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 June 30, 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

37,202,374 shares outstanding at July 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 — June 30, 2012 and December 31, 2011	4
	Condensed Consolidated Statements of Income and Comprehensive Income — Three and Six Months Ended June 30, 2012 and 2011	5
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 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	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	48
PART II. OTHER INFORMATION		49
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 6.	Exhibits	54
SIGNATURES		55

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 $23.5 million in preliminary survey and investigative costs related to our proposed Mountain States Transmission Intertie (MSTI) transmission project. If we abandon our efforts to pursue MSTI 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 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.

3

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	June 30, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	8,105		$	5,928
Restricted cash	7,857			12,716
Accounts receivable, net	102,931			147,151
Inventories	43,012			59,532
Regulatory assets	42,710			48,900
Deferred income taxes	18,457			6,522
Other	10,535			9,450
Total current assets	233,607			290,199
Property, plant, and equipment, net	2,266,196			2,213,267
Goodwill	355,128			355,128
Regulatory assets	320,860			308,804
Other noncurrent assets	48,298			43,040
Total assets	$	3,224,089		$	3,210,438
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,561		$	1,370
Current maturities of long-term debt	—			3,792
Short-term borrowings	129,968			166,934
Accounts payable	58,318			76,735
Accrued expenses	176,356			193,939
Regulatory liabilities	28,488			33,184
Total current liabilities	394,691			475,954
Long-term capital leases	32,395			32,918
Long-term debt	905,061			905,049
Deferred income taxes	321,408			282,406
Noncurrent regulatory liabilities	270,219			265,987
Other noncurrent liabilities	399,113			389,012
Total liabilities	2,322,887			2,351,326
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 40,660,436 and 37,081,672 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	407			398
Treasury stock at cost	(90,897		)	(90,273		)
Paid-in capital	843,021			816,700
Retained earnings	145,185			128,631
Accumulated other comprehensive income	3,486			3,656
Total shareholders' equity	901,202			859,112
Total liabilities and shareholders' equity	$	3,224,089		$	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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues
Electric	$	196,176		186,789			$	403,231		$	395,411
Gas	48,101			64,692			149,847			193,904
Other	326			325			625			751
Total Revenues	244,603			251,806			553,703			590,066
Operating Expenses
Cost of sales	96,427			110,407			234,823			272,478
Operating, general and administrative	67,096			69,539			132,669			136,922
Property and other taxes	25,934			20,550			49,599			45,946
Depreciation	26,426			25,066			52,859			50,381
Total Operating Expenses	215,883			225,562			469,950			505,727
Operating Income	28,720			26,244			83,753			84,339
Interest Expense, net	(15,893		)	(16,896		)	(31,855		)	(34,043		)
Other Income	1,176			1,106			2,160			1,911
Income Before Income Taxes	14,003			10,454			54,058			52,207
Income Tax (Expense) Benefit	(2,565		)	516			(10,577		)	(8,662		)
Net Income	$	11,438		$	10,970		$	43,481		$	43,545
Other comprehensive (loss) income, net of tax:
Reclassification of net gains on derivative instruments	(191		)	(297		)	(374		)	(594		)
Postretirement medical liability adjustment	—			—			205			—
Foreign currency translation	46			18			(1		)	69
Total Other Comprehensive Loss	(145		)	(279		)	(170		)	(525		)
Comprehensive Income	$	11,293		$	10,691		$	43,311		$	43,020
Average Common Shares Outstanding	36,635			36,258			36,482			36,250
Basic Earnings per Average Common Share	$	0.31		$	0.30		$	1.19		$	1.20
Diluted Earnings per Average Common Share	$	0.31		$	0.30		$	1.19		$	1.19
Dividends Declared per Average Common Share	$	0.37		$	0.36		$	0.74		$	0.72

See Notes to Condensed Consolidated Financial Statements

5

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2012			2011
OPERATING ACTIVITIES:
Net Income	$	43,481		$	43,545
Items not affecting cash:
Depreciation	52,859			50,381
Amortization of debt issue costs, discount and deferred hedge gain	180			798
Amortization of restricted stock	1,638			1,066
Equity portion of allowance for funds used during construction	(1,831		)	(552		)
Gain on disposition of assets	(122		)	(13		)
Deferred income taxes	27,067			25,557
Changes in current assets and liabilities:
Restricted cash	4,859			(1,159		)
Accounts receivable	44,220			36,787
Inventories	16,520			6,407
Other current assets	(1,085		)	(4,141		)
Accounts payable	(17,217		)	(18,900		)
Accrued expenses	(14,729		)	7,868
Regulatory assets	(1,026		)	9,091
Regulatory liabilities	(4,696		)	2,111
Other noncurrent assets	(13,298		)	(4,112		)
Other noncurrent liabilities	8,247			8,726
Cash provided by operating activities	145,067			163,460
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(97,812		)	(71,857		)
Proceeds from sale of assets	149			209
Cash used in investing activities	(97,663		)	(71,648		)
FINANCING ACTIVITIES:
Treasury stock activity	(624		)	125
Proceeds from issuance of common stock, net	23,876			—
Dividends on common stock	(26,927		)	(25,952		)
Repayments on long-term debt	(3,833		)	(3,626		)
Line of credit borrowings	—			80,000
Line of credit repayments	—			(233,000		)
(Repayments) issuances of short-term borrowings, net	(36,965		)	89,988
Financing costs	(754		)	(1,041		)
Cash used in financing activities	(45,227		)	(93,506		)
Increase (Decrease) in Cash and Cash Equivalents	2,177			(1,694		)
Cash and Cash Equivalents, beginning of period	5,928			6,234
Cash and Cash Equivalents, end of period	$	8,105		$	4,540
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	1,944			18
Interest	25,825			26,463
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	15,756			4,740

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 June 30, 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.

Change in Accounting Policy

We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Prior to 2012, we performed the annual impairment testing of goodwill using October 1 as the measurement date. Our annual financial and strategic planning process includes an update of our long-term cash flow projections during the first quarter, creating a difference in the timing of our long-term planning cycle as compared with our annual impairment test. These long-term cash flow projections are a key component in performing our annual impairment test of goodwill. Accordingly, effective with our 2012 annual impairment test, we have changed our goodwill impairment test date from October 1 to April 1 of each year. This change was made to better align the timing of our annual impairment testing with the timing of our annual strategic planning process. We believe this change is preferable as it allows us to more efficiently utilize the reporting units' long-term financial projections, which are generated from the annual strategic planning process, as the basis for performing our annual impairment testing. This change does not result in any delay, acceleration or avoidance of impairment, nor does this change result in adjustments to previously issued financial statements. This change was applied prospectively beginning on October 1, 2011; retrospective application to prior periods is impracticable as we are unable to objectively determine, without the use of hindsight, the assumptions that would have been used in those earlier periods.

We completed our goodwill impairment test as of April 1, 2012 and no impairment was identified. For further discussion see Note 4 - Goodwill.

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

7

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 $401.8 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 six months ended June 30, 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.

