NORTHWESTERN CORP - Quarter Report: 2013 September (Form 10-Q)

Location of gain reclassified from AOCI to Income

Nine Months Ended September 30, 2013 and 2012

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, 2013

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

(Exact name of registrant as specified in its charter)



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

38,463,262 shares outstanding at October 18, 2013

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, 2013 and December 31, 2012	4
	Condensed Consolidated Statements of Income (Loss) — Three and Nine Months Ended September 30, 2013 and 2012	5
	Condensed Consolidated Statements of Comprehensive Income (Loss) — Three and Nine Months Ended September 30, 2013 and 2012	6
	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2013 and 2012	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	52
PART II. OTHER INFORMATION		53
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	53
Item 6.	Exhibits	58
SIGNATURES		59

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.

In addition, actual results may differ materially from those contemplated in any forward-looking statement due to the timing and likelihood of the closing of the purchase of PPL Montana LLC's hydro-electric generating facilities. Refer to Acquisition Agreements on page 9 for additional information relative to the transaction.

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, 2013			December 31, 2012

ASSETS
Current Assets:
Cash and cash equivalents	$	10,921		$	9,822
Restricted cash	8,236			6,700
Accounts receivable, net	129,195			143,695
Inventories	62,623			54,161
Regulatory assets	26,142			40,301
Deferred income taxes	30,255			37,143
Other	13,289			11,306
Total current assets	280,661			303,128
Property, plant, and equipment, net	2,573,562			2,435,590
Goodwill	355,128			355,128
Regulatory assets	395,746			367,890
Other noncurrent assets	28,553			23,797
Total assets	$	3,633,650		$	3,485,533
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,659		$	1,612
Short-term borrowings	102,980			122,934
Accounts payable	63,390			83,746
Accrued expenses	209,719			192,548
Regulatory liabilities	40,216			48,425
Total current liabilities	417,964			449,265
Long-term capital leases	30,315			31,562
Long-term debt	1,055,091			1,055,074
Deferred income taxes	397,856			363,928
Noncurrent regulatory liabilities	343,597			276,618
Other noncurrent liabilities	384,545			375,054
Total liabilities	2,629,368			2,551,501
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 42,059,560 and 38,462,477 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	421			408
Treasury stock at cost	(91,809		)	(90,702		)
Paid-in capital	896,242			849,218
Retained earnings	197,579			172,791
Accumulated other comprehensive income	1,849			2,317
Total shareholders' equity	1,004,282			934,032
Total liabilities and shareholders' equity	$	3,633,650		$	3,485,533

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Unaudited)

(in thousands, except per share amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues
Electric	$	227,103		$	202,485		$	637,667		$	605,716
Gas	34,772			32,965			196,652			182,812
Other	373			416			1,110			1,041
Total Revenues	262,248			235,866			835,429			789,569
Operating Expenses
Cost of sales	104,298			93,061			343,407			327,884
Operating, general and administrative	72,540			63,056			208,741			195,725
Mountain States Transmission Intertie impairment	—			24,039			—			24,039
Property and other taxes	25,956			24,796			77,525			74,395
Depreciation	28,053			26,505			84,685			79,364
Total Operating Expenses	230,847			231,457			714,358			701,407
Operating Income	31,401			4,409			121,071			88,162
Interest Expense, net	(17,056		)	(17,743		)	(50,976		)	(49,598		)
Other Income	3,117			974			6,760			3,134
Income (Loss) Before Income Taxes	17,462			(12,360		)	76,855			41,698
Income Tax (Expense) Benefit	(1,815		)	8,588			(8,965		)	(1,989		)
Net Income (Loss)	$	15,647		$	(3,772	)	$	67,890		$	39,709
Average Common Shares Outstanding	38,459			37,201			37,983			36,723
Basic Earnings (Loss) per Average Common Share	$	0.41		$	(0.10	)	$	1.79		$	1.09
Diluted Earnings (Loss) per Average Common Share	$	0.40		$	(0.10	)	$	1.78		$	1.08
Dividends Declared per Common Share	$	0.38		$	0.37		$	1.14		$	1.11

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(in thousands, except per share amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net Income (Loss)	$	15,647		$	(3,772	)	$	67,890		$	39,709
Other comprehensive (loss) income, net of tax:
Reclassification of net gains on derivative instruments	(183		)	(178		)	(549		)	(552		)
Postretirement medical liability adjustment	—			—			—			205
Foreign currency translation	(54		)	(79		)	81			(80		)
Total Other Comprehensive Loss	(237		)	(257		)	(468		)	(427		)
Comprehensive Income (Loss)	$	15,410		$	(4,029	)	$	67,422		$	39,282

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)



	Nine Months Ended September 30,
	2013			2012
OPERATING ACTIVITIES:
Net income	$	67,890		$	39,709
Items not affecting cash:
Depreciation	84,685			79,364
Amortization of debt issue costs, discount and deferred hedge gain	290			273
Amortization of restricted stock	1,826			2,199
Equity portion of allowance for funds used during construction	(3,572		)	(3,311		)
Gain on disposition of assets	(761		)	(232		)
Deferred income taxes	41,159			21,663
Mountain States Transmission Intertie impairment	—			24,039
Changes in current assets and liabilities:
Restricted cash	(1,536		)	4,731
Accounts receivable	14,500			37,688
Inventories	(8,462		)	156
Other current assets	(1,983		)	(712		)
Accounts payable	(19,512		)	(9,604		)
Accrued expenses	22,358			29,139
Regulatory assets	9,384			(3,266		)
Regulatory liabilities	(8,209		)	10,573
Other noncurrent assets	(32,298		)	(13,400		)
Other noncurrent liabilities	5,579			3,619
Cash provided by operating activities	171,338			222,628
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(153,951		)	(157,859		)
Asset acquisition	—			(18,384		)
Proceeds from sale of assets	3,887			262
Cash used in investing activities	(150,064		)	(175,981		)
FINANCING ACTIVITIES:
Treasury stock activity	(1,107		)	(557		)
Proceeds from issuance of common stock, net	44,102			28,477
Dividends on common stock	(43,103		)	(40,584		)
Issuance of long-term debt	—			150,000
Repayments on long-term debt	(113		)	(3,871		)
Repayments of short-term borrowings, net	(19,954		)	(166,934		)
Financing costs	—			(910		)
Cash used in financing activities	(20,175		)	(34,379		)
Increase in Cash and Cash Equivalents	1,099			12,268
Cash and Cash Equivalents, beginning of period	9,822			5,928
Cash and Cash Equivalents, end of period	$	10,921		$	18,196
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	$	47		$	1,944
Interest	40,873			34,416
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	11,245			13,292

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 673,200 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, 2013, 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, 2012.

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 $291.8 million through 2024.

(2) New Accounting Standards

Accounting Standards Issued

In July 2013, the Financial Accounting Standards Board (FASB) issued guidance for the presentation of unrecognized tax benefits when a net operating loss carryforward or other tax credit carryforwards exist at the reporting date. If such a carryforward exists, the guidance generally requires an unrecognized tax benefit to be presented as a decrease in a deferred tax asset. Our current practice is consistent with this guidance.

Accounting Standards Adopted

In February 2013, the FASB issued guidance that requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. Significant amounts are required to be presented by the respective line items of net income or should be cross-referenced to other disclosures. These disclosures may be presented on the income statement or in the notes to the financial statements. We adopted this standard during the first quarter of 2013 and have included the required disclosures in notes to the financial statements. The adoption of this standard did not have a material effect on our financial statement disclosures.

(3) Acquisition Agreements

Hydro Transaction

On September 26, 2013, we entered into an agreement with PPL Montana, LLC (PPL Montana), a wholly owned subsidiary of PPL Corporation, to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity, for a purchase price of $900 million (Hydro Transaction). The purchase price will be subject to adjustment for proration of operating expenses, performance of planned capital expenditures, and termination of certain power purchase agreements. If the acquisition is completed, we will own over 60 percent of our average load serving requirements in Montana.

We expect to close on this acquisition during the second half of 2014; however, it is subject to customary conditions and approvals, including approval from the Federal Energy Regulatory Commission (FERC), the Montana Public Service Commission (MPSC), other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act. In addition, the closing is conditioned upon the termination or waiver of certain restrictions applicable to the hydro assets under a sale-leaseback arrangement through which PPL Montana holds its interest in the Colstrip thermal generating facility (which interest we will not be acquiring). Through September 30, 2013 we have expensed approximately $3.3 million of legal and professional fees associated with the transaction.

Either party may terminate the agreement if the closing does not occur by September 26, 2014; however, this date will be extended for an additional six months if any governmental approval is still pending.

