10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(mark one)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2014
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. 69th Street, Sioux Falls, South Dakota	57108
(Address of principal executive offices)	(Zip Code)
Registrant’s telephone number, including area code: 605-978-2900

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

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

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

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

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

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

Common Stock, Par Value $0.01

39,143,732 shares outstanding at October 17, 2014

1

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets — September 30, 2014 and December 31, 2013	4
	Condensed Consolidated Statements of Income — Three and Nine Months Ended September 30, 2014 and 2013	5
	Condensed Consolidated Statements of Comprehensive Income — Three and Nine Months Ended September 30, 2014 and 2013	6
	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2014 and 2013	7
	Condensed Consolidated Statements of Shareholders' Equity — Nine Months Ended September 30, 2014 and 2013	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 4.	Controls and Procedures	55
PART II. OTHER INFORMATION		56
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 6.	Exhibits	61
SIGNATURES		62

2

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

• 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 (Hydro Transaction) and the integration of those facilities. See Note 3 - Hydro Transaction, to the Condensed Consolidated Financial Statements for additional information relative to this 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.

3

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	September 30, 2014			December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	17,731		$	16,557
Restricted cash	38,363			6,896
Accounts receivable, net	120,713			174,913
Inventories	62,966			55,609
Regulatory assets	46,167			37,719
Deferred income taxes	25,872			14,301
Other	8,668			14,961
Total current assets	320,480			320,956
Property, plant, and equipment, net	2,799,823			2,690,128
Goodwill	355,128			355,128
Regulatory assets	349,153			316,952
Other noncurrent assets	49,714			32,096
Total assets	$	3,874,298		$	3,715,260
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,707		$	1,662
Short-term borrowings	169,944			140,950
Accounts payable	61,942			92,957
Accrued expenses	206,864			181,613
Regulatory liabilities	52,613			46,406
Total current liabilities	493,070			463,588
Long-term capital leases	28,605			29,895
Long-term debt	1,182,092			1,155,097
Deferred income taxes	435,465			395,333
Noncurrent regulatory liabilities	360,209			348,053
Other noncurrent liabilities	293,171			292,624
Total liabilities	2,792,612			2,684,590
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 42,753,751 and 39,143,568 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	428			423
Treasury stock at cost	(92,625		)	(91,744		)
Paid-in capital	926,390			910,184
Retained earnings	246,182			209,091
Accumulated other comprehensive income	1,311			2,716
Total shareholders' equity	1,081,686			1,030,670
Total liabilities and shareholders' equity	$	3,874,298		$	3,715,260

See Notes to Condensed Consolidated Financial Statements

4

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenues
Electric	212,430			$	227,103		$	652,951		$	637,667
Gas	39,482			34,772			238,965			196,652
Other	—			373			—			1,110
Total Revenues	251,912			262,248			891,916			835,429
Operating Expenses
Cost of sales	94,592			104,298			374,494			343,407
Operating, general and administrative	68,108			72,540			214,557			208,741
Property and other taxes	27,773			25,956			84,292			77,525
Depreciation and depletion	30,452			28,053			91,139			84,685
Total Operating Expenses	220,925			230,847			764,482			714,358
Operating Income	30,987			31,401			127,434			121,071
Interest Expense, net	(18,794		)	(17,056		)	(57,887		)	(50,976		)
Other (Expense) Income	(439		)	3,117			4,730			6,760
Income Before Income Taxes	11,754			17,462			74,277			76,855
Income Tax Benefit (Expense)	18,437			(1,815		)	9,240			(8,965		)
Net Income	$	30,191		$	15,647		$	83,517		$	67,890
Average Common Shares Outstanding	39,141			38,459			39,046			37,983
Basic Earnings per Average Common Share	0.77			$	0.41		$	2.14		$	1.79
Diluted Earnings per Average Common Share	0.77			$	0.40		$	2.13		$	1.78
Dividends Declared per Common Share	0.40			$	0.38		$	1.20		$	1.14

See Notes to Condensed Consolidated Financial Statements

5

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014			2013
Net Income	30,191		15,647		$	83,517		$	67,890
Other comprehensive (loss) income, net of tax:
Foreign currency translation	134		(54	)	155			81
Cash flow hedges:
Unrealized loss on cash flow hedging derivatives	(1,011	)	—		(1,011		)	—
Reclassification of net gains on derivative instruments	(183	)	(183	)	(549		)	(549		)
Total Other Comprehensive Loss	(1,060	)	(237	)	(1,405		)	(468		)
Comprehensive Income	29,131		15,410		$	82,112		$	67,422

See Notes to Condensed Consolidated Financial Statements

6

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2014			2013
OPERATING ACTIVITIES:
Net income	$	83,517		$	67,890
Items not affecting cash:
Depreciation and depletion	91,139			84,685
Amortization of debt issue costs, discount and deferred hedge gain	4,856			290
Amortization of restricted stock	2,238			1,826
Equity portion of allowance for funds used during construction	(4,393		)	(3,572		)
Gain on disposition of assets	(347		)	(761		)
Deferred income taxes	29,537			41,159
Changes in current assets and liabilities:
Restricted cash	(10,286		)	(1,536		)
Accounts receivable	55,388			14,500
Inventories	(7,357		)	(8,462		)
Other current assets	5,086			(1,983		)
Accounts payable	(30,298		)	(19,512		)
Accrued expenses	26,257			22,358
Regulatory assets	(8,448		)	9,384
Regulatory liabilities	6,207			(8,209		)
Other noncurrent assets	(34,650		)	(32,298		)
Other noncurrent liabilities	(3,480		)	5,579
Cash provided by operating activities	204,966			171,338
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(186,085		)	(153,951		)
Change in restricted cash	(21,180		)	—
Investment in New Market Tax Credit program	(18,169		)	—
Asset acquisitions	1,367			—
Proceeds from sale of assets	390			3,887
Cash used in investing activities	(223,677		)	(150,064		)
FINANCING ACTIVITIES:
Treasury stock activity	(881		)	(1,107		)
Proceeds from issuance of common stock, net	13,320			44,102
Dividends on common stock	(46,426		)	(43,103		)
Issuance of long-term debt	25,789			—
Repayments on long-term debt	(80		)	(113		)
Issuance (Repayments) of short-term borrowings, net	28,995			(19,954		)
Financing costs	(832		)	—
Cash provided by (used in) financing activities	19,885			(20,175		)
Increase in Cash and Cash Equivalents	1,174			1,099
Cash and Cash Equivalents, beginning of period	16,557			9,822
Cash and Cash Equivalents, end of period	$	17,731		$	10,921
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	$	28		$	47
Interest	44,170			40,873
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	7,989			11,245

See Notes to Condensed Consolidated Financial Statements

7

NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

(in thousands, except per share data)

	Number  of Common Shares	Number of Treasury Shares	Common Stock		Paid in Capital		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income			Total Shareholders' Equity
Balance at December 31, 2012	40,792	3,571	$	408	$	849,218	$	(90,702	)	$	172,791		$	2,317		$	934,032
Net income	0	0	$	—	$	—	$	—		$	67,890		$	—		$	67,890
Foreign currency translation adjustment	0	0	$	—	$	—	$	—		$	—		$	81		$	81
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	0	0	$	—	$	—	$	—		$	—		$	(549	)	$	(549	)
Stock based compensation	165	32	$	—	$	2,809	$	(1,294	)	$	—		$	—		$	1,515
Issuance of shares	1,103	(6)	$	13	$	44,215	$	187		$	—		$	—		$	44,415
Dividends on common stock ($1.14 per share)	0	0	$	—	$	—	$	—		$	(43,102	)	$	—		$	(43,102	)
Balance at September 30, 2013	42,060	3,597	$	421	$	896,242	$	(91,809	)	$	197,579		$	1,849		$	1,004,282
Balance at December 31, 2013	42,340	3,595	$	423	$	910,184	$	(91,744	)	$	209,091		$	2,716		$	1,030,670
Net income	0	0	$	—	$	—	$	—		$	83,517		$	—		$	83,517
Foreign currency translation adjustment	0	0	$	—	$	—	$	—		$	—		$	155		$	155
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	0	0	$	—	$	—	$	—		$	—		$	(549	)	$	(549	)
Unrealized loss on cash flow hedging derivatives, net of tax	0	0	$	—	$	—	$	—		$	—		$	(1,011	)	$	(1,011	)
Stock based compensation	118	0	$	—	$	2,727	$	(922	)	$	—		$	—		$	1,805
Issuance of shares	296	15	$	5	$	13,479	$	41		$	—		$	—		$	13,525
Dividends on common stock ($1.20 per share)	0	0	$	—	$	—	$	—		$	(46,426	)	$	—		$	(46,426	)
Balance at September 30, 2014	42,754	3,610	$	428	$	926,390	$	(92,625	)	$	246,182		$	1,311		$	1,081,686

8

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 678,200 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, 2014, 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, 2013.

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 $268.9 million through 2024.

(2) New Accounting Standards

Accounting Standards Issued

In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance will be effective for us in our first quarter of 2017. Early adoption is not permitted. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures.

9

Accounting Standards Adopted

There have been no new accounting pronouncements or changes in accounting pronouncements adopted during the nine months ended September 30, 2014 that are of significance, or potential significance, to us.

(3) 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 and one storage reservoir, 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.

The addition of hydro-electric generation is intended to provide long-term supply diversity to our portfolio and reduce risks associated with variable fuel prices. We expect the Hydro Transaction to allow us to reduce our reliance on third party power purchase agreements and spot market purchases, more closely matching our electric generation resources with forecasted customer demand. With reduced amounts of purchased power, we believe we will be less exposed to market volatility and will be better positioned to control the cost of supplying electricity to our customers. Assuming the Hydro Transaction is completed, and ownership of the Kerr Project is transferred as discussed below, we will own generation facilities that provide approximately 60% of our average electric load serving requirements in Montana.

Regulatory Approvals - Completion of the Hydro Transaction is subject to customary conditions and approvals, including approval from the Montana Public Service Commission (MPSC). In December 2013, we submitted a filing with the MPSC requesting approval of the Hydro Transaction, to include the hydro assets in rate base, and to issue the securities necessary to complete the purchase. On September 26, 2014, the MPSC issued a final order (MPSC Order) approving the application, subject to certain conditions, including the following:

• Inclusion of $870 million of the $900 million purchase price for the hydro assets in our Montana jurisdictional rate base with a 50-year life;

• Return on equity of 9.8%, a cost of debt of 4.25%, and a capital structure of 52% debt and 48% equity, resulting in an associated first year annual retail revenue requirement of approximately $117 million;

• Authorized issuance in aggregate of $900 million of securities necessary to complete the purchase, with the debt portion of the financing to have a term of 30 years and not to exceed 4.25%;

• A final compliance filing in December 2015 to reflect post-closing adjustments, the conveyance of the Kerr Project as discussed below and the actual property tax expense for the Hydroelectric facilities; and

• Tracking of revenue credits on a portfolio basis through our electricity supply cost tracker.

Following receipt of the MPSC Order, in September 2014, we requested the final necessary approval from the Federal Energy Regulatory Commission (FERC), which is authority to issue securities in connection with the Hydro Transaction. If the FERC's decision is consistent with our request, we anticipate closing of the Hydro Transaction to occur before the end of 2014. We have obtained approval from other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act. Either we or PPL Montana may terminate the agreement if the closing does not occur by March 26, 2015.

Financing - The permanent financing for the Hydro Transaction is anticipated to be a combination of up to $450 million of long-term debt, up to $400 million of equity and up to $50 million of cash flows from operations. In September 2014, we entered into forward starting interest rate swaps to effectively fix the benchmark interest rate associated with the anticipated $450 million debt issuance at a rate we anticipate will meet the conditions in the MPSC Order.

