medical liability adjustment, net of taxes of $155, $75 and $1,088, respectively	(581		)	(134		)	(1,737		)
Foreign currency translation adjustment	25			111			296
Total other comprehensive loss	(4,858		)	(1,211		)	(2,629		)
Comprehensive Income	$	87,698		$	76,165		$	70,791

ITEM 6.                      EXHIBITS

(a)Exhibits

Exhibit 10.1—Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated February 21, 2012, Commission File No. 1-10499).

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

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SIGNATURES

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

			NorthWestern Corporation
Date:	April 25, 2012	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

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EXHIBIT INDEX

Exhibit Number	Description
10.1	Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated February 21, 2012, Commission File No. 1-10499).
*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

44

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.

April 25, 2012

/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.

April 25, 2012

/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 March 31, 2012, 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.

April 25, 2012	/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 March 31, 2012, 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.

April 25, 2012	/s/ BRIAN B. BIRD
	Brian B. Bird
	Vice President, Chief Financial Officer and Treasurer

XML

Commitments and Contingencies Environmental (Details) (USD $) In Millions, unless otherwise specified							3 Months Ended
	Mar. 31, 2012	Mar. 31, 2012 Manufactured Gas Plants [Member]	Mar. 31, 2012 Manufactured Gas Plants [Member] Aberdeen South Dakota Site [Member]	Mar. 31, 2012 Clean Air Act Rules and Associated Emission Control Equipment Expenditures [Member] Big Stone Generating Facility [Member] Jointly Owned Electricity Generation Plant [Member]	Feb. 23, 2010 Clean Air Act Rules and Associated Emission Control Equipment Expenditures [Member] Coyote Generating Facility [Member]	Mar. 31, 2012 Clean Air Act Rules and Associated Emission Control Equipment Expenditures [Member] Coyote Generating Facility [Member] Jointly Owned Electricity Generation Plant [Member]	Mar. 31, 2012 Clean Air Act Rules and Associated Emission Control Equipment Expenditures [Member] Neal 4 Generating Facility [Member] Jointly Owned Electricity Generation Plant [Member]	Mar. 31, 2012 Clean Air Act Rules and Associated Emission Control Equipment Expenditures [Member] Colstrip Unit 4 [Member] Jointly Owned Electricity Generation Plant [Member]
Environmental remediation obligation, minimum	$ 28.3
Environmental remediation obligation, maximum	37.5
Accrual for environmental loss contingencies	31.3	25.9	11.8
Environmental remediation obligation next 5 years			9.1
Jointly owned utility plant ownership percentage				23.40%		10.00%	8.70%	30.00%
NOx emissions per million Btu as calculated on a 12-month rolling basis					0.5
Estimated capital expenditures for environmental obligations				$ 490.0		$ 6.0	$ 270.0
Site contingency, time frame of disbursements							scheduled to commence in 2011 and be spread over the next three years.

XML

Fair Value Measurements Fair Value Recurring Basis (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2012 Fair Value, Measurements, Recurring [Member] Total Net Fair Value [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Total Net Fair Value [Member]		Mar. 31, 2012 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member]		Mar. 31, 2012 Fair Value, Measurements, Recurring [Member] Significant Other Observable Inputs(Level 2) [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Significant Other Observable Inputs(Level 2) [Member]		Mar. 31, 2012 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs(Level 3) [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs(Level 3) [Member]		Mar. 31, 2012 Fair Value, Measurements, Recurring [Member] Margin Cash Collateral Offset [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Margin Cash Collateral Offset [Member]
Fair Value, Assets and Liabilities Measured on Recurring 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		8,645,000		12,292,000		8,645,000		12,292,000		0		0		0		0		0		0
Rabbi trust investments		10,017,000		8,049,000		10,017,000		8,049,000		0		0		0		0		0		0
Derivative liability (1)		(19,056,000)	[1]	(20,312,000)	[1]	0	[1]	0	[1]	(19,056,000)	[1]	(20,312,000)	[1]	0	[1]	0	[1]	0	[1]	0	[1]
Net derivative liability				(20,312,000)				0				(20,312,000)				0				0
Total		$ (394,000)		$ 29,000		$ 18,662,000		$ 20,341,000		$ (19,056,000)		$ (20,312,000)		$ 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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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2012

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
	March 31, 2012	March 31, 2011
Basic computation	36,328,360	36,241,904
Dilutive effect of
Restricted stock and performance share awards (1)	171,933	221,966
Diluted computation	36,500,293	36,463,870

______________________

(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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Earnings Per Share (Details)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Basic computation	36,328,360	36,241,904
Restricted stock and performance share awards (1)	171,933	221,966
Diluted computation	36,500,293	36,463,870

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Goodwill

3 Months Ended

Mar. 31, 2012

Goodwill [Abstract]

Goodwill Disclosure [Text Block]

Goodwill

There were no changes in our goodwill during the three months ended March 31, 2012. Goodwill by segment is as follows for both March 31, 2012 and December 31, 2011 (in thousands):

