NORTHWESTERN CORP - Quarter Report: 2012 September (Form 10-Q)

Location of gain reclassified from AOCI to Income

Nine Months Ended September 30, 2012 and 2011

Amount of gain reclassified from AOCI

Interest Expense

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 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. 69^th Street, Sioux Falls, South Dakota		57108
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code: 605-978-2900

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



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

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

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

Common Stock, Par Value $0.01

37,215,556 shares outstanding at October 19, 2012

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX



		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets — September 30, 2012 and December 31, 2011	4
	Condensed Consolidated Statements of Income (Loss) — Three and Nine Months Ended September 30, 2012 and 2011	5
	Condensed Consolidated Statements of Comprehensive Income (Loss) — Three and Nine Months Ended September 30, 2012 and 2011	6
	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2012 and 2011	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 4.	Controls and Procedures	51
PART II. OTHER INFORMATION		52
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 6.	Exhibits	56
SIGNATURES		58

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;


•	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.

PART 1. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)



	September 30, 2012			December 31, 2011

ASSETS
Current Assets:
Cash and cash equivalents	$	18,196		$	5,928
Restricted cash	7,985			12,716
Accounts receivable, net	109,463			147,151
Inventories	59,376			59,532
Regulatory assets	39,423			48,900
Deferred income taxes	42,519			6,522
Other	10,162			9,450
Total current assets	287,124			290,199
Property, plant, and equipment, net	2,319,173			2,213,267
Goodwill	355,128			355,128
Regulatory assets	320,956			308,804
Other noncurrent assets	24,565			43,040
Total assets	$	3,306,946		$	3,210,438
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,585		$	1,370
Current maturities of long-term debt	—			3,792
Short-term borrowings	—			166,934
Accounts payable	62,238			76,735
Accrued expenses	214,136			193,939
Regulatory liabilities	43,757			33,184
Total current liabilities	321,716			475,954
Long-term capital leases	31,979			32,918
Long-term debt	1,055,067			905,049
Deferred income taxes	339,851			282,406
Noncurrent regulatory liabilities	273,744			265,987
Other noncurrent liabilities	395,770			389,012
Total liabilities	2,418,127			2,351,326
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 40,790,925 and 37,214,807 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	408			398
Treasury stock at cost	(90,830		)	(90,273		)
Paid-in capital	848,256			816,700
Retained earnings	127,756			128,631
Accumulated other comprehensive income	3,229			3,656
Total shareholders' equity	888,819			859,112
Total liabilities and shareholders' equity	$	3,306,946		$	3,210,438

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF (LOSS) INCOME

(Unaudited)

(in thousands, except per share amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues
Electric	$	202,485		206,613			$	605,716		$	602,024
Gas	32,965			37,067			182,812			230,971
Other	416			361			1,041			1,112
Total Revenues	235,866			244,041			789,569			834,107
Operating Expenses
Cost of sales	93,061			98,045			327,884			370,523
Operating, general and administrative	63,056			66,332			195,725			203,254
Mountain States Transmission Intertie impairment	24,039			—			24,039			—
Property and other taxes	24,796			22,605			74,395			68,551
Depreciation	26,505			25,181			79,364			75,562
Total Operating Expenses	231,457			212,163			701,407			717,890
Operating Income	4,409			31,878			88,162			116,217
Interest Expense, net	(17,743		)	(16,694		)	(49,598		)	(50,737		)
Other Income	974			346			3,134			2,257
(Loss) Income Before Income Taxes	(12,360		)	15,530			41,698			67,737
Income Tax Benefit (Expense)	8,588			(635		)	(1,989		)	(9,297		)
Net (Loss) Income	$	(3,772	)	$	14,895		$	39,709		$	58,440
Average Common Shares Outstanding	37,201			36,262			36,723			36,254
Basic (Loss) Earnings per Average Common Share	$	(0.10	)	$	0.41		$	1.09		$	1.61
Diluted (Loss) Earnings per Average Common Share	$	(0.10	)	$	0.41		$	1.08		$	1.60
Dividends Declared per Average Common Share	$	0.37		$	0.36		$	1.11		$	1.08

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)

(in thousands, except per share amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net (Loss) Income	$	(3,772	)	$	14,895		$	39,709		$	58,440
Other comprehensive (loss) income, net of tax:
Reclassification of net gains on derivative instruments	(178		)	(183		)	(552		)	(777		)
Postretirement medical liability adjustment	—			—			205			—
Foreign currency translation	(79		)	(168		)	(80		)	(99		)
Total Other Comprehensive Loss	(257		)	(351		)	(427		)	(876		)
Comprehensive (Loss) Income	$	(4,029	)	$	14,544		$	39,282		$	57,564

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)



	Nine Months Ended September 30,
	2012			2011
OPERATING ACTIVITIES:
Net Income	$	39,709		$	58,440
Items not affecting cash:
Depreciation	79,364			75,562
Amortization of debt issue costs, discount and deferred hedge gain	273			914
Amortization of restricted stock	2,199			1,649
Equity portion of allowance for funds used during construction	(3,311		)	(960		)
(Loss) gain on disposition of assets	(232		)	850
Deferred income taxes	21,663			31,310
Mountain States Transmission Intertie impairment	24,039			—
Changes in current assets and liabilities:
Restricted cash	4,731			1,188
Accounts receivable	37,688			36,192
Inventories	156			(21,346		)
Other current assets	(712		)	(1,896		)
Accounts payable	(9,604		)	(12,808		)
Accrued expenses	29,139			37,018
Regulatory assets	(3,266		)	5,539
Regulatory liabilities	10,573			2,663
Other noncurrent assets	(13,400		)	(3,451		)
Other noncurrent liabilities	3,619			(359		)
Cash provided by operating activities	222,628			210,505
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(157,859		)	(124,484		)
Asset acquisition	(18,384		)	—
Proceeds from sale of assets	262			209
Cash used in investing activities	(175,981		)	(124,275		)
FINANCING ACTIVITIES:
Treasury stock activity	(557		)	169
Proceeds from issuance of common stock, net	28,477			—
Dividends on common stock	(40,584		)	(38,930		)
Issuance of long-term debt	150,000			—
Repayments on long-term debt	(3,871		)	(6,586		)
Line of credit borrowings	—			80,000
Line of credit repayments	—			(233,000		)
(Repayments) issuances of short-term borrowings, net	(166,934		)	112,993
Financing costs	(910		)	(1,116		)
Cash used in financing activities	(34,379		)	(86,470		)
Increase (Decrease) in Cash and Cash Equivalents	12,268			(240		)
Cash and Cash Equivalents, beginning of period	5,928			6,234
Cash and Cash Equivalents, end of period	$	18,196		$	5,994
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	1,944			18
Interest	34,416			28,950
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	13,292			4,314

See Notes to Condensed Consolidated Financial Statements

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


(1)	Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 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 September 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 6 - 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

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 $394.9 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 nine months ended September 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. We have changed the presentation of comprehensive income from a single continuous financial statement to two separate, but consecutive, statements during the third quarter of 2012. The adoption of this standard did not have a material effect on our financial statement disclosures.