The Hydro Transaction is supported by a fully committed $900 million364-day senior bridge credit facility, which expires on March 26, 2015, if unused. The bridge facility is meant to be a short-term backup source of financing in case capital markets are not accessible at the time of closing of the Hydro Transaction. If the permanent financing is not in place at the time of closing, the bridge facility may be used temporarily in a single draw to finance the Hydro Transaction and pay related fees and expenses pending completion of the permanent financing. Any advance under the bridge facility is subject to certain conditions including regulatory approval of the Hydro Transaction, and would be due and payable within one year of borrowing.

Kerr Project - The Hydro Transaction includes the Kerr Project, a 194 megawatt hydro-electric generating facility that we expect will be transferred to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) in September 2015, in accordance with its FERC license, which gives the CSKT the right to acquire the project between September 2015 and September 2025. The CSKT have formally provided notice of their intent to acquire the Kerr Project and designated September

10

5, 2015, as the date for conveyance to occur. PPL Montana and the CSKT previously conducted an arbitration over the conveyance price of the Kerr Project. In March 2014, an arbitration panel set an estimated conveyance price of approximately $18.3 million. Under our agreement with PPL Montana, the $900 million purchase price for the Hydro Transaction includes a $30 million reference price for the Kerr Project. If the CSKT complete the acquisition and pay $18.3 million for the Kerr Project, PPL Montana will pay the difference of $11.7 million to us. If the Hydro Transaction is completed, we expect to sell any excess generation from the Kerr Project in the market and provide revenue credits to our Montana retail customers until the CSKT exercises their right to acquire the Kerr Project. The MPSC Order provides that customers will have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT.

During the nine months ended September 30, 2014, we incurred approximately $2.3 million of legal and professional fees associated with the Hydro Transaction, which are included in operating, general and administrative expense, and approximately $5.6 million of expenses related to the bridge credit facility included in interest expense.

(4) Regulatory Matters

Hydro Transaction

See Note 3 - Hydro Transaction.

Dave Gates Generating Station at Mill Creek (DGGS)

FERC Filing - In April 2014, the FERC issued an order affirming a FERC Administrative Law Judge's (ALJ) initial decision in September 2012, regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded we should allocate only a fraction of the costs we believe, based on facts and the law, should be allocated to FERC jurisdictional customers. We have been recognizing revenue consistent with the ALJ's initial decision. As of September 30, 2014, we have cumulative deferred revenue of approximately $27.3 million, which is subject to refund and recorded within current regulatory liabilities in the Condensed Consolidated Balance Sheets. The order included a requirement to issue customer refunds (included in deferred revenue) within 30 days.

In May 2014, we filed a request for rehearing, which remains pending. In our request for rehearing, we have argued that no refunds are due even if the cost allocation method is modified prospectively. The timing for FERC to act on our rehearing petition is uncertain, but could occur during the fourth quarter of 2014. Customer refunds, if any, will not be due until 30 days after a FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal could, depending on when the FERC issues a rehearing order, extend into 2016 or beyond.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We continue to evaluate options to use DGGS in combination with other generation resources, including the pending Hydro Transaction, to ensure cost recovery. Any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change.

Montana Electric and Natural Gas Tracker Filings

Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended

June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas supply procurement activities were prudent.

In May 2014, we filed our annual natural gas supply tracker filing for the 2013/2014 tracker period. During June 2014, the MPSC approved this filing on an interim basis and consolidated it with our pending natural gas filing for the 2012/2013 tracker period. Discovery is currently in process and a hearing is scheduled for January 2015.

In May 2014, we filed our annual electric supply tracker filing for the 2013/2014 tracker period. The MPSC approved this filing on an interim basis and consolidated it with our pending electric supply filing for the 2012/2013 tracker period. Our 2014 electric tracker filing includes market purchases made between July 2013 and January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion of these costs in the tracker filing is consistent with the treatment of replacement power during previous outages. During a June 2014 MPSC work session, approximately $11 million of these incremental market purchases related to the Colstrip Unit 4 outage were identified by the MPSC for additional prudency review. In July 2014, the Montana Environmental Information Center and Sierra Club filed a petition to intervene in the consolidated 2013 and 2014

11

tracker dockets to challenge our recovery of costs associated with Colstrip Unit 4, particularly the costs incurred as a result of the outage, as imprudent. A procedural schedule has not yet been established for the consolidated electric supply tracker docket.

Demand-side management (DSM) lowers our sales to customers. In 2005, the MPSC created a Lost Revenue Adjustment Mechanism (LRAM) by which we collect revenue that we would have collected without any DSM. In an order issued in October 2013, which was related to our 2012 electric supply tracker, the MPSC required us to lower our LRAM revenue recovery and imposed a new burden of proof on us for future LRAM recovery. We appealed the October 2013 order to Montana District Court. The appeal is pending. The District Court approved a partial settlement of our appeal, in which the MPSC agreed to remove from the October 2013 order the sentence that imposed the new burden and to initiate a separate docket to review lost revenue policy issues. The MPSC initiated the new proceeding in June 2014, but has not issued a procedural order.

Based on the MPSC's October 2013 order, we expect to be able to collect at least $7.1 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.

Natural Gas Production Assets

In 2012 and 2013, we purchased natural gas production interests in northern Montana's Bear Paw Basin (Bear Paw). 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. We are recognizing Bear Paw related revenue based on the precedent established by the MPSC's approval of Battle Creek in the fourth quarter of 2012. Since acquisition, we have recognized approximately $22.8 million of revenue that is subject to refund.

(5) Income Taxes

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

	Three Months Ended September 30,
	2014					2013
Income Before Income Taxes	$	11,754				$	17,462
Income tax calculated at 35% federal statutory rate	4,114			35.0	%	6,112			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(108		)	(0.9	)	(671		)	(4.0	)
Release of unrecognized tax benefit	(12,607		)	(107.3	)	—			—
Prior year permanent return to accrual adjustments	(5,172		)	(44.0	)	—			—
Flow-through repairs deductions	(3,413		)	(29.0	)	(3,085		)	(17.7	)
Plant and depreciation of flow through items	(685		)	(5.8	)	—			—
Production tax credits	(300		)	(2.6	)	(482		)	(2.9	)
Other, net	(266		)	(2.3	)	(59		)	—
	(22,551		)	(191.9	)	(4,297		)	(24.6	)
Income tax (benefit) expense	$	(18,437	)	(156.9	)%	$	1,815		10.4	%

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	Nine Months Ended September 30,
	2014					2013
Income Before Income Taxes	$	74,277				$	76,855
Income tax calculated at 35% federal statutory rate	25,997			35.0	%	26,899			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	257			0.3		(2,615		)	(3.4	)
Flow-through repairs deductions	(14,885		)	(20.0	)	(12,897		)	(16.8	)
Release of unrecognized tax benefit	(12,607		)	(17.0	)	—			—
Prior year permanent return to accrual adjustments	(5,172		)	(7.0	)	541			0.7
Production tax credits	(2,054		)	(2.8	)	(2,152		)	(2.8	)
Plant and depreciation of flow through items	(182		)	(0.2	)	49			—
Other, net	(594		)	(0.7	)	(860		)	(1.0	)
	(35,237		)	(47.4	)	(17,934		)	(23.3	)
Income tax (benefit) expense	$	(9,240	)	(12.4	)%	$	8,965		11.7	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% 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.

The income tax benefit for 2014 reflects the release of approximately $12.6 million of unrecognized tax benefits, including approximately $0.4 million of accrued interest and penalties due to the lapse of statutes of limitation in the third quarter of 2014.

In September 2013, the Internal Revenue Service (IRS) issued final tangible property regulations, which included guidance on a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. The regulations were effective January 1, 2014. During the third quarter of 2014, we elected the safe harbor method and recorded an income tax benefit of approximately $4.3 million for the cumulative adjustment for years prior to 2014, which is included in the prior year permanent return to accrual adjustment in the table above.

Uncertain Tax Positions

After the releases discussed above, we have unrecognized tax benefits of approximately $96.0 million as of September 30, 2014, including approximately $66.2 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As discussed above, during the nine months ended September 30, 2014, we released $0.4 million of accrued interest in the Condensed Consolidated Statements of Income. As of September 30, 2014 we do not have any amounts accrued for the payment of interest and penalties. As of December 31, 2013, we had $0.4 million of interest accrued in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2013, we did not recognize expense for interest or penalties and did not have any amounts accrued for the payment of interest and penalties.

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

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(6) Goodwill

We completed our annual goodwill impairment test as of April 1, 2014, and no impairment was 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, 2014. Goodwill by segment is as follows for both September 30, 2014 and December 31, 2013 (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, 2014
	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	$	134		$	—	$	134		$	155		$	—	$	155
Reclassification of net gains on derivative instruments	(297		)	114		$	(183	)	(891		)	342		(549		)
Unrealized loss on cash flow hedging derivatives	(1,644		)	633		$	(1,011	)	(1,644		)	633		(1,011		)
Other comprehensive loss	$	(1,807	)	$	747	$	(1,060	)	$	(2,380	)	$	975	$	(1,405	)

	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	(297		)	114		(183		)	(891		)	342		(549		)
Other comprehensive loss	$	(351	)	$	114	$	(237	)	$	(810	)	$	342	$	(468	)

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, 2014			December 31, 2013
Foreign currency translation	$	687		$	532
Derivative instruments designated as cash flow hedges	1,953			3,513
Pension and postretirement medical plans	(1,329		)	(1,329		)
Accumulated other comprehensive income	$	1,311		$	2,716

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

		September 30, 2014
		Three Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	3,147		$	(1,329	)	$	553	$	2,371
Other comprehensive income before reclassifications		(1,011		)	—			134		(877		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(183		)	—			—		(183		)
Net current-period other comprehensive (loss) income		(1,194		)	—			134		(1,060		)
Ending balance		$	1,953		$	(1,329	)	$	687	$	1,311

		September 30, 2013
		Three Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	3,877		$	(2,292	)	$	501		$	2,086
Other comprehensive income before reclassifications		—			—			(54		)	(54		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(183		)	—			—			(183		)
Net current-period other comprehensive loss		(183		)	—			(54		)	(237		)
Ending balance		$	3,694		$	(2,292	)	$	447		$	1,849

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		September 30, 2014
		Nine Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	3,513		$	(1,329	)	$	532	$	2,716
Other comprehensive income before reclassifications		(1,011		)	—			155		(856		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(549		)	—			—		(549		)
Net current-period other comprehensive (loss) income		(1,560		)	—			155		(1,405		)
Ending balance		$	1,953		$	(1,329	)	$	687	$	1,311

		September 30, 2013
		Nine Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate 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

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consumers. These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines.

In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

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

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to 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, 2014 and December 31, 2013. 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.

Credit Risk

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 limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.

We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. 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.

Interest Rate Swaps Designated as Cash Flow Hedges

In the third quarter of 2014, we entered into two forward starting swaps of $225 million each at 3.217% and 3.227% to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the anticipated debt issuance of $450 million associated with the Hydro Transaction. At September 30, 2014, we had net unrealized pre-tax losses of $1.6 million recorded in other current liabilities and AOCI based on the market value of our interest rate swaps. These hedging instruments are assessed on a quarterly basis to determine if they are effective in offsetting the interest rate risk associated with the forecasted transaction and as of September 30, 2014, we had no hedge ineffectiveness on these swaps.

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These forward starting interest rate swaps were designated as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated the forward starting interest rate swaps are being recorded as a component of AOCI. When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of AOCI and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred will be reported as a component of interest expense.

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):

	Location of gain reclassified from AOCI to Income	Nine Months Ended September 30, 2014 and 2013
Amount of gain reclassified from AOCI	Interest Expense	$	891

Approximately $4.8 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of September 30, 2014, and we expect to reclassify approximately $1.2 million from AOCI into interest expense during the next twelve months.

(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.

Applicable accounting guidance establishes a 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. 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. See Note 8 - Risk Management and Hedging Activities for further discussion.

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.