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

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Income Taxes Tax Reconciliation (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Income Tax Disclosure [Abstract]
Income Before Income Taxes	$ 40,055	$ 41,753
Income tax calculated at 35% federal statutory rate	(14,019)	(14,614)
Permanent or flow through adjustments:
Flow-through repairs deductions	5,571	3,982
Flow-through of state bonus depreciation deduction	1,371	2,603
Recognition of state net operating loss benefit/valuation allowance release	0	847
State income tax & other, net	(935)	(1,996)
Total permanent or flow-through adjustments	6,007	5,436
Income tax expense	$ (8,012)	$ (9,178)

XML

Income Taxes (Details) (USD $)	3 Months Ended		3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Internal Revenue Service (IRS) [Member]	Mar. 31, 2011 Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Effective income tax rate			20.00%	22.00%
Federal effective income tax rate			35.00%
Unrecognized tax benefits	$ 132,600,000
Unrecognized tax benefits, income tax penalties and interest expense	0
Unrecognized tax benefits, income tax penalties and interest accrued	0	0
Unrecognized tax benefits that would impact effective tax rate	$ 79,600,000
Open tax years by major tax jurisdiction			from 2000 forward

XML

Goodwill (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Goodwill [Line Items]
Goodwill	$ 355,128,000	$ 355,128,000
Change in goodwill	0
Electric [Member]
Goodwill [Line Items]
Goodwill	241,100,000	241,100,000
Natural gas [Member]
Goodwill [Line Items]
Goodwill	$ 114,028,000	$ 114,028,000

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Comprehensive Income (Loss) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Other Comprehensive Income (Loss), before Tax [Abstract]
Foreign currency translation adjustment	$ (47)	$ 51
Reclassification of net gains on derivative instruments to net income	(297)	(297)
Pension and postretirement medical liability adjustment	333
Other comprehensive loss	(11)	(246)
Other Comprehensive Income (Loss), Tax [Abstract]
Foreign currency translation adjustment	0	0
Reclassification of net gains on derivative instruments to net income	114	0
Pension and postretirement medical liability adjustment	(128)
Other comprehensive loss	(14)	0
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment	(47)	51
Reclassification of net gains on derivative instruments to net income	(183)	(297)
Pension and postretirement medical liability adjustment	205	0
Total Other Comprehensive Loss	(25)	(246)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation	373		420
Derivative instruments designated as cash flow hedges	4,792		4,975
Pension and postretirement medical plans	(1,534)		(1,739)
Accumulated other comprehensive income	$ 3,631		$ 3,656

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Income Taxes

3 Months Ended

Mar. 31, 2012

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

Our effective tax rate was 20% for the three months ended March 31, 2012 as compared with 22% for the three months ended March 31, 2011. The following table summarizes the significant differences from the federal statutory rate, which resulted in reduced income tax expense (in thousands):

	Three Months Ended March 31,
	2012			2011
Income Before Income Taxes	$	40,055		$	41,753
Income tax calculated at 35% federal statutory rate	(14,019		)	(14,614		)
Permanent or flow through adjustments:
Flow-through repairs deductions	5,571			3,982
Flow-through of state bonus depreciation deduction	1,371			2,603
Recognition of state net operating loss benefit/valuation allowance release	—			847
State income tax & other, net	(935		)	(1,996		)
	$	6,007		$	5,436
Income tax expense	$	(8,012	)	$	(9,178	)

Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions and state tax benefit of 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.

Uncertain Tax Positions

We have unrecognized tax benefits of approximately $132.6 million as of March 31, 2012, including approximately $79.6 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 three months ended March 31, 2012, we have not recognized expense for interest or penalties, and do not have any amounts accrued at March 31, 2012 and December 31, 2011, 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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Risk Management and Hedging Activities (Details) (USD $)					3 Months Ended					3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011	Mar. 31, 2012 Commodity Contract [Member] Forward Contracts [Member]	Mar. 31, 2012 Commodity Contract [Member] Forward Contracts [Member] Not Designated as Hedging Instrument [Member]	Mar. 31, 2011 Commodity Contract [Member] Forward Contracts [Member] Not Designated as Hedging Instrument [Member]	Mar. 31, 2012 Commodity Contract [Member] Forward Contracts [Member] Not Designated as Hedging Instrument [Member] Accrued Liabilities [Member]	Dec. 31, 2011 Commodity Contract [Member] Forward Contracts [Member] Not Designated as Hedging Instrument [Member] Accrued Liabilities [Member]	Mar. 31, 2012 Interest Rate Swap [Member]	Mar. 31, 2012 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							19,056,000	20,312,000
Natural gas derivative, unrealized gain(loss) recognized in regulatory assets					1,256,000	3,090,000
Credit rating, fair value liability				7,191,000
Credit rating, posted collateral				0
Credit rating, contingent collateral				7,191,000
Amount of gain recalssified from AOCI										297,000
Pre-tax gain on cash flow hedges remaining in AOCI	4,792,000	4,975,000							7,800,000
Pre-tax gain on cash flow hedge to be reclassified within twelve months from AOCI to interest expense									1,200,000
Interest rate swaps outstanding	$ 0		$ 0