Natural Gas Production Assets

In May 2013, we entered into an agreement to purchase additional natural gas production interests in northern Montana's Bear Paw Basin for approximately $70 million, subject to purchase price adjustments. This purchase would include an 82 percent interest in the Havre Pipeline Company, LLC (Havre Pipeline), which represents approximately $6 million of the purchase price. Due to the requirements of a previous stipulation with the MPSC, we requested a regulatory waiver in June 2013 to acquire the Havre Pipeline. In addition, approval of the sale of the Havre Pipeline must also be approved by the MPSC. In October 2013, the MPSC approved our waiver request. While the seller does not believe MPSC approval is needed to sell its ownership interests in the Havre Pipeline, they have filed a request for determination, which we expect the MPSC to decide on by October 31, 2013. Either party to the agreement may terminate the transaction if the closing does not occur by October 31, 2013. If the MPSC issues a favorable order on the seller's filing by October 31, 2013, we hope to extend the agreement and close on this transaction during the fourth quarter of 2013.

As of January 1, 2013, the amount of net proven developed producing reserves associated with the pending acquisition was estimated to be 64.6 billion cubic feet. We estimate the current annual production associated with this pending acquisition would be approximately 28 percent of our total annual natural gas load in Montana, which would increase our total owned production to approximately 37 percent.

(4) Regulatory Matters

Dave Gates Generating Station at Mill Creek (DGGS)

As a result of a FERC Administrative Law Judge's (ALJ) nonbinding decision issued in September 2012, we have cumulative deferred revenue of approximately $22.5 million, which is subject to refund and recorded within current regulatory liabilities in the Condensed Consolidated Balance Sheets. The ALJ concluded we should allocate only a fraction of the costs we believe (based on past practice) should be allocated to FERC jurisdictional customers. The matter has been fully briefed before the FERC.

We do not know when the FERC will consider the matter and issue its decision. The FERC is not obligated to follow any of the ALJ's findings and conclusions, and the FERC can accept or reject the decision in whole or in part. If the FERC upholds the ALJ's 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 or beyond. We continue to bill FERC jurisdictional customers interim rates that have been in effect since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC.

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 its April 2012 electric supply tracker order for the 2010/2011 tracker period, the MPSC had authorized us to include forecasted demand-side management (DSM) lost revenues in future tracker filings. We had not recognized the entire forecasted amount for tracker periods since 2010/2011 as we were required to provide the MPSC with a detailed independent study supporting our requested DSM lost revenues.

During October 2013, the MPSC approved an order related to our 2012 electric supply tracker filing (covering July 1, 2011 through June 30, 2012), which includes a decision on a review of an independent study related to our request for DSM lost revenues, addresses future DSM lost revenue recovery, and includes a decision on DGGS related incremental contract costs included in the 2012 filing. Based on the MPSC's October 2013 decision we recognized revenue of approximately $4.6 million during the three months ended September 30, 2013 related to prior periods (including $2.3 million related to calendar year 2012) that we had previously deferred pending outcome of the review of the study results.

The order also includes a provision expressing concern with the policy of continuing to allow DSM lost revenue recovery, indicating that we bear the burden of demonstrating why any incremental DSM lost revenue recovery from the date of its order forward is reasonable and in the public interest. As of September 30, 2013, we have recognized approximately $7.8 million of DSM lost revenues for the 2012/ 2013 tracker period and approximately $1.9 million for the 2013/2014 tracker period. Based on the MPSC's order, we expect to be able to collect at least $7.8 million of DSM lost revenues for each annual tracker period; however, since the 2012/2013 annual tracker filing is still subject to final approval, the MPSC may ultimately require us to refund a portion of the DSM lost revenues we have recognized since July 2012. We do not expect the MPSC to issue a final order related to 2012/2013 DSM lost revenues until at least the first quarter of 2014.

Lastly, the MPSC indicated that $1.4 million of incremental costs associated with regulation service acquired from third parties during a 2012 outage at DGGS were imprudently incurred, and disallowed recovery. While we recognized these costs consistent with the MPSC order, we are evaluating a potential appeal of the MPSC's decision.

Natural Gas Production Assets

During the third quarter of 2012, we completed the purchase of natural gas production interests in northern Montana's Bear Paw Basin, including a 75% interest in two gas gathering systems. We are collecting the cost of service for natural gas produced from these assets, including a return on our investment, through our natural gas supply tracker on an interim basis. As a result, we do not expect to file an application with the MPSC to place these assets in natural gas rate base until our next natural gas rate case. Since acquisition, we have recognized approximately $3.2 million of revenue that is subject to refund.

(5) Income Taxes

The following table reconciles our effective income tax rate to the federal statutory rate:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Flow-through repairs deductions	(17.7	)	14.6		(16.8	)	(22.9	)
Flow-through of state bonus depreciation deduction	(4.5	)	2.2		(4.3	)	(5.2	)
Production tax credits	(2.8	)	—		(2.8	)	—
Prior year permanent return to accrual adjustments	—		15.0		0.6		(4.5	)
Recognition of state net operating loss benefit / valuation allowance release	—		0.4		—		(0.1	)
State income tax and other, net	0.4		2.3		—		2.5
	10.4	%	69.5	%	11.7	%	4.8	%

The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Income (Loss) Before Income Taxes	$	17,462		$	(12,360	)	$	76,855		$	41,698

Income tax calculated at 35% federal statutory rate	6,112			(4,326		)	26,899			14,594

Permanent or flow through adjustments:
Flow-through repairs deductions	(3,086		)	(1,808		)	(12,898		)	(9,547		)
Flow-through of state bonus depreciation deduction	(786		)	(276		)	(3,287		)	(2,159		)
Production tax credits	(482		)	—			(2,152		)	—
Prior year permanent return to accrual adjustments	—			(1,857		)	541			(1,857		)
Recognition of state net operating loss benefit / valuation allowance release	—			(51		)	—			(51		)
State income tax and other, net	57			(270		)	(138		)	1,009
	$	(4,297	)	$	(4,262	)	$	(17,934	)	$	(12,605	)

Income tax expense (benefit)	$	1,815		$	(8,588	)	$	8,965		$	1,989

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, state tax benefit of bonus depreciation deductions and production tax credits. 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 $114.0 million as of September 30, 2013, including approximately $79.1 million that, if recognized, would impact our effective tax rate. It is reasonably possible that a

significant portion of our unrecognized tax benefits may decrease in the next 12 months due to the expiration of statutes of limitation.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the nine months ended September 30, 2013, we recognized approximately $0.3 million of interest in the Condensed Consolidated Statement of Income. As of September 30, 2013 we have $0.3 million of interest accrued in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2012, we did not recognize any expense for interest or penalties, and did not have any amounts accrued as of December 31, 2012, for the payment of interest and penalties.

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. That guidance was updated in the third quarter of 2012 to allow companies additional time to adopt the safe harbor method. 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. In September 2013, the IRS issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. We continue to evaluate what impact the adoption of the regulations will have on our consolidated financial statements. We do not expect the adoption of the regulations to have a material impact on our consolidated financial statements.

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, 2013, 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.

There were no changes in our goodwill during the nine months ended September 30, 2013. Goodwill by segment is as follows for both September 30, 2013 and December 31, 2012 (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 (in thousands):



	September 30, 2013
	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	$	(54	)	$	—	$	(54	)	$	81		$	—	$	81
Reclassification of net gains on derivative instruments to net income	(297		)	114		(183		)	(891		)	342		(549		)
Other comprehensive loss	$	(351	)	$	114	$	(237	)	$	(810	)	$	342	$	(468	)



	September 30, 2012
	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	$	(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	)

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, 2013			December 31, 2012
Foreign currency translation	$	447		$	366
Derivative instruments designated as cash flow hedges	3,694			4,243
Pension and postretirement medical plans	(2,292		)	(2,292		)
Accumulated other comprehensive income	$	1,849		$	2,317

The following table displays the changes in AOCI by component, net of tax (in thousands):



		September 30, 2013
		Nine Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Gains on Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	4,243		$	(2,292	)	$	366	$	2,317
Other comprehensive income before reclassifications		—			—			81		81
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(549		)	—			—		(549		)
Net current-period other comprehensive (loss) income		(549		)	—			81		(468		)
Ending balance		$	3,694		$	(2,292	)	$	447	$	1,849

(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, in the past we have used and in the future 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, 2013 and December 31, 2012. 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, 2013		December 31, 2012

Natural gas net derivative liability	Accrued Expenses	$	653	$	5,428

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, 2013		September 30, 2012		September 30, 2013		September 30, 2012

Natural gas	$	1,624	$	5,527	$	4,775	$	12,743

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.

As of September 30, 2013, none of the forward purchase contracts that do not qualify for NPNS contain credit risk-related contingent features.