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	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
September 30, 2014
Restricted cash	$	17,018	$	—		$	—	$	—	$	17,018
Rabbi trust investments	19,819		—			—		—		19,819
Interest rate derivative liability	—		(1,644		)	—		—		(1,644		)
Total	$	36,837	$	(1,644	)	$	—	$	—	$	35,193
December 31, 2013
Restricted cash	$	6,650	$	—		$	—	$	—	$	6,650
Rabbi trust investments	16,477		—			—		—		16,477
Total	$	23,127	$	—		$	—	$	—	$	23,127

Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments 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 interest rate derivatives was determined based on models using quoted three-month rates.

Financial Instruments

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

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,182,092	$	1,309,855	$	1,155,097	$	1,237,151

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.

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(10) Financing Activities

In April 2012, we entered into an Equity Distribution Agreement pursuant to which we were able to 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 March 31, 2014, we sold 295,979 shares of our common stock at an average price of $45.65 per share, with proceeds of approximately $13.4 million, which are net of sales commissions of approximately $147,000 and other fees. This concluded our sales pursuant to the Equity Distribution Agreement. Total shares issued under the Equity Distribution Agreement were 2,492,889 at an average price of $40.11, for net proceeds of $98.7 million.

During 2014 we entered into a New Market Tax Credit (NMTC) financing agreement, pursuant to Section 45D of the Internal Revenue Code of 1986 as amended, to take advantage of a tax credit program related to the development and construction of a new office building in Butte, Montana. This financing agreement was structured with unrelated third party financial institutions (the Investor) and their wholly-owned community development entities (CDEs) in connection with our participation in qualified transactions under the NMTC program. Upon closing of this transaction, we entered into two loans totaling $27.0 million payable to the CDEs sponsoring the project, and provided an $18.2 million investment to the Investor. The loans have a term of thirty years with an interest rate of approximately 1.146%. In exchange for substantially all of the benefits derived from the tax credits, the Investor contributed approximately $8.8 million to the project. The NMTC is subject to recapture for a period of seven years. If the expected tax benefits are delivered without risk of recapture to the Investor and our performance obligation is relieved, we expect $7.9 million of the loan to be forgiven in July 2021. If we do not meet the conditions for loan forgiveness, we would be required to repay $27.0 million and would concurrently receive the return of our $18.2 million investment. As we are the primary beneficiary of the entities created in relation to the NMTC transaction, they have been consolidated as variable interest entities. The loans of $27.0 million are recorded in long-term debt and the investment of $18.2 million is recorded in other assets in the Condensed Consolidated Balance Sheets.

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(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, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	212,430		$	39,482		$	—		$	—	$	251,912
Cost of sales	84,720			9,872			—			—		94,592
Gross margin	127,710			29,610			—			—		157,320
Operating, general and administrative	48,528			21,005			(1,425		)	—		68,108
Property and other taxes	20,413			7,357			3			—		27,773
Depreciation and depletion	23,174			7,270			8			—		30,452
Operating income (loss)	35,595			(6,022		)	1,414			—		30,987
Interest expense	(14,025		)	(2,627		)	(2,142		)	—		(18,794		)
Other income (expense)	1,337			336			(2,112		)	—		(439		)
Income tax benefit	5,235			926			12,276			—		18,437
Net income (loss)	$	28,142		$	(7,387	)	$	9,436		$	—	$	30,191
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
Capital expenditures	$	62,054		$	12,011		$	—		$	—	$	74,065

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 and depletion	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

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Nine Months Ended
September 30, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	652,951		$	238,965		$	—		$	—	$	891,916
Cost of sales	273,754			100,740			—			—		374,494
Gross margin	379,197			138,225			—			—		517,422
Operating, general and administrative	144,933			66,254			3,370			—		214,557
Property and other taxes	61,322			22,961			9			—		84,292
Depreciation and depletion	69,398			21,716			25			—		91,139
Operating income (loss)	103,544			27,294			(3,404		)	—		127,434
Interest expense	(43,663		)	(7,979		)	(6,245		)	—		(57,887		)
Other income	3,204			876			650			—		4,730
Income tax (expense) benefit	(575		)	(3,334		)	13,149			—		9,240
Net income	$	62,510		$	16,857		$	4,150		$	—	$	83,517
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
Capital expenditures	$	161,718		$	24,367		$	—		$	—	$	186,085

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 and depletion	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

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(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 earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards.

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

	Three Months Ended
	September 30, 2014	September 30, 2013
Basic computation	39,141,148	38,459,484
Dilutive effect of
Restricted stock and performance share awards (1)	139,655	186,192
Diluted computation	39,280,803	38,645,676

	Nine Months Ended
	September 30, 2014	September 30, 2013
Basic computation	39,045,790	37,982,673
Dilutive effect of
Restricted stock and performance share awards (1)	141,560	181,462
Diluted computation	39,187,350	38,164,135

_______________

(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.

(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,
	2014			2013			2014			2013
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,708		$	3,367		$	116		$	135
Interest cost	6,536			5,680			214			219
Expected return on plan assets	(7,377		)	(8,123		)	(245		)	(254		)
Amortization of prior service cost	62			62			(500		)	(500		)
Recognized actuarial loss	530			2,911			87			242
Net Periodic Benefit Cost (Income)	$	2,459		$	3,897		$	(328	)	$	(158	)

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	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Components of Net Periodic Benefit Cost (Income)
Service cost	$	8,123		$	10,100		$	349		$	406
Interest cost	19,610			17,040			644			658
Expected return on plan assets	(22,130		)	(24,369		)	(736		)	(764		)
Amortization of prior service cost	185			185			(1,499		)	(1,499		)
Recognized actuarial loss	1,589			8,735			261			728
Net Periodic Benefit Cost (Income)	$	7,377		$	11,691		$	(981	)	$	(471	)

(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 $27.3 million to $35.0 million, primarily for manufactured gas plants discussed below. As of September 30, 2014, 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 results of operations.

Manufactured Gas Plants - Approximately $22.2 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 feasibility studies and implementing 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 $11.4 million, and we estimate that approximately $8.3 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. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. 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.

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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 soil and groundwater impacts. 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 and additional monitoring wells will be installed at the Butte site. 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, the Title V operating permit programs and the New Source Performance Standards (NSPS). In 2014, the EPA reproposed NSPS that specify permissible levels of GHG emissions from newly-constructed fossil fuel-fired electric generating units.

As directed by President Obama's Climate Action Plan, on June 2, 2014, the EPA proposed the Clean Power Plan (CPP) rule to control carbon dioxide emissions from existing fossil fuel fired electric generating units. The rule proposes the establishment of statewide reductions of GHG emissions for individual states based on the state's potential to shift generation to existing natural gas combined cycle plants, to develop new renewable energy, to achieve demand-side management savings, and to improve performance at existing coal-fired units. The comment period on the proposed rule has been extended to December 1, 2014. EPA intends to finalize those regulations and guidelines by June 1, 2015. Under the CPP proposed rule, States must submit individual plans for achieving GHG emission standards to EPA by June 30, 2016, although EPA is proposing a dual-phase submittal process for state plans that would allow for additional time to June 30, 2018 under certain circumstances. The initial performance period for compliance would commence in 2020, with full implementation by 2030.

On June 23, 2014, the U.S. Supreme Court struck down the EPA's Tailoring Rule, which limited the sources subject to GHG permitting requirements to the largest fossil-fueled power plants, indicating that EPA had exceeded its authority under the Clean Air Act by "rewriting unambiguous statutory terms." However, the decision affirmed EPA's ability to regulate GHG emissions from sources already subject to regulation under the PSD program, which includes most electric generating units.

Requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance and increase our costs of procuring electricity. Although there continues to be changes in legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. In addition, 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. 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 alter their ash management 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. In a

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January 2014 consent decree in the case Appalachian Voices v. McCarthy, the EPA agreed to take final action with respect to the CCR regulations by December 19, 2014. In addition, legislation has been 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 technology available (BTA)” for minimizing environmental impacts. On May 19, 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule gives seven options for meeting BTA, and provides a more flexible compliance approach than the proposed rule. In August 2014, EPA published the final rule establishing national requirements applicable to cooling water intake structures, which became effective October 14, 2014. Permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements.

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 reviewing public comments on 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 is under a modified consent decree to take final action by September 30, 2015. 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). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. Facilities that are subject to the MATS must come into compliance by April 2015, unless a one year extension is granted on a case-by-case basis. On April 15, 2014, the U.S. Court of Appeals for the D.C. Circuit upheld the MATS rule. The decision has been appealed by 23 states and industry groups to the Supreme Court, which has not yet decided whether to hear the case.

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 in certain states beginning in 2012. On April 29, 2014 the Supreme Court reversed and remanded the 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated the CSAPR. EPA has filed a motion in the U.S. Court of Appeals for the D.C. Circuit to lift the stay and allow EPA to implement the CSAPR.

In October 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. In November 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. Court of Appeals for the Ninth Circuit. Montana Environmental Information Center and Sierra Club have challenged the EPA's decision not to require any emissions reductions from Colstrip

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Units 3 and 4. The Ninth Circuit held oral argument on the petition on May 16, 2014. At this time, we cannot predict or determine the timing or 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 estimated total project cost for the AQCS at the Big Stone plant is approximately $384 million (our share is 23.4%) and it is expected to be operational during the second half of 2015. As of September 30, 2014, we have capitalized costs of approximately $64.4 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, Big Stone will meet the requirements by installing the AQCS system and using activated carbon injection for mercury control. 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. New mercury emissions monitoring equipment will also be required.

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 $9.0 million (our share is 10.0%).

Based on the finalized MATS, Coyote will meet the requirements by using activated carbon injection for mercury control.

Iowa. The Neal #4 generating facility, of which we have an 8.7% ownership, installed a scrubber, a baghouse, and a selective non-catalytic reduction system to comply with national ambient air quality standards and the MATS. The project was substantially completed in 2013.

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.

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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 (Court) against the six individual owners of Colstrip, including us, as well as the operator or managing agent of the station (Defendants). 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 dropped claims associated with projects completed before 2001, the Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects.

In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of SO₂, NOx and particulate matter and (b) were “major modifications” subject to permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits. 

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. 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.

On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications.

The parties filed a joint notice (Notice) on April 21, 2014 that advised the Court of Plaintiffs’ intent to file a Second Amended Complaint which dropped claims relating to 52 projects, and added one additional project. At the joint request of the parties, the Court extended various deadlines previously set and set a bench trial date for the liability portion of the case for June 8, 2015.

On May 6, 2014, the Court held oral argument on Defendants' motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the Magistrate issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ motion to dismiss, but dismissed seven of Plaintiffs’ “best available control technology” claims and dismissed two of Plaintiffs' claims for injunctive relief. The Plaintiffs filed an objection to the Magistrate's findings and recommendations with the U.S. Federal District Court Judge, and on August 13, 2014, the Court adopted the Magistrate's findings and conclusions.

On August 27, 2014, the Plaintiffs filed their Second Amended Complaint, which alleges a total of 13 claims covering eight projects and seeks 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. Defendants filed their Answer to the Second Amended Complaint on September 26, 2014.

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 or range of loss, if any, that would be associated with an adverse decision.

Billings Refinery Outage Claim

In August 2014, we received a demand letter from a refinery in Billings claiming damages in excess of $48.5 million allegedly resulting from an outage that occurred in January 2014. We have notified our insurance carrier of the claims and our policy has a $2 million retention. We intend to vigorously defend these claims. Due to the preliminary nature of the matter, at this time, we cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse result.

Other Legal Proceedings

We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 678,200 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, 2013.

SIGNIFICANT ITEMS

Significant items during the three months ended September 30, 2014 include:

• Received MPSC approval of our application associated with the Hydro Transaction; and

• Improvement in Net Income of approximately $14.6 million as compared with the same period in 2013, due primarily to the release of an unrecognized tax benefit and tax method change, resulting in an income tax benefit of $18.4 million in the third quarter of 2014.

Hydro Transaction

On September 26, 2013, we entered into an agreement with 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 and one storage reservoir, 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.