XML

Commitments and Contingencies Legal Proceedings (Details) (Colstrip Energy Limited Partnership (CELP) [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Loss Contingencies [Line Items]
Loss contingency allegation	$ 23
Increase [Member]
Loss Contingencies [Line Items]
Estimated litigation settlement	20
Decrease [Member]
Loss Contingencies [Line Items]
Estimated litigation settlement	$ 42

XML

CONDENSED CONSOLIDATED BALANCE SHEET (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Current Assets:
Cash and cash equivalents	$ 7,792	$ 5,928
Restricted cash	9,035	12,716
Accounts receivable, net	131,512	147,151
Inventories	41,676	59,532
Regulatory assets	40,925	48,900
Deferred income taxes	24,619	6,522
Other	8,297	9,450
Total current assets	263,856	290,199
Property, plant, and equipment, net	2,230,788	2,213,267
Goodwill	355,128	355,128
Regulatory assets	321,448	308,804
Other noncurrent assets	46,151	43,040
Total assets	3,217,371	3,210,438
Current Liabilities:
Current maturities of capital leases	1,538	1,370
Current maturities of long-term debt	0	3,792
Short-term borrowings	112,978	166,934
Accounts payable	52,396	76,735
Accrued expenses	215,935	193,939
Regulatory liabilities	32,390	33,184
Total current liabilities	415,237	475,954
Long-term capital leases	32,784	32,918
Long-term debt	905,055	905,049
Deferred income taxes	320,698	282,406
Noncurrent regulatory liabilities	270,594	265,987
Other noncurrent liabilities	393,301	389,012
Total liabilities	2,337,669	2,351,326
Commitments and Contingencies (Note 12)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,967,749 and 36,385,268 respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	399	398
Treasury stock at cost	(90,198)	(90,273)
Paid-in capital	818,554	816,700
Retained earnings	147,316	128,631
Accumulated other comprehensive income	3,631	3,656
Total shareholders' equity	879,702	859,112
Total liabilities and shareholders' equity	$ 3,217,371	$ 3,210,438

XML

Nature of Operations and Basis of Consolidation

3 Months Ended

Mar. 31, 2012

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 668,300 customers in Montana, South Dakota and Nebraska.

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 March 31, 2012, 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, 2011.

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 $408.6 million through 2024.

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Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 watts
Wind Generation [Member]
Megawatts of capacity	40
Estimated construction costs	$ 86
Authorized rate of return on equity for base rate	7.40%
Computed return on equity for base rate	10.00%
Long term debt cost percentage	5.00%
Capital structure percentage of debt	52.00%
Capitalized structure percentage of equity	48.00%
Dave Gates Generating Station [Member]
Percentage of revenue based on MPSC	80.00%
Percentage of revenues based on FERC	20.00%
Customer refund liability, current	6.2
Deferred revenue, revenue recognized	2.7
Deferred revenue	1.9
Battle Creek Field [Member]
Computed return on equity for base rate	10.00%
Capital structure percentage of debt	52.00%
Capitalized structure percentage of equity	48.00%
Customer refund liability, noncurrent	$ 1.8

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Risk Management and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2012

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	March 31, 2012		December 31, 2011
Natural gas net derivative liability	Accrued Expenses	$	19,056	$	20,312

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 recognized in Regulatory Assets
	Three Months Ended
Derivatives Subject to Regulatory Deferral	March 31, 2012		March 31, 2011
Natural gas	$	1,256	$	3,090

Schedule of Price Risk Derivatives [Table Text Block]

The following table presents, as of March 31, 2012, 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 March 31, 2012, the collateral posting requirements would be as follows (in thousands):

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral
Credit rating	$	7,191	$	—	$	7,191

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	Three months ended March 31, 2012 and 2011
Amount of gain reclassified from AOCI	Interest Expense	$	297

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
Operating revenues	$ 309,100	$ 338,260
Cost of sales	138,396	162,071
Gross margin	170,704	176,189
Operating, general, and administrative	65,573	67,383
Property and other taxes	23,665	25,396
Depreciation	26,433	25,315
Operating Income	55,033	58,095
Interest expense	(15,962)	(17,147)
Other income	984	805
Income tax expense	(8,012)	(9,178)
Net Income	32,043	32,575
Total assets	3,217,371	3,016,439	3,210,438
Capital expenditures	47,107	37,580
Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues	207,055	208,622
Cost of sales	82,979	84,446
Gross margin	124,076	124,176
Operating, general, and administrative	45,357	45,286
Property and other taxes	17,538	18,741
Depreciation	21,569	20,354
Operating Income	39,612	39,795
Interest expense	(13,667)	(13,527)
Other income	612	615
Income tax expense	(3,174)	(3,921)
Net Income	23,383	22,962
Total assets	2,266,842	2,123,470
Capital expenditures	24,856	26,094
Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues	101,746	129,212
Cost of sales	55,417	77,625
Gross margin	46,329	51,587
Operating, general, and administrative	19,288	21,448
Property and other taxes	6,124	6,652
Depreciation	4,856	4,953
Operating Income	16,061	18,534
Interest expense	(2,067)	(2,665)
Other income	345	164
Income tax expense	(3,590)	(4,570)
Net Income	10,749	11,463
Total assets	938,335	880,688
Capital expenditures	22,251	11,486
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	299	426
Cost of sales	0	0
Gross margin	299	426
Operating, general, and administrative	928	649
Property and other taxes	3	3
Depreciation	8	8
Operating Income	(640)	(234)
Interest expense	(228)	(955)
Other income	27	26
Income tax expense	(1,248)	(687)
Net Income	(2,089)	(1,850)
Total assets	12,194	12,281
Capital expenditures	0	0
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Cost of sales	0	0
Gross margin	0	0
Operating, general, and administrative	0	0
Property and other taxes	0	0
Depreciation	0	0
Operating Income	0	0
Interest expense	0	0
Other income	0	0
Income tax expense	0	0
Net Income	0	0
Total assets	0	0
Capital expenditures	$ 0	$ 0