Interest Rate Swaps Designated as Cash Flow Hedges

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 $6.0 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of September 30, 2013, 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. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. 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
	(in thousands)
September 30, 2013
Restricted cash	$	7,987	$	—		$	—	$	—	$	7,987
Rabbi trust investments	16,835		—			—		—		16,835
Derivative liability (1)	—		(653		)	—		—		(653		)
Total	$	24,822	$	(653	)	$	—	$	—	$	24,169

December 31, 2012
Restricted cash	$	6,392	$	—		$	—	$	—	$	6,392
Rabbi trust investments	10,522		—			—		—		10,522
Derivative liability (1)	—		(5,428		)	—		—		(5,428		)
Total	$	16,914	$	(5,428	)	$	—	$	—	$	11,486

_________________________


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

We present our derivative assets and liabilities on a net basis in the Condensed Consolidated Balance Sheets. The table above disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required and classifies each individual asset or liability within the appropriate level in the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts. These gross balances are intended solely to provide information on sources of inputs

to fair value and do not represent our actual credit exposure or net economic exposure. Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices.

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

Financial Instruments

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



	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,055,091	$	1,160,253	$	1,055,074	$	1,229,233

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 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 April 2012, we entered into an Equity Distribution Agreement 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, 1,917,996 shares of our common stock at an average price of $38.38 per share have been issued, for net proceeds of $72.6 million. During the three and nine months ended September 30, 2013, we sold 8,400 and 1,102,580 shares, of our common stock at an average price of $40.00 and $40.45 per share, respectively. Proceeds received during the three and nine months ended September 30, 2013, were approximately $0.3 million and $44.1 million, which are net of sales commissions of approximately $15,000 and $0.5 million, respectively, and other fees.

(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 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, 2013	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	227,103		$	34,772		$	373		$	—	$	262,248
Cost of sales	95,264			9,034			—			—		104,298
Gross margin	131,839			25,738			373			—		157,950
Operating, general and administrative	49,155			18,521			4,864			—		72,540
Property and other taxes	19,381			6,572			3			—		25,956
Depreciation	22,150			5,895			8			—		28,053
Operating income (loss)	41,153			(5,250		)	(4,502		)	—		31,401
Interest expense	(14,302		)	(2,560		)	(194		)	—		(17,056		)
Other income	2,213			878			26			—		3,117
Income tax (expense) benefit	(8,412		)	3,520			3,077			—		(1,815		)
Net income (loss)	$	20,652		$	(3,412	)	$	(1,593	)	$	—	$	15,647
Total assets	$	2,542,068		$	1,082,294		$	9,288		$	—	$	3,633,650
Capital expenditures	$	55,579		$	9,823		$	—		$	—	$	65,402



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



Nine Months Ended
September 30, 2013	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	637,667		$	196,652		$	1,110		$	—	$	835,429
Cost of sales	260,879			82,528			—			—		343,407
Gross margin	376,788			114,124			1,110			—		492,022
Operating, general and administrative	142,594			56,899			9,248			—		208,741
Property and other taxes	57,549			19,968			8			—		77,525
Depreciation	67,454			17,206			25			—		84,685
Operating income (loss)	109,191			20,051			(8,171		)	—		121,071
Interest expense	(42,840		)	(7,553		)	(583		)	—		(50,976		)
Other income	4,926			1,753			81			—		6,760
Income tax (expense) benefit	(12,792		)	(153		)	3,980			—		(8,965		)
Net income (loss)	$	58,485		$	14,098		$	(4,693	)	$	—	$	67,890
Total assets	$	2,542,068		$	1,082,294		$	9,288		$	—	$	3,633,650
Capital expenditures	$	130,585		$	23,366		$	—		$	—	$	153,951



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

(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, 2013	September 30, 2012
Basic computation	38,459,484	37,201,051
Dilutive effect of
Restricted stock and performance share awards (1) (2)	186,192	—

Diluted computation	38,645,676	37,201,051



	Nine Months Ended
	September 30, 2013	September 30, 2012
Basic computation	37,982,673	36,723,105
Dilutive effect of
Restricted stock and performance share awards (1)	181,462	70,848

Diluted computation	38,164,135	36,793,953

_________________

(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.

(2) 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,
	2013			2012			2013			2012
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,367		$	2,586		$	135		$	162
Interest cost	5,680			6,016			219			309
Expected return on plan assets	(8,123		)	(7,501		)	(254		)	(253		)
Amortization of prior service cost	62			62			(500		)	(500		)
Recognized actuarial loss	2,911			2,291			242			234
Net Periodic Benefit Cost (Income)	$	3,897		$	3,454		$	(158	)	$	(48	)



	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Components of Net Periodic Benefit Cost (Income)
Service cost	$	10,100		$	8,616		$	406		$	406
Interest cost	17,040			17,867			658			875
Expected return on plan assets	(24,369		)	(22,497		)	(764		)	(766		)
Amortization of prior service cost	185			185			(1,499		)	(1,499		)
Recognized actuarial loss	8,735			6,485			728			593
Net Periodic Benefit Cost (Income)	$	11,691		$	10,656		$	(471	)	$	(391	)

(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 are incurred.

Our liability for environmental remediation obligations is estimated to range between $27.7 million to $35.7 million, primarily for manufactured gas plants discussed below. As of September 30, 2013, we have a reserve of approximately $28.7 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 costs become determinable, 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 $24.0 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 conducting remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources (DENR). Our current reserve for remediation costs at this site is approximately $11.7 million, and we estimate that approximately $8.1 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 manufactured gas plant. 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 period of 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 - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide. These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions 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 the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating GHG emissions of the very largest emitters, including large power plants, under the Clean Air Act, and specifically under the Prevention of Significant Deterioration (PSD) pre-construction permit and Title V operating permit programs.

In September 2013, the EPA issued proposed New Source Performance Standards (NSPS) that specify permissible levels of GHG emissions from newly-constructed fossil fuel-fired electric generating units. The proposed NSPS sets separate standards for natural gas combined cycle units and coal-fired generating units. As directed by President Obama's June 25, 2013, Climate Action Plan, the EPA also announced plans to establish, pursuant to Section 111(d) of the Clean Air Act, carbon dioxide emissions standards for existing fossil fuel fired electric generating units. EPA plans to publish the proposed standards for existing units by June 1, 2014, and finalize those guidelines by June 1, 2015. States must then submit their individual plans for reducing power plants' GHG emissions to EPA by June 30, 2016. Thus, it is possible that existing power plants may be required to comply with GHG performance standards as soon as July 2016.

In October 2013, the U.S. Supreme Court granted certiorari to review EPA's GHG regulations, including the Tailoring Rule which limits the sources subject to GHG permitting requirements to the largest fossil-fueled power plants. It is conceivable that the Court could invalidate EPA's PSD and Title V Tailoring Rule, but still leave power plants subject to anticipated new and existing source performance standards for GHG.

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 and increase our costs of procuring electricity. 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 special wastes subject to regulation under subtitle C, the hazardous waste provisions, 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. The EPA has not issued a final CCR rule and is currently reviewing comments on additional data submitted during the public comment period, which closed in September 2013. In an order dated September 30, 2013, a federal district judge in the case Appalachian Voices v. McCarthy, indicated that he will issue an opinion in the next 30 days in favor of the environmental group plaintiffs, which could include a schedule for the EPA to promulgate the final CCR rule. In addition, legislation was introduced in Congress to regulate coal ash. We cannot predict at this time the final requirements of any CCR regulations or legislation and what impact, if any, they would have on us, but the costs of complying with any such requirements could be significant.

Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act (CWA) 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 the EPA has discretion to consider costs relative to benefits in developing cooling water intake structure regulations. In March 2011, the EPA proposed a rule to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. The EPA has indicated that it expects to issue the final rule in November 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.

In April 2013, the EPA proposed CWA regulations to address mercury, arsenic, lead, and selenium in water discharged from power plants. The proposed regulations include a variety of options for whether and how these different waste streams should be treated. The EPA is expected to evaluate comments on all of these options prior to enacting final regulations. Under the proposed approach, new requirements for existing power plants would be phased in between 2017 and 2022. The EPA also announced its intention to align this CWA rule with the related rule for CCRs discussed above. The EPA is under a consent decree to take final action by May 22, 2014. The EPA estimates that over half of the existing power plants will not incur costs under any of the proposed options because many power plants already have the technology and procedures in place to meet the proposed pollution control standards; however, it is too early to determine whether the impacts of these rules will be material.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures

The 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, the MATS 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. In March 2013, the EPA finalized updates to emission limits under MATS for new power plants. Numerous challenges to the MATS have been filed with the EPA and in Federal court and we cannot predict the outcome of such challenges.

In July 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) were to be required beginning in 2012. In an order issued on June 24, 2013, the Supreme Court granted certiorari to review the D.C. Circuit's 2012 decision which vacated the CSAPR, and briefs have been filed with the Court. The Clean Air Interstate Rule remains in effect until the EPA issues a valid replacement.

On October 7, 2013, the Supreme Court denied certiorari in Luminant Generation Co v. EPA, which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions.

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. By 2018, Montana, or EPA, must develop a revised Plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. On November 14, 2012, National Parks Conservation Association, Montana Environmental Information Center, and Sierra Club jointly filed a petition for review of the Federal Implementation Plan in the U.S. Ninth Circuit Court of Appeals. Montana Environmental Information Center and Sierra Club have challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. Briefing in this matter is complete and a decision is not likely until 2014, at the earliest. At this time, we cannot predict or determine the outcome of this petition.