(3) Regulatory Matters

Dave Gates Generating Station at Mill Creek (DGGS)

On January 1, 2011, we began commercial operations of DGGS, a 150 MW natural gas fired facility that provides regulating resources (in place of previously contracted ancillary services). DGGS was constructed for a total cost of $183 million, as compared to an original estimate of $202 million. Our regulatory filings seeking approval of rates related to DGGS are based on an allocation of approximately 80% of revenues related to the facility from retail customers being subject to the jurisdiction of the Montana Public Service Commission (MPSC) and approximately 20% of revenues allocated to wholesale customers subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).

In our DGGS FERC proceedings total project costs were not challenged and the parties to the case have stipulated to the revenue requirement; however, intervenors have challenged the allocation of costs. Our allocation methodology of 20% of the DGGS revenue requirement to FERC jurisdictional customers is based on our past practice of allocating the contracted costs for these services. A hearing was held in June 2012 before a FERC Administrative Law Judge (ALJ) to consider this proposed allocation methodology. In September 2012, we received an initial decision from the ALJ concluding that we should only recover approximately 4.4% of the revenue requirement from FERC jurisdictional customers. The ALJ's initial decision is nonbinding.

In response to the initial decision, we and the intervening parties will have the opportunity to respond with briefs in support or opposition to be filed during the fourth quarter of 2012. We intend to vigorously appeal the initial decision to the full FERC. The FERC is expected to consider the matter and issue a binding decision during the second quarter of 2013. The FERC is not obliged to follow any of the findings from the ALJ's initial decision and can accept or reject the initial decision in whole or in part. If the FERC upholds the ALJ decision and a portion of the costs are effectively disallowed, we would be required to assess DGGS for impairment. If we disagree with a decision issued by the FERC, we may pursue full appellate rights through rehearing and appeal to a United States Circuit Court of Appeals, which could extend into 2015.

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. As a result of the ALJ initial decision we deferred additional revenue of approximately $11.4 million during the third quarter of 2012. Of this charge, approximately $6.4 million relates to revenues collected during 2011. As of September 30, 2012, our cumulative deferred revenue related to DGGS FERC jurisdictional revenues is approximately $14.3 million.

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.

DGGS 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 by May 3, 2012, five of the six turbines had 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. Testing of the conclusions of the root cause analysis is expected to occur during the fourth quarter of 2012. We expect that any required modifications or further servicing of the turbines to implement the root cause analysis will take place during the first quarter of 2013. We anticipate that the 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.

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 requested natural gas tracker rates 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 from interim recovery and provides that they are to be reviewed at a future date.

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. This increase in DSM lost revenues is included in our annual tracker filings until the next general rate case. Historically, the MPSC has authorized us to include a calculation of lost revenues based on actual DSM program activity, but prohibited the inclusion of forecasted or estimated future lost revenue in the electric tracker. In April 2012, we received a final order for our 2011 annual electric tracker filing, which authorized us to include forecasted lost revenues in future 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. The study will also be subject to review and potential challenge by intervenors, such as the Montana Consumer Counsel (MCC). The MPSC could ultimately determine our requested amounts are too high and we may have to refund a portion of DSM lost revenues that we have recognized. We do not expect the MPSC to issue a final order related to the DSM lost revenues until at least the first quarter of 2013.

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 40 MW of name plate 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 on our revenue requirement.

We expect to take ownership of the project and pay Compass approximately $81 million during the fourth quarter of 2012. Both the energy and associated renewable energy credits will be placed into our electric supply portfolio to meet future customer loads and renewable portfolio standards obligations. Through September 30, 2012 we have completed construction of the required transmission infrastructure and capitalized approximately $5.3 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 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 was held in September 2012 and we expect to receive a final order during the fourth quarter of 2012. Pending MPSC approval, the corresponding amounts included in the natural gas supply tracker are subject to refund and through September 30, 2012, we have deferred revenue of approximately $2.2 million based on the difference between our cost of service and current natural gas market prices.

Montana Natural Gas Rate Filing

In September 2012, we filed a request with the MPSC for a natural gas distribution revenue increase of approximately $15.7 million. This request was based on a return on equity of 10.5%, a capital structure consisting of 52% debt and 48% equity and rate base of $309.5 million. We are currently awaiting the establishment of a procedural schedule.

(4) Mountain States Transmission Intertie (MSTI) Impairment

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 was significant market uncertainty related to the project. In addition, we reported in our Form 10-Q for the period ended June 30, 2012 that we would consider writing down or writing off the costs of the MSTI project depending on the likelihood of reaching an agreement with the Bonneville Power Administration (BPA) to serve its southern Idaho loads. On October 2, 2012, BPA notified us that it has ranked other options ahead of MSTI to serve BPA's southern Idaho loads. This notification was in conjunction with the January 2012 Memorandum of Understanding between NorthWestern and BPA agreeing to explore the potential for MSTI to accommodate BPA's needs. Based on BPA's decision, continued market uncertainty, and permitting issues causing timeline delays, we have determined that we will not further pursue development of MSTI at this time. As a result, during the third quarter of 2012 we recorded an impairment charge of substantially all of the capitalized preliminary survey and investigative costs related to MSTI, totaling approximately $24.0 million.

(5) Income Taxes

Our effective tax rate was (69.5)% and 4.8% for the three and nine months ended September 30, 2012 as compared with 4.1% and 13.7% for the three and nine months ended September 30, 2011. The following table summarizes the significant differences from the federal statutory rate (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
(Loss) Income Before Income Taxes	$	(12,360	)	$	15,530		$	41,698		$	67,737

Income tax calculated at 35% federal statutory rate	4,326			(5,435		)	(14,594		)	(23,707		)

Permanent or flow through adjustments:
Prior year permanent return to accrual adjustments	1,857			—			1,857			(2,571		)
Flow-through repairs deductions	1,808			3,243			9,547			8,745
Flow-through of state bonus depreciation deduction	276			1,170			2,159			4,452
Recognition of state net operating loss benefit/valuation allowance release	51			—			51			2,402
State income tax and other, net	270			387			(1,009		)	1,382
	$	4,262		$	4,800		$	12,605		$	14,410

Income tax benefit (expense)	$	8,588		$	(635	)	$	(1,989	)	$	(9,297	)

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 $135.5 million as of September 30, 2012, including approximately $80.2 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

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

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

(6) 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 nine months ended September 30, 2012. Goodwill by segment is as follows for both September 30, 2012 and December 31, 2011 (in thousands):



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

(7) Comprehensive (Loss) Income

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



	September 30, 2012
	Three Months Ended								Nine Months Ended
	Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit (Expense)			Net-of-Tax Amount
Foreign currency translation adjustment	$	(79	)	$	—	$	(79	)	$	(80	)	$	—		$	(80	)
Reclassification of net gains on derivative instruments to net income	(297		)	119		(178		)	(891		)	339			(552		)
Pension and postretirement medical liability adjustment	—			—		—			333			(128		)	205
Other comprehensive loss	$	(376	)	$	119	$	(257	)	$	(638	)	$	211		$	(427	)



	September 30, 2011
	Three Months Ended								Nine Months Ended
	Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	(168	)	$	—	$	(168	)	$	(99	)	$	—	$	(99	)
Reclassification of net gains on derivative instruments to net income	(297		)	114		(183		)	(891		)	114		(777		)
Other comprehensive loss	$	(465	)	$	114	$	(351	)	$	(990	)	$	114	$	(876	)

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



	September 30, 2012			December 31, 2011
Foreign currency translation	$	340		$	420
Derivative instruments designated as cash flow hedges	4,423			4,975
Pension and postretirement medical plans	(1,534		)	(1,739		)
Accumulated other comprehensive income	3,229			3,656

(8) Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

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

Objectives and Strategies for Using Derivatives

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts, such as fixed-price forward purchase and sales contracts. The objective of these transactions is to fix the price for a portion of anticipated energy purchases to supply our customers. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of 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 September 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 9.