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2012

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
March 31, 2012	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	207,055		$	101,746		$	299		$	—	$	309,100
Cost of sales	82,979			55,417			—			—		138,396
Gross margin	124,076			46,329			299			—		170,704
Operating, general and administrative	45,357			19,288			928			—		65,573
Property and other taxes	17,538			6,124			3			—		23,665
Depreciation	21,569			4,856			8			—		26,433
Operating income (loss)	39,612			16,061			(640		)	—		55,033
Interest expense	(13,667		)	(2,067		)	(228		)	—		(15,962		)
Other income	612			345			27			—		984
Income tax expense	(3,174		)	(3,590		)	(1,248		)	—		(8,012		)
Net income (loss)	$	23,383		$	10,749		$	(2,089	)	$	—	$	32,043
Total assets	$	2,266,842		$	938,335		$	12,194		$	—	$	3,217,371
Capital expenditures	$	24,856		$	22,251		$	—		$	—	$	47,107

Three Months Ended
March 31, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	208,622		$	129,212		$	426		$	—	$	338,260
Cost of sales	84,446			77,625			—			—		162,071
Gross margin	124,176			51,587			426			—		176,189
Operating, general and administrative	45,286			21,448			649			—		67,383
Property and other taxes	18,741			6,652			3			—		25,396
Depreciation	20,354			4,953			8			—		25,315
Operating income (loss)	39,795			18,534			(234		)	—		58,095
Interest expense	(13,527		)	(2,665		)	(955		)	—		(17,147		)
Other income	615			164			26			—		805
Income tax expense	(3,921		)	(4,570		)	(687		)	—		(9,178		)
Net income (loss)	22,962			11,463			(1,850		)	—		32,575
Total assets	$	2,123,470		$	880,688		$	12,281		$	—	$	3,016,439
Capital expenditures	$	26,094		$	11,486		$	—		$	—	$	37,580

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New Accounting Standards

3 Months Ended

Mar. 31, 2012

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

New Accounting Pronouncements [Text Block]

New Accounting Standards

Accounting Standards Issued

There have been no new accounting pronouncements or changes in accounting pronouncements issued during the three months ended March 31, 2012 that are of significance, or potential significance, to us.

Accounting Standards Adopted

In May 2011, the Financial Accounting Standards Board (FASB) issued 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 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 was effective during the first quarter of 2012. The adoption of this standard did not have a material effect on our financial statement disclosures.

In June 2011, the FASB issued 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. We adopted this standard during the first quarter of 2012 and present net income and other comprehensive income in one continuous statement. The adoption of this standard did not have a material effect on our financial statement disclosures.

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CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL (USD $)	Mar. 31, 2012
Common stock, par value	$ 0.01
Common stock, shares authorized	200,000,000
Common stock, shares issued	39,967,749
Common stock, shares outstanding	36,385,268
Preferred stock, par value	$ 0.01
Preferred stock, shares authorized	50,000,000
Preferred stock, shares issued	0

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2012

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, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, 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 $28.3 million to $37.5 million, primarily for manufactured gas plants discussed below. As of March 31, 2012, we have a reserve of approximately $31.3 million, which has not been discounted. 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 effect on our consolidated financial position or ongoing operations.

Manufactured Gas Plants - Approximately $25.9 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 (DENR). Our current reserve for remediation costs at this site is approximately $11.8 million, and we estimate that approximately $9.1 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, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of 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 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 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 regulations require that major sources in the United States collect and report information regarding their GHG emissions. The first required annual reports for electric generating facilities were submitted to the EPA in September 2011. The first annual reports for petroleum and natural gas facilities were submitted in March 2012.

In March 2012, the EPA proposed New Source Performance Standards that would limit carbon dioxide emissions from new electric generating units (EGUs). The proposed limits would not apply to existing or reconstructed EGUs. The proposed rule was part of an agreement to settle litigation brought by states, municipalities and environmental groups. The settlement required that the standards be proposed by July 2011 and finalized by May 2012. It is not clear if the final standards will be issued by the May deadline.

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. 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 may 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. EPA has not yet issued a final CCR rule; however, at least one lawsuit has been filed to require EPA to do so. We cannot predict at this time the final requirements of any CCR regulations and what impact, if any, they would have on us, but the costs of complying with any such requirements 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 a rule to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. EPA has not yet issued a final rule; however, it is under a consent decree to do so by July 2012. When a final rule is 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 in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in such 'Class I' areas.