(3) Income Taxes

Our effective tax rate was 18.3% and 19.6% for the three and six months ended June 30, 2012 as compared with (4.9)% and 16.6% for the three and six months ended June 30, 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Income Before Income Taxes	$	14,003		$	10,454		$	54,058		$	52,207
Income tax calculated at 35% federal statutory rate	(4,901		)	(3,659		)	(18,920		)	(18,272		)
Permanent or flow through adjustments:
Flow-through repairs deductions	2,168			1,520			7,739			5,502
Flow-through of state bonus depreciation deduction	512			679			1,883			3,282
Recognition of state net operating loss benefit/valuation allowance release	—			1,555			—			2,402
State income tax and other, net	(344		)	421			(1,279		)	(1,576		)
	$	2,336		$	4,175		$	8,343		$	9,610
Income tax (expense) benefit	$	(2,565	)	$	516		$	(10,577	)	$	(8,662	)

8

Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through the federal and state tax benefit 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 $134.3 million as of June 30, 2012, including approximately $80.0 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 anticipate electing the safe harbor method when we file our 2011 tax return during the third quarter of 2012. We expect this election to result in a favorable adjustment to related repairs deductions and unrecognized tax benefits ranging from approximately $3.0 million to $8.0 million.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 2012, we have not recognized expense for interest or penalties, and do not have any amounts accrued at June 30, 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

We completed our annual goodwill impairment test as of April 1, 2012 and no impairments were identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.

The long-term growth rates used for our reporting units reflect increased infrastructure investment. However, even if we assumed a 10% reduction in cash flows for either reporting unit, there would be no impairment of goodwill. Additionally, due to our regulated environment, if an increase in the cost of capital occurred, the effect on the corresponding reporting unit's fair value should be ultimately offset by a similar increase in the reporting unit's regulated revenues since those rates include a component that is based on the reporting unit's cost of capital.

There were no changes in our goodwill during the six months ended June 30, 2012. Goodwill by segment is as follows for both June 30, 2012 and December 31, 2011 (in thousands):

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

9

(5) Comprehensive Income (Loss)

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

	June 30, 2012
	Three Months Ended								Six Months Ended
	Before-Tax Amount			Tax (Expense) Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax (Expense) Benefit			Net-of-Tax Amount
Foreign currency translation adjustment	$	46		$	—	$	46		$	(1	)	$	—		$	(1	)
Reclassification of net gains on derivative instruments to net income	(297		)	106		(191		)	(594		)	220			(374		)
Pension and postretirement medical liability adjustment	—			—		—			333			(128		)	205
Other comprehensive loss	$	(251	)	$	106	$	(145	)	$	(262	)	$	92		$	(170	)

	June 30, 2011
	Three Months Ended								Six Months Ended
	Before-Tax Amount			Tax (Expense) Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax (Expense) Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	18		$	—	$	18		$	69		$	—	$	69
Reclassification of net gains on derivative instruments to net income	(297		)	—		(297		)	(594		)	—		(594		)
Other comprehensive loss	$	(279	)	$	—	$	(279	)	$	(525	)	$	—	$	(525	)

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

	June 30, 2012			December 31, 2011
Foreign currency translation	$	419		$	420
Derivative instruments designated as cash flow hedges	4,601			4,975
Pension and postretirement medical plans	(1,534		)	(1,739		)
Accumulated other comprehensive income	3,486			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 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

10

portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater 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 consistent with regulatory guidelines. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

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

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to most of our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Financial Statements at June 30, 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	June 30, 2012		December 31, 2011
Natural gas net derivative liability	Accrued Expenses	$	13,097	$	20,312

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

	Unrealized gain recognized in Regulatory Assets				Unrealized gain recognized in Regulatory Assets
	Three Months Ended				Six Months Ended
Derivatives Subject to Regulatory Deferral	June 30, 2012		June 30, 2011		June 30, 2012		June 30, 2011
Natural gas	$	5,959	$	4,725	$	7,215	$	7,815

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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 June 30, 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 June 30, 2012, the collateral posting requirements would be as follows (in thousands):

Contracts with Contingent Feature	Fair Value Liability		Posted Collateral		Contingent Collateral
Credit rating	$	3,898	$	—	$	3,898

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	Six months ended June 30, 2012 and 2011
Amount of gain reclassified from AOCI	Interest Expense	$	594

Approximately $7.2 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of June 30, 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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(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.

	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
June 30, 2012	(in thousands)
Restricted cash	$	7,520	$	—		$	—	$	—	$	7,520
Rabbi trust investments	10,665		—			—		—		10,665
Derivative liability (1)	—		(13,097		)	—		—		(13,097		)
Total	$	18,185	$	(13,097	)	$	—	$	—	$	5,088
December 31, 2011
Restricted cash	$	12,292	$	—		$	—	$	—	$	12,292
Rabbi trust investments	8,049		—			—		—		8,049
Derivative liability (1)	—		(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

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components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices.

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

Financial Instruments

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

	June 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt (including current portion)	$	905,061	$	1,072,571	$	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 hierarchy.

(8) Financing Activities

In February 2012, we filed a shelf registration statement with the SEC that can be used for the issuance of debt or equity securities. In April 2012, we entered into an Equity Distribution Agreement with UBS Securities LLC (UBS) pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During the second quarter of 2012 we sold 687,285 shares of our common stock at an average price of $35.40 per share. Proceeds received were approximately $23.9 million, which are net of sales commissions paid to UBS of approximately $0.2 million and other fees.

In May 2012, we priced $90 million aggregate principal amount of Montana and South Dakota First Mortgage Bonds at a fixed interest rate of 4.15% maturing in 2042. At the same time, we also priced $60 million aggregate principal amount of Montana and South Dakota First Mortgage Bonds at a fixed interest rate of 4.30% maturing in 2052. We expect to issue the bonds in August 2012. The bonds will be secured by our electric and natural gas assets in the respective jurisdictions. The bonds will be issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds will be used to repay commercial paper borrowings and fund strategic growth investment opportunities.

(9) Regulatory Matters

Mountain States Transmission Intertie Project (MSTI)

The MSTI line is a proposed 500 kV transmission project from southwestern Montana to southeastern Idaho with a potential capacity of 1500 MWs. We reported in our annual report on Form 10-K for the year ended December 31, 2011 that there is significant market uncertainty related to the project. California is the largest potential market that could be served by

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renewable (primarily wind) generation from Montana. However, California may ultimately implement restrictions limiting the ability to use out-of-state resources to meet its renewable portfolio standards. In addition, there are other proposed competing projects to MSTI that may ultimately be able to provide more cost effective transmission to end users.

In January 2012, we signed a Memorandum of Understanding (MOU) with the Bonneville Power Administration (BPA) agreeing to explore the potential for MSTI to accommodate its needs. The MOU provides that by July 31, 2012, the parties will seek to complete economic and engineering viability studies and a capacity and cost allocation methodology that considers other partners in the line and treatment for unsubscribed capacity and cost. The outcome of these studies will provide information necessary for BPA and us to determine whether or not to consider future agreements for participation in MSTI. We are currently evaluating options with BPA and we expect BPA to notify us of its intent to participate in MSTI by September 30, 2012. The viability of some of these options is also likely dependent on our ability to obtain other customers.