Mark-to-Market Transactions	Balance Sheet Location	September 30, 2012		December 31, 2011

Natural gas net derivative liability	Accrued Expenses	$	7,569	$	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				Nine Months Ended
Derivatives Subject to Regulatory Deferral	September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011

Natural gas	$	5,527	$	1,840	$	12,743	$	9,655

Credit Risk

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

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

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

The following table presents, as of September 30, 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 September 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	$	943	$	—	$	943

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 previously 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):

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

(9) 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 8 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
September 30, 2012	(in thousands)
Cash equivalents	$	18,000	$	—		$	—	$	—	$	18,000
Restricted cash	7,671		—			—		—		7,671
Rabbi trust investments	10,689		—			—		—		10,689
Derivative liability (1)	—		(7,569		)	—		—		(7,569		)
Total	$	36,360	$	(7,569	)	$	—	$	—	$	28,791

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 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.

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

Financial Instruments

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



	September 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt (including current portion)	$	1,055,067	$	1,239,671	$	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.

(10) 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 three months ended September 30, 2012, we sold 128,131 shares of our common stock at an average price of $36.50 per share. Proceeds received were approximately $4.6 million, which are net of sales commissions paid to UBS of approximately $0.1 million and other fees.

In August 2012, we issued $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 issued $60 million aggregate principal amount of Montana and South Dakota First Mortgage Bonds at a fixed interest rate of 4.30% maturing in 2052. The bonds are secured by our electric and natural gas assets in the respective jurisdictions. The bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used primarily to repay commercial paper borrowings.

(11) Segment Information

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

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



Three Months Ended
September 30, 2012	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	202,485		$	32,965		$	416		$	—	$	235,866
Cost of sales	83,814			9,247			—			—		93,061
Gross margin	118,671			23,718			416			—		142,805
Operating, general and administrative	44,711			17,452			893			—		63,056
MSTI impairment	24,039			—			—			—		24,039
Property and other taxes	18,621			6,172			3			—		24,796
Depreciation	21,636			4,860			9			—		26,505
Operating income (loss)	9,664			(4,766		)	(489		)	—		4,409
Interest expense	(15,181		)	(2,363		)	(199		)	—		(17,743		)
Other income	405			541			28			—		974
Income tax benefit (expense)	5,762			3,102			(276		)	—		8,588
Net income (loss)	$	650		$	(3,486	)	$	(936	)	$	—	$	(3,772	)
Total assets	$	2,319,856		$	976,152		$	10,938		$	—	$	3,306,946
Capital expenditures	$	45,932		$	32,499		$	—		$	—	$	78,431



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



Nine Months Ended
September 30, 2012	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	605,716		$	182,812		$	1,041		$	—	$	789,569
Cost of sales	244,902			82,982			—			—		327,884
Gross margin	360,814			99,830			1,041			—		461,685
Operating, general and administrative	137,753			55,397			2,575			—		195,725
MSTI impairment	24,039			—			—			—		24,039
Property and other taxes	55,628			18,759			8			—		74,395
Depreciation	64,770			14,569			25			—		79,364
Operating income (loss)	78,624			11,105			(1,567		)	—		88,162
Interest expense	(42,257		)	(6,660		)	(681		)	—		(49,598		)
Other income	1,818			1,235			81			—		3,134
Income tax (expense) benefit	(3,322		)	522			811			—		(1,989		)
Net income (loss)	$	34,863		$	6,202		$	(1,356	)	$	—	$	39,709
Total assets	$	2,319,856		$	976,152		$	10,938		$	—	$	3,306,946
Capital expenditures	$	130,723		$	45,520		$	—		$	—	$	176,243



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

(12) 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
	September 30, 2012	September 30, 2011
Basic computation	37,201,051	36,262,246
Dilutive effect of
Restricted stock and performance share awards (1)	—	248,775

Diluted computation	37,201,051	36,511,021



	Nine Months Ended
	September 30, 2012	September 30, 2011
Basic computation	36,723,105	36,254,159
Dilutive effect of
Restricted stock and performance share awards (1)	70,848	245,500

Diluted computation	36,793,953	36,499,659

___________________

(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.

In periods in which a net loss has been incurred, all potentially dilutive shares are considered antidilutive and thus are excluded from the calculation. For the three months ended September 30, 2012, we had 173,624 potentially dilutive restricted stock and performance share awards which were not included in the calculation.

(13) Employee Benefit Plans

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



	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,						Three Months Ended September 30,
	2012			2011			2012			2011
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,586		$	2,549		$	162		$	109
Interest cost	6,016			6,099			309			337
Expected return on plan assets	(7,501		)	(7,616		)	(253		)	(296		)
Amortization of prior service cost	62			62			(500		)	(500		)
Recognized actuarial loss	2,291			629			234			165
Net Periodic Benefit Cost (Income)	$	3,454		$	1,723		$	(48	)	$	(185	)



	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Components of Net Periodic Benefit Cost (Income)
Service cost	$	8,616		$	7,649		$	406		$	328
Interest cost	17,867			18,296			875			1,011
Expected return on plan assets	(22,497		)	(22,847		)	(766		)	(889		)
Amortization of prior service cost	185			185			(1,499		)	(1,499		)
Recognized actuarial loss	6,485			1,887			593			494
Net Periodic Benefit Cost (Income)	$	10,656		$	5,170		$	(391	)	$	(555	)

(14) 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 September 30, 2012, we have a reserve of approximately $31.0 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 $25.6 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 $11.6 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 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, EPA regulations now require that major sources in the United States collect and annually report information regarding their GHG emissions.

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 June 2013. When a final rule is issued and implemented, additional capital and/or increased operating costs may be incurred. The costs of complying with any such final water intake standards are not currently determinable, but could be significant.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures

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

The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in such 'Class I' areas.

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

On July 7, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions reductions were to be required beginning in 2012. After having issued a stay of CSAPR earlier this year, however, a Federal court found that CSAPR violated federal law and ordered that it be vacated. The Clean Air Interstate Rule remains in effect until the EPA issues a valid replacement. The EPA has filed a petition seeking legal review of the Federal court's ruling.

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 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 and MATS standards. These improvements are also expected to result in compliance with the regional haze provisions of the Clean Air Act. Capital expenditures for such equipment are currently estimated to be approximately $270 million (our share is 8.7%). The plant began incurring such costs in 2011 and the costs will be spread over the next three years. Our incremental capital expenditure projections include amounts related to our share of the emission control equipment at Neal 4 based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process.

Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is currently controlling emissions of mercury under regulations issued by the State of Montana, which are more strict than the Federal MATS standard, and has been since January 2010. The owners do not believe additional equipment will be necessary to meet the MATS standards for mercury, 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 September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. As finalized, Colstrip Unit 4 does not have to improve removal efficiency for pollutants that contribute to regional haze. The plan is reviewed every five years and Colstrip Unit 4 could be impacted during a subsequent review period. The plant operator has indicated that costs for future compliance, if any, are unknown at this time; however, if such costs are subsequently incurred they could be significant.

See 'Legal Proceedings - Notice of Intent to Sue Colstrip Owners' below for discussion of potential Sierra Club action.

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

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


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


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

LEGAL PROCEEDINGS

Colstrip Energy Limited Partnership

In December 2006 and June 2007, the MPSC issued orders relating to certain QF long-term rates for the period July 1, 2003, through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a QF with which we have a power purchase agreement through June 2024. Under the terms of the power purchase agreement with CELP, energy and capacity rates were fixed through June 30, 2004 (with a small portion to be set by the MPSC's determination of rates in the annual avoided cost filing), and beginning July 1, 2004 through the end of the contract, energy and capacity rates are to be determined each year pursuant to a formula, with the rates to be used in that formula derived from the annual MPSC QF rate review.

CELP initially appealed the MPSC's orders and then, in July 2007, filed a complaint against NorthWestern and the MPSC in Montana district court, which contested the MPSC's orders. CELP disputed inputs into the underlying rates used in the formula, which initially are calculated by us and reviewed by the MPSC on an annual basis, to calculate energy and capacity payments for the contract years 2004-2005 and 2005-2006. CELP claimed that NorthWestern breached the power purchase agreement causing damages, which CELP asserted to be approximately $23 million for contract years 2004-2005 and 2005-2006. The parties stipulated that NorthWestern would not implement the final derived rates resulting from the MPSC orders, pending an ultimate decision on CELP's complaint.

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

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

On June 15, 2010, the Montana district court confirmed the final arbitration panel award and denied CELP's motion to vacate, modify or correct the award. CELP 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. A hearing was held July 30 through August 1, 2012, and we expect a decision during the fourth quarter of 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.

Notice of Intent to Sue Colstrip Owners

In a letter dated July 25, 2012, the Sierra Club and the Montana Environmental Information Center (MEIC) served on each of the individual owners of the Colstrip Steam Electric Station (CSES), including us and the owner or managing agent of the station, a notice of intent to sue over alleged violations of the federal Clean Air Act, 42 U.S.C. § 7401 et seq. The Notice states that the Sierra Club and MEIC will request a United States District Court to impose injunctive relief and civil penalties, require a beneficial environmental project in the areas directly impacted by the highest concentrations of air pollution emissions from CSES, and require reimbursement of the Sierra Club's and MEIC's costs of litigation and attorneys' fees. Since then, the Sierra Club and MEIC have twice amended their notice of intent to sue. The first amendment, contained in a letter dated August 30, 2012, asserts that the owners, and the owner or managing agent, violated the Colstrip Title V air quality operating permit by

failing to provide complete reports to the Montana Department of Environmental Quality (MDEQ) regarding opacity exceedances for the third quarter of 2008 and the second and third quarters of 2009. The second amendment, contained in a letter dated September 27, 2012, asserts that the owners, and the owner or managing agent, have violated the Clean Air Act each day since April 13, 2010, by failing to timely submit a complete air quality operating permit application to the MDEQ. We intend to vigorously defend any lawsuit filed by the Sierra Club and MEIC. Due to the uncertainty around this matter and the lack of any pending lawsuit, we currently are unable to predict its outcome.

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.


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 items during the three months ended September 30, 2012 include:


•	An initial decision by a FERC Administrative Law Judge related to DGGS, causing us to defer additional revenue of approximately $11.4 million; and


•	A charge of approximately $24 million in the third quarter of 2012 for the impairment of substantially all of the capitalized preliminary survey and investigative costs associated with MSTI.

Dave Gates Generating Station at Mill Creek (DGGS)

five of the six turbines had 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. Testing of the conclusions of the root cause analysis is expected to occur during the fourth quarter of 2012. We expect that any required modifications or further servicing of the turbines to implement the root cause analysis will take place during the first quarter of 2013. We anticipate that the 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.

Mountain States Transmission Intertie Project (MSTI) Impairment

STRATEGY UPDATE

We are focused on growing through investing in our core utility business and providing safe, reliable service while earning a reasonable return on invested capital. In response to our aging infrastructure, we continue to make significant maintenance capital investments in our distribution and transmission system in excess of our depreciation, which is the amount of these costs we recover through rates.

We are considering opportunities for the ownership and/or development of electric generation facilities and seeking opportunities to acquire proven gas reserves, which help to stabilize our customers' energy costs while providing us the opportunity to grow our rate base and earn a return on investment.

Regulatory Matters

Rate cases are a key component of our earnings growth and achieving our financial objectives. In September 2012, we filed a request with the MPSC for a natural gas distribution revenue increase of approximately $15.7 million. This request was based on a return on equity of 10.5%, a capital structure consisting of 52% debt and 48% equity and rate base of $309.5 million. We are currently awaiting the establishment of a procedural schedule.

Supply Investments

During the third quarter of 2012, we completed the purchase of natural gas production interests in northern Montana’s Bear Paw Basin, including 75% interests in two gas gathering systems. The purchase price for the Bear Paw Basin assets including the interests in the two gathering systems was $19.5 million (subject to customary post closing adjustments). We expect annual production to be approximately 8% of our natural gas load in Montana.

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.

OVERALL CONSOLIDATED RESULTS

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



	Three Months Ended September 30,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	202.5	$	206.6	$	(4.1	)	(2.0	)%
Natural Gas	33.0		37.0		(4.0		)	(10.8	)
Other	0.4		0.4		—			—
	$	235.9	$	244.0	$	(8.1	)	(3.3	)%



	Three Months Ended September 30,
	2012		2011		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	83.8	$	85.2	$	(1.4	)	(1.6	)%
Natural Gas	9.2		12.8		(3.6		)	(28.1	)
	$	93.0	$	98.0	$	(5.0	)	(5.1	)%



	Three Months Ended September 30,
	2012		2011		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	118.7	$	121.4	$	(2.7	)	(2.2	)%
Natural Gas	23.8		24.2		(0.4		)	(1.7	)
Other	0.4		0.4		—			—
	$	142.9	$	146.0	$	(3.1	)	(2.1	)%

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



	Gross Margin 2012 vs. 2011
	(in millions)
DGGS	$	(9.6	)
Natural gas retail volumes	(0.3		)
Electric retail volumes	3.8
Operating expenses recovered in trackers	1.4
Montana property tax tracker	1.4
South Dakota natural gas rate increase	0.3
Other	(0.1		)
Decrease in Consolidated Gross Margin	$	(3.1	)

Consolidated gross margin decreased $3.1 million primarily due to the impacts of the FERC jurisdictional DGGS deferral discussed above, offset in part by higher DGGS retail revenues due to the regulatory treatment of bonus depreciation. In addition, natural gas retail volumes decreased due to lower customer usage.

This decrease was partly offset by the following improvements:


•	Warmer summer weather increasing electric customer usage for cooling during the third quarter of 2012;


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


•	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 which was effective in December 2011.