In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS), which was formerly the proposed Maximum Achievable Control Technology standards for hazardous air pollutant emissions from new and existing electric generating units. Among other things, these MATS standards set stringent emission limits for acid gases, mercury, and other hazardous air pollutants. Facilities that are subject to the MATS must come into compliance within three years after the effective date of the rule (or by 2015) unless a one year extension is granted on a case-by-case basis. Numerous challenges to the MATS standards have been filed with the EPA and in Federal court and we cannot predict the outcome of such challenges.

On July 7, 2011, the EPA finalized the 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, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions reductions would be required beginning in 2012. The CSAPR was to become effective on January 1, 2012; however, on December 30, 2011, a Federal court ordered that CSAPR be stayed until a hearing could be held on the numerous legal challenges brought against EPA regarding the rule. A hearing was held in April 2012 and a decision on CSAPR will be issued sometime thereafter. The Federal court that stayed the CSAPR ordered that the Clean Air Interstate Rule remain in effect while the CSAPR is stayed. Regardless of the outcome of the stay hearing, 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 or may become subject to various regulations that have been issued or proposed under the Clean Air Act, as discussed below.

South Dakota. The South Dakota DENR determined that the Big Stone Plant, of which we have a 23.4% ownership, is subject to the Regional Haze 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 SO2, NOx and particulate emissions as expeditiously as practicable, but no later than five years after the EPA's approval of South Dakota's SIP. The Administrator of EPA Region 8 signed the final rule approving the SIP in March 2012. The rule will be effective 30 days following its publication in the Federal Register. 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 South Dakota Public Utilities Commission (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 finalized MATS standards, it appears that Big Stone would meet the requirements by installing the AQCS system and using mercury control technology such as activated carbon injection. Mercury emissions monitoring equipment 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 begin 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 10.0%). In April 2012, the EPA published the final rule partially approving and partially disapproving the North Dakota Regional Haze SIP. Those portions of the final rule that were partially disapproved do not impact Coyote.

Iowa. The Neal 4 generating facility, of which we have an 8.7% ownership, is installing a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system to comply with national ambient air quality standards, the CSAPR and MATS standards. These improvements are also expected to result in compliance with the regional haze provisions of the Clean Air Act. 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. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is currently controlling emissions of mercury under regulations issued by the State of Montana, which are more strict than the Federal MATS standard, and has been since January 2010. The owners do not believe additional equipment will be necessary to meet the MATS standards for mercury. Additionally, the Colstrip facility anticipates meeting the expected MATS for acid gases without additional costs. However, Colstrip may have to install additional controls to further reduce particulate matter to meet MATS using particulate matter as a surrogate for non-mercury metals. 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 March 2012, EPA issued a proposed Federal Implementation Plan for Montana to address regional haze, which is expected to be finalized in 2012. As proposed, Colstrip does not have to improve removal efficiency for pollutants that contribute to regional haze including SO2, NOx and particulate matter.The plant operator has indicated there would be no additional costs to comply with the proposed Federal Implementation Plan.

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). The parties initially agreed to submit the matter without witnesses but following simultaneous submission of briefs in February 2012 and a hearing on March 1, 2012, the arbitration panel has requested further proceedings, including witness testimony at a hearing scheduled for July 30 through August 1, 2012. Based on our current assumptions (including current discount rates), if CELP prevailed entirely, we could be required to increase our QF liability by approximately $20 million. If we prevailed entirely, we could reduce our QF liability by up to $42 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.

Other Legal Proceedings

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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DOCUMENT AND ENTITY INFORMATION	3 Months Ended
	Mar. 31, 2012	Apr. 20, 2012
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	Mar. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		36,390,258
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

XML

Nature of Operations and Basis of Consolidation (Policies)

3 Months Ended

Mar. 31, 2012

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 $408.6 million through 2024.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Revenues
Electric	$ 207,055	$ 208,622
Gas	101,746	129,212
Other	299	426
Total Revenues	309,100	338,260
Operating Expenses
Cost of sales	138,396	162,071
Operating, general and administrative	65,573	67,383
Property and other taxes	23,665	25,396
Depreciation	26,433	25,315
Total Operating Expenses	254,067	280,165
Operating Income	55,033	58,095
Interest Expense, net	(15,962)	(17,147)
Other Income	984	805
Income Before Income Taxes	40,055	41,753
Income Tax Expense	(8,012)	(9,178)
Net Income	32,043	32,575
Other comprehensive (loss) income, net of tax:
Reclassification of net gains on derivative instruments	(183)	(297)
Postretirement medical liability adjustment	205	0
Foreign currency translation	(47)	51
Total Other Comprehensive Loss	(25)	(246)
Comprehensive Income	$ 32,018	$ 32,329
Average Common Shares Outstanding	36,328,360	36,241,904
Basic Earnings per Average Common Share	$ 0.88	$ 0.90
Diluted Earnings per Average Common Share	$ 0.88	$ 0.89
Dividends Declared per Average Common Share	$ 0.37	$ 0.36

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

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.