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's State Implementation Plan (SIP) was approved by the EPA in May 2012. 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 the SIP. The current project cost for the AQCS is estimated to be approximately $405

million (our share is 23.4%) and it is expected to be operational by 2016. As of September 30, 2013, we have capitalized costs of approximately $27.6 million million related to this project.

Our incremental capital expenditure projections include amounts related to our share of the BART 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 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, it appears that Big Stone would meet the requirements by installing the AQCS system and using mercury control technology such as activated carbon injection. In August 2013, the South Dakota DENR granted Big Stone a one year extension to comply with MATS, such that the new compliance deadline is April 16, 2016. 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. Coyote must install control equipment to limit its NOx emissions to 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 $9 million (our share is 10.0%).

Based on the finalized MATS, 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 the MATS. 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 project is expected to be complete in 2014. As of September 30, 2013, we have capitalized costs of approximately $20.8 million related to this project.

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 stricter than the Federal MATS. The owners do not believe additional equipment will be necessary to meet the MATS 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.

See 'Legal Proceedings - Colstrip Litigation' below for discussion of Sierra Club litigation.

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 Litigation

On March 6, 2013, the Sierra Club and the MEIC (Plaintiffs) filed suit in the United States District Court for the District of Montana against the six individual owners of Colstrip, including us, as well as the operator or managing agent of the station. On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief. The original complaint included 39 claims for relief based upon alleged violations of the Clean Air Act and the Montana State Implementation Plan. The Amended Complaint drops claims associated with projects completed before 2001, the Title V claims and the opacity claims. There are now a total of 23 claims.

In the Amended Complaint, Plaintiffs have identified physical changes made at Colstrip between 2001 and 2012, which they allege have increased emissions of SO2, NOx and particulate matter and were “major modifications” subject to permitting requirements under the Clean Air Act. They also have alleged violations of the requirements related to Part 70 Operating Permits. Plaintiffs seek injunctive and declaratory relief, civil penalties (including $100,000 of civil penalties to be used for beneficial environmental projects), and recovery of their attorney fees.

On May 3, 2013, the Colstrip owners and operator filed a partial motion to dismiss, seeking dismissal of 36 of the 39 claims asserted in the original complaint. Plaintiffs filed their opposition on May 31, 2013, and the owners and operator filed their reply on June 21, 2013. The motion was not ruled upon and the Colstrip owners filed a second motion to dismiss the Amended Complaint on October 11, 2013, incorporating parts of the first motion and supplementing it with new authorities and with regard to new claims contained in the Amended Complaint.

We intend to vigorously defend this lawsuit. Due to the preliminary nature of the lawsuit, at this time, we cannot predict an outcome, nor is it reasonably possible to estimate the amount of loss, if any, that would be associated with an adverse decision.

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 673,200 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, 2012.

Hydro Transaction

On September 26, 2013, we entered into an agreement with PPL Montana, LLC (PPL Montana), a wholly owned subsidiary of PPL Corporation, to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity, for a purchase price of $900 million. The purchase price will be subject to adjustment for proration of operating expenses, performance of planned capital expenditures, and termination of certain power purchase agreements. We believe the Hydro Transaction is an opportunity to help stabilize our customers' energy costs and is consistent with our strategy of owning generation facilities. If the acquisition is completed, we will own over 60 percent of our average load serving requirements in Montana.

We expect to close on this acquisition during the second half of 2014; however, it is subject to customary conditions and approvals, including approval from the FERC, the MPSC, other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act. In addition, the closing is conditioned upon the termination or waiver of certain restrictions applicable to the hydro assets under a sale-leaseback arrangement through which PPL Montana holds its interest in the Colstrip thermal generating facility (which interest we will not be acquiring). Through September 30, 2013 we have expensed approximately $3.3 million of legal and professional fees associated with the transaction.

Natural Gas Production Assets

During the third quarter of 2012, we completed the purchase of other natural gas production interests in the Bear Paw Basin, including a 75% interest in two gas gathering systems. During the nine months ended September 30, 2013, this acquisition contributed approximately $5.0 million to gross margin. We are collecting the cost of service for natural gas produced from these assets, including a return on our investment, through our natural gas supply tracker on an interim basis. As a result, we do not expect to file an application with the MPSC to place these assets in natural gas rate base until our next natural gas rate case. Since acquisition we have recognized approximately $3.2 million of revenue that is subject to refund.

Wind Generation

During the fourth quarter of 2012, we purchased and placed into service the 40 MW Spion Kop wind project in Judith Basin County in Montana for approximately $84 million. Beginning in December 2012, the cost of service of the electricity generated, including a return on our investment, has been included in electric supply rates. During the nine months ended September 30, 2013, the acquisition of Spion Kop contributed approximately $4.6 million to gross margin and approximately $2.2 million in production tax credits (lower income tax expense).

Dave Gates Generating Station at Mill Creek (DGGS)

As a result of a FERC Administrative Law Judge's (ALJ) nonbinding decision issued in September 2012, we have cumulative deferred revenue of approximately $22.5 million, which includes approximately $1.8 million and $6.0 million deferred during the three and nine months ended September 30, 2013, respectively. These amounts are subject to refund and recorded within current regulatory liabilities in the Condensed Consolidated Balance Sheets. The ALJ concluded we should allocate only a fraction of the costs we believed (based on past practice) should be allocated to FERC jurisdictional customers. The matter has been fully briefed before the FERC. We expect to defer revenues of approximately $0.7 million per month pending final resolution at FERC.

We do not know when the FERC will consider the matter and issue its decision. The FERC is not obligated to follow any of the ALJ's findings and conclusions, and the FERC can accept or reject the initial decision in whole or in part. If the FERC upholds the ALJ's 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 or beyond. We continue to bill FERC jurisdictional customers interim rates that have been in effect since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC.

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, 2013 Compared with the Three Months Ended September 30, 2012



	Three Months Ended September 30,
	2013		2012		Change		% Change
	(dollars in millions)
Operating Revenues
Electric	$	227.1	$	202.5	$	24.6	12.1	%
Natural Gas	34.8		33.0		1.8		5.5
Other	0.4		0.4		—		—
	$	262.3	$	235.9	$	26.4	11.2	%



	Three Months Ended September 30,
	2013		2012		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	95.3	$	83.8	$	11.5		13.7	%
Natural Gas	9.0		9.2		(0.2		)	(2.2	)
	$	104.3	$	93.0	$	11.3		12.2	%



	Three Months Ended September 30,
	2013		2012		Change		% Change
	(dollars in millions)
Gross Margin
Electric	$	131.8	$	118.7	$	13.1	11.0	%
Natural Gas	25.8		23.8		2.0		8.4
Other	0.4		0.4		—		—
	$	158.0	$	142.9	$	15.1	10.6	%

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



	Gross Margin 2013 vs. 2012
	(in millions)
DGGS	$	10.2
DSM lost revenues	5.0
Spion Kop	1.6
Natural gas production	1.2
Montana natural gas rate increase	1.2
Property tax trackers	0.9
Electric retail volumes	(3.5		)
Operating expenses recovered in trackers	(1.9		)
Electric transmission	(0.4		)
Other	0.8
Increase in Consolidated Gross Margin	$	15.1

Consolidated gross margin increased $15.1 million primarily due to the following:


•	Higher DGGS revenue primarily due to the inclusion in 2012 results of $11.4 million related to the FERC ALJ nonbinding decision as discussed above;

•

A $5.8 million increase in electric DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers, offset in part by an $0.8 million decrease in natural gas DSM lost revenues. The three months ended September 30, 2013 included recognition of approximately $4.6 million in revenues related to prior periods (including $2.3 million related to calendar year 2012) that we had previously deferred pending approval of our electric tracker filing. See additional discussion in Note 4, Regulatory Matters;


•	The acquisition of the Spion Kop wind farm in the fourth quarter of 2012;


•	An increase in natural gas production margin, primarily due to the full period effect of the acquisition of natural gas production assets in the third quarter of 2012;


•	An increase in Montana natural gas delivery rates implemented in April 2013; and


•	An increase in property taxes included in a tracker.

These increases were partly offset by:


•	A decrease in electric retail volumes due primarily to cooler summer weather and reduced customer irrigation;


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


•	A decrease in electric transmission revenues due primarily to an outage at Colstrip Unit 4 during the third quarter of 2013. We expect the outage at Colstrip Unit 4 to have a negative impact on transmission revenues for the remainder of 2013.