	Three Months Ended September 30,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	63.1	$	66.3	$	(3.2	)	(4.8	)%
MSTI impairment	24.0		—		24.0			—
Property and other taxes	24.8		22.6		2.2			9.7
Depreciation	26.5		25.2		1.3			5.2
	$	138.4	$	114.1	$	24.3		21.3	%

Consolidated operating, general and administrative expenses were $63.1 million for the three months ended September 30, 2012, as compared with $66.3 million for the three months ended September 30, 2011. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2012 vs. 2011
	(in millions)
Insurance settlements and recoveries	$	(2.3	)
Labor	(1.6		)
Abandoned gas transmission project	(0.8		)
Operating expenses recovered in trackers	1.4
Other	0.1
Decrease in Operating, General & Administrative Expenses	$	(3.2	)

The decrease in operating, general and administrative expenses of $3.2 million was primarily due to the following:


•	Lower insurance settlements and recoveries as 2011 results included an increase of $2.3 million related to a settlement with a former employee;


•	Decreased labor costs primarily due to a lower incentive accrual, offset in part by compensation increases and a higher number of employees; and


•	Third quarter 2011 results included the write-off of an abandoned gas transmission project due to the pursuit of a more cost effective solution.

These decreases were offset in part by higher operating expenses primarily related to costs incurred for customer efficiency programs, which are recovered from customers through supply trackers and have no impact on operating income.

As discussed above, we recorded a charge of approximately $24 million in the third quarter of 2012 for the impairment of substantially all of the preliminary survey and investigative costs associated with MSTI.

Property and other taxes was $24.8 million for the three months ended September 30, 2012, as compared with $22.6 million in the third 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 $26.5 million for the three months ended September 30, 2012, as compared with $25.2 million in the third quarter of 2011. This increase was primarily due to plant additions.

Consolidated operating income for the three months ended September 30, 2012 was $4.4 million, as compared with $31.9 million in the third quarter of 2011. This decrease was primarily due to the MSTI impairment and a decrease in gross margin partly offset by lower operating, general and administrative expenses as discussed above.

Consolidated interest expense for the three months ended September 30, 2012 was $17.7 million, as compared with $16.7 million in the third quarter of 2011. This increase was primarily due to higher debt outstanding and interest accrued on DGGS deferred revenues, partially offset by higher capitalization of allowance for funds used during construction (AFUDC).

Consolidated other income for the three months ended September 30, 2012, was $1.0 million, as compared with $0.3 million in the third quarter of 2011. This increase was primarily due to higher capitalization of AFUDC.

Consolidated income tax benefit for the three months ended September 30, 2012 was $8.6 million, as compared with income tax expense of $0.6 million in the same period of 2011. Our effective tax rate was (69.5)% for the three months ended September 30, 2012 as compared with 4.1% for the three months ended September 30, 2011. The following table summarizes the significant differences from the federal statutory rate (in thousands):



	Three Months Ended September 30,
	2012			2011
(Loss) Income Before Income Taxes	$	(12.4	)	$	15.5

Income tax calculated at 35% federal statutory rate	4.3			(5.4		)

Permanent or flow through adjustments:
Prior year permanent return to accrual adjustments	1.9			—
Flow-through repairs deductions	1.8			3.2
Flow-through of state bonus depreciation deduction	0.3			1.2
Recognition of state net operating loss benefit/valuation allowance release	0.1			—
State income tax and other, net	0.2			0.4
	4.3			4.8

Income tax benefit (expense)	$	8.6		$	(0.6	)

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 loss for the three months ended September 30, 2012 was $3.8 million as compared with consolidated net income of $14.9 million for the same period in 2011. This decrease was primarily due to the MSTI impairment and the deferral of DGGS FERC related revenues as discussed above.

Nine Months Ended September 30, 2012 Compared with the Nine Months Ended September 30, 2011



	Nine Months Ended September 30,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	605.7	$	602.0	$	3.7		0.6	%
Natural Gas	182.8		230.9		(48.1		)	(20.8	)
Other	1.0		1.1		(0.1		)	(9.1	)
	$	789.5	$	834.0	$	(44.5	)	(5.3	)%



	Nine Months Ended September 30,
	2012		2011		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	244.9	$	246.6	$	(1.7	)	(0.7	)%
Natural Gas	83.0		123.9		(40.9		)	(33.0	)
	$	327.9	$	370.5	$	(42.6	)	(11.5	)%



	Nine Months Ended September 30,
	2012		2011		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	360.8	$	355.4	$	5.4		1.5	%
Natural Gas	99.8		107.0		(7.2		)	(6.7	)
Other	1.0		1.1		(0.1		)	(9.1	)
	$	461.6	$	463.5	$	(1.9	)	(0.4	)%

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



	Gross Margin 2012 vs. 2011
	(in millions)
Electric and natural gas retail volumes	$	(6.7	)
DGGS	(4.6		)
Gas production	(0.8		)
DSM lost revenues	5.1
Montana property tax tracker	2.4
Operating expenses recovered in trackers	1.4
Transmission capacity	1.4
South Dakota natural gas rate increase	1.3
Other	(1.4		)
Decrease in Consolidated Gross Margin	$	(1.9	)

This $1.9 million decrease in gross margin includes the following:


•	A decrease in electric and natural gas retail volumes due primarily to warmer winter and spring weather offset partially by increased electric usage due to warmer summer weather;


•	Lower DGGS related revenues primarily due to the deferral of DGGS FERC jurisdictional revenues as discussed above, offset in part by higher DGGS retail revenues due to the regulatory treatment of bonus depreciation and approximately $2.7 million that we had deferred in prior periods pending outcome of allocation uncertainty in Montana; and


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

These decreases were partly offset by the following:


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


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


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


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


•	An increase in South Dakota natural gas rates.

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 the electric tracker. 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. The study will also be subject to review and potential challenge by intervenors, such as the Montana Consumer Counsel. The MPSC could ultimately determine our requested amounts are too high and we may have to refund a portion of DSM lost revenues that we have recognized. We do not expect the MPSC to issue a final order related to the DSM lost revenues until at least the first quarter of 2013.



	Nine Months Ended September 30,
	2012		2011		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	195.7	$	203.3	$	(7.6	)	(3.7	)%
Mountain States Transmission Intertie impairment	24.0		—		24.0			—
Property and other taxes	74.4		68.5		5.9			8.6
Depreciation	79.4		75.6		3.8			5.0
	$	373.5	$	347.4	$	26.1		7.5	%

Consolidated operating, general and administrative expenses were $195.7 million for the nine months ended September 30, 2012, as compared with $203.3 million for the nine months ended September 30, 2011. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2012 vs. 2011
	(in millions)
Operating and maintenance	$	(2.3	)
Insurance settlements and recoveries	(1.4		)
Labor	(1.1		)
Bad debt expense	(1.0		)
Abandoned gas transmission project	(0.8		)
Plant operator costs	(0.7		)
Other	(0.3		)
Decrease in Operating, General & Administrative Expenses	$	(7.6	)

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


•	Lower proactive line maintenance and tree trimming expenses 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 insurance settlements and recoveries as 2011 results included an increase of $2.3 million related to a settlement with a former employee, partly offset by higher claims during 2012;


•	Decreased labor costs primarily due to a lower incentive accrual, offset in part by compensation increases and a higher number of employees;


•	Lower bad debt expense based on higher collections from customers and lower average customer bills due to warmer winter weather;


•	Third quarter 2011 results included the write-off of an abandoned gas transmission project due to the pursuit of a more cost effective solution; 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.