	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
March 31, 2012	(in thousands)
Restricted cash	$	8,645	$	—		$	—	$	—	$	8,645
Rabbi trust investments	10,017		—			—		—		10,017
Derivative liability (1)	—		(19,056		)	—		—		(19,056		)
Total	$	18,662	$	(19,056	)	$	—	$	—	$	(394	)
December 31, 2011
Restricted cash	$	12,292	$	—		$	—	$	—	$	12,292
Rabbi trust investments	8,049		—			—		—		8,049
Derivative liability (1)	—		(20,312		)	—		—		(20,312		)
Net derivative liability	—		(20,312		)	—		—		(20,312		)
Total	$	20,341	$	(20,312	)	$	—	$	—	$	29

_________________________

(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):

	March 31, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt (including current portion)	$	905,055	$	1,042,436	$	908,841	$	1,070,539

Short-term borrowings consist of commercial paper and are 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. These are significant other observable inputs, or level 2 inputs, in the fair value heirarchy.

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Risk Management and Hedging Activities

3 Months Ended

Mar. 31, 2012

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. 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 March 31, 2012 and December 31, 2011. 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	March 31, 2012		December 31, 2011
Natural gas net derivative liability	Accrued Expenses	$	19,056	$	20,312

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

	Unrealized gain recognized in Regulatory Assets
	Three Months Ended
Derivatives Subject to Regulatory Deferral	March 31, 2012		March 31, 2011
Natural gas	$	1,256	$	3,090

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 March 31, 2012, 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 March 31, 2012, the collateral posting requirements would be as follows (in thousands):

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral
Credit rating	$	7,191	$	—	$	7,191

Interest Rate Swaps Designated as Cash Flow Hedges

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

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

	Location of gain reclassified from AOCI to Income	Three months ended March 31, 2012 and 2011
Amount of gain reclassified from AOCI	Interest Expense	$	297

Approximately $7.8 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of March 31, 2012, 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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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Disclosures [Abstract]

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

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.

	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
March 31, 2012	(in thousands)
Restricted cash	$	8,645	$	—		$	—	$	—	$	8,645
Rabbi trust investments	10,017		—			—		—		10,017
Derivative liability (1)	—		(19,056		)	—		—		(19,056		)
Total	$	18,662	$	(19,056	)	$	—	$	—	$	(394	)
December 31, 2011
Restricted cash	$	12,292	$	—		$	—	$	—	$	12,292
Rabbi trust investments	8,049		—			—		—		8,049
Derivative liability (1)	—		(20,312		)	—		—		(20,312		)
Net derivative liability	—		(20,312		)	—		—		(20,312		)
Total	$	20,341	$	(20,312	)	$	—	$	—	$	29

_________________________

(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):

	March 31, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt (including current portion)	$	905,055	$	1,042,436	$	908,841	$	1,070,539

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2012

Income Tax Disclosure [Abstract]

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

The following table summarizes the significant differences from the federal statutory rate, which resulted in reduced income tax expense (in thousands):

	Three Months Ended March 31,
	2012			2011
Income Before Income Taxes	$	40,055		$	41,753
Income tax calculated at 35% federal statutory rate	(14,019		)	(14,614		)
Permanent or flow through adjustments:
Flow-through repairs deductions	5,571			3,982
Flow-through of state bonus depreciation deduction	1,371			2,603
Recognition of state net operating loss benefit/valuation allowance release	—			847
State income tax & other, net	(935		)	(1,996		)
	$	6,007		$	5,436
Income tax expense	$	(8,012	)	$	(9,178	)

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Earnings Per Share

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

Earnings Per Share

Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing net income 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
	March 31, 2012	March 31, 2011
Basic computation	36,328,360	36,241,904
Dilutive effect of
Restricted stock and performance share awards (1)	171,933	221,966
Diluted computation	36,500,293	36,463,870

______________________

(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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Regulatory Matters

3 Months Ended

Mar. 31, 2012

Regulated Operations [Abstract]

Public Utilities Disclosure [Text Block]

Regulatory Matters

Dave Gates Generating Station at Mill Creek (DGGS)

Our regulatory filings seeking approval of rates related to DGGS are based on approximately 80% of our revenues related to the facility being subject to the jurisdiction of the Montana Public Service Commission (MPSC) and approximately 20% being subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Intervenors in both jurisdictions have been challenging our proposed allocation methodology. In March 2012, the MPSC issued a final order in review of our previously submitted required compliance filing. The MPSC found that the total project costs incurred were prudent and established final rates. As a result of the lower than estimated construction costs and impact of the flow-through of accelerated state tax depreciation, the final rates are lower than our 2011 interim rates. The amount we over collected of approximately $6.2 million will be refunded to customers over a one-year period beginning in May 2012. The MPSC's final order approves using our proposed cost allocation methodology on a temporary basis, and requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers.

Based on the MPSC's final order we recognized revenue of approximately $2.7 million during the three months ended March 31, 2012 that we had previously deferred pending outcome of the allocation uncertainty.

A FERC hearing regarding DGGS rates is scheduled for June 11, 2012 and an initial decision is scheduled to be issued on September 24, 2012. We continue to bill customers interim rates which have been effective since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC.