	Three Months Ended September 30,
	2013		2012		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	72.5	$	63.1	$	9.4		14.9	%
Mountain States Transmission Intertie (MSTI) impairment	—		24.0		(24.0		)	(100.0	)
Property and other taxes	26.0		24.8		1.2			4.8
Depreciation	28.1		26.5		1.6			6.0
	$	126.6	$	138.4	$	(11.8	)	(8.5	)%

Consolidated operating, general and administrative expenses were $72.5 million for the three months ended September 30, 2013, as compared with $63.1 million for the three months ended September 30, 2012. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2013 vs. 2012
	(in millions)
Distribution System Infrastructure Project (DSIP) expenses	$	3.3
Legal and professional fees	2.8
Labor	1.7
Plant operator costs	1.6
Nonemployee directors deferred compensation	1.5
Bad debt expense	0.6
Pension and employee benefits	(3.1		)
Operating expenses recovered in trackers	(1.9		)
Other	2.9
Increase in Operating, General & Administrative Expenses	$	9.4

The increase in operating, general and administrative expenses of $9.4 million was primarily due to the following:

•

Incremental operating and maintenance costs related to the phase-in of DSIP during 2012 and 2011 were deferred in accordance with the MPSC's approval of an accounting order. Incremental DSIP costs for 2013 forward are being expensed as incurred and the amounts previously deferred are being amortized over five years. During the third quarter of 2013 we amortized approximately $0.8 million and incurred incremental DSIP expenses of approximately $2.5 million;


•	Legal and professional fees associated with the Hydro Transaction;


•	Increased labor costs due primarily to compensation increases and a larger number of employees;


•	Higher plant operator costs due primarily to the Spion Kop acquisition and higher maintenance and outage costs at Colstrip Unit 4;

•

Non-employee directors deferred compensation increased as compared to the prior year, primarily due to changes in our stock price. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes up, deferred compensation expense increases; however, we account for the deferred shares as trading securities and their increase in value is reflected in other income with no impact on net income; and


•	Higher bad debt expense.

These increases were partly offset by:

•

Decreased pension expense, offset in part by higher other employee benefit costs. Our Montana pension costs are included in expense on a pay as you go (cash funding) basis. We received a pension accounting order from the MPSC in 2008, which based our Montana pension expense on an average of our funding requirements for calendar years 2005 through 2012 in order to smooth the impact of increased cash funding. We expect our 2013 Montana pension expense to be approximately $17.0 million to $20.0 million lower than 2012 on an annualized basis due to the expiration of this order and our current cash funding estimate: and


•	Lower operating expenses recovered in trackers, primarily related to customer efficiency programs.

In the third quarter of 2012 we recorded a charge of approximately $24 million for the impairment of substantially all of the preliminary survey and investigative costs associated with MSTI, a proposed 500 kV transmission project from southwestern Montana to southeastern Idaho with a potential capacity of 1500 MWs.

Property and other taxes were $26.0 million for the three months ended September 30, 2013, as compared with $24.8 million in the same period of 2012. This increase was primarily due to higher estimated property valuations in Montana and plant additions. We estimate property taxes throughout each year and update to the actual expense when we receive our Montana property tax bills in November.

Depreciation expense was $28.1 million for the three months ended September 30, 2013, as compared with $26.5 million in the same period of 2012. This reflects an increase in depreciation expense due to plant additions, offset in part by a reduction in depreciation rates of approximately $1.5 million as a result of new depreciation studies conducted by an independent consultant and implemented during the second quarter of 2013. These studies reflect longer asset lives on our electric and natural gas assets in Montana, and electric assets in South Dakota. We expect depreciation expense to be reduced due to the change in rates by approximately $1.5 million for the remainder of 2013.

Consolidated operating income for the three months ended September 30, 2013 was $31.4 million, as compared with $4.4 million in the same period of 2012. This increase was primarily due to the 2012 MSTI impairment and the improvement in gross margin partly offset by higher operating, general and administrative expenses as discussed above.

Consolidated interest expense for the three months ended September 30, 2013 was $17.1 million, as compared with $17.7 million in the same period of 2012. This decrease was primarily due to higher interest accrued on DGGS deferred revenues in 2012 due to the FERC ALJ nonbinding decision as discussed above partially offset by higher debt outstanding.

Consolidated other income for the three months ended September 30, 2013, was $3.1 million, as compared with $1.0 million in the same period of 2012. This increase was primarily due to changes in the value of deferred shares held in trust for non-employee directors deferred compensation, which is offset in operating, general and administrative expenses above.

Consolidated income tax expense for the three months ended September 30, 2013 was $1.8 million, as compared with a benefit of $8.6 million in the same period of 2012. Our effective tax rate was 10.4% for the three months ended September 30, 2013 as compared with (69.5)% for the three months ended September 30, 2012. The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in millions):



	Three Months Ended September 30,
	2013			2012
Income (Loss) Before Income Taxes	$	17.5		$	(12.4	)

Income tax calculated at 35% federal statutory rate	6.1			(4.3		)

Permanent or flow through adjustments:
Flow-through repairs deductions	(3.1		)	(1.8		)
Flow-through of state bonus depreciation deduction	(0.8		)	(0.3		)
Production tax credits	(0.5		)	—
Prior year permanent return to accrual adjustments	—			(1.9		)
Recognition of state net operating loss benefit / valuation allowance release	—			(0.1		)
State income tax and other, net	0.1			(0.2		)
	(4.3		)	(4.3		)

Income tax expense (benefit)	$	1.8		$	(8.6	)

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, state tax benefit of bonus depreciation deductions and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

Consolidated net income for the three months ended September 30, 2013 was $15.6 million as compared with a $3.8 million consolidated net loss for the same period in 2012. This increase was primarily due to the changes in operating income discussed above, partly offset by higher income tax expense.

Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012



	Nine Months Ended September 30,
	2013		2012		Change		% Change
	(dollars in millions)
Operating Revenues
Electric	$	637.7	$	605.7	$	32.0	5.3	%
Natural Gas	196.7		182.8		13.9		7.6
Other	1.1		1.0		0.1		10.0
	$	835.5	$	789.5	$	46.0	5.8	%



	Nine Months Ended September 30,
	2013		2012		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	260.9	$	244.9	$	16.0		6.5	%
Natural Gas	82.5		83.0		(0.5		)	(0.6	)
	$	343.4	$	327.9	$	15.5		4.7	%



	Nine Months Ended September 30,
	2013		2012		Change		% Change
	(dollars in millions)
Gross Margin
Electric	$	376.8	$	360.8	$	16.0	4.4	%
Natural Gas	114.2		99.8		14.4		14.4
Other	1.1		1.0		0.1		10.0
	$	492.1	$	461.6	$	30.5	6.6	%

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



	Gross Margin 2013 vs. 2012
	(in millions)
Natural gas production	$	7.0
DGGS	5.1
Spion Kop	4.6
Electric transmission	3.6
Natural gas retail volumes	3.4
Montana natural gas rate increase	2.1
Property tax trackers	1.9
Natural gas transportation capacity	1.1
Electric QF supply costs	1.0
Operating expenses recovered in trackers	(2.4		)
Electric retail volumes	(0.5		)
Other	3.6
Increase in Consolidated Gross Margin	$	30.5

Consolidated gross margin increased $30.5 million primarily due to the following:


•	An increase in natural gas production margin, primarily due to the full period effect of the acquisition of natural gas production assets in the third quarter of 2012;


•	Higher DGGS revenue primarily due to the inclusion in 2012 results of an increased deferral of FERC jurisdictional revenues related to the FERC ALJ nonbinding decision as discussed above;


•	The acquisition of the Spion Kop wind farm in the fourth quarter of 2012;


•	An increase in electric transmission revenues due to market pricing and other conditions;


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


•	An increase in Montana natural gas delivery rates implemented in April 2013;


•	An increase in property taxes included in a tracker;


•	An increase in demand for natural gas transportation capacity; and


•	Lower QF related supply costs based on actual QF pricing and output.

These increases were partly offset by:


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


•	A weather related decrease in electric retail volumes.



	Nine Months Ended September 30,
	2013		2012		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	208.7	$	195.7	$	13.0		6.6	%
MSTI impairment	—		24.0		(24.0		)	(100.0	)%
Property and other taxes	77.5		74.4		3.1			4.2
Depreciation	84.7		79.4		5.3			6.7
	$	370.9	$	373.5	$	(2.6	)	(0.7	)%

Consolidated operating, general and administrative expenses were $208.7 million for the nine months ended September 30, 2013, as compared with $195.7 million for the nine months ended September 30, 2012. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2013 vs. 2012
	(in millions)
Distribution System Infrastructure Project (DSIP) expenses	$	8.8
Legal and professional fees	3.3
Plant operator costs	3.0
Labor	2.8
Nonemployee directors deferred compensation	2.6
Natural gas production	1.6
Bad debt expense	1.0
Pension and employee benefits	(10.7		)
Operating expenses recovered in trackers	(2.4		)
Other	3.0
Increase in Operating, General & Administrative Expenses	$	13.0

The increase in operating, general and administrative expenses of $13.0 million was primarily due to the following:

•

Incremental operating and maintenance costs related to the phase-in of DSIP during 2012 and 2011 were deferred in accordance with the MPSC's approval of an accounting order. Incremental DSIP costs for 2013 forward are being expensed as incurred and the amounts previously deferred are being amortized over five years. During the first nine months of 2013 we amortized approximately $2.4 million and incurred incremental DSIP expenses of approximately $6.4 million;


•	Legal and professional fees associated with the Hydro Transaction;


•	Higher plant operator costs primarily due to the Spion Kop acquisition and higher maintenance and outage costs at Colstrip Unit 4;


•	Increased labor costs due primarily to compensation increases and a larger number of employees;


•	Non-employee directors deferred compensation increased primarily due to changes in our stock price;


•	Higher natural gas production costs due to the 2012 acquisition of the natural gas production assets; and


•	Higher bad debt expense.