We also reported in our annual report on Form 10-K for the year ended December 31, 2011 that we received a favorable Montana Supreme Court ruling on siting issues and we expected the Montana Department of Environmental Quality (MDEQ) to issue a draft environmental impact statement (EIS) by August 31, 2012, a final EIS by September 30, 2013, a Record of Decision by December 31, 2013, and a Notice to Proceed by third quarter 2014.On May 30, 2012, the Idaho Bureau of Land Management (BLM) issued a decision which ultimately led to a letter dated June 25, 2012 from the BLM acting in its role as a lead agency on MSTI permitting requiring additional MSTI route alternatives be developed and studied in detail to avoid core sage grouse habitat. This ruling is expected to delay the EIS timeline described above by a minimum of six to nine months; however, the BLM and the MDEQ have not provided us with a fully updated schedule at this time. Such a delay in the timeline would also result in increased costs and delay the anticipated construction timeline, which would impact the ability of MSTI to be available for potential market participants and provides uncertainty for market participants relying on production tax credits as a part of their development strategy. Based on these developments, if the project proceeds, we currently estimate the project could be completed in late 2018. Due to the lack of clarity around the key market participants and permitting issues noted above, we have indefinitely extended the open season process for MSTI.

Due to the uncertainty surrounding the project, certain aspects are scalable and thus can be built out to more closely match the timing and needs of new generation and loads. To avoid excessive risk for us, it is critical to reduce regulatory uncertainty before beginning construction and making large capital investments and/or commitments. We have been contemplating a strategic partner to own up to 50% of MSTI, however there can be no assurance that we will enter into such a partnership. Through June 30, 2012, we have capitalized approximately $23.5 million of preliminary survey and investigative costs associated with the MSTI transmission project. Due to the continued market uncertainty and permitting issues related to the sage grouse causing a delay in the EIS timeline, we are currently evaluating our decision to continue pursuing MSTI. If we determine an agreement with BPA is unlikely, or cannot be completed on a timely basis, we may abandon the project. If we abandon our efforts to pursue MSTI, 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.

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). 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. We are refunding the amount we over collected of approximately $6.2 million 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.

A FERC hearing regarding DGGS rates, including our proposed allocation methodology which has been challenged by intervenors, was held in June 2012 and an initial decision is scheduled to be issued in September 2012. In response to the initial decision, we and the intervening parties will have the opportunity to respond with briefs in support or opposition. Following these briefs the FERC is expected to take up the record and issue a binding decision, which we currently expect during the second quarter of 2013. 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 June 30, 2012, we have deferred revenue of approximately $2.7 million associated with DGGS due to lower than

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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. There are two power turbines per unit, and as of June 30, 2012 five of the six turbines have been returned to service through using a combination of the original turbines after servicing by their supplier Pratt & Whitney Power Systems (PWPS) and 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. Between February and April, we acquired regulation service from third parties, which resulted in incremental costs of approximately $1.4 million, as compared to fully operating DGGS. We believe the incremental contracted costs for regulation service should be 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.

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. We expect construction to be complete and the transfer of ownership to occur in October 2012. We are responsible for the construction of the required transmission infrastructure, which is nearly complete. 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.Through June 30, 2012 we have capitalized approximately $3.9 million of costs associated with this project.

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. A hearing is scheduled for September 2012. Pending MPSC approval, the corresponding amounts included in the natural gas supply tracker are subject to refund and through June 30, 2012, we have deferred revenue of approximately $2.1 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.

In May 2012, we filed our 2012 annual electric and natural gas supply tracker filings. During June, we received an order from the MPSC approving the natural gas tracker filing on an interim basis. During July, the MPSC approved the electric tracker filing on an interim basis; however, the order specifically excludes DGGS contract costs to be reviewed at a future date.

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(10) Segment Information

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

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

Three Months Ended
June 30, 2012	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	196,176		$	48,101		$	326		$	—	$	244,603
Cost of sales	78,109			18,318			—			—		96,427
Gross margin	118,067			29,783			326			—		148,176
Operating, general and administrative	47,685			18,657			754			—		67,096
Property and other taxes	19,469			6,463			2			—		25,934
Depreciation	21,565			4,853			8			—		26,426
Operating income (loss)	29,348			(190		)	(438		)	—		28,720
Interest expense	(13,409		)	(2,230		)	(254		)	—		(15,893		)
Other income	801			349			26			—		1,176
Income tax (expense) benefit	(5,910		)	1,010			2,335			—		(2,565		)
Net income (loss)	$	10,830		$	(1,061	)	$	1,669		$	—	$	11,438
Total assets	$	2,268,913		$	943,471		$	11,705		$	—	$	3,224,089
Capital expenditures	$	44,712		$	5,993		$	—		$	—	$	50,705

Three Months Ended
June 30, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	186,789		$	64,692		$	325		$	—	$	251,806
Cost of sales	76,925			33,482			—			—		110,407
Gross margin	109,864			31,210			325			—		141,399
Operating, general and administrative	49,374			19,224			941			—		69,539
Property and other taxes	15,302			5,246			2			—		20,550
Depreciation	20,386			4,671			9			—		25,066
Operating income (loss)	24,802			2,069			(627		)	—		26,244
Interest expense	(13,689		)	(2,729		)	(478		)	—		(16,896		)
Other income	724			355			27			—		1,106
Income tax (expense) benefit	(3,670		)	326			3,860			—		516
Net income	$	8,167		$	21		$	2,782		$	—	$	10,970
Total assets	$	2,116,854		$	877,235		$	12,901		$	—	$	3,006,990
Capital expenditures	$	28,756		$	5,521		$	—		$	—	$	34,277

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Six Months Ended
June 30, 2012	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	403,231		$	149,847		$	625		$	—	$	553,703
Cost of sales	161,088			73,735			—			—		234,823
Gross margin	242,143			76,112			625			—		318,880
Operating, general and administrative	93,042			37,945			1,682			—		132,669
Property and other taxes	37,007			12,587			5			—		49,599
Depreciation	43,134			9,709			16			—		52,859
Operating income (loss)	68,960			15,871			(1,078		)	—		83,753
Interest expense	(27,076		)	(4,297		)	(482		)	—		(31,855		)
Other income	1,413			694			53			—		2,160
Income tax (expense) benefit	(9,084		)	(2,580		)	1,087			—		(10,577		)
Net income (loss)	$	34,213		$	9,688		$	(420	)	$	—	$	43,481
Total assets	$	2,268,913		$	943,471		$	11,705		$	—	$	3,224,089
Capital expenditures	$	84,791		$	13,021		$	—		$	—	$	97,812

Six Months Ended
June 30, 2011	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	395,411		$	193,904		$	751		$	—	$	590,066
Cost of sales	161,371			111,107			—			—		272,478
Gross margin	234,040			82,797			751			—		317,588
Operating, general and administrative	94,660			40,672			1,590			—		136,922
Property and other taxes	34,043			11,898			5			—		45,946
Depreciation	40,740			9,624			17			—		50,381
Operating income (loss)	64,597			20,603			(861		)	—		84,339
Interest expense	(27,216		)	(5,394		)	(1,433		)	—		(34,043		)
Other income	1,339			519			53			—		1,911
Income tax (expense) benefit	(7,591		)	(4,244		)	3,173			—		(8,662		)
Net income	$	31,129		$	11,484		$	932		$	—	$	43,545
Total assets	$	2,116,854		$	877,235		$	12,901		$	—	$	3,006,990
Capital expenditures	$	54,850		$	17,007		$	—		$	—	$	71,857

(11) 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
	June 30, 2012	June 30, 2011
Basic computation	36,634,653	36,258,104
Dilutive effect of
Restricted stock and performance share awards (1)	143,913	256,901
Diluted computation	36,778,566	36,515,005