Through March 31, 2012, we have deferred revenue of approximately $1.9 million associated with DGGS due to lower than estimated construction costs, our current estimate of operating expenses as compared to amounts included in our interim rate requests, and uncertainty related to the FERC's ultimate treatment of our cost allocation methodology. This uncertainty could result in an inability to fully recover our costs, as well as requiring us to refund more interim revenues than our current estimate.

Wind Generation

In February 2012, the MPSC approved our application for pre-approval 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. The approval includes an authorized rate of return of 7.4%, which was computed using a 10% return on equity, a 5% estimated cost of debt and a capital structure consisting of 52% debt and 48% equity. The approval also includes a performance condition that would reduce our revenue requirement if the average production failed to meet a minimum threshold for the first three years. We do not believe this performance condition will have a significant impact. Construction has commenced and commercial operation is projected to begin by December 31, 2012. Both the energy and associated renewable energy credits would be placed into our electric supply portfolio to meet future customer loads and renewable portfolio standards obligations.

Battle Creek Filing

In March 2012, we submitted an application with the MPSC to place our majority interest in the Battle Creek Field natural gas production fields and gathering system acquired in 2010 in regulated natural gas rate base. The application reflects a joint stipulation between us and the Montana Consumer Counsel (MCC) of a 10% return on equity and a capital structure consisting of 52% debt and 48% equity. Since November 2010, the cost of service for the natural gas produced, including a return on our investment has been included in our natural gas supply tracker on an interim basis. Pending MPSC approval, the corresponding amounts included in the natural gas supply tracker are subject to refund and through March 31, 2012, we have deferred revenue of approximately $1.8 million based on the difference between our cost of service and current natural gas market prices.

Montana Electric and Natural Gas Tracker Filings

Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas supply procurement activities were prudent. During March 2012, the MPSC found that our natural gas supply costs through the period ended June 30, 2011 were prudently incurred. During April 2012, the MPSC found that our electric supply costs through the period ended June 30, 2011 were prudently incurred.

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Segment Information

3 Months Ended

Mar. 31, 2012

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
March 31, 2012	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	207,055		$	101,746		$	299		$	—	$	309,100
Cost of sales	82,979			55,417			—			—		138,396
Gross margin	124,076			46,329			299			—		170,704
Operating, general and administrative	45,357			19,288			928			—		65,573
Property and other taxes	17,538			6,124			3			—		23,665
Depreciation	21,569			4,856			8			—		26,433
Operating income (loss)	39,612			16,061			(640		)	—		55,033
Interest expense	(13,667		)	(2,067		)	(228		)	—		(15,962		)
Other income	612			345			27			—		984
Income tax expense	(3,174		)	(3,590		)	(1,248		)	—		(8,012		)
Net income (loss)	$	23,383		$	10,749		$	(2,089	)	$	—	$	32,043
Total assets	$	2,266,842		$	938,335		$	12,194		$	—	$	3,217,371
Capital expenditures	$	24,856		$	22,251		$	—		$	—	$	47,107

Three Months Ended
March 31, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	208,622		$	129,212		$	426		$	—	$	338,260
Cost of sales	84,446			77,625			—			—		162,071
Gross margin	124,176			51,587			426			—		176,189
Operating, general and administrative	45,286			21,448			649			—		67,383
Property and other taxes	18,741			6,652			3			—		25,396
Depreciation	20,354			4,953			8			—		25,315
Operating income (loss)	39,795			18,534			(234		)	—		58,095
Interest expense	(13,527		)	(2,665		)	(955		)	—		(17,147		)
Other income	615			164			26			—		805
Income tax expense	(3,921		)	(4,570		)	(687		)	—		(9,178		)
Net income (loss)	22,962			11,463			(1,850		)	—		32,575
Total assets	$	2,123,470		$	880,688		$	12,281		$	—	$	3,016,439
Capital expenditures	$	26,094		$	11,486		$	—		$	—	$	37,580

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Employee Benefit Plans

3 Months Ended

Mar. 31, 2012

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 March 31,
	2012			2011			2012			2011
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,024		$	2,782		$	123		$	126
Interest cost	5,935			6,087			285			327
Expected return on plan assets	(7,506		)	(7,535		)	(257		)	(296		)
Amortization of prior service cost	62			62			(500		)	(488		)
Recognized actuarial loss	2,105			592			184			122
Net Periodic Benefit Cost (Income)	$	3,620		$	1,988		$	(165	)	$	(209	)

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Fair Value Measurements Fair Value Finanical Insruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion), carrying value	$ 905,055	$ 908,841
Long-term debt (including current portion), fair value	$ 1,042,436	$ 1,070,539

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Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2012

Statement of Income and Comprehensive Income [Abstract]

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

The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):

	Three Months Ended March 31, 2012
	Before-Tax Amount			Tax (Expense) Benefit			Net-of-Tax Amount
Foreign currency translation adjustment	$	(47	)	$	—		$	(47	)
Reclassification of net gains on derivative instruments to net income	(297		)	114			(183		)
Pension and postretirement medical liability adjustment	333			(128		)	205
Other comprehensive loss	$	(11	)	$	(14	)	$	(25	)