These increases were partly offset by:


•	Decreased pension expense, offset in part by higher other employee benefit costs; and


•	Lower operating expenses recovered in trackers, primarily related to customer efficiency programs.

Property and other taxes were $77.5 million for the nine months ended September 30, 2013, as compared with $74.4 million in the same period of 2012. This increase was primarily due to higher estimated property valuations in Montana and plant additions.

Depreciation expense was $84.7 million for the nine months ended September 30, 2013, as compared with $79.4 million in the same period of 2012. This increase was primarily due to plant additions. Partially offsetting the increase in the third quarter of 2013 was a reduction in depreciation rates as discussed above.

Consolidated operating income for the nine months ended September 30, 2013 was $121.1 million, as compared with $88.2 million in the same period of 2012. This increase was primarily due to the 2012 MSTI impairment and an increase in gross margin partly offset by higher operating, general and administrative expenses as discussed above.

Consolidated interest expense for the nine months ended September 30, 2013 was $51.0 million, as compared with $49.6 million in the same period of 2012. This increase was primarily due to higher debt outstanding partially offset by higher interest accrued on DGGS deferred revenues in 2012 due to the initial FERC ALJ nonbinding decision as discussed above.

Consolidated other income for the nine months ended September 30, 2013, was $6.8 million, as compared with $3.1 million in the same period of 2012. This increase was primarily due to a $2.6 million gain on deferred shares held in trust for non-employee directors deferred compensation discussed above and higher capitalization of AFUDC.

Consolidated income tax expense for the nine months ended September 30, 2013 was $9.0 million, as compared with $2.0 million in the same period of 2012. Our effective tax rate was 11.7% for the nine months ended September 30, 2013 as compared with 4.8% for the nine months ended September 30, 2012. The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in millions):



	Nine Months Ended September 30,
	2013			2012
Income (Loss) Before Income Taxes	$	76.9		$	41.7

Income tax calculated at 35% federal statutory rate	26.9			14.6

Permanent or flow through adjustments:
Flow-through repairs deductions	(12.9		)	(9.5		)
Flow-through of state bonus depreciation deduction	(3.3		)	(2.2		)
Production tax credits	(2.1		)	—
Prior year permanent return to accrual adjustments	0.5			(1.9		)
Recognition of state net operating loss benefit / valuation allowance release	—			(0.1		)
State income tax and other, net	(0.1		)	1.1
	(17.9		)	(12.6		)

Income tax expense	$	9.0		$	2.0

Consolidated net income for the nine months ended September 30, 2013 was $67.9 million as compared with $39.7 million for the same period in 2012. This increase was primarily due to the changes in operating income discussed above, partly offset by higher income tax expense.

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, which has a minimal impact on gross margin.


•	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, 2013 Compared with the Three Months Ended September 30, 2012



	Results
	2013		2012			Change			% Change
	(dollars in millions)
Retail revenues	$	201.5	$	203.3		$	(1.8	)	(0.9	)%
Regulatory amortization	11.8		(5.2		)	17.0			(326.9	)
Total retail revenues	213.3		198.1			15.2			7.7
Transmission	11.2		11.6			(0.4		)	(3.4	)
Ancillary services	0.4		(9.2		)	9.6			(104.3	)
Wholesale	0.8		0.8			—			—
Other	1.4		1.2			0.2			16.7
Total Revenues	227.1		202.5			24.6			12.1
Total Cost of Sales	95.3		83.8			11.5			13.7
Gross Margin	$	131.8	$	118.7		$	13.1		11.0	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2013		2012		2013	2012	2013	2012
	(in thousands)
Retail Electric
Montana	$	65,455	$	63,951	575	587	274,835	273,130
South Dakota	12,698		13,947		146	158	49,350	48,940
Residential	78,153		77,898		721	745	324,185	322,070
Montana	83,624		83,605		823	867	62,639	62,179
South Dakota	18,502		19,643		255	259	12,154	12,235
Commercial	102,126		103,248		1,078	1,126	74,793	74,414
Industrial	10,105		10,011		737	806	74	74
Other	11,131		12,148		91	103	7,813	7,816
Total Retail Electric	$	201,515	$	203,305	2,627	2,780	406,865	404,374
Total Wholesale Electric	$	845	$	781	39	41	—	—



	Degree Days			2013 as compared with:
Cooling Degree-Days	2013	2012	Historic Average	2012	Historic Average
Montana	393	395	259	1% cooler	52% warmer
South Dakota	702	911	639	23% cooler	10% warmer



	Degree Days			2013 as compared with:
Heating Degree-Days	2013	2012	Historic Average	2012	Historic Average
Montana	231	244	357	5% warmer	35% warmer
South Dakota	60	65	90	8% warmer	33% warmer

The following summarizes the components of the changes in electric gross margin for the three months ended September 30, 2013 and 2012:



	Gross Margin 2013 vs. 2012
	(in millions)
DGGS	$	10.2
DSM lost revenues	5.8
Spion Kop	1.6
Property tax trackers	0.5
Retail volumes	(3.5		)
Operating expenses recovered in trackers	(1.5		)
Transmission	(0.4		)
Other	0.4
Increase in Gross Margin	$	13.1

This increase in gross margin was primarily due to the following:


•	Higher DGGS ancillary services revenue primarily due to inclusion in 2012 results of a $11.4 million deferral related to the FERC ALJ nonbinding decision discussed above;


•	The recognition of $5.8 million in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers in the third quarter 2013 as discussed above;


•	The acquisition of the Spion Kop wind farm in the fourth quarter of 2012; and


•	An increase in property taxes included in a tracker.

These increases were partially offset primarily due to the following:


•	A decrease in volumes due primarily to cooler summer weather and reduced customer irrigation;


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


•	A decrease in transmission revenues due primarily to an unplanned outage at Colstrip Unit 4 in the third quarter 2013.

The increase in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin.

Retail volumes decreased primarily due to cooler summer weather and reduced customer irrigation.

Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012



	Results
	2013		2012			Change			% Change
	(dollars in millions)
Retail revenues	$	581.5	$	561.9		$	19.6		3.5	%
Regulatory amortization	11.9		10.8			1.1			10.2
Total retail revenues	593.4		572.7			20.7			3.6
Transmission	37.3		33.7			3.6			10.7
Ancillary services	1.1		(6.5		)	7.6			(116.9	)
Wholesale	2.0		2.4			(0.4		)	(16.7	)
Other	3.9		3.4			0.5			14.7
Total Revenues	637.7		605.7			32.0			5.3
Total Cost of Sales	260.9		244.9			16.0			6.5
Gross Margin	$	376.8	$	360.8		$	16.0		4.4	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2013		2012		2013	2012	2013	2012
	(in thousands)
Retail Electric
Montana	$	198,375	$	188,768	1,751	1,749	275,913	273,711
South Dakota	37,150		36,993		447	424	49,250	48,887
Residential	235,525		225,761		2,198	2,173	325,163	322,598
Montana	238,482		230,498		2,356	2,416	62,638	62,046
South Dakota	52,009		52,887		722	712	12,168	12,116
Commercial	290,491		283,385		3,078	3,128	74,806	74,162
Industrial	31,089		28,185		2,194	2,217	74	74
Other	24,352		24,600		168	178	6,129	6,101
Total Retail Electric	$	581,457	$	561,931	7,638	7,696	406,172	402,935
Total Wholesale Electric	$	2,022	$	2,382	97	137	—	—



	Degree Days			2013 as compared with:
Cooling Degree-Days	2013	2012	Historic Average	2012	Historic Average
Montana	438	450	300	3% cooler	46% warmer
South Dakota	752	1,061	696	29% cooler	8% warmer



	Degree Days			2013 as compared with:
Heating Degree-Days	2013	2012	Historic Average	2012	Historic Average
Montana	4,721	4,488	4,947	5% colder	5% warmer
South Dakota	6,174	4,375	5,573	41% colder	11% colder

The following summarizes the components of the changes in electric gross margin for the nine months ended September 30, 2013 and 2012:



	Gross Margin 2013 vs. 2012
	(in millions)
DGGS	$	5.1
Spion Kop	4.6
Transmission	3.6
QF supply costs	1.0
DSM lost revenues	0.9
Property tax trackers	0.8
Operating expenses recovered in trackers	(1.8		)
Retail volumes	(0.5		)
Other	2.3
Increase in Gross Margin	$	16.0

The increase in margin and volumes is primarily due to the same reasons discussed above for the three months ended September 30, 2013. Lower QF related supply costs based on actual QF pricing and output and an increase in property taxes included in a tracker also contributed to the increase.