As discussed above, we recorded a charge of approximately $24 million in the third quarter of 2012 for the impairment of substantially all of the capitalized preliminary survey and investigative costs associated with MSTI.

Property and other taxes were $74.4 million for the nine months ended September 30, 2012, as compared with $68.5 million in the same period of 2011. This increase was due primarily to higher assessed property valuations in Montana and plant additions.

Depreciation expense was $79.4 million for the nine months ended September 30, 2012, as compared with $75.6 million in the same period of 2011. This increase was primarily due to plant additions.

Consolidated operating income for the nine months ended September 30, 2012 was $88.2 million, as compared with $116.2 million in the same period of 2011. This decrease was primarily due to the MSTI impairment and a decrease in gross margin partly offset by lower operating, general and administrative expenses as discussed above.

Consolidated interest expense for the nine months ended September 30, 2012 was $49.6 million, as compared with $50.7 million in the same period of 2011. This decrease was primarily due to lower interest rates on debt outstanding and higher capitalization of AFUDC.

Consolidated other income for the nine months ended September 30, 2012 was $3.1 million, as compared with $2.3 million in the same period of 2011. This increase was primarily due to higher capitalization of AFUDC.

We had a consolidated income tax expense for the nine months ended September 30, 2012 of $2.0 million, as compared with $9.3 million in the same period of 2011. Our effective tax rate was 4.8% for the nine months ended September 30, 2012 as compared with 13.7% for the nine months ended September 30, 2011. The following table summarizes the significant differences from the federal statutory rate (in thousands):



	Nine Months Ended September 30,
	2012			2011
Income Before Income Taxes	$	41.7		$	67.7

Income tax calculated at 35% federal statutory rate	(14.6		)	(23.7		)

Permanent or flow through adjustments:
Prior year permanent return to accrual adjustments	1.9			(2.6		)
Flow-through repairs deductions	9.5			8.7
Flow-through of state bonus depreciation deduction	2.2			4.5
Recognition of state net operating loss benefit/valuation allowance release	0.1			2.4
State income tax and other, net	(1.1		)	1.4
	12.6			14.4

Income tax expense	$	(2.0	)	$	(9.3	)

Consolidated net income for the nine months ended September 30, 2012 was $39.7 million as compared with $58.4 million for the same period in 2011. This decrease was primarily due to the MSTI impairment and the deferral of DGGS FERC related revenues as discussed above.

ELECTRIC SEGMENT

We have various classifications of electric revenues, defined as follows:


•	Retail: Sales of electricity to residential, commercial and industrial customers.


•	Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers.


•	Transmission: Reflects transmission revenues regulated by the FERC.


•	Ancillary Services: FERC jurisdictional services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation service, reserves and voltage support.


•	Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are based on prevailing market prices.


•	Other: Miscellaneous electric revenues.

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



	Results
	2012			2011		Change			% Change
	(dollars in millions)
Retail revenues	$	203.3		$	189.2	$	14.1		7.5	%
Regulatory amortization	(5.2		)	2.0		(7.2		)	(360.0	)
Total retail revenues	198.1			191.2		6.9			3.6
Transmission	11.6			11.5		0.1			0.9
Ancillary services	(9.2		)	2.2		(11.4		)	(518.2	)
Wholesale	0.8			0.4		0.4			100.0
Other	1.2			1.3		(0.1		)	(7.7	)
Total Revenues	202.5			206.6		(4.1		)	(2.0	)
Total Cost of Sales	83.8			85.2		(1.4		)	(1.6	)
Gross Margin	$	118.7		$	121.4	$	(2.7	)	(2.2	)%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Electric
Montana	$	63,951	$	58,531	587	552	273,130	271,073
South Dakota	13,947		12,858		158	150	48,940	48,664
Residential	77,898		71,389		745	702	322,070	319,737
Montana	83,605		79,634		867	840	62,179	61,623
South Dakota	19,643		18,076		259	250	12,235	12,054
Commercial	103,248		97,710		1,126	1,090	74,414	73,677
Industrial	10,011		8,961		806	718	74	73
Other	12,148		11,179		103	92	7,816	7,627
Total Retail Electric	$	203,305	$	189,239	2,780	2,602	404,374	401,114
Total Wholesale Electric	$	781	$	378	41	15	—	—



	Degree Days			2012 as compared with:
Cooling Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	395	308	260	28% warmer	52% warmer
South Dakota	911	753	635	21% warmer	43% warmer



	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	244	235	367	4% colder	34% warmer
South Dakota	65	70	83	7% warmer	22% warmer

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



	Gross Margin 2012 vs. 2011
	(in millions)
DGGS	$	(9.6	)
Retail volumes	3.8
Operating expenses recovered in trackers	1.6
Montana property tax tracker	1.1
DSM lost revenues	0.7
Other	(0.3		)
Decrease in Gross Margin	$	(2.7	)

This decrease in gross margin was primarily due to the impacts of the FERC jurisdictional DGGS deferral discussed above, offset in part by higher DGGS retail revenues due to the regulatory treatment of bonus depreciation.

This was partly offset by the following improvements:


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


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


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


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

The decrease 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.

Retail volumes increased from warmer weather and customer growth. 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.

Nine Months Ended September 30, 2012 Compared with the Nine Months Ended September 30, 2011



	Results
	2012			2011		Change			% Change
	(dollars in millions)
Retail revenues	$	561.9		$	552.4	$	9.5		1.7	%
Regulatory amortization	10.8			6.0		4.8			80.0
Total retail revenues	572.7			558.4		14.3			2.6
Transmission	33.7			32.3		1.4			4.3
Ancillary services	(6.5		)	5.3		(11.8		)	(222.6	)
Wholesale	2.4			1.5		0.9			60.0
Other	3.4			4.5		(1.1		)	(24.4	)
Total Revenues	605.7			602.0		3.7			0.6
Total Cost of Sales	244.9			246.6		(1.7		)	(0.7	)
Gross Margin	$	360.8		$	355.4	$	5.4		1.5	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Electric
Montana	$	188,768	$	187,856	1,749	1,786	273,711	271,975
South Dakota	36,993		36,556		424	448	48,887	48,660
Residential	225,761		224,412		2,173	2,234	322,598	320,635
Montana	230,498		228,556		2,416	2,407	62,046	61,516
South Dakota	52,887		49,748		712	702	12,116	11,938
Commercial	283,385		278,304		3,128	3,109	74,162	73,454
Industrial	28,185		27,723		2,217	2,113	74	72
Other	24,600		21,936		178	150	6,101	5,953
Total Retail Electric	$	561,931	$	552,375	7,696	7,606	402,935	400,114
Total Wholesale Electric	$	2,382	$	1,507	137	88	—	—



	Degree Days			2012 as compared with:
Cooling Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	450	324	301	39% warmer	50% warmer
South Dakota	1,061	814	701	30% warmer	51% warmer



	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	4,488	5,235	5,007	14% warmer	10% warmer
South Dakota	4,375	6,211	5,683	30% warmer	23% warmer

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



	Gross Margin 2012 vs. 2011
	(in millions)
DSM lost revenues	$	5.1
Operating expenses recovered in trackers	2.4
Montana property tax tracker	2.0
Transmission capacity	1.4
DGGS	(4.6		)
Retail volumes	(0.4		)
Other	(0.5		)
Increase in Gross Margin	$	5.4

The increase in gross margin is primarily due to:


•	DSM lost revenues recovered through our supply tracker filings as discussed above;


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


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


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

Partially offsetting these increases was lower DGGS related revenues as discussed above and a decrease in retail volumes due primarily to warmer winter weather.