The addition of hydro-electric generation is intended to provide long-term supply diversity to our portfolio and reduce risks associated with variable fuel prices. We expect the Hydro Transaction to allow us to reduce our reliance on third party power purchase agreements and spot market purchases, more closely matching our electric generation resources with forecasted customer demand. With reduced amounts of purchased power, we believe we will be less exposed to market volatility and will be better positioned to control the cost of supplying electricity to our customers. Assuming the Hydro Transaction is completed, and ownership of the Kerr Project is transferred as discussed below, we will own generation facilities that provide approximately 60% of our average electric load serving requirements in Montana.

In the first full year following the closing, we expect the Hydro Transaction would provide additional annual net income of approximately $38 - $40 million, with capital expenditures of approximately $10 million.

Regulatory Approvals - Completion of the Hydro Transaction is subject to customary conditions and approvals, including approval from the MPSC. In December 2013, we submitted a filing with the MPSC requesting approval of the Hydro Transaction, to include the hydro assets in rate base, and to issue the securities necessary to complete the purchase. On September 26, 2014, the MPSC issued a final order approving the application, subject to certain conditions, including the following:

• Inclusion of $870 million of the $900 million purchase price for the hydro assets in our Montana jurisdictional rate base with a 50-year life;

• Return on equity of 9.8%, a cost of debt of 4.25%, and a capital structure of 52% debt and 48% equity, resulting in an associated first year annual retail revenue requirement of approximately $117 million;

• Authorized issuance in aggregate of $900 million of securities necessary to complete the purchase, with the debt portion of the financing to have a term of 30 years and not to exceed 4.25%;

• A final compliance filing in December 2015 to reflect post-closing adjustments, the conveyance of the Kerr Project as discussed below and the actual property tax expense for the Hydroelectric facilities; and

• Tracking of revenue credits on a portfolio basis through our electricity supply cost tracker.

Following receipt of the MPSC Order, in September 2014, we requested the final necessary approval from the FERC, which is authority to issue securities in connection with the Hydro Transaction. If the FERC's decision is consistent with our request, we anticipate closing of the Hydro Transaction to occur before the end of 2014. We have obtained approval from other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act. Either we or PPL Montana may terminate the agreement if the closing does not occur by March 26, 2015.

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Financing - The permanent financing for the Hydro Transaction is anticipated to be a combination of up to $450 million of long-term debt, up to $400 million of equity and up to $50 million of cash flows from operations. In September 2014, we entered into forward starting interest rate swaps to effectively fix the benchmark interest rate associated with the anticipated $450 million debt issuance at a rate we anticipate will meet the conditions in the MPSC Order.

The Hydro Transaction is supported by a fully committed $900 million364-day senior bridge credit facility, which expires on March 26, 2015, if unused. The bridge facility is meant to be a short-term backup source of financing in case capital markets are not accessible at the time of closing of the Hydro Transaction. If the permanent financing is not in place at the time of closing, the bridge facility may be used temporarily in a single draw to finance the Hydro Transaction pending completion of the permanent financing. Any advance under the bridge facility is subject to certain conditions including regulatory approval of the Hydro Transaction, and would be due and payable within one year of borrowing.

Kerr Project - The Hydro Transaction includes the Kerr Project, a 194 megawatt hydro-electric generating facility that we expect will be transferred to the CSKT in September 2015, in accordance with its FERC license, which gives the CSKT the right to acquire the project between September 2015 and September 2025. The CSKT have formally provided notice of their intent to acquire the Kerr Project and designated September 5, 2015, as the date for conveyance to occur. PPL Montana and the CSKT previously conducted an arbitration over the conveyance price of the Kerr Project. In March 2014, an arbitration panel set an estimated conveyance price of approximately $18.3 million. Under our agreement with PPL Montana, the $900 million purchase price for the Hydro Transaction includes a $30 million reference price for the Kerr Project. If the CSKT complete the acquisition and pay $18.3 million for the Kerr Project, PPL Montana will pay the difference of $11.7 million to us. If the Hydro Transaction is completed, we expect to sell any excess generation from the Kerr Project in the market and provide revenue credits to our Montana retail customers until the CSKT exercises their right to acquire the Kerr Project. The MPSC Order provides that customer will have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT.

During the nine months ended September 30, 2014, we incurred approximately $2.3 million of legal and professional fees associated with the Hydro Transaction, which are included in operating, general and administrative expense, and approximately $5.6 million of expenses related to the bridge credit facility included in interest expense.

Dave Gates Generating Station at Mill Creek (DGGS)

In April 2014, the FERC issued an order affirming a FERC Administrative Law Judge's (ALJ) initial decision in September 2012, regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded we should allocate only a fraction of the costs we believe based on facts and the law, should be allocated to FERC jurisdictional customers. We have been recognizing revenue consistent with the ALJ's initial decision. As of September 30, 2014, we have cumulative deferred revenue of approximately $27.3 million, which is subject to refund and recorded within current regulatory liabilities in the Condensed Consolidated Balance Sheets. The order included a requirement to issue customer refunds (included in deferred revenue) within 30 days.

In May 2014, we filed a request for rehearing, which remains pending. In our request for rehearing, we have argued that no refunds are due even if the cost allocation method is modified prospectively. The timing for FERC to act on our rehearing petition is uncertain, but could occur during the fourth quarter of 2014. Customer refunds, if any, will not be due until 30 days after a FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal could, depending on when the FERC issues a rehearing order, extend into 2016 or beyond.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We continue to evaluate options to use DGGS in combination with other generation resources including the pending Hydro Transaction, to ensure cost recovery. Any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change.

Outage - During the third quarter and early fourth quarter of 2014, we experienced unscheduled outages at DGGS, due primarily to component failures within several of the gas generators and power turbines. DGGS has three electric generating units, with each unit comprised of two gas generators and two power turbines that drive an electric generator. As of October 20, 2014, one half of the plant was in service through a combination of the original equipment and loaned equipment from the turbine manufacturer, PW Power Systems. We are coordinating with PW Power Systems to complete repairs on three gas generators and two power turbines, which are expected to be complete by the first quarter of 2015. The power turbines are still under warranty. Although the plant is expected to remain in service throughout the repair period, the amount of available regulation service will vary as equipment is repaired and returned to service. We have continued to meet our regulation service

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requirement, and have not acquired replacement regulation service during this time. Assuming completion of repairs by the first quarter of 2015 and no further component failures, we currently believe we have sufficient availability to meet regulation needs and do not anticipate needing to acquire any regulation service from third parties. If we should need to acquire regulation service from third parties, there can be no assurance that the MPSC and/or FERC would allow us full recovery of such costs. In addition, if repairs are in excess of planned maintenance costs, we may not be able to recover these costs.

Natural Gas Production Assets

In 2012 and 2013, we purchased natural gas production interests in northern Montana's Bear Paw Basin. 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. We are recognizing Bear Paw related revenue based on the precedent established by the MPSC's approval of Battle Creek in the fourth quarter of 2012. Since acquisition, we have recognized approximately $22.8 million of revenue that is subject to refund.

South Dakota Electric General Rate Case

General rate cases are necessary to cover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We periodically evaluate the need for electric and natural gas rate changes in each state in which we provide service. Based on our evaluation, we expect to file an electric rate case in South Dakota during the fourth quarter of 2014. We have not filed an electric rate case in South Dakota since 1980. This filing will include capital expenditures related to improvements to our transmission and distribution delivery systems over time, the Aberdeen Generating Station, and additions to comply with additional emission reduction requirements at two of our jointly owned electric generating units that serve our South Dakota customers.

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RESULTS OF OPERATIONS

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

Non-GAAP Financial Measure

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

Factors Affecting Results of Operations

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

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

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OVERALL CONSOLIDATED RESULTS

Three Months Ended September 30, 2014 Compared with the Three Months Ended September 30, 2013

	Three Months Ended September 30,
	2014		2013		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	212.4	$	227.1	$	(14.7	)	(6.5	)%
Natural Gas	39.5		34.8		4.7			13.5
Other	—		0.4		(0.4		)	(100.0	)
	$	251.9	$	262.3	$	(10.4	)	(4.0	)%

	Three Months Ended September 30,
	2014		2013		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	84.7	$	95.3	$	(10.6	)	(11.1	)%
Natural Gas	9.9		9.0		0.9			10.0
	$	94.6	$	104.3	$	(9.7	)	(9.3	)%

	Three Months Ended September 30,
	2014		2013		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	127.7	$	131.8	$	(4.1	)	(3.1	)%
Natural Gas	29.6		25.8		3.8			14.7
Other	—		0.4		(0.4		)	(100.0	)
	$	157.3	$	158.0	$	(0.7	)	(0.4	)%

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

	Gross Margin 2014 vs. 2013
	(in millions)
DSM lost revenues	$	(4.9	)
Operating expenses recovered in trackers	(1.7		)
Natural gas and electric retail volumes	(0.8		)
Electric transmission capacity	3.5
Natural gas production	2.8
Other	0.4
Decrease in Consolidated Gross Margin	$	(0.7	)

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Consolidated gross margin decreased $0.7 million primarily due to the following:

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

• Lower revenue for operating expenses recovered through our supply trackers primarily related to efficiency measures implemented by customers; and

• Lower retail volumes as a result of cooler summer weather.

These decreases were partly offset by:

• Higher demand to transmit energy across our lines due primarily to interconnection with the Montana Alberta Transmission Line (MATL) that went into commercial operation late in 2013; and

• An increase in natural gas production margin from the acquisition of gas production assets in December 2013, of which the revenues are subject to refund.

	Three Months Ended September 30,
	2014		2013		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	68.1	$	72.5	$	(4.4	)	(6.1	)%
Property and other taxes	27.8		26.0		1.8			6.9
Depreciation and depletion	30.5		28.1		2.4			8.5
	$	126.4	$	126.6	$	(0.2	)	(0.2	)%

Consolidated operating, general and administrative expenses were $68.1 million for the three months ended September 30, 2014, as compared with $72.5 million for the three months ended September 30, 2013. Primary components of the change include the following:

	Operating, General & Administrative Expenses
	2014 vs. 2013
	(in millions)
Non-employee directors deferred compensation	$	(3.6	)
Hydro Transaction costs	(2.2		)
Operating expenses recovered in trackers	(1.7		)
Bad debt expense	(0.6		)
Natural gas production	2.6
Other	1.1
Decrease in Operating, General & Administrative Expenses	$	(4.4	)

The decrease in operating, general and administrative expenses of $4.4 million was primarily due to the following:

• Non-employee directors deferred compensation decreased as compared to the prior year, primarily due to a decrease in our stock price during the three months ended September 30, 2014. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes down, deferred compensation expense decreases; however, we account for the deferred shares as trading securities and their change in value is also reflected in other income with no impact on net income;

• Lower legal and professional fees associated with the Hydro Transaction. Hydro Transaction related legal and professional fees were $0.6 million for the three months ended September 30, 2014 as compared to $2.8 million for the same period

34

in 2013. We expect to continue to incur Hydro Transaction related legal and professional fees during the remainder of 2014;

• Lower operating expenses primarily related to customer efficiency programs, which are recovered through trackers and have no impact on operating income; and

• Lower bad debt expense, due to improved collection of receivables from customers.

These decreases were partly offset by higher natural gas production costs due to the acquisition of the natural gas production assets discussed above.

Property and other taxes were $27.8 million for the three months ended September 30, 2014, as compared with $26.0 million in the same period of 2013. This increase was primarily due to plant additions and higher estimated property valuations in Montana. We estimate property taxes throughout each year and update to the actual expense when we receive our Montana property tax bills in November.

Depreciation and depletion expense was $30.5 million for the three months ended September 30, 2014, as compared with $28.1 million in the same period of 2013. This increase was primarily due to plant additions, including approximately $1.2 million related to natural gas production assets.

Consolidated operating income for the three months ended September 30, 2014 was $31.0 million, as compared with $31.4 million in the same period of 2013.

Consolidated interest expense for the three months ended September 30, 2014 was $18.8 million, as compared with $17.1 million in the same period of 2013. This increase includes $1.9 million of expenses associated with the bridge credit facility related to the Hydro Transaction and higher interest from the issuance in December 2013 of $100 million of long-term debt unrelated to the Hydro Transaction, partly offset by lower interest accrued on supply trackers and higher capitalization of AFUDC.