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	Six Months Ended
	June 30, 2012	June 30, 2011
Basic computation	36,481,506	36,250,049
Dilutive effect of
Restricted stock and performance share awards (1)	142,539	250,728
Diluted computation	36,624,045	36,500,777

___________________

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

(12) Employee Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,
	2012			2011			2012			2011
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,006		$	2,318		$	121		$	93
Interest cost	5,916			6,110			281			347
Expected return on plan assets	(7,490		)	(7,696		)	(256		)	(297		)
Amortization of prior service cost	61			61			(499		)	(511		)
Recognized actuarial loss	2,089			666			175			207
Net Periodic Benefit Cost (Income)	$	3,582		$	1,459		$	(178	)	$	(161	)

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Components of Net Periodic Benefit Cost (Income)
Service cost	$	6,030		$	5,100		$	244		$	219
Interest cost	11,851			12,197			566			674
Expected return on plan assets	(14,996		)	(15,231		)	(513		)	(593		)
Amortization of prior service cost	123			123			(999		)	(999		)
Recognized actuarial loss	4,194			1,258			359			329
Net Periodic Benefit Cost (Income)	$	7,202		$	3,447		$	(343	)	$	(370	)

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(13) Commitments and Contingencies

ENVIRONMENTAL LIABILITIES AND REGULATION

The operation of electric generating, transmission and distribution facilities, and gas gathering, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, 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 June 30, 2012, we have a reserve of approximately $31.1 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 $25.7 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 $11.7 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. In April of 2012, we received a letter from NDEQ regarding a recently completed Vapor Intrusion Assessment Report and an invitation to join NDEQ's Voluntary Cleanup Program (VCP). We declined NDEQ's offer to join its VCP at this time and also committed to conducting a limited soil vapor investigation. We will work independently to fully characterize the nature and extent of impacts associated with the former MGP.  After the site has been fully characterized, we will discuss the possibility of joining NDEQ's VCP. 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

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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. EPA accepted comments on the proposed standards through the end of June 2012. It is not clear when the final standards will be issued.

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. In addition, on June 26, 2012 a federal court issued a ruling affirming several of EPA's greenhouse gas rules, which had been challenged by industry petitioners and certain states.

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, litigation has commenced 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

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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 BART requirements of 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, which was effective in May 2012. 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. The equipment will need to be reevaluated for operability under the final rule.

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

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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, which was effective in May 2012. Those portions of the final rule that were partially disapproved do not impact Coyote.

Based on the finalized MATS standards, it appears that Coyote would meet the requirements by using mercury control technology such as activated carbon injection.

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 (Colstrip), 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, and anticipate meeting all other expected MATS emissions limitations required by the rule without additional costs except those costs related to increased monitoring frequency. These additional costs are not expected to be significant. While it is not expected that additional control will be necessary, if a control technology becomes necessary, it is impossible to predict the costs associated with implementing such control technology, but such costs 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 $30 million. If we prevailed entirely, we could reduce our QF liability by up to $52 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 June 30, 2012 include:

• Entered into an Equity Distribution Agreement with UBS Securities LLC. Under this agreement we sold 687,285 shares of common stock at an average price of $35.40 per share; and

• Priced $90 million of First Mortgage Bonds at 4.15% and $60 million of First Mortgage Bonds at 4.30%, which are expected to be issued in August 2012.

Strategy Update

Mountain States Transmission Intertie Project (MSTI)

The MSTI line is a proposed 500 kV transmission project from southwestern Montana to southeastern Idaho with a potential capacity of 1,500 MWs. We reported in our annual report on Form 10-K for the year ended December 31, 2011 that there is significant market uncertainty related to the project. California is the largest potential market that could be served by renewable (primarily wind) generation from Montana. However, California may ultimately implement restrictions limiting the ability to use out-of-state resources to meet its renewable portfolio standards. In addition, there are other proposed competing projects to MSTI that may ultimately be able to provide more cost effective transmission to end users.

In January 2012, we signed a Memorandum of Understanding (MOU) with the Bonneville Power Administration (BPA) agreeing to explore the potential for MSTI to accommodate its needs. The MOU provides that by July 31, 2012, the parties will seek to complete economic and engineering viability studies and a capacity and cost allocation methodology that considers other partners in the line and treatment for unsubscribed capacity and cost. The outcome of these studies will provide information necessary for BPA and us to determine whether or not to consider future agreements for participation in MSTI. We are currently evaluating options with BPA and we expect BPA to notify us of its intent to participate in MSTI by September 30, 2012. The viability of some of these options is also likely dependent on our ability to obtain other customers.

We also reported in our annual report on Form 10-K for the year ended December 31, 2011 that we received a favorable Montana Supreme Court ruling on siting issues and we expected the Montana Department of Environmental Quality (MDEQ) to issue a draft environmental impact statement (EIS) by August 31, 2012, a final EIS by September 30, 2013, a Record of Decision by December 31, 2013, and a Notice to Proceed by third quarter 2014.On May 30, 2012, the Idaho Bureau of Land Management issued a decision which ultimately led to a letter dated June 25, 2012 from the BLM acting in its role as a lead agency on MSTI permitting requiring additional MSTI route alternatives be developed and studied in detail to avoid core sage grouse habitat. This ruling is expected to delay the EIS timeline described above by a minimum of six to nine months; however, the BLM and the MDEQ have not provided us with a fully updated schedule at this time. Such a delay in the timeline would also result in increased costs and delay the anticipated construction timeline, which would impact the ability of MSTI to be available for potential market participants and provides uncertainty for market participants relying on production tax credits as a part of their development strategy. Based on these developments, if the project proceeds, we currently estimate the project would be completed in late 2018. Due to the lack of clarity around the key market participants and permitting issues noted above, we have indefinitely extended the open season process for MSTI.

Due to the uncertainty surrounding the project, certain aspects are scalable and thus can be built out to more closely match the timing and needs of new generation and loads. To avoid excessive risk for us, it is critical to reduce regulatory uncertainty before beginning construction and making large capital investments and/or commitments. We have been contemplating a strategic partner to own up to 50% of MSTI, however there can be no assurance that we will enter into such a partnership. Through June 30, 2012, we have capitalized approximately $23.5 million of preliminary survey and investigative costs associated with the MSTI transmission project. Due to the continued market uncertainty and permitting issues related to the sage grouse causing a delay in the EIS timeline, we are currently evaluating our decision to continue pursuing MSTI. If we determine an agreement with BPA is unlikely, or cannot be completed on a timely basis, we may abandon the project. If we abandon our efforts to pursue MSTI, we may have to write-off all or a portion of these costs, which could have a material

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adverse effect on our results of operations.

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). 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. We are refunding the amount we over collected of approximately $6.2 million 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.