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.

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.

NATURAL GAS SEGMENT

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



	Results
	2012		2011		Change			% Change
	(dollars in millions)
Retail revenues	$	19.9	$	23.7	$	(3.8	)	(16.0	)%
Regulatory amortization	5.1		5.2		(0.1		)	(1.9	)
Total retail revenues	25.0		28.9		(3.9		)	(13.5	)
Wholesale and other	8.0		8.1		(0.1		)	(1.2	)
Total Revenues	33.0		37.0		(4.0		)	(10.8	)
Total Cost of Sales	9.2		12.8		(3.6		)	(28.1	)
Gross Margin	$	23.8	$	24.2	$	(0.4	)	(1.7	)%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Gas
Montana	$	8,795	$	10,151	758	790	158,524	157,491
South Dakota	1,757		1,717		113	121	37,551	37,167
Nebraska	1,887		2,204		149	155	36,222	36,175
Residential	12,439		14,072		1,020	1,066	232,297	230,833
Montana	5,171		6,020		515	525	22,181	22,024
South Dakota	1,130		1,462		171	199	5,931	5,854
Nebraska	985		1,883		187	289	4,517	4,528
Commercial	7,286		9,365		873	1,013	32,629	32,406
Industrial	93		136		10	13	269	275
Other	68		82		8	8	150	147
Total Retail Gas	$	19,886	$	23,655	1,911	2,100	265,345	263,661



	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	244	235	367	4% colder	34% warmer
South Dakota	65	70	83	7% warmer	22% warmer
Nebraska	27	49	46	45% warmer	41% warmer

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



	Gross Margin 2012 vs. 2011
	(in millions)
Retail volumes	$	(0.3	)
Operating expenses recovered in trackers	(0.2		)
Montana property tax tracker	0.3
South Dakota rate increase	0.3
Other	(0.5		)
Decrease in Gross Margin	$	(0.4	)

This decrease in gross margin was primarily due to reduced retail volumes driven by lower customer usage. 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.

Nine Months Ended September 30, 2012 Compared with the Nine Months Ended September 30, 2011



	Results
	2012		2011			Change			% Change
	(dollars in millions)
Retail revenues	$	150.0	$	199.4		$	(49.4	)	(24.8	)%
Regulatory amortization	7.3		(0.8		)	8.1			(1,012.5	)
Total retail revenues	157.3		198.6			(41.3		)	(20.8	)
Wholesale and other	25.5		32.3			(6.8		)	(21.1	)
Total Revenues	182.8		230.9			(48.1		)	(20.8	)
Total Cost of Sales	83.0		123.9			(40.9		)	(33.0	)
Gross Margin	$	99.8	$	107.0		$	(7.2	)	(6.7	)%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2012		2011		2012	2011	2012	2011
	(in thousands)
Retail Gas
Montana	$	67,049	$	85,553	7,656	8,883	159,316	158,457
South Dakota	15,447		20,589		1,709	2,333	37,792	37,388
Nebraska	14,234		18,571		1,578	2,038	36,520	36,525
Residential	96,730		124,713		10,943	13,254	233,628	232,370
Montana	34,409		44,543		4,004	4,667	22,329	22,188
South Dakota	9,656		14,742		1,545	2,107	5,961	5,899
Nebraska	7,880		13,591		1,279	2,143	4,571	4,577
Commercial	51,945		72,876		6,828	8,917	32,861	32,664
Industrial	672		1,055		80	115	273	279
Other	641		763		85	93	150	146
Total Retail Gas	$	149,988	$	199,407	17,936	22,379	266,912	265,459



	Degree Days			2012 as compared with:
Heating Degree-Days	2012	2011	Historic Average	2011	Historic Average
Montana	4,488	5,235	5,007	14% warmer	10% warmer
South Dakota	4,375	6,211	5,683	30% warmer	23% warmer
Nebraska	3,611	4,847	4,684	26% warmer	23% warmer

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



	Gross Margin 2012 vs. 2011
	(in millions)
Retail volumes	$	(6.3	)
Operating expenses recovered in trackers	(1.0		)
Gas production	(0.8		)
South Dakota rate increase	1.3
Montana property tax tracker	0.4
Other	(0.8		)
Decrease in Gross Margin	$	(7.2	)

This decrease in gross margin and volumes was primarily due to warmer winter and spring weather. In addition, gas production margin decreased from lower market prices.

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 September 30, 2012, our total net liquidity was approximately $312.2 million, including $18.2 million of cash and $294.0 million of revolving credit facility availability. Revolving credit facility availability was $296.5 million as of October 19, 2012.

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



Amount outstanding	$	—
Daily average amount outstanding	$	47.6
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. Since inception, 815,416 shares of our common stock at an average price of $35.58 per share have been issued. Proceeds received were approximately $28.5 million, which are net of sales commissions paid to UBS of approximately $0.3 million and other fees. In addition, we issued $150 million of first mortgage bonds during the third quarter of 2012. Proceeds were used primarily to repay commercial paper borrowings.

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. In order to maintain this debt to total capital ratio, we may issue additional common stock of approximately $20 million during the remainder of 2012 to fund our wind generation project or other growth opportunities.

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 and electric sales 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.

As of September 30, 2012, we are under collected on our current Montana natural gas and electric trackers by approximately $2.2 million, as compared with an under collection of $14.7 million as of December 31, 2011, and an under collection of $4.1 million as of September 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 October 19, 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.

Cash Flows

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



	Nine Months Ended September 30,
	2012			2011
Operating Activities
Net income	$	39.7		$	58.4
Non-cash adjustments to net income	124.0			109.3
Changes in working capital	68.7			46.6
Other	(9.8		)	(3.8		)
	222.6			210.5

Investing Activities
Property, plant and equipment additions	(157.8		)	(124.5		)
Asset acquisition	(18.4		)	—
Other	0.3			0.2
	(175.9		)	(124.3		)

Financing Activities
Proceeds from issuance of common stock, net	28.5			—
Issuances (repayments) of long-term debt, net	146.1			(159.6		)
(Repayments) issuances of short-term borrowings, net	(166.9		)	113.0
Dividends on common stock	(40.6		)	(38.9		)
Other	(1.5		)	(0.9		)
	(34.4		)	(86.4		)

Net Increase (Decrease) in Cash and Cash Equivalents	$	12.3		$	(0.2	)
Cash and Cash Equivalents, beginning of period	$	5.9		$	6.2
Cash and Cash Equivalents, end of period	$	18.2		$	6.0

Cash Provided by Operating Activities

As of September 30, 2012, cash and cash equivalents were $18.2 million as compared with $5.9 million at December 31, 2011 and $6.0 million at September 30, 2011. Cash provided by operating activities totaled $222.6 million for the nine months ended September 30, 2012 as compared with $210.5 million during the nine months ended September 30, 2011. This increase in operating cash flows is primarily due to improvements in the collection of our supply costs and lower average prices for gas storage inventory. These increases were offset in part by increased expenditures related to the distribution system infrastructure project (DSIP) implementation.