Consolidated other expense for the three months ended September 30, 2014, was $0.4 million, as compared with income of $3.1 million in the same period of 2013. This decrease was primarily due to a $3.6 million reduction in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, had a corresponding reduction to operating, general and administrative expenses) partially offset by higher capitalization of AFUDC.

Consolidated income tax benefit for the three months ended September 30, 2014 was $18.4 million, as compared with income tax expense of $1.8 millionin the same period of 2013. Our effective tax rate was (156.9)% for the three months ended September 30, 2014 as compared with 10.4% for the three months ended September 30, 2013.

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

	Three Months Ended September 30,
	2014					2013
Income Before Income Taxes	$	11.8				$	17.5
Income tax calculated at 35% federal statutory rate	4.1			35.0	%	6.1			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(0.1		)	(0.9	)	(0.7		)	(4.0	)
Release of unrecognized tax benefit	(12.6		)	(107.3	)	—			—
Prior year permanent return to accrual adjustments	(5.2		)	(44.0	)	—			—
Flow-through repairs deductions	(3.4		)	(29.0	)	(3.1		)	(17.7	)
Plant and depreciation of flow through items	(0.7		)	(5.8	)	—			—
Production tax credits	(0.3		)	(2.6	)	(0.5		)	(2.9	)
Other, net	(0.2		)	(2.3	)	—			—
	(22.5		)	(191.9	)	(4.3		)	(24.6	)
Income tax (benefit) expense	$	(18.4	)	(156.9	)%	$	1.8		10.4	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% 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 2014 benefit also reflects the release of approximately $12.6 million of previously unrecognized tax benefits due to the lapse of statutes of limitation in the third quarter of 2014. In addition, in the third quarter of 2014, we elected the safe harbor method related to the deductibility of repair costs. This resulted in an income tax benefit of approximately $4.3 million for the cumulative adjustment for years prior to 2014, which is included in the prior year permanent return to accrual adjustments.

Consolidated net income for the three months ended September 30, 2014 was $30.2 million as compared with $15.6 million for the same period in 2013. This increase was primarily due to the income tax benefit in 2014 as discussed above, partly offset by lower operating income, higher interest expense, and lower other income.

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Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013

	Nine Months Ended September 30,
	2014		2013		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	653.0	$	637.7	$	15.3		2.4	%
Natural Gas	239.0		196.7		42.3			21.5
Other	—		1.1		(1.1		)	(100.0	)
	$	892.0	$	835.5	$	56.5		6.8	%

	Nine Months Ended September 30,
	2014		2013		Change		% Change
	(dollars in millions)
Cost of Sales
Electric	$	273.8	$	260.9	$	12.9	4.9	%
Natural Gas	100.7		82.5		18.2		22.1
	$	374.5	$	343.4	$	31.1	9.1	%

	Nine Months Ended September 30,
	2014		2013		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	379.2	$	376.8	$	2.4		0.6	%
Natural Gas	138.3		114.2		24.1			21.1
Other	—		1.1		(1.1		)	(100.0	)
	$	517.5	$	492.1	$	25.4		5.2	%

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

	Gross Margin 2014 vs. 2013
	(in millions)
Natural gas production	$	17.4
Natural gas and electric retail volumes	6.2
Montana natural gas rate increase	4.9
Electric transmission capacity	3.5
DSM lost revenues	(3.0		)
Operating expenses recovered in trackers	(2.1		)
Other	(1.5		)
Increase in Consolidated Gross Margin	$	25.4

Consolidated gross margin increased $25.4 million primarily due to the following:

• An increase in natural gas production margin primarily due to the acquisition of gas production assets in December 2013, of which the revenues are subject to refund;

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

• The full period effect of an increase in Montana natural gas delivery rates implemented in April 2013; and

• Higher demand to transmit energy across our lines as discussed above.

These increases were partly offset by:

• A decrease in DSM lost revenues recovered through our supply trackers as discussed in the quarterly results above; and

• Lower revenue for operating expenses recovered through our supply trackers, primarily related to efficiency measures implemented by customers.

	Nine Months Ended September 30,
	2014		2013		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	214.6	$	208.7	5.9		2.8	%
Property and other taxes	84.3		77.5		6.8		8.8
Depreciation and depletion	91.1		84.7		6.4		7.6
	$	390.0	$	370.9	$	19.1	5.1	%

Consolidated operating, general and administrative expenses were $214.6 million for the nine months ended September 30, 2014, as compared with $208.7 million for the nine months ended September 30, 2013. Primary components of the change include the following:

	Operating, General & Administrative Expenses
	2014 vs. 2013
	(in millions)
Natural gas production	$	7.6
Bad debt expense	2.5
Non-employee directors deferred compensation	(2.2		)
Operating expenses recovered in trackers	(2.1		)
Hydro Transaction costs	(1.0		)
Other	1.1
Increase in Operating, General & Administrative Expenses	$	5.9

The increase in operating, general and administrative expenses of $5.9 million was primarily due to the following:

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

• Higher bad debt expense, due to a combination of higher revenues and slower collections of receivables from customers related to our customer information systems implementation.

These increases were partly offset by:

• Non-employee directors deferred compensation decreased as compared to the prior year, due to a decrease in our stock price;

• Lower operating expenses primarily related to customer efficiency programs, which are recovered through trackers and have no impact on operating income; and

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• Lower legal and professional fees associated with the Hydro Transaction. Hydro Transaction related legal and professional fees were $2.3 million for the nine months ended September 30, 2014 as compared to $3.3 million for the same period in 2013.

Property and other taxes were $84.3 million for the nine months ended September 30, 2014, as compared with $77.5 million in the same period of 2013. This increase was primarily due to plant additions and higher estimated property valuations in Montana.

Depreciation and depletion expense was $91.1 million for the nine months ended September 30, 2014, as compared with $84.7 million in the same period of 2013. This increase was primarily due to plant additions, including approximately $3.6 million related to natural gas production assets. These increases were 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.

Consolidated operating income for the nine months ended September 30, 2014 was $127.4 million, as compared with $121.1 million in the same period of 2013. This increase was due to the increase in gross margin partly offset by higher operating expenses as discussed above.

Consolidated interest expense for the nine months ended September 30, 2014 was $57.9 million, as compared with $51.0 million in the same period of 2013. This increase includes $5.7 million of expenses associated with the bridge credit facility related to the Hydro Transaction and higher interest from the issuance in December 2013 of $100 million of long-term debt unrelated to the Hydro Transaction, partly offset by lower interest accrued on supply trackers and higher capitalization of AFUDC.

Consolidated other income for the nine months ended September 30, 2014, was $4.7 million, as compared with $6.8 million in the same period of 2013. This decrease was primarily due to a $2.2 million reduction in the value of deferred shares held in trust for non-employee directors deferred compensation.

Consolidated income tax benefit for the nine months ended September 30, 2014 was $9.2 million, as compared with income tax expense of $9.0 millionin the same period of 2013. Our effective tax rate was (12.4)% for the nine months ended September 30, 2014 as compared with 11.7% for the nine months ended September 30, 2013.

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

	Nine Months Ended September 30,
	2014					2013
Income Before Income Taxes	$	74.3				$	76.9
Income tax calculated at 35% federal statutory rate	26.0			35.0	%	26.9			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	0.3			0.3		(2.6		)	(3.4	)
Flow-through repairs deductions	(14.9		)	(20.0	)	(12.9		)	(16.8	)
Release of unrecognized tax benefit	(12.6		)	(17.0	)	—			—
Prior year permanent return to accrual adjustments	(5.2		)	(7.0	)	0.5			0.7
Production tax credits	(2.1		)	(2.8	)	(2.2		)	(2.8	)
Plant and depreciation of flow through items	(0.2		)	(0.2	)	—			—
Other, net	(0.5		)	(0.7	)	(0.7		)	(1.0	)
	(35.2		)	(47.4	)	(17.9		)	(23.3	)
Income tax (benefit) expense	$	(9.2	)	(12.4	)%	$	9.0		11.7	%

Our effective tax rate typically differs from the federal statutory tax rate of 35% 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

39

tax credits. As discussed above, the income tax benefit during 2014 also reflects the release of unrecognized tax benefits and a change in tax accounting method.

Consolidated net income for the nine months ended September 30, 2014 was $83.5 million as compared with $67.9 million for the same period in 2013. This increase was primarily due to the higher operating income and 2014 tax benefit discussed above, partly offset by higher interest expense and lower other income.

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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 is also reflected in cost of sales and therefore has 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, 2014 Compared with the Three Months Ended September 30, 2013

	Results
	2014			2013		Change			% Change
	(dollars in millions)
Retail revenues	$	197.9		$	201.5	$	(3.6	)	(1.8	)%
Regulatory amortization	(2.3		)	11.8		(14.1		)	(119.5	)
Total retail revenues	195.6			213.3		(17.7		)	(8.3	)
Transmission	14.7			11.2		3.5			31.3
Ancillary services	0.3			0.4		(0.1		)	(25.0	)
Wholesale	0.2			0.8		(0.6		)	(75.0	)
Other	1.6			1.4		0.2			14.3
Total Revenues	212.4			227.1		(14.7		)	(6.5	)
Total Cost of Sales	84.7			95.3		(10.6		)	(11.1	)
Gross Margin	$	127.7		$	131.8	$	(4.1	)	(3.1	)%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2014		2013		2014	2013	2014	2013
	(in thousands)
Retail Electric
Montana	$	59,545	$	65,455	545	575	283,412	280,284
South Dakota	12,527		12,698		132	146	49,581	49,350
Residential	72,072		78,153		677	721	332,993	329,634
Montana	84,726		83,624		826	823	63,906	63,266
South Dakota	19,963		18,502		251	255	12,451	12,154
Commercial	104,689		102,126		1,077	1,078	76,357	75,420
Industrial	10,329		10,105		721	737	77	74
Other	10,805		11,131		86	91	8,031	7,813
Total Retail Electric	$	197,895	$	201,515	2,561	2,627	417,458	412,941
Total Wholesale Electric	$	202	$	845	12	39	—	—

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	Degree Days			2014 as compared with:
Cooling Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	324	393	265	18% colder	22% warmer
South Dakota	467	702	635	33% colder	26% colder

	Degree Days			2014 as compared with:
Heating Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	330	231	355	43% colder	7% warmer
South Dakota	107	60	83	78% colder	29% colder

The following summarizes the components of the changes in electric gross margin for the three months ended September 30, 2014 and 2013:

	Gross Margin 2014 vs. 2013
	(in millions)
DSM lost revenues	$	(4.9	)
Operating expenses recovered in trackers	(1.7		)
Retail volumes	(1.3		)
Transmission capacity	3.5
Other	0.3
Decrease in Gross Margin	$	(4.1	)

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

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

• Lower revenue for operating expenses recovered through our supply trackers, primarily related to efficiency measures implemented by customers; and

• Lower retail volumes as a result of cooler summer weather, partly offset by customer growth.

These decreases were partly offset by higher demand to transmit energy across our lines due primarily to interconnection with the MATL line that went into commercial operation late in 2013. In addition, the decrease in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin.

Retail volumes decreased primarily due to cooler summer weather, partly offset by customer growth. Wholesale volumes decreased as a result of lower utilization in 2014.