A FERC hearing regarding DGGS rates, including our proposed allocation methodology which has been challenged by intervenors, was held in June 2012 and an initial decision is scheduled to be issued in September 2012. In response to the initial decision, we and the intervening parties will have the opportunity to respond with briefs in support or opposition. Following these briefs the FERC is expected to take up the record and issue a binding decision, which we currently expect during the second quarter of 2013. 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 June 30, 2012, we have deferred revenue of approximately $2.7 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. There are two power turbines per unit, and as of June 30, 2012 five of the six turbines have been returned to service through using a combination of the original turbines after servicing by their supplier Pratt & Whitney Power Systems (PWPS) and 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. Between February and April, we acquired regulation service from third parties, which resulted in incremental costs of approximately $1.4 million, as compared to fully operating DGGS. We believe the incremental contracted costs for regulation service should be 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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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 June 30,2012 Compared with the Three Months Ended June 30,2011

	Three Months Ended June 30,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	196.2	$	186.8	$	9.4		5.0	%
Natural Gas	48.1		64.7		(16.6		)	(25.7	)
Other	0.3		0.3		—			—
	$	244.6	$	251.8	$	(7.2	)	(2.9	)%

	Three Months Ended June 30,
	2012		2011		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	78.1	$	76.9	$	1.2		1.6	%
Natural Gas	18.3		33.5		(15.2		)	(45.4	)
	$	96.4	$	110.4	$	(14.0	)	(12.7	)%

	Three Months Ended June 30,
	2012		2011		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	118.1	$	109.9	$	8.2		7.5	%
Natural Gas	29.8		31.2		(1.4		)	(4.5	)
Other	0.3		0.3		—			—
	$	148.2	$	141.4	$	6.8		4.8	%

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

	Gross Margin 2012 vs. 2011
	(in millions)
Demand-side management (DSM) lost revenues	$	4.5
Montana property tax tracker	2.3
Transmission capacity	1.1
DGGS	0.5
South Dakota natural gas rate increase	0.4
Operating expenses recovered in trackers	0.2
Natural gas retail volumes	(2.4		)
Other	0.2
Increase in Consolidated Gross Margin	$	6.8

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This $6.8 million increase in gross margin includes the following:

• An increase in DSM lost revenues recovered through our electric supply tracker related to our DSM efficiency programs, as described further below;

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

• An increase in transmission capacity revenues due to higher demand to transmit energy for others across our lines;

• Higher DGGS related revenues due to the regulatory treatment of bonus depreciation;

• An increase in South Dakota natural gas rates due to a rate case settlement in 2011; and

• Higher revenues for operating expenses recovered in trackers, primarily related to customer efficiency programs and environmental remediation costs.

These increases were partly offset by a decrease in natural gas retail volumes due primarily to warmer spring weather reducing our customer usage for heating during the second quarter.

Demand-side Management (DSM) lost revenues - Base rates, including impacts of past DSM activities, are reset in general rate case filings. As time passes between rate cases, more energy saving measures (primarily more efficient residential and commercial lighting) are implemented, causing an increase in DSM lost revenues. During the second quarter of 2012 we recognized approximately $6.6 million of DSM lost revenues as compared with approximately $2.1 million during the second quarter of 2011. The 2012 amount includes $3.3 million in DSM lost revenues for the July 2010 through June 2011 tracker period, which we recognized as revenue when we received MPSC approval in April 2012.

Historically, the MPSC has authorized us to include a calculation of lost revenues based on actual historic DSM program activity, but prohibited the inclusion of forecasted or estimated future lost revenue. In its April 2012 order, the MPSC authorized us to include forecasted lost revenues in future tracker filings. Based on this order, we have recognized $3.3 million of the requested $5.7 million of lost revenues for the 2011/2012 tracker period. We have not recognized the entire amount as we are required to provide the MPSC with a detailed independent study supporting our requested DSM lost revenues during the fourth quarter of 2012. At this time, we cannot anticipate the results of the study. If it supports our request, we may be able to recognize an additional $2.4 million of lost revenues. Alternatively, the study could indicate that our requested amounts are too high and we may have to refund a portion of DSM lost revenues that we have recognized for the latest tracker period. We do not expect the MPSC to issue a final order related to the 2011/2012 DSM lost revenues until at least the first quarter of 2013.

	Three Months Ended June 30,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	67.1	$	69.5	$	(2.4	)	(3.5	)%
Property and other taxes	25.9		20.6		5.3			25.7
Depreciation	26.4		25.1		1.3			5.2
	$	119.4	$	115.2	$	4.2		3.6	%

29

Consolidated operating, general and administrative expenses were $67.1 million for the three months ended June 30, 2012, as compared with $69.5 million for the three months ended June 30, 2011. Primary components of the change include the following: 

	Operating, General & Administrative Expenses
	2012 vs. 2011
	(in millions)
Bad debt expense	$	(1.3	)
Operating and maintenance	(0.6		)
Plant operator costs	(0.5		)
Operating expenses recovered in trackers	0.2
Other	(0.2		)
Decrease in Operating, General & Administrative Expenses	$	(2.4	)

The decrease in operating, general and administrative expenses of $2.4 million was primarily due to lower bad debt expense based on higher collections from customers, a timing related decrease in proactive line maintenance and tree trimming as more time was spent on capital projects as compared to the same period in 2011, and lower plant operator costs at Colstrip Unit 4 offset in part by higher plant operator costs at Big Stone and Coyote due to the timing of scheduled maintenance. These decreases were partly offset by higher operating expenses primarily related to costs incurred for customer efficiency programs and environmental remediation costs, which are recovered from customers through trackers and have no impact on operating income.

Property and other taxes was $25.9 million for the three months ended June 30, 2012, as compared with $20.6 million in the second quarter of 2011. This increase was due to higher assessed property valuations in Montana and plant additions. The higher assessed property valuations are primarily due to a lower capitalization rate used by the Montana Department of Revenue. 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 June 30, 2012, as compared with $25.1 million in the second quarter of 2011. This increase was primarily due to plant additions.

Consolidated operating income for the three months ended June 30, 2012 was $28.7 million, as compared with $26.2 million in the second quarter of 2011. This increase was primarily due to an increase in gross margin offset in part by higher operating expenses as discussed above.

Consolidated interest expense for the three months ended June 30, 2012 was $15.9 million, as compared with $16.9 million in the second quarter of 2011. This decrease was primarily due to lower interest rates on debt outstanding and higher capitalization of allowance for funds used during construction.

Consolidated other income for the three months ended June 30, 2012, was $1.2 million, as compared with $1.1 million in the second quarter of 2011.

30

Consolidated income tax expense for the three months ended June 30, 2012 was $2.6 million, as compared with an income tax benefit of $0.5 million in the same period of 2011. Our effective tax rate was 18.3% for the three months ended June 30, 2012 as compared with (4.9)% for the three months ended June 30, 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 June 30,
	2012		2011
Income Before Income Taxes	14.0		10.5
Income tax calculated at 35% federal statutory rate	(4.9	)	(3.7	)
Permanent or flow through adjustments:
Flow-through repairs deductions	2.2		1.5
Flow-through of state bonus depreciation deduction	0.5		0.7
Recognition of state net operating loss benefit/valuation allowance release	—		1.6
State income tax and other, net	(0.4	)	0.4
	2.3		4.2
Income tax (expense) benefit	(2.6	)	0.5

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.

Consolidated net income for the three months ended June 30, 2012 was $11.4 million as compared with $11.0 million for the same period in 2011. This increase was primarily due to higher operating income and lower interest expense partly offset by higher income tax expense as discussed above.