Cash Used in Investing Activities

Cash used in investing activities increased by approximately $51.6 million as compared with the first nine months of 2011. Plant additions during 2012 include maintenance additions of approximately $91.4 million, the Bear Paw natural gas acquisition of $18.4 million, supply related capital expenditures of approximately $45.9 million, primarily related to the 60 MW peaking facility in South Dakota, and DSIP capital expenditures of approximately $14.0 million.

Cash Used in Financing Activities

Cash used in financing activities totaled approximately $34.4 million during the nine months ended September 30, 2012 as compared with approximately $86.4 million during the nine months ended September 30, 2011. During the nine months ended September 30, 2012, net cash used in financing activities consisted of net repayments of commercial paper of $166.9 million and the payment of dividends of $40.6 million offset in part by proceeds received from the issuance of common stock pursuant

to our equity distribution agreement of $28.5 million and proceeds from the issuance of debt of $150.0 million. During the nine months ended September 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 $113.0 million, the repayment of long-term debt of $6.6 million and the payment of dividends of $38.9 million.

Financing Activities - In August 2012, we issued $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 issued $60 million aggregate principal amount of Montana and South Dakota First Mortgage Bonds at a fixed interest rate of 4.30% maturing in 2052. The bonds are secured by our electric and natural gas assets in the respective jurisdictions. The bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used primarily to repay commercial paper borrowings.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of September 30, 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	$	1,055,067	$	—	$	—	$	—	$	—	$	150,000	$	905,067
Capital leases	33,564		389		1,613		1,668		1,732		1,837		26,325
Future minimum operating lease payments	5,489		518		1,734		1,152		786		610		689
Estimated pension and other postretirement obligations (1)	56,716		916		14,400		13,800		13,800		13,800		N/A
Qualifying facilities liability (2)	1,218,611		17,039		69,816		72,354		74,135		75,945		909,322
Supply and capacity contracts (3)	1,579,123		78,555		267,474		191,055		116,565		117,707		807,767
Contractual interest payments on debt	641,146		16,795		56,880		56,880		56,880		56,880		396,831
Total Commitments (4)	$	4,589,716	$	114,212	$	411,917	$	336,909	$	263,898	$	416,779	$	3,046,001

_________________________


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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s discussion and analysis of financial condition and results of operations is based on our condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.

As of September 30, 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.


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 September 30, 2012, we had no commercial paper outstanding and no borrowings on our revolving credit facility.

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.


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.

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

See Note 14, 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. In September 2012, we received a non-binding initial decision from a FERC ALJ concluding that we should only recover approximately 4.4% of the revenue requirement from FERC jurisdictional customers. Although we are asking the FERC to reject this decision, there is significant uncertainty related to the FERC's ultimate treatment of our cost allocation methodology, which could result in an inability to fully recover our costs.

We are subject to various rules and regulations of the FERC covering our electric and natural gas business. We must also comply with established reliability standards and requirements, 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, NERC, or a regional reliability organization may assess penalties against any responsible entity found to be in noncompliance with their rules, regulations or standards. Violations may be discovered through various means, including self-certification, self-reporting, compliance investigations, periodic data submissions, exception reporting, and complaints. Penalties for the most severe violations can reach as high as $1 million per violation, per day. If a serious reliability incident or other incidence of noncompliance 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 was signed into law, which is intended to improve the regulation of financial markets. Certain provisions of the Act relating to derivatives could result in increased capital and/or collateral requirements. Despite certain exemptions in the law, 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 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 provide for substantial civil and criminal fines for noncompliance which, if imposed, could result in material costs or liabilities. In addition, there is a risk of environmental damages claims from private parties or government entities. 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 a reduction in revenue and / or increased expenses which may not be fully recoverable from customers.

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.

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

Our proposed capital investment projects are based on assumptions regarding future growth and resulting power demand that may not be realized. This planning process must look many years into the future in order to accommodate the long lead times associated with the permitting and construction of new generation facilities. Inherent risk exists in predicting demand this far into the future as these future loads are dependent on many uncertain factors, including regional economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. We may increase our transmission and/or baseload capacity and have excess capacity if anticipated growth levels are not realized. The resulting excess capacity could exceed our obligation to serve retail customers or demand for transmission capacity and, as a result, may not be recoverable 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. Operational risks 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 or ancillary services, 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 costs associated with the execution of contracts with third parties for replacement regulation service for the period of time in which DGGS was not operational. To the extent that the repair costs are not covered by the manufacturer's warranty or the contract costs are not fully recoverable from customers, our results of operations and financial position could be adversely affected.

In addition, 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.

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 depressed 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.

We currently procure a large portion of our natural gas supply and 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 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 harm our physical infrastructure. We may not recover all costs related to mitigating these physical and financial risks.

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

Our cash requirements are driven by the capital-intensive nature of our business. Access to the capital and credit markets, at a reasonable cost, is necessary for us to fund our operations, including capital requirements. We rely on a revolving credit facility and commercial paper market for short-term liquidity needs due to the seasonality of our business, and on capital markets to raise capital for growth projects that are not otherwise provided by operating cash flows. Instability in the financial markets may increase the cost of capital, limit our ability to draw on our revolving credit facility, access the commercial paper market and/or raise capital. If we are unable to obtain the liquidity needed to meet our business requirements on favorable terms, we may defer growth projects and/or capital expenditures.

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

A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms, including through the commercial paper markets. Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our results of operations.

Our secured credit ratings are also tied to our ability to invest in unregulated ventures due to an existing stipulation with the MPSC and MCC, which includes diminishing limits for such investment at certain credit rating levels. The stipulation does not limit investment in unregulated ventures so long as we maintain credit ratings on a secured basis of at least BBB+ from S&P and Baa1 from Moody's.

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

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

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

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

ITEM 6. EXHIBITS

(a) Exhibits

Exhibit 4.1—Thirtieth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon and Philip L. Watson, as trustees under the Mortgage and Deed of Trust dated as of October 1, 1945 (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499).

Exhibit 4.2—Tenth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon, as trustees under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499).

Exhibit 31.1—Certification of chief executive officer.

Exhibit 31.2—Certification of chief financial officer.

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

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

Exhibit 101.INS—XBRL Instance Document

Exhibit 101.SCH—XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL—XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF—XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB—XBRL Taxonomy Label Linkbase Document

Exhibit 101.PRE—XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

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



			NorthWestern Corporation
Date:	October 24, 2012	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

EXHIBIT INDEX



Exhibit Number		Description
4.1		Thirtieth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon and Philip L. Watson, as trustees under the Mortgage and Deed of Trust dated as of October 1, 1945 (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499).
4.2		Tenth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon, as trustees under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499).
*31.1		Certification of chief executive officer.
*31.2		Certification of chief financial officer.
*32.1		Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Taxonomy Extension Schema Document
*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB		XBRL Taxonomy Label Linkbase Document
*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

_________________________


*	Filed herewith