Demand for transmission can fluctuate substantially from year to year based on hydro, weather and market conditions in Montana and states to the South and West. While improved market pricing and other conditions resulted in increased demand to transmit electricity from Montana over our lines, the outage at Colstrip Unit 4 reduced energy available to transmit over our lines.

NATURAL GAS SEGMENT

We have various classifications of natural gas revenues, defined as follows:


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


•	Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin.


•	Wholesale: Primarily represents transportation and storage for others.

Three Months Ended September 30, 2013 Compared with the Three Months Ended September 30, 2012



	Results
	2013		2012		Change			% Change
	(dollars in millions)
Retail revenues	$	22.8	$	19.9	$	2.9		14.6	%
Regulatory amortization	3.2		5.1		(1.9		)	(37.3	)
Total retail revenues	26.0		25.0		1.0			4.0
Wholesale and other	8.8		8.0		0.8			10.0
Total Revenues	34.8		33.0		1.8			5.5
Total Cost of Sales	9.0		9.2		(0.2		)	(2.2	)
Gross Margin	$	25.8	$	23.8	$	2.0		8.4	%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2013		2012		2013	2012	2013	2012
	(in thousands)
Retail Gas
Montana	$	9,770	$	8,795	807	758	159,197	158,524
South Dakota	1,916		1,757		124	113	37,846	37,551
Nebraska	2,257		1,887		157	149	36,315	36,222
Residential	13,943		12,439		1,088	1,020	233,358	232,297
Montana	6,042		5,171		581	515	22,271	22,181
South Dakota	1,296		1,130		171	171	5,971	5,931
Nebraska	1,281		985		185	187	4,538	4,517
Commercial	8,619		7,286		937	873	32,780	32,629
Industrial	145		93		12	10	262	269
Other	94		68		10	8	156	150
Total Retail Gas	$	22,801	$	19,886	2,047	1,911	266,556	265,345



	Degree Days			2013 as compared with:
Heating Degree-Days	2013	2012	Historic Average	2012	Historic Average
Montana	231	244	357	5% warmer	35% warmer
South Dakota	60	65	90	8% warmer	33% warmer
Nebraska	21	27	49	22% warmer	57% warmer

The following summarizes the components of the changes in natural gas gross margin for the three months ended September 30, 2013 and 2012:



	Gross Margin 2013 vs. 2012
	(in millions)
Natural gas production	$	1.2
Montana natural gas rate increase	1.2
Montana property tax tracker	0.4
Retail volumes	0.3
DSM lost revenues	(0.8		)
Operating expenses recovered in trackers	(0.4		)
Other	0.1
Increase in Gross Margin	$	2.0

This increase in gross margin was primarily due to:


•	An increase in natural gas production margin primarily due to the acquisition of the Bear Paw assets in the third quarter of 2012;


•	An increase in Montana natural gas delivery rates implemented in April 2013;


•	An increase in Montana property taxes included in a tracker; and


•	Higher retail margin driven by increased volumes.

These increases were partly offset primarily due to the following:


•	A decrease in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers; and


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

Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012



	Results
	2013			2012		Change			% Change
	(dollars in millions)
Retail revenues	$	173.5		$	150.0	$	23.5		15.7	%
Regulatory amortization	(6.3		)	7.3		(13.6		)	(186.3	)
Total retail revenues	167.2			157.3		9.9			6.3
Wholesale and other	29.5			25.5		4.0			15.7
Total Revenues	196.7			182.8		13.9			7.6
Total Cost of Sales	82.5			83.0		(0.5		)	(0.6	)
Gross Margin	$	114.2		$	99.8	$	14.4		14.4	%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2013		2012		2013	2012	2013	2012
	(in thousands)
Retail Gas
Montana	$	72,171	$	67,049	8,014	7,656	160,330	159,316
South Dakota	20,227		15,447		2,354	1,709	38,146	37,792
Nebraska	18,774		14,234		2,012	1,578	36,656	36,520
Residential	111,172		96,730		12,380	10,943	235,132	233,628
Montana	37,338		34,409		4,252	4,004	22,443	22,329
South Dakota	13,498		9,656		2,119	1,545	6,028	5,961
Nebraska	10,016		7,880		1,496	1,279	4,596	4,571
Commercial	60,852		51,945		7,867	6,828	33,067	32,861
Industrial	776		672		88	80	264	273
Other	720		641		97	85	157	150
Total Retail Gas	$	173,520	$	149,988	20,432	17,936	268,620	266,912



	Degree Days			2013 as compared with:
Heating Degree-Days	2013	2012	Historic Average	2012	Historic Average
Montana	4,721	4,488	4,947	5% colder	5% warmer
South Dakota	6,174	4,375	5,573	41% colder	11% colder
Nebraska	4,741	3,611	4,584	31% colder	3% colder

The following summarizes the components of the changes in natural gas gross margin for the nine months ended September 30, 2013 and 2012:



	Gross Margin 2013 vs. 2012
	(in millions)
Natural gas production	$	7.0
Retail volumes	3.4
Montana natural gas rate increase	2.1
Montana property tax tracker	1.1
Transportation capacity	1.1
DSM lost revenues	(0.8		)
Operating expenses recovered in trackers	(0.6		)
Other	1.1
Increase in Gross Margin	$	14.4

The increase in margin and volumes is primarily due to the same reasons discussed above for the three months ended September 30, 2013, along with an increase in transportation revenues due to higher demand. Wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

LIQUIDITY AND CAPITAL RESOURCES

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, 2013, our total net liquidity was approximately $207.9 million, including $10.9 million of cash and $197.0 million of revolving credit facility availability. Revolving credit facility availability was $210.0 million as of October 18, 2013.

The following table presents additional information about short term borrowings during the three months ended September 30, 2013 (in millions):



Amount outstanding	$	103.0
Daily average amount outstanding	$	57.6
Maximum amount outstanding	$	103.0

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.

We issue debt securities to refinance retiring maturities, reduce short-term debt, fund construction programs and for other general corporate purposes. To fund our strategic growth opportunities, including the Hydro Transaction as discussed below, we intend to utilize available cash flow, debt capacity that would allow us to maintain investment grade ratings, and issue equity. In February 2012, we filed a shelf registration statement with the SEC that can be used for the issuance of debt or equity securities. In April 2012, we entered into an Equity Distribution Agreement with UBS pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During the three months ended September 30, 2013, we sold 8,400 shares of our common stock at an average price of $40.00 per share. Proceeds received were approximately $0.3 million, which are net of sales commissions paid to UBS of approximately $15,000 and other fees. Since inception, we have issued 1,917,996 shares at an average price of $38.38, for net proceeds of approximately $72.6 million. Proceeds were ultimately used to fund a portion of our investment growth opportunities.

On September 26, 2013, in connection with the Hydro Transaction, we signed a commitment letter with Credit Suisse Securities (USA) LLC and Bank of America, N.A., under which the lenders committed to provide a $900 million 364-day senior bridge term loan facility. The permanent financing for the Hydro Transaction is anticipated to be a combination of debt and equity securities and cash flows from operations. 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 earnings per share; however, there can be no assurance that we will be able to meet these targets.

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, 2013, we are under collected on our current Montana natural gas and electric trackers by approximately $8.4 million, as compared with an under collection of $10.4 million as of December 31, 2012, and an under collection of $2.2 million as of September 30, 2012.

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 18, 2013, our current ratings with these agencies are as follows:



	Senior Secured Rating	Senior Unsecured Rating	Commercial Paper	Outlook
Fitch	A-	BBB+	F2	Positive Watch
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,
	2013			2012
Operating Activities
Net income	$	67.9		$	39.7
Non-cash adjustments to net income	123.6			124.0
Changes in working capital	6.5			68.7
Other	(26.7		)	(9.8		)
	171.3			222.6

Investing Activities
Property, plant and equipment additions	(153.9		)	(157.8		)
Asset acquisition	—			(18.4		)
Other	3.9			0.3
	(150.0		)	(175.9		)

Financing Activities
Proceeds from issuance of common stock, net	44.1			28.5
(Repayments) issuances of long-term debt, net	(0.1		)	146.1
Repayments of short-term borrowings, net	(20.0		)	(166.9		)
Dividends on common stock	(43.1		)	(40.6		)
Other	(1.1		)	(1.5		)
	(20.2		)	(34.4		)

Increase in Cash and Cash Equivalents	$	1.1		$	12.3
Cash and Cash Equivalents, beginning of period	$	9.8		$	5.9
Cash and Cash Equivalents, end of period	$	10.9		$	18.2

Cash Provided by Operating Activities

As of September 30, 2013, cash and cash equivalents were $10.9 million as compared with $9.8 million at December 31, 2012 and $18.2 million at September 30, 2012. Cash provided by operating activities totaled $171.3 million for the nine months ended September 30, 2013 as compared with $222.6 million during the nine months ended September 30, 2012. This decrease in operating cash flows is due primarily to timing of the collection of receivables from customers and payment of supply costs and increased injections of natural gas into storage. During September 2013, we implemented a new customer information system and have experienced billing delays, which resulted in delays in collections of customer receivables as compared to the same period in 2012. We expect the billing delays to be resolved during the fourth quarter of 2013.