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Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013

	Results
	2014		2013		Change			% Change
	(dollars in millions)
Retail revenues	$	583.7	$	581.5	$	2.2		0.4	%
Regulatory amortization	21.6		11.9		9.7			81.5
Total retail revenues	605.3		593.4		11.9			2.0
Transmission	40.8		37.3		3.5			9.4
Ancillary services	1.2		1.1		0.1			9.1
Wholesale	1.2		2.0		(0.8		)	(40.0	)
Other	4.5		3.9		0.6			15.4
Total Revenues	653.0		637.7		15.3			2.4
Total Cost of Sales	273.8		260.9		12.9			4.9
Gross Margin	$	379.2	$	376.8	$	2.4		0.6	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2014		2013		2014	2013	2014	2013
	(in thousands)
Retail Electric
Montana	$	192,303	$	198,375	1,773	1,751	282,836	280,113
South Dakota	39,049		37,150		453	447	49,548	49,250
Residential	231,352		235,525		2,226	2,198	332,384	329,363
Montana	242,274		238,482		2,410	2,356	63,658	63,120
South Dakota	56,343		52,009		738	722	12,322	12,168
Commercial	298,617		290,491		3,148	3,078	75,980	75,288
Industrial	30,612		31,089		2,116	2,194	75	74
Other	23,154		24,352		156	168	6,260	6,129
Total Retail Electric	$	583,735	$	581,457	7,646	7,638	414,699	410,854
Total Wholesale Electric	$	1,219	$	2,022	72	97	—	—

	Degree Days			2014 as compared with:
Cooling Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	332	438	306	24% colder	8% warmer
South Dakota	544	752	698	28% colder	22% colder

	Degree Days			2014 as compared with:
Heating Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	5,049	4,721	4,936	7% colder	2% colder
South Dakota	6,265	6,174	5,602	1% colder	12% colder

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The following summarizes the components of the changes in electric gross margin for the nine months ended September 30, 2014 and 2013:

	Gross Margin 2014 vs. 2013
	(in millions)
Transmission capacity	$	3.5
Retail volumes	3.4
DSM lost revenue	(3.0		)
Operating expenses recovered in trackers	(2.1		)
Other	0.6
Increase in Gross Margin	$	2.4

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

• Higher demand to transmit energy across our lines; and

• An increase in retail volumes due primarily to colder winter weather and customer growth.

These increases were partly offset by:

• A decrease in DSM lost revenues recovered through our supply trackers as discussed above; and

• Lower revenue for operating expenses recovered through our supply trackers, primarily related to efficiency measures implemented by customers.

In addition, 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 increased primarily due to colder winter weather and customer growth. Wholesale volumes decreased as a result of lower utilization in 2014.

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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 is also reflected in cost of sales and therefore has minimal impact on gross margin.

• Wholesale: Primarily represents transportation and storage for others.

Three Months Ended September 30, 2014 Compared with the Three Months Ended September 30, 2013

	Results
	2014		2013		Change		% Change
	(dollars in millions)
Retail revenues	$	25.4	$	22.8	$	2.6	11.4	%
Regulatory amortization	4.0		3.2		0.8		25.0
Total retail revenues	29.4		26.0		3.4		13.1
Wholesale and other	10.1		8.8		1.3		14.8
Total Revenues	39.5		34.8		4.7		13.5
Total Cost of Sales	9.9		9.0		0.9		10.0
Gross Margin	$	29.6	$	25.8	$	3.8	14.7	%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2014		2013		2014	2013	2014	2013
	(in thousands)
Retail Gas
Montana	$	11,057	$	9,770	904	807	163,474	161,988
South Dakota	2,051		1,916		116	124	38,196	37,846
Nebraska	2,299		2,257		154	157	36,480	36,315
Residential	15,407		13,943		1,174	1,088	238,150	236,149
Montana	6,567		6,042		596	581	22,580	22,457
South Dakota	1,726		1,296		210	171	6,105	5,971
Nebraska	1,457		1,281		194	185	4,571	4,538
Commercial	9,750		8,619		1,000	937	33,256	32,966
Industrial	135		145		13	12	260	262
Other	102		94		10	10	153	156
Total Retail Gas	$	25,394	$	22,801	2,197	2,047	271,819	269,533

	Degree Days			2014 as compared with:
Heating Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	330	231	355	43% colder	7% warmer
South Dakota	107	60	83	78% colder	29% colder
Nebraska	63	21	43	200% colder	47% colder

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The following summarizes the components of the changes in natural gas gross margin for the three months ended September 30, 2014 and 2013:

	Gross Margin 2014 vs. 2013
	(in millions)
Natural gas production	$	2.8
Retail volumes	0.5
Other	0.5
Increase in Gross Margin	$	3.8

This increase in gross margin was primarily due to the acquisition of gas production assets in December 2013, of which the revenues are subject to refund, and an increase in retail volumes from cooler summer weather and customer growth. Average natural gas supply prices increased in 2014 resulting in higher retail revenues and cost of sales as compared with 2013, with no impact to gross margin.

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Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013

	Results
	2014		2013			Change		% Change
	(dollars in millions)
Retail revenues	$	202.7	$	173.5		$	29.2	16.8	%
Regulatory amortization	3.7		(6.3		)	10.0		(158.7	)
Total retail revenues	206.4		167.2			39.2		23.4
Wholesale and other	32.6		29.5			3.1		10.5
Total Revenues	239.0		196.7			42.3		21.5
Total Cost of Sales	100.7		82.5			18.2		22.1
Gross Margin	$	138.3	$	114.2		$	24.1	21.1	%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2014		2013		2014	2013	2014	2013
	(in thousands)
Retail Gas
Montana	$	86,186	$	72,171	8,460	8,014	163,662	162,362
South Dakota	22,820		20,227		2,553	2,354	38,490	38,146
Nebraska	19,528		18,774		2,116	2,012	36,787	36,656
Residential	128,534		111,172		13,129	12,380	238,939	237,164
Montana	44,869		37,338		4,840	4,252	22,707	22,613
South Dakota	16,670		13,498		2,322	2,119	6,138	6,028
Nebraska	10,862		10,016		1,580	1,496	4,619	4,596
Commercial	72,401		60,852		8,742	7,867	33,464	33,237
Industrial	920		776		96	88	262	264
Other	856		720		104	97	153	157
Total Retail Gas	$	202,711	$	173,520	22,071	20,432	272,818	270,822

	Degree Days			2014 as compared with:
Heating Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	5,049	4,721	4,936	7% colder	2% colder
South Dakota	6,265	6,174	5,602	1% colder	12% colder
Nebraska	4,775	4,741	4,605	1% colder	4% colder

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The following summarizes the components of the changes in natural gas gross margin for the nine months ended September 30, 2014 and 2013:

	Gross Margin 2014 vs. 2013
	(in millions)
Natural gas production	$	17.4
Montana natural gas rate increase	4.9
Retail volumes	2.8
Other	(1.0		)
Increase in Gross Margin	$	24.1

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

• An increase in natural gas production margin primarily due to the acquisition of gas production assets in December 2013, of which the revenues are subject to refund;

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

• An increase in retail volumes due primarily to colder weather and customer growth.

Average natural gas supply prices increased in 2014 resulting in higher retail revenues and cost of sales as compared with 2013, with no impact to gross margin.

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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, 2014, our total net liquidity was approximately $147.8 million, including $17.7 million of cash and $130.1 million of revolving credit facility availability. In October 2014, we increased the size of our existing revolving credit facility to $340 million (from $300 million) pursuant to an accordion feature. Revolving credit facility availability was $186.0 millionas of October 17, 2014.

The following table presents additional information about short term borrowings during the three months ended September 30, 2014 (in millions):

Amount outstanding at period end	$	169.9
Daily average amount outstanding	$	151.5
Maximum amount outstanding	$	169.9

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 above, we intend to utilize available cash flow, debt capacity that would allow us to maintain investment grade ratings, and issue equity. In April 2012, we entered into an Equity Distribution Agreement pursuant to which we were able to 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 March 31, 2014, we sold 295,979 shares of our common stock at an average price of $45.65 per share. Proceeds received were approximately $13.4 million, which are net of sales commissions paid to UBS of approximately $147,000 and other fees. This concluded our sales pursuant to the Equity Distribution Agreement. Total shares issued under the Equity Distribution Agreement were 2,492,889 at an average price of $40.11, for net proceeds of $98.7 million.

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.

Hydro Transaction - During the fourth quarter of 2014, assuming receipt of reasonably satisfactory regulatory approvals related to the Hydro Transaction, we expect to issue up to $450 million of debt securities and up to $400 million of equity securities, as well as use up to $50 million cash, to fund the Hydro Transaction. In November 2013, in connection with the Hydro Transaction, we entered into a $900 million 364-day senior bridge credit facility (bridge facility), which expires on March 26, 2015, if unused. The bridge facility is meant to be a short-term backup source of financing in case capital markets are not accessible at the time of closing of the Hydro Transaction. If the permanent financing is not in place at the time of closing, the bridge facility may be used temporarily in a single draw to finance the Hydro Transaction pending completion of the permanent financing. Any advance under the bridge facility is subject to certain conditions including regulatory approval of the Hydro Transaction, and would be due and payable within one year of borrowing.

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.

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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, 2014, we are under collected on our natural gas and electric trackers by approximately $31.9 million, as compared with an under collection of $27.3 million as of December 31, 2013, and an under collection of $8.4 million as of September 30, 2013.

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 our customers, and impact our trade credit availability. Fitch Ratings (Fitch), 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 17, 2014, 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	A1	A3	Prime-2	Stable
S&P	A-	BBB	A-2	Stable

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

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Cash Flows

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

	Nine Months Ended September 30,
	2014			2013
Operating Activities
Net income	$	83.5		$	67.9
Non-cash adjustments to net income	123.0			123.6
Changes in working capital	36.5			6.5
Other	(38.1		)	(26.7		)
	204.9			171.3
Investing Activities
Property, plant and equipment additions	(186.1		)	(153.9		)
Change in restricted cash	(21.2		)	—
Investment in New Market Tax Credit program	(18.2		)	—
Asset acquisitions	1.4			—
Other	0.4			3.9
	(223.7		)	(150.0		)
Financing Activities
Proceeds from issuance of common stock, net	13.3			44.1
Issuances (Repayments) of long-term debt, net	25.7			(0.1		)
Issuances (Repayments) of short-term borrowings, net	29.0			(20.0		)
Dividends on common stock	(46.4		)	(43.1		)
Other	(1.7		)	(1.1		)
	19.9			(20.2		)
Increase in Cash and Cash Equivalents	$	1.1		$	1.1
Cash and Cash Equivalents, beginning of period	$	16.6		$	9.8
Cash and Cash Equivalents, end of period	$	17.7		$	10.9

Cash Provided by Operating Activities

As of September 30, 2014, cash and cash equivalents were $17.7 million as compared with $16.6 million at December 31, 2013 and $10.9 million at September 30, 2013. Cash provided by operating activities totaled $204.9 million for the nine months ended September 30, 2014 as compared with $171.3 million during the nine months ended September 30, 2013. This increase in operating cash flows is primarily due to higher collections of customer receivables as compared with 2013, offset in part by a higher under collection of supply costs in our trackers, as discussed above.

Cash Used in Investing Activities

Cash used in investing activities increased by approximately $73.6 million as compared with the first nine months of 2013. Plant additions during 2014 include maintenance additions of approximately $117.9 million, supply related capital expenditures of approximately $30.2 million, primarily related to electric generation facilities in South Dakota, and Distribution System Infrastructure Project (DSIP) capital expenditures of approximately $38.0 million. Plant additions during the first nine months of 2013 include maintenance additions of approximately $87.3 million, supply related capital expenditures of approximately $34.5 million, which were primarily related to electric generation facilities in South Dakota, and DSIP capital expenditures of approximately $31.8 million.

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Cash Used in Financing Activities

Cash provided by financing activities totaled approximately $19.9 million during the nine months ended September 30, 2014 as compared with cash used by financing activities of approximately $20.2 million during the nine months ended September 30, 2013. During the nine months ended September 30, 2014, net cash provided by financing activities consisted of proceeds received from the issuance of common stock pursuant to our equity distribution agreement of $13.3 million and net issuances of commercial paper and long term debt of $54.7 million, partially offset by the payment of dividends of $46.4 million. 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.

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, 2014. See our Annual Report on Form 10-K for the year ended December 31, 2013 for additional discussion.