31

Six Months Ended June 30,2012 Compared with the Six Months Ended June 30,2011

	Six Months Ended June 30,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	403.2	$	395.4	$	7.8		2.0	%
Natural Gas	149.9		193.9		(44.0		)	(22.7	)
Other	0.6		0.8		(0.2		)	(25.0	)
	$	553.7	$	590.1	$	(36.4	)	(6.2	)%

	Six Months Ended June 30,
	2012		2011		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	161.1	$	161.4	$	(0.3	)	(0.2	)%
Natural Gas	73.7		111.1		(37.4		)	(33.7	)
	$	234.8	$	272.5	$	(37.7	)	(13.8	)%

	Six Months Ended June 30,
	2012		2011		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	242.1	$	234.0	$	8.1		3.5	%
Natural Gas	76.2		82.8		(6.6		)	(8.0	)
Other	0.6		0.8		(0.2		)	(25.0	)
	$	318.9	$	317.6	$	1.3		0.4	%

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

	Gross Margin 2012 vs. 2011
	(in millions)
DGGS	$	5.0
DSM lost revenues	4.5
Transmission capacity	1.3
Montana property tax tracker	1.0
South Dakota natural gas rate increase	1.0
Electric and natural gas retail volumes	(10.2		)
Gas production	(0.8		)
Other	(0.5		)
Increase in Consolidated Gross Margin	$	1.3

32

This $1.3 million increase in gross margin includes 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;

• An increase in DSM lost revenues recovered through our supply tracker related to efficiency measures implemented by customers;

• An increase in transmission capacity revenues due to higher demand to transmit energy for others across our lines;

• An increase in Montana property taxes included in a tracker as compared to the same period in 2011; and

• An increase in South Dakota natural gas rates.

These increases were partly offset by the following:

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

• A decrease in Battle Creek gas production margin from lower market prices.

	Six Months Ended June 30,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	132.7	$	136.9	$	(4.2	)	(3.1	)%
Property and other taxes	49.6		45.9		3.7			8.1
Depreciation	52.9		50.4		2.5			5.0
	$	235.2	$	233.2	$	2.0		0.9	%

Consolidated operating, general and administrative expenses were $132.7 million for the six months ended June 30, 2012, as compared with $136.9 million for the six months ended June 30, 2011. Primary components of the change include the following: 

	Operating, General & Administrative Expenses
	2012 vs. 2011
	(in millions)
Operating and maintenance	$	(2.4	)
Bad debt expense	(1.2		)
Plant operator costs	(0.6		)
Decrease in Operating, General & Administrative Expenses	$	(4.2	)

The decrease in operating, general and administrative expenses was primarily due to timing related proactive line maintenance and tree trimming as more time was spent on capital projects as compared to the same period in 2011. We expect these costs to be higher for the remainder of the year. Lower bad debt expense based on higher collections from customers and warmer winter weather and lower plant operator costs at Colstrip Unit 4 offset in part by higher plant operator costs at Big Stone and Coyote due to the timing of scheduled maintenance also contributed to the decrease in operating, general and administrative expenses.

Property and other taxes was $49.6 million for the six months ended June 30, 2012, as compared with $45.9 millionin the same period of 2011. This increase was due primarily to higher assessed property valuations in Montana and plant additions.

Depreciation expense was $52.9 million for the six months ended June 30, 2012, as compared with $50.4 millionin the same period of 2011. This increase was primarily due to plant additions.

Consolidated operating income for the six months ended June 30, 2012 was $83.8 million, as compared with $84.3 millionin the same period of 2011. This decrease was primarily due to higher property tax expense and depreciation, offset in part by an increase in gross margin and a decrease in operating, general and administrative expenses as discussed above.

Consolidated interest expense for the six months ended June 30, 2012 was $31.9 million, as compared with $34.0 millionin the same period of 2011. This decrease was primarily due to lower interest rates on debt outstanding and higher

33

capitalization of AFUDC.

Consolidated other income for the six months ended June 30, 2012 was $2.2 million, as compared with $1.9 millionin the same period of 2011. The increase was primarily due to higher capitalization of AFUDC.

We had a consolidated income tax expense for the six months ended June 30, 2012 of $10.6 million, as compared with $8.7 million in the same period of 2011. Our effective tax rate was 19.6% for the six months ended June 30, 2012 as compared with 16.6% for the six months ended June 30, 2011. The following table summarizes the significant differences from the federal statutory rate, which resulted in reduced income tax expense (in thousands):

	Six Months Ended June 30,
	2012		2011
Income Before Income Taxes	54.1		52.2
Income tax calculated at 35% federal statutory rate	(18.9	)	(18.3	)
Permanent or flow through adjustments:
Flow-through repairs deductions	7.7		5.5
Flow-through of state bonus depreciation deduction	1.9		3.3
Recognition of state net operating loss benefit/valuation allowance release	—		2.4
State income tax and other, net	(1.3	)	(1.6	)
	8.3		9.6
Income tax (expense) benefit	(10.6	)	(8.7	)

We currently expect our effective tax rate to range between 16% - 18% for 2012. 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.

Consolidated net income for the six months ended June 30, 2012 remained flat at $43.5 million, with lower interest expense and higher other income offset by lower operating income and higher income tax expense as discussed above.

34

ELECTRIC SEGMENT

Three Months Ended June 30,2012 Compared with the Three Months Ended June 30,2011

	Results
	2012		2011		Change			% Change
	(dollars in millions)
Retail revenue	$	166.7	$	166.9	$	(0.2	)	(0.1	)%
Transmission	11.0		9.9		1.1			11.1
Wholesale	0.7		0.8		(0.1		)	(12.5	)
Regulatory amortization and other	17.8		9.2		8.6			93.5
Total Revenues	196.2		186.8		9.4			5.0
Total Cost of Sales	78.1		76.9		1.2			1.6
Gross Margin	$	118.1	$	109.9	$	8.2		7.5	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Electric
Montana	$	52,681	$	53,662	491	503	273,840	272,328
South Dakota	10,060		10,305		106	119	48,883	48,611
Residential	62,741		63,967		597	622	322,723	320,939
Montana	71,197		71,789		756	747	61,948	61,465
South Dakota	16,328		15,363		217	213	12,160	11,971
Commercial	87,525		87,152		973	960	74,108	73,436
Industrial	8,537		9,579		682	704	74	72
Other	7,871		6,238		51	34	5,977	5,610
Total Retail Electric	$	166,674	$	166,936	2,303	2,320	402,882	400,057
Total Wholesale Electric	$	733	$	820	43	42	—	—

	Degree Days			2012 as compared with:
Cooling Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	55	16	41	244% warmer	34% warmer
South Dakota	150	61	66	141% warmer	127% warmer

	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	1,205	1,510	1,321	20% warmer	9% warmer
South Dakota	893	1,572	1,497	43% warmer	40% warmer

35

The following summarizes the components of the changes in electric gross margin for the three months ended June 30, 2012 and 2011:

	Gross Margin 2012 vs. 2011
	(in millions)
DSM lost revenues	$	4.5
Montana property tax tracker	1.7
Transmission capacity	1.1
DGGS	0.5
Operating expenses recovered in trackers	0.5
Other	(0.1		)
Increase in Gross Margin	$	8.2

This improvement in margin was primarily due to:

• An increase in DSM lost revenues recovered through our supply tracker related to efficiency measures implemented by customers;

• An increase in Montana property taxes included in a tracker, which fluctuate depending upon volumes and estimated property tax expense;

• An increase in transmission capacity revenues due to higher demand to transmit energy for others across our lines;

• Higher revenue from DGGS rates due to the regulatory treatment of bonus depreciation; and

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

Demand for transmission capacity can fluctuate substantially from year to year based on weather and market conditions in states to the South and West. For example, increased availability of local natural gas fired generation due to low natural gas prices and increased generation in the Pacific Northwest due to favorable hydro conditions may make it more economically viable to utilize local generation rather than transmit electricity from Montana over our transmission lines. In 2012, decreased availability of local generation in the Southwest caused an increase in demand to transfer energy across our lines. The increase in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin.