	Three Months Ended March 31, 2011
	Before-Tax Amount			Tax (Expense) Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	51		$	—	$	51
Reclassification of net gains on derivative instruments to net income	(297		)	—		(297		)
Other comprehensive loss	$	(246	)	$	—	$	(246	)

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

Balances by classification included within accumulated other comprehensive income (AOCI) on the Condensed Consolidated Balance Sheets are as follows (in thousands):

	March 31, 2012			December 31, 2011
Foreign currency translation	$	373		$	420
Derivative instruments designated as cash flow hedges	4,792			4,975
Pension and postretirement medical plans	(1,534		)	(1,739		)
Accumulated other comprehensive income	3,631			3,656

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Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2012

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 March 31,
	2012			2011			2012			2011
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,024		$	2,782		$	123		$	126
Interest cost	5,935			6,087			285			327
Expected return on plan assets	(7,506		)	(7,535		)	(257		)	(296		)
Amortization of prior service cost	62			62			(500		)	(488		)
Recognized actuarial loss	2,105			592			184			122
Net Periodic Benefit Cost (Income)	$	3,620		$	1,988		$	(165	)	$	(209	)

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
OPERATING ACTIVITIES:
Net Income	$ 32,043	$ 32,575
Items not affecting cash:
Depreciation	26,433	25,315
Amortization of debt issue costs, discount and deferred hedge gain	90	398
Amortization of restricted stock	1,075	560
Equity portion of allowance for funds used during construction	(930)	(261)
Gain on disposition of assets	(56)	0
Deferred income taxes	20,195	19,596
Changes in current assets and liabilities:
Restricted cash	3,681	266
Accounts receivable	15,639	(1,421)
Inventories	17,856	23,848
Other current assets	1,153	(2,765)
Accounts payable	(16,099)	(17,369)
Accrued expenses	19,812	26,490
Regulatory assets	6,718	6,123
Regulatory liabilities	(794)	6,014
Other noncurrent assets	(13,717)	(2,751)
Other noncurrent liabilities	6,826	5,462
Cash provided by operating activities	119,925	122,080
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(47,107)	(37,580)
Proceeds from sale of assets	80	0
Cash used in investing activities	(47,027)	(37,580)
FINANCING ACTIVITIES:
Treasury stock activity	75	55
Dividends on common stock	(13,358)	(12,975)
Repayments on long-term debt	(3,795)	(3,623)
Line of credit borrowings	0	80,000
Line of credit repayments	0	(233,000)
(Repayments) issuances of short-term borrowings, net	(53,956)	85,989
Cash used in financing activities	(71,034)	(83,554)
Increase in Cash and Cash Equivalents	1,864	946
Cash and Cash Equivalents, beginning of period	5,928	6,234
Cash and Cash Equivalents, end of period	7,792	7,180
Cash (received) paid during the period for:
Income taxes	(335)	0
Interest	8,806	9,584
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	$ 5,823	$ 1,695

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Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2012

Statement of Income and Comprehensive Income [Abstract]

Comprehensive Income (Loss) Note [Text Block]

Comprehensive Income (Loss)

The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):

	Three Months Ended March 31, 2012
	Before-Tax Amount			Tax (Expense) Benefit			Net-of-Tax Amount
Foreign currency translation adjustment	$	(47	)	$	—		$	(47	)
Reclassification of net gains on derivative instruments to net income	(297		)	114			(183		)
Pension and postretirement medical liability adjustment	333			(128		)	205
Other comprehensive loss	$	(11	)	$	(14	)	$	(25	)

	Three Months Ended March 31, 2011
	Before-Tax Amount			Tax (Expense) Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	51		$	—	$	51
Reclassification of net gains on derivative instruments to net income	(297		)	—		(297		)
Other comprehensive loss	$	(246	)	$	—	$	(246	)

Balances by classification included within accumulated other comprehensive income (AOCI) on the Condensed Consolidated Balance Sheets are as follows (in thousands):

	March 31, 2012			December 31, 2011
Foreign currency translation	$	373		$	420
Derivative instruments designated as cash flow hedges	4,792			4,975
Pension and postretirement medical plans	(1,534		)	(1,739		)
Accumulated other comprehensive income	3,631			3,656

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Nature of Operations and Basis of Consolidation (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 watts customers
Number of customers	668,300
Number of megawatts of qualifying facility	35
Estimated aggregate gross contractual payments for qualifying facilities	$ 408.6

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Employee Benefit Plans Net Periodic Benefit Cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pension Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	$ 3,024	$ 2,782
Interest cost	5,935	6,087
Expected return on plan assets	(7,506)	(7,535)
Amortization of prior service cost	62	62
Recognized actuarial loss	2,105	592
Net Periodic Benefit Cost (Income)	3,620	1,988
Other Postretirement Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	123	126
Interest cost	285	327
Expected return on plan assets	(257)	(296)
Amortization of prior service cost	(500)	(488)
Recognized actuarial loss	184	122
Net Periodic Benefit Cost (Income)	$ (165)	$ (209)

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Goodwill (Tables)

3 Months Ended

Mar. 31, 2012

Goodwill [Abstract]

Schedule of Goodwill [Table Text Block]

Goodwill by segment is as follows for both March 31, 2012 and December 31, 2011 (in thousands):

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