	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Long-term debt	$	1,182,092	$	—	$	—	$	150,000	$	—	$	55,000	$	977,092
Capital leases	30,312		417		1,732		1,837		1,979		2,133		22,214
Short-term borrowings	169,944		169,944		—		—		—		—		—
Future minimum operating lease payments	4,772		554		1,894		1,424		621		58		221
Estimated pension and other postretirement obligations (1)	55,226		643		13,749		13,695		13,623		13,516		N/A
Qualifying facilities liability (2)	1,031,909		16,821		69,606		71,598		73,622		75,688		724,574
Supply and capacity contracts (3)	1,554,303		79,787		203,382		149,751		125,374		97,722		898,287
Contractual interest payments on debt (4)	713,662		19,284		62,285		62,285		53,225		51,506		465,077
Environmental remediation obligations (1)	8,300		1,000		1,300		2,200		2,200		1,600		N/A
Total Commitments (5)	$	4,750,520	$	288,450	$	353,948	$	452,790	$	270,644	$	297,223	$	3,087,465

_________________________

(1) We estimate cash obligations related to our pension and other postretirement benefit programs and environmental remediation obligations for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit 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 $74 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $1.0 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $0.8 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 28 years.

(4) For our variable rate short-term borrowings outstanding, we have assumed an average interest rate of 0.39% through maturity.

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

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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, 2014, 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, 2013. The policies disclosed included the accounting for the following: goodwill and long-lived assets, qualifying facilities liability, revenue recognition, regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing primarily fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit facility. The revolving credit facility bears interest at the lower of prime or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.88% to 1.75%. 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, 2014, we had approximately $169.9 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 $1.7 million.

Commodity Price Risk

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

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

Counterparty Credit Risk

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

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and accumulated and reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 established by several 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 April 2014, the FERC issued an order affirming a FERC Administrative Law Judge's (ALJ) initial decision in September 2012, regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded we should allocate only a fraction of the costs we believe, based on facts and the law, should be allocated to FERC jurisdictional customers. We filed a request for rehearing, which remains pending. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals, which could extend into 2016 or beyond. The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We continue to evaluate options to use DGGS in combination with other generation resources to ensure cost recovery, and do not believe an impairment loss is probable at this time. Any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We will continue to evaluate recovery of this asset in the future as facts and circumstances change. If we are not able to ensure cost recovery of DGGS we may be required to record an impairment charge, which could have a material adverse effect on our operating results.

In October 2013, the MPSC concluded 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. We have appealed that decision to the Montana district court. In addition, our 2014 electric tracker filing includes market purchases made between July 2013 and January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion of these costs in the tracker filing is consistent with the treatment of replacement power during previous Colstrip outages. During a June 2014 MPSC work session, approximately $11 million of these incremental market purchases related to the Colstrip Unit 4 outage were identified by the MPSC for additional prudency review. In July 2014, the Montana Environmental Information Center and Sierra Club filed a petition to intervene in the consolidated 2013 and 2014 tracker dockets to challenge our recovery of costs associated with Colstrip Unit 4, particularly the costs incurred as a result of the outage, as imprudent. We believe the costs associated with the outage and incremental market purchases were prudently incurred. However, there is risk that the MPSC ultimately disallows all or a portion of these costs, which could have a material adverse effect on our operating results.

We are subject to many FERC rules and orders that regulate 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

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(NERC) functions for which we have registered in both the Midwest Reliability Organization (MRO) for our South Dakota operations and the Western Electricity Coordination Council (WECC) 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.

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 the Hydro Transaction assets or future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

In order to complete the Hydro Transaction, we must still obtain approval from the FERC to issue securities. Failure to obtain approvals in a timely manner or on terms consistent with our application 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 permitting, 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.

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, migratory birds and other 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. As directed by President Obama's Climate Action Plan, on June 2, 2014, the EPA proposed the Clean Power Plan rule to control carbon dioxide emissions from existing fossil fuel fired electric generating units. The EPA has expressed the intent to finalize those regulations and guidelines by June 1, 2015.

Requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance and increase our costs of procuring electricity. Although there continues to be changes in legislation and regulations that affect GHG emissions from power plants, 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.

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

57

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 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. Colstrip Unit 4 returned to service in early 2014. There is no assurance that we will be able to fully recover our costs for the purchase of replacement power while Colstrip Unit 4 was out of service.

In addition, during the third quarter and early fourth quarter of 2014, we experienced unscheduled outages at DGGS, due primarily to component failures within several of the gas generators and power turbines. We have continued to meet our regulation responsibilities, and have not acquired replacement regulation service during this time. We are coordinating with PW Power Systems to complete repairs, which are expected to be complete by the first quarter of 2015. Although the plant is expected to remain in service throughout the repair period, the amount of available regulation service will vary as equipment is repaired and returned to service. We do not currently anticipate needing to acquire any regulation service from third parties during this time. If we should need to acquire regulation service, there can be no assurance that the MPSC and/or FERC would allow us full recovery of such costs.

We also 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

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business, and substantial unplanned costs, any of which could harm our reputation and have a material adverse effect on our business, financial condition or results of operations.

Consistent with our expectations, we experienced billing delays, which resulted in delays in collections of customer receivables and increased bad debt expense during the transition to the new system. We are still experiencing delays in collections of customer receivables. Any additional 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.

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. As discussed above, in our latest electric tracker filing the treatment of costs for replacement power due to an outage at Colstrip Unit 4 have been identified by the MPSC for additional prudence review. 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.

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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 revenue 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.

In connection with the Hydro Transaction, we entered into a $900 million 364-day senior bridge credit facility (bridge facility), which may be used to temporarily finance a significant portion of the acquisition and pay related fees and expenses in the event that permanent financing is not in place at the time of the closing of the transaction. The permanent financing is anticipated to include a mix of long-term debt and common equity. Although we believe we have taken prudent steps to position ourselves for successful capital raises, there can be no assurance as to the ultimate cost or availability of permanent financing.

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.

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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 the 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 reduced economic activity.

ITEM 6.                      EXHIBITS

(a)Exhibits

Exhibit 31.1—Certification of chief executive officer.

Exhibit 31.2—Certification of chief financial officer.

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

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

Exhibit 101.INS—XBRL Instance Document

Exhibit 101.SCH—XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL—XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF—XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB—XBRL Taxonomy Label Linkbase Document

Exhibit 101.PRE—XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

			NorthWestern Corporation
Date:	October 23, 2014	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

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EXHIBIT INDEX

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

_________________________

* Filed herewith

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EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert C. Rowe, certify that:

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

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

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

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

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

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

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

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

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

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

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

October 23, 2014

/s/ ROBERT C. ROWE

Robert C. Rowe

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Brian B. Bird, certify that:

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

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

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

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

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

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

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

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

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

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

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

October 23, 2014

/s/ BRIAN B. BIRD

Brian B. Bird

Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

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

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

In connection with the Quarterly Report of NorthWestern Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert C. Rowe, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

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

October 23, 2014	/s/ ROBERT C. ROWE
	Robert C. Rowe
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

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

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

In connection with the Quarterly Report of NorthWestern Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brian B. Bird, Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

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

October 23, 2014	/s/ BRIAN B. BIRD
	Brian B. Bird
	Vice President and Chief Financial Officer

XML

Risk Management and Hedging Activities (Details) (USD $)	9 Months Ended			9 Months Ended
	Sep. 30, 2014 swaps	Dec. 31, 2013	Sep. 30, 2014 Interest rate swap at 3.217% [Member]	Sep. 30, 2014 Interest Rate Swap [Member]	Sep. 30, 2014 Interest Rate Swap [Member] Interest Expense [Member]	Sep. 30, 2013 Interest Rate Swap [Member] Interest Expense [Member]	Sep. 30, 2014 Interest rate swap at 3.227% [Member]	Dec. 31, 2014 Scenario, Forecast [Member]
Derivative [Line Items]
Number of forward starting swaps	2
Derivative, Amount of Hedged Item	$ 225,000,000
Derivative, Fixed Interest Rate			3.217%				3.227%
Other long-term debt	27,000,000							450,000,000
Amount of gain reclassified from AOCI					891,000	891,000
Pre-tax gain on cash flow hedges remaining in AOCI	1,600,000			4,800,000
Pre-tax gain on cash flow hedge to be reclassified within twelve months from AOCI to interest expense				1,200,000
Interest rate swaps outstanding	0
Physical purchase and sale of gas and electricity at fixed prices	0	0
Hedge ineffectiveness on interest rate swaps	$ 0

XML

Commitments and Contingencies Environmental (Details) (USD $) In Millions, unless otherwise specified							9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014 Colstrip Unit 4 [Member]	Sep. 30, 2014 Neal 4 Generating Facility [Member]	Sep. 30, 2014 Coyote Generating Facility [Member]	Sep. 30, 2014 Big Stone Generating Facility [Member]	Sep. 30, 2014 Manufactured Gas Plants [Member]	Sep. 30, 2014 Aberdeen South Dakota Site [Member] Manufactured Gas Plants [Member]	Jul. 01, 2018 Scenario, Forecast [Member] Coyote Generating Facility [Member]
Environmental remediation obligation, minimum	$ 27.3
Environmental remediation obligation, maximum	35.0
Accrual for environmental loss contingencies	28.7					22.2	11.4
Environmental remediation obligation next 5 years							8.3
Jointly owned utility plant ownership percentage		30.00%	8.70%	10.00%	23.40%
NOx emissions per million Btu as calculated on a 30 day rolling average basis								0.5
Estimated capital expenditures for environmental obligations				9.0	384.0
Joint ownership share of capitalized project costs					$ 64.4
Number of years for environmental remediation obligation to be incurred							5 years

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Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified		24 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014 Montana Natural Gas Production Assets [Member] Revenue Subject to Refund [Member]	Sep. 30, 2014 Dave Gates Generating Station [Member] Revenue Subject to Refund [Member]	Sep. 30, 2014 Regulatory Reviews of Filings [Member]
Customer refund liability, current			$ 27.3
CU4 incremental market purchases identified for further review				11
Revenue recognized, subject to refund		22.8
Demand side management expected lost revenue recovery	$ 7.1

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Comprehensive (Loss) Income (Tables)

9 Months Ended

Sep. 30, 2014

Statement of Comprehensive Income [Abstract]

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

The following tables display the components of Other Comprehensive (Loss) Income (in thousands):

	September 30, 2014
	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	$	134		$	—	$	134		$	155		$	—	$	155
Reclassification of net gains on derivative instruments	(297		)	114		$	(183	)	(891		)	342		(549		)
Unrealized loss on cash flow hedging derivatives	(1,644		)	633		$	(1,011	)	(1,644		)	633		(1,011		)
Other comprehensive loss	$	(1,807	)	$	747	$	(1,060	)	$	(2,380	)	$	975	$	(1,405	)

	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	(297		)	114		(183		)	(891		)	342		(549		)
Other comprehensive loss	$	(351	)	$	114	$	(237	)	$	(810	)	$	342	$	(468	)

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

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

	September 30, 2014			December 31, 2013
Foreign currency translation	$	687		$	532
Derivative instruments designated as cash flow hedges	1,953			3,513
Pension and postretirement medical plans	(1,329		)	(1,329		)
Accumulated other comprehensive income	$	1,311		$	2,716

Accumulated Other Comprehensive Income [Table Text Block]

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

		September 30, 2014
		Three Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	3,147		$	(1,329	)	$	553	$	2,371
Other comprehensive income before reclassifications		(1,011		)	—			134		(877		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(183		)	—			—		(183		)
Net current-period other comprehensive (loss) income		(1,194		)	—			134		(1,060		)
Ending balance		$	1,953		$	(1,329	)	$	687	$	1,311

		September 30, 2013
		Three Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	3,877		$	(2,292	)	$	501		$	2,086
Other comprehensive income before reclassifications		—			—			(54		)	(54		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(183		)	—			—			(183		)
Net current-period other comprehensive loss		(183		)	—			(54		)	(237		)
Ending balance		$	3,694		$	(2,292	)	$	447		$	1,849