While heating and cooling degree days may fluctuate significantly during the second quarter, our electric customer usage is not highly sensitive to these changes between the heating and cooling seasons.

36

Six Months Ended June 30,2012 Compared with the Six Months Ended June 30,2011

	Results
	2012		2011		Change			% Change
	(dollars in millions)
Retail revenue	$	358.6	$	363.1	$	(4.5	)	(1.2	)%
Transmission	22.1		20.8		1.3			6.3
Wholesale	1.6		1.2		0.4			33.3
Regulatory amortization and other	20.9		10.3		10.6			102.9
Total Revenues	403.2		395.4		7.8			2.0
Total Cost of Sales	161.1		161.4		(0.3		)	(0.2	)
Gross Margin	$	242.1	$	234.0	$	8.1		3.5	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Electric
Montana	$	124,818	$	129,325	1,162	1,233	274,003	272,426
South Dakota	23,046		23,698		266	298	48,861	48,658
Residential	147,864		153,023		1,428	1,531	322,864	321,084
Montana	146,893		148,922		1,549	1,567	61,980	61,462
South Dakota	33,244		31,672		453	452	12,057	11,880
Commercial	180,137		180,594		2,002	2,019	74,037	73,342
Industrial	18,174		18,762		1,411	1,396	73	72
Other	12,452		10,758		75	58	5,243	5,116
Total Retail Electric	$	358,627	$	363,137	4,916	5,004	402,217	399,614
Total Wholesale Electric	$	1,602	$	1,129	96	73	—	—

	Degree Days			2012 as compared with:
Cooling Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	55	16	41	244% warmer	34% warmer
South Dakota	150	61	66	141% warmer	127% warmer

There are no cooling degree-days in the first three months of the year in our service territories; therefore, cooling degree-days are the same for the three and six months ended June 30, 2012.

	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	4,244	5,000	4,640	15% warmer	9% warmer
South Dakota	4,310	6,141	5,600	30% warmer	23% warmer

37

The following summarizes the components of the changes in electric gross margin for the six months ended June 30, 2012 and 2011:

	Gross Margin 2012 vs. 2011
	(in millions)
DGGS	$	5.0
DSM lost revenues	4.5
Transmission capacity	1.3
Montana property tax tracker	0.9
Operating expenses recovered in trackers	0.8
Retail volumes	(4.2		)
Other	(0.2		)
Increase in Gross Margin	$	8.1

The increase in margin is primarily due to the same reasons discussed above for the three months ended June 30, 2012. In addition, DGGS revenues recognized during the first quarter of 2012 included approximately $2.7 million that we had deferred in prior periods pending outcome of allocation uncertainty in Montana. A decrease in retail volumes due primarily to warmer winter and spring weather partly offset these increases.

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.

38

NATURAL GAS SEGMENT

Three Months Ended June 30,2012 Compared with the Three Months Ended June 30,2011

	Results
	2012		2011		Change			% Change
	(dollars in millions)
Retail revenue	$	34.5	$	54.7	$	(20.2	)	(36.9	)%
Wholesale and other	13.6		10.0		3.6			36.0
Total Revenues	48.1		64.7		(16.6		)	(25.7	)
Total Cost of Sales	18.3		33.5		(15.2		)	(45.4	)
Gross Margin	$	29.8	$	31.2	$	(1.4	)	(4.5	)%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Gas
Montana	$	16,415	$	24,302	1,915	2,455	159,539	158,851
South Dakota	3,327		5,565		341	613	37,727	37,223
Nebraska	2,926		4,882		287	500	36,420	36,452
Residential	22,668		34,749		2,543	3,568	233,686	232,526
Montana	8,187		12,085		965	1,227	22,380	22,267
South Dakota	1,873		3,978		323	577	5,950	5,954
Nebraska	1,480		3,465		263	566	4,556	4,567
Commercial	11,540		19,528		1,551	2,370	32,886	32,788
Industrial	136		228		16	24	274	278
Other	178		231		24	28	150	145
Total Retail Gas	$	34,522	$	54,736	4,134	5,990	266,996	265,737

	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	1,205	1,510	1,321	20% warmer	9% warmer
South Dakota	893	1,572	1,497	43% warmer	40% warmer
Nebraska	635	1,225	1,228	48% warmer	48% warmer

39

The following summarizes the components of the changes in natural gas gross margin for the three months ended June 30, 2012 and 2011:

	Gross Margin 2012 vs. 2011
	(in millions)
Retail volumes	$	(2.4	)
Operating expenses recovered in trackers	(0.3		)
Montana property tax tracker	0.6
South Dakota rate increase	0.4
Other	0.3
Decrease in Gross Margin	$	(1.4	)

This decrease in gross margin and volumes was primarily due to reduced retail volumes driven by warmer spring weather. In addition, there were lower revenues for operating expenses recovered in trackers primarily related to customer efficiency programs and environmental remediation costs. These decreases were offset in part by an increase in Montana property taxes included in a tracker due to an increase in estimated property tax expense and an increase in South Dakota natural gas rates due to a 2011 rate case settlement. 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.

40

Six Months Ended June 30,2012 Compared with the Six Months Ended June 30,2011

	Results
	2012		2011		Change			% Change
	(dollars in millions)
Retail revenue	$	130.1	$	175.8	$	(45.7	)	(26.0	)%
Wholesale and other	19.8		18.1		1.7			9.4
Total Revenues	149.9		193.9		(44.0		)	(22.7	)
Total Cost of Sales	73.7		111.1		(37.4		)	(33.7	)
Gross Margin	$	76.2	$	82.8	$	(6.6	)	(8.0	)%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Gas
Montana	$	58,254	$	75,402	6,898	8,093	159,712	158,940
South Dakota	13,690		18,871		1,597	2,212	37,913	37,467
Nebraska	12,347		16,367		1,429	1,882	36,669	36,700
Residential	84,291		110,640		9,924	12,187	234,294	233,107
Montana	29,238		38,523		3,489	4,142	22,403	22,270
South Dakota	8,526		13,280		1,373	1,909	5,976	5,954
Nebraska	6,894		11,708		1,092	1,853	4,598	4,602
Commercial	44,658		63,511		5,954	7,904	32,977	32,826
Industrial	579		920		70	102	276	280
Other	573		680		77	86	150	145
Total Retail Gas	$	130,101	$	175,751	16,025	20,279	267,697	266,358

	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	4,244	5,000	4,640	15% warmer	9% warmer
South Dakota	4,310	6,141	5,600	30% warmer	23% warmer
Nebraska	3,584	4,798	4,638	25% warmer	23% warmer

41

The following summarizes the components of the changes in natural gas gross margin for the six months ended June 30, 2012 and 2011:

	Gross Margin 2012 vs. 2011
	(in millions)
Retail volumes	$	(6.0	)
Operating expenses recovered in trackers	(0.9		)
Gas production	(0.8		)
South Dakota rate increase	1.0
Other	0.1
Decrease in Gross Margin	$	(6.6	)

This decrease in gross margin and volumes was primarily due to warmer winter and spring weather, lower revenues for operating expenses recovered in trackers primarily related to customer efficiency programs and environmental remediation costs, and a decrease in gas production margin from lower market prices. An increase in South Dakota natural gas rates partly offset these decreases. 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.