Cash Used in Investing Activities

Cash used in investing activities decreased by approximately $25.9 million as compared with the first nine months of 2012. Plant additions during 2013 include maintenance additions of approximately $87.3 million, supply related capital expenditures of approximately $34.5 million, primarily related to electric generation facilities in South Dakota, and DSIP capital expenditures of approximately $31.8 million. Plant additions during the first nine months of 2012 include maintenance additions of approximately $91.4 million, supply related capital expenditures of approximately $45.9 million, which were primarily related to supply investments in South Dakota, and DSIP capital expenditures of approximately $14.0 million.

Cash Used in Financing Activities

Cash used in financing activities totaled approximately $20.2 million during the nine months ended September 30, 2013 as compared with approximately $34.4 million during the nine months ended September 30, 2012. During the nine months ended

September 30, 2013, net cash used in financing activities consisted of net repayments of commercial paper of $20.0 million and the payment of dividends of $43.1 million, offset in part by proceeds received from the issuance of common stock pursuant to our equity distribution agreement of $44.1 million. 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, the repayment of long-term debt of $3.9 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.

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, 2013. See our Annual Report on Form 10-K for the year ended December 31, 2012 for additional discussion.



	Total		2013		2014		2015		2016		2017		Thereafter
	(in thousands)
Long-term debt	$	1,055,091	$	—	$	—	$	—	$	150,000	$	—	$	905,091
Capital leases	31,974		412		1,668		1,732		1,837		1,979		24,346
Short-term borrowings	102,980		102,980		—		—		—		—		—
Future minimum operating lease payments	4,660		495		1,576		1,180		743		434		232
Estimated pension and other postretirement obligations (1)	55,302		919		13,673		13,633		13,583		13,494		—
Qualifying facilities liability (2)	1,098,427		16,056		67,283		69,606		71,598		73,622		800,262
Supply and capacity contracts (3)	1,533,997		87,702		267,407		184,366		138,933		117,676		737,913
Contractual interest payments on debt (4)	587,439		16,892		57,269		57,269		57,074		47,820		351,115
Total Commitments (5)	$	4,469,870	$	225,456	$	408,876	$	327,786	$	433,768	$	255,025	$	2,818,959

_________________________


(1)	We estimate 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 $71 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $1.1 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)	For our variable rate short-term borrowings outstanding, we have assumed an average interest rate of 0.37% through maturity.


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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

As of September 30, 2013, 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, 2012. 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, 2013, we had approximately $103.0 million of commercial paper outstanding and no borrowings on our revolving credit facility. A 1% increase in interest rates would increase our annual interest expense by approximately $1.0 million.

Commodity Price Risk

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

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

Counterparty Credit Risk

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


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

During September 2013, we implemented a new customer information system. This implementation has resulted in certain changes to business processes and internal controls impacting financial reporting. We have taken steps to monitor and maintain appropriate internal control over financial reporting during this period of system change and will continue to evaluate the operating effectiveness of related controls during subsequent periods.

Other than this system implementation, 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.

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 potential unfavorable government and regulatory outcomes, including extensive and changing laws

and regulations that affect our industry and our operations, which could have a material adverse effect on our liquidity and results of operations.

Our profitability 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 set 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 March 2012, the MPSC's final order approved using our proposed cost allocation methodology, but 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. However, there is no assurance that both the MPSC and FERC will agree on the results of this study, which could result in an inability to fully recover our costs.

In September 2012, we received a non-binding 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.

In October 2013, the MPSC indicated that $1.4 million of incremental costs associated with regulation service acquired from third parties during a 2012 outage at DGGS were imprudently incurred, and disallowed recovery. While we believe this to be an isolated incident associated with specific circumstances at DGGS, the MPSC may use this determination as precedent for disallowing replacement costs in the future.

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 that violates 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.

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.

National and international actions have been initiated to address global climate change and the contribution of GHG emissions including, most significantly, carbon dioxide. These actions include legislative proposals, Executive and EPA actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. In June 2013, President Obama announced that he would use Executive Powers to require reductions in the amount of carbon dioxide emitted by the nation's power plants. Under the President's plan, draft regulations would be issued by EPA in the next two years. 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 the acquisition of assets including hydro-electric generating facilities and natural gas reserves, capital improvements to current assets, generation investments, and transmission grid expansion involve substantial risks.

Acquisitions include a number of risks, including but not limited to, additional costs, the assumption of material liabilities, the diversion of management’s attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, securing adequate capital to support the transaction, and regulatory approval. Uncertainties exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to complete an acquisition successfully, or to integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

In September 2013, we entered into an agreement to purchase approximately 633 MWs of hydro-electric generating assets from PPL Montana. In addition, we are in the process of acquiring additional natural gas reserves. In order to complete these transactions, we must obtain certain approvals from the MPSC and other state and federal agencies. These regulatory agencies may not approve the transactions, or may impose terms or conditions on the approval which could delay closing, impose additional costs, or otherwise impact the anticipated benefits of the transactions. In addition, failure to obtain approvals on terms consistent with the applications could negatively affect credit ratings and equity valuation, and our ability to invest in our Montana utility operations, including but not limited to supply.

Our business strategy also includes significant investment in capital improvements and additions to modernize existing infrastructure, generation investments and transmission capacity expansion. 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. In addition, these capital projects may require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support such projects. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital.

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, in early July 2013, following the return to service from a scheduled maintenance outage, Colstrip Unit 4 tripped off-line and incurred damage to its stator and rotor. Based on information from the plant operator, we currently estimate that Colstrip Unit 4 will be out of service and under repair until early 2014. Our share of the capital expenditures for this repair is currently estimated at approximately $4.5 million, which will be covered by property damage insurance subject to a $375,000 deductible. There is no assurance that we will be able to fully recover our costs for purchasing replacement power while Colstrip Unit 4 is out of service. Demand for our electric transmission capacity may also be negatively affected by the outage.

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 or response to price increases. 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. Our customers may voluntarily reduce their consumption of electricity and natural gas from us in response to increases in prices, decreases in their disposable income, individual energy conservation efforts or the use of distributed generation for electricity.

Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions. The levels of wholesale sales depend on the wholesale market price, transmission availability and the availability of generation for wholesale sales, among other factors. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce wholesale sales. These events could adversely affect our results of operations, financial position and cash flows.

We implemented a new customer information system, and we may experience additional difficulties, delays and interruptions associated with the transition to this new system. Any unexpected significant difficulties in completing the transition could negatively impact our business.

During September 2013, we implemented a new customer information system. There are inherent risks associated with replacing and changing these types of systems, such as delayed and/or inaccurate customer bills, potential disruption of our business, and substantial unplanned costs.

Consistent with our expectations, we have experienced billing delays and other disruptions during the first month of our transition to this new system. Any unexpected significant difficulties in completing the transition of our customer information system could materially impact our ability to timely and accurately record, process and report information that is important to our business. We could experience increased costs, unfavorable customer experiences or could suffer a material weakness in our internal control over financial reporting, any of which could harm our reputation and have a material adverse effect on our business, financial condition or results of operations.

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

Inherent in our natural gas distribution services are a variety of hazards and operating risks, such as leaks, explosions and mechanical problems. These risks could cause a loss of human life, significant damage to property, environmental pollution, impairment of our operations, and substantial financial 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 potentially 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 make up the difference. In addition, we are subject to price escalation risk with one of our largest QF contracts.

As part of a 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 through June 2029. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. 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 purchase the difference from other sources. The anticipated source for any QF shortfall is the wholesale market, which would subject us to commodity price risk if the cost of replacement power is higher than contracted QF rates.

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 3% over the remaining term of the contract (through June 2024). To the extent the annual escalation rate exceeds 3%, our results of operations, cash flows 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 exacerbate the risks to physical infrastructure. We may not recover all costs related to mitigating these physical and financial risks.

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

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

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

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

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 affect 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. Any significant interruption of these systems could prevent us from fulfilling our critical business functions, and sensitive, confidential and other data could be compromised.

Terrorist acts, cyber attacks (such as hacking and viruses) 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 2.1—Purchase and Sale Agreement, dated September 26, 2013, between NorthWestern Corporation and PPL Montana (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation's Current Report on Form 8-K, dated September 26, 2013, 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, 2013	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

EXHIBIT INDEX



Exhibit Number		Description
2.1		Purchase and Sale Agreement, dated September 26, 2013, between NorthWestern Corporation and PPL Montana, LLC (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation's Current Report on Form 8-K, dated September 26, 2013, 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