42

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 June 30, 2012, our total net liquidity was approximately $170.1 million, including $8.1 million of cash and $162.0 million of revolving credit facility availability. Revolving credit facility availability was $184.0 millionas of July 20, 2012.

The following table presents additional information about short term borrowings during the three months ended June 30, 2012 (in millions):

Amount outstanding	$	130.0
Daily average amount outstanding	$	96.0
Maximum amount outstanding	$	130.0

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.

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 over the next three years. In February 2012, we filed a shelf registration statement with the SEC that can be used for the issuance of debt or equity securities. In April 2012, we entered into an Equity Distribution Agreement with UBS pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During the second quarter of 2012, we sold 687,285 shares of our common stock at an average price of $35.40 per share. Proceeds received were approximately $23.9 million, which are net of sales commissions paid to UBS of approximately $0.2 million and other fees.

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. Due to the progress on our supply related investment growth opportunities, we expect to issue approximately $25 million of additional common stock during 2012. In addition, we priced $150 million of First Mortgage Bonds in May 2012, which we expect to issue in August 2012.

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 June 30, 2012, we are under collected on our current Montana natural gas and electric trackers by approximately $11.1 million, as compared with an under collection of $14.7 million as of December 31, 2011, and an over collection of $1.0 million as of June 30, 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. In July 2012, the Commodity Futures Trading Commission (CFTC) issued a final rule providing for an exemption to such clearing requirements as outlined in the legislation 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 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. At this time, 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 July 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):

	Six Months Ended June 30,
	2012			2011
Operating Activities
Net income	$	43.5		$	43.5
Non-cash adjustments to net income	79.8			77.3
Changes in working capital	26.8			38.1
Other	(5.0		)	4.6
	145.1			163.5
Investing Activities
Property, plant and equipment additions	(97.8		)	(71.9		)
Other	0.1			0.2
	(97.7		)	(71.7		)
Financing Activities
Proceeds from issuance of common stock, net	23.9			—
Net repayment of debt	(40.8		)	(66.6		)
Dividends on common stock	(26.9		)	(26.0		)
Other	(1.4		)	(0.9		)
	(45.2		)	(93.5		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	2.2		$	(1.7	)
Cash and Cash Equivalents, beginning of period	$	5.9		$	6.2
Cash and Cash Equivalents, end of period	$	8.1		$	4.5

Cash Provided by Operating Activities

As of June 30, 2012, cash and cash equivalents were $8.1 million as compared with $5.9 million at December 31, 2011 and $4.5 million at June 30, 2011. Cash provided by operating activities totaled $145.1 million for the six months ended June 30, 2012 as compared with $163.5 million during the six months ended June 30, 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, federal tax payments and increased expenditures related to the distribution system infrastructure project (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 $26.0 million as compared with the first six months of 2011. Plant additions during the first half of 2012 include supply related capital expenditures of approximately $23.2 million, related to the 60 MW peaking facility in South Dakota, and DSIP capital expenditures of approximately $8.0 million.

Cash Used in Financing Activities

Cash used in financing activities totaled approximately $45.2 million during the six months ended June 30, 2012 as compared with approximately $93.5 million during the six months ended June 30, 2011. During the six months ended June 30, 2012, net cash used in financing activities consisted of net repayments of commercial paper of $37.0 million, the repayment of long-term debt of $3.8 million and the payment of dividends of $26.9 million offset in part by proceeds received from the issuance of common stock pursuant to our equity distribution agreement of $23.9 million. During the six months ended June 30, 2011, net cash used in financing activities consisted of net revolving credit facility repayments of $153.0 million, net issuance of commercial paper of $90.0 million, the repayment of long-term debt of $3.6 million and the payment of dividends of $26.0 million.

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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 June 30, 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	$	905,061	$	—	$	—	$	—	$	—	$	150,000	$	755,061
Capital leases	33,956		781		1,613		1,667		1,732		1,837		26,326
Short-term borrowings	129,968		129,968		—		—		—		—		—
Future minimum operating lease payments	3,383		988		1,172		599		280		130		214
Estimated pension and other postretirement obligations (1)	58,632		1,832		15,400		13,800		13,800		13,800		N/A
Qualifying facilities liability (2)	1,235,650		34,078		69,816		72,354		74,135		75,945		909,322
Supply and capacity contracts (3)	1,643,300		146,753		263,596		190,899		116,721		117,525		807,806
Contractual interest payments on debt (4)	498,196		25,606		51,212		51,212		51,212		50,888		268,066
Total Commitments (5)	$	4,508,146	$	340,006	$	402,809	$	330,531	$	257,880	$	410,125	$	2,766,795

_________________________

(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 $1.2 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $0.9 billion.

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

(4) We have assumed a weighted average interest rate of 0.5% 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 June 30, 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 June 30, 2012, we had approximately $130.0 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 $1.3 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 are also exposed to counterparty credit risk related to providing transmission service to our customers under our Open Access Transmission Tariff and under gas transportation agreements. 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 were 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 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 13, Commitments and Contingencies, to the Financial Statements for information about legal proceedings.

ITEM 1A. RISK FACTORS

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

We are subject to extensive and changing governmental laws and regulations that affect our industry and our operations, which could have a material adverse effect on our liquidity and results of operations.

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

For example, in our regulatory filings related to DGGS, we proposed an allocation of approximately 80% of costs to retail customers subject to the MPSC's jurisdiction and approximately 20% allocated to wholesale customers subject to FERC's jurisdiction. There is 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 or abandon certain projects.

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 or delay a project from proceeding, increase the anticipated cost of the project or cause us to abandon 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 June 30, 2012, we have capitalized approximately $23.5 million in preliminary survey and investigative costs related to MSTI. If we are unable to complete the development and ultimate construction of MSTI or decide to delay or cancel construction for any reason, including failure to receive necessary regulatory approvals and/or siting or environmental permits, we may not be able to recover our investment. Even if MSTI is completed, the total costs may be higher than estimated and there is no assurance that we will be able to recover such costs from MSTI customers. If we abandon our efforts to pursue MSTI 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

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exceed our obligation to serve retail customers or demand for transmission capacity and, as a result, may not be recoverable from customers.

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, litigation 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.

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.

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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.

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

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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.

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ITEM 6.                      EXHIBITS

(a)Exhibits

Exhibit 1.1—Equity Distribution Agreement between NorthWestern Corporation and UBS Securities LLC, dated as of April 25, 2012 (incorporated by reference to Exhibit 1.1 of NorthWestern Corporation's Current Report on Form 8-K, dated April 25, 2012, Commission File No. 1-10499).

Exhibit 18.1—Letter of Independent Registered Public Accounting Firm regarding change in accounting principle.

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:	July 24, 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
1.1	Equity Distribution Agreement between NorthWestern Corporation and UBS Securities LLC, dated as of April 25, 2012 (incorporated by reference to Exhibit 1.1 of NorthWestern Corporation's Current Report on Form 8-K, dated April 25, 2012, Commission File No. 1-10499).
*18.1	Letter of Independent Registered Public Accounting Firm regarding change in accounting principle.
*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

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