		September 30, 2014
		Nine Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	3,513		$	(1,329	)	$	532	$	2,716
Other comprehensive income before reclassifications		(1,011		)	—			155		(856		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(549		)	—			—		(549		)
Net current-period other comprehensive (loss) income		(1,560		)	—			155		(1,405		)
Ending balance		$	1,953		$	(1,329	)	$	687	$	1,311

		September 30, 2013
		Nine Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate 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

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Financing Activities (Details) (USD $)	9 Months Ended		3 Months Ended	24 Months Ended		3 Months Ended		3 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Mar. 31, 2014 Equity Distribution Agreement [Member]	Mar. 31, 2014 Equity Distribution Agreement [Member]	Apr. 02, 2012 Equity Distribution Agreement [Member]	Sep. 30, 2014 Unrelated third party investment [Member]	Sep. 30, 2014 New Market Tax Credit [Member]	Sep. 30, 2021 Scenario, Forecast [Member]	Dec. 31, 2014 Scenario, Forecast [Member]
Debt Instrument [Line Items]
Common stock, aggregate gross sales price					$ 100,000,000				$ 400,000,000
Stock issued during period, shares, new issues			295,979	2,492,889
Common stock average share price during the period			$ 45.65	$ 40.11
Proceeds received from new issues during the period			13,400,000	98,700,000
Sales commissons and fees			147,000
Investments							18,200,000
Debt instrument, term	30 years
Debt instrument, interest rate, percentage	1.146%
Investment in New Market Tax Credit Program	18,169,000	0				8,800,000
Debt instrument, decrease, forgiveness								7,900,000
Other long-term debt	$ 27,000,000								$ 450,000,000

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Comprehensive (Loss) Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Other Comprehensive Income (Loss), before Tax [Abstract]
Foreign currency translation adjustment	$ 134	$ (54)	$ 155	$ 81
Reclassification of net gains on derivative instruments	(297)	(297)	(891)	(891)
Unrealized loss on cash flow hedging derivatives	(1,644)		(1,644)
Other comprehensive loss	(1,807)	(351)	(2,380)	(810)
Other Comprehensive Income (Loss), Tax [Abstract]
Foreign currency translation adjustment	0	0	0	0
Reclassification of net gains on derivative instruments	114	114	342	342
Unrealized loss o cash flow hedging derivatives	633		633
Other comprehensive loss	747	114	975	342
Other comprehensive (loss) income, net of tax:
Foreign currency translation	134	(54)	155	81
Reclassification of net gains on derivative instruments	(183)	(183)	(549)	(549)
Unrealized loss on cash flow hedging derivatives	(1,011)	0	(1,011)	0
Total Other Comprehensive Loss	(1,060)	(237)	(1,405)	(468)
Accumulated Other Comprehensive Income [Abstract]
Foreign currency translation	687		687		532
Derivative instruments designated as cash flow hedges	1,953		1,953		3,513
Pension and postretirement medical plans	(1,329)		(1,329)		(1,329)
Accumulated other comprehensive income	$ 1,311		$ 1,311		$ 2,716

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Commitments and Contingencies Litigation (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]
Damages sought, value	$ 48.5
Deductible amount	$ 2

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New Accounting Standards

9 Months Ended

Sep. 30, 2014

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

New Accounting Pronouncements [Text Block]

New Accounting Standards

Accounting Standards Issued

In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance will be effective for us in our first quarter of 2017. Early adoption is not permitted. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures.

Accounting Standards Adopted

There have been no new accounting pronouncements or changes in accounting pronouncements adopted during the nine months ended September 30, 2014 that are of significance, or potential significance, to us.

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating revenues	$ 251,912	$ 262,248	$ 891,916	$ 835,429
Cost of sales	94,592	104,298	374,494	343,407
Gross margin	157,320	157,950	517,422	492,022
Operating, general and administrative	68,108	72,540	214,557	208,741
Property and other taxes	27,773	25,956	84,292	77,525
Depreciation and depletion	30,452	28,053	91,139	84,685
Operating income (loss)	30,987	31,401	127,434	121,071
Interest expense	(18,794)	(17,056)	(57,887)	(50,976)
Other income (expense)	(439)	3,117	4,730	6,760
Income tax (expense) benefit	18,437	(1,815)	9,240	(8,965)
Net Income	30,191	15,647	83,517	67,890
Total assets	3,874,298	3,633,650	3,874,298	3,633,650	3,715,260
Capital expenditures	74,065	65,402	186,085	153,951
Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues	212,430	227,103	652,951	637,667
Cost of sales	84,720	95,264	273,754	260,879
Gross margin	127,710	131,839	379,197	376,788
Operating, general and administrative	48,528	49,155	144,933	142,594
Property and other taxes	20,413	19,381	61,322	57,549
Depreciation and depletion	23,174	22,150	69,398	67,454
Operating income (loss)	35,595	41,153	103,544	109,191
Interest expense	(14,025)	(14,302)	(43,663)	(42,840)
Other income (expense)	1,337	2,213	3,204	4,926
Income tax (expense) benefit	5,235	(8,412)	(575)	(12,792)
Net Income	28,142	20,652	62,510	58,485
Total assets	2,694,883	2,542,068	2,694,883	2,542,068
Capital expenditures	62,054	55,579	161,718	130,585
Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues	39,482	34,772	238,965	196,652
Cost of sales	9,872	9,034	100,740	82,528
Gross margin	29,610	25,738	138,225	114,124
Operating, general and administrative	21,005	18,521	66,254	56,899
Property and other taxes	7,357	6,572	22,961	19,968
Depreciation and depletion	7,270	5,895	21,716	17,206
Operating income (loss)	(6,022)	(5,250)	27,294	20,051
Interest expense	(2,627)	(2,560)	(7,979)	(7,553)
Other income (expense)	336	878	876	1,753
Income tax (expense) benefit	926	3,520	(3,334)	(153)
Net Income	(7,387)	(3,412)	16,857	14,098
Total assets	1,170,843	1,082,294	1,170,843	1,082,294
Capital expenditures	12,011	9,823	24,367	23,366
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	373	0	1,110
Cost of sales	0	0	0	0
Gross margin	0	373	0	1,110
Operating, general and administrative	(1,425)	4,864	3,370	9,248
Property and other taxes	3	3	9	8
Depreciation and depletion	8	8	25	25
Operating income (loss)	1,414	(4,502)	(3,404)	(8,171)
Interest expense	(2,142)	(194)	(6,245)	(583)
Other income (expense)	(2,112)	26	650	81
Income tax (expense) benefit	12,276	3,077	13,149	3,980
Net Income	9,436	(1,593)	4,150	(4,693)
Total assets	8,572	9,288	8,572	9,288
Capital expenditures	0	0	0	0
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Cost of sales	0	0	0	0
Gross margin	0	0	0	0
Operating, general and administrative		0		0
Property and other taxes	0	0	0	0
Depreciation and depletion	0	0	0	0
Operating income (loss)	0	0	0	0
Interest expense	0	0	0	0
Other income (expense)	0	0	0	0
Income tax (expense) benefit	0	0	0	0
Net Income	0	0	0	0
Total assets	0	0	0	0
Capital expenditures	$ 0	$ 0	$ 0	$ 0

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

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

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

	Three Months Ended
	September 30, 2014	September 30, 2013
Basic computation	39,141,148	38,459,484
Dilutive effect of
Restricted stock and performance share awards (1)	139,655	186,192
Diluted computation	39,280,803	38,645,676

	Nine Months Ended
	September 30, 2014	September 30, 2013
Basic computation	39,045,790	37,982,673
Dilutive effect of
Restricted stock and performance share awards (1)	141,560	181,462
Diluted computation	39,187,350	38,164,135

_______________

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

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

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

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

Three Months Ended
September 30, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	212,430		$	39,482		$	—		$	—	$	251,912
Cost of sales	84,720			9,872			—			—		94,592
Gross margin	127,710			29,610			—			—		157,320
Operating, general and administrative	48,528			21,005			(1,425		)	—		68,108
Property and other taxes	20,413			7,357			3			—		27,773
Depreciation and depletion	23,174			7,270			8			—		30,452
Operating income (loss)	35,595			(6,022		)	1,414			—		30,987
Interest expense	(14,025		)	(2,627		)	(2,142		)	—		(18,794		)
Other income (expense)	1,337			336			(2,112		)	—		(439		)
Income tax benefit	5,235			926			12,276			—		18,437
Net income (loss)	$	28,142		$	(7,387	)	$	9,436		$	—	$	30,191
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
Capital expenditures	$	62,054		$	12,011		$	—		$	—	$	74,065

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 and depletion	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

Nine Months Ended
September 30, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	652,951		$	238,965		$	—		$	—	$	891,916
Cost of sales	273,754			100,740			—			—		374,494
Gross margin	379,197			138,225			—			—		517,422
Operating, general and administrative	144,933			66,254			3,370			—		214,557
Property and other taxes	61,322			22,961			9			—		84,292
Depreciation and depletion	69,398			21,716			25			—		91,139
Operating income (loss)	103,544			27,294			(3,404		)	—		127,434
Interest expense	(43,663		)	(7,979		)	(6,245		)	—		(57,887		)
Other income	3,204			876			650			—		4,730
Income tax (expense) benefit	(575		)	(3,334		)	13,149			—		9,240
Net income	$	62,510		$	16,857		$	4,150		$	—	$	83,517
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
Capital expenditures	$	161,718		$	24,367		$	—		$	—	$	186,085

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 and depletion	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

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Earnings Per Share (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Basic computation	39,141,148	38,459,484	39,045,790	37,982,673
Dilutive effect of restricted stock and performance share awards (1)	139,655	186,192	141,560	181,462
Diluted computation	39,280,803	38,645,676	39,187,350	38,164,135

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,						Three Months Ended September 30,
	2014			2013			2014			2013
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,708		$	3,367		$	116		$	135
Interest cost	6,536			5,680			214			219
Expected return on plan assets	(7,377		)	(8,123		)	(245		)	(254		)
Amortization of prior service cost	62			62			(500		)	(500		)
Recognized actuarial loss	530			2,911			87			242
Net Periodic Benefit Cost (Income)	$	2,459		$	3,897		$	(328	)	$	(158	)

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Components of Net Periodic Benefit Cost (Income)
Service cost	$	8,123		$	10,100		$	349		$	406
Interest cost	19,610			17,040			644			658
Expected return on plan assets	(22,130		)	(24,369		)	(736		)	(764		)
Amortization of prior service cost	185			185			(1,499		)	(1,499		)
Recognized actuarial loss	1,589			8,735			261			728
Net Periodic Benefit Cost (Income)	$	7,377		$	11,691		$	(981	)	$	(471	)

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Nature of Operations and Basis of Consolidation (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014 watts	Dec. 31, 2013 customers
Number of customers		678,200
Number of megawatts of qualifying facility	35
Estimated aggregate gross contractual payments for qualifying facilities through 2024	$ 268.9

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Nature of Operations and Basis of Consolidation

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 678,200 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, 2014, 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, 2013.

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 $268.9 million through 2024.

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Hydro Transaction Hydro-electric (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended			3 Months Ended
	Sep. 30, 2014	Sep. 26, 2013 days watts	Sep. 26, 2013 Kerr Project [Member] watts	Dec. 31, 2014 Scenario, Forecast [Member]
Significant Acquisitions and Disposals [Line Items]
Megawatts of hydro-electric generation capacity		633	194
Purchase price		$ 900	$ 30
Owned average load serving requirement	60.00%
Estimated rate base, Hydro Electric	870
Authorized return on equity	9.80%
Hydro assets, useful life	50 years
Authorized cost of debt	4.25%
Capital structure, percentage of debt	52.00%
Capitalized structure, percentage of equity	48.00%
Annual revenue requirement increase	117
Debt instrument, term	30 years
Long term debt, Hydro financing	27.0			450.0
Common stock, aggregate gross sales price				400
Estimated cash from operating activities				50
Bridge term loan facility		900
Bridge term loan facility agreement term		364
Estimated conveyance price of hydro facility			18.3
Estimated reference price less conveyance price			11.7
Authorized issuance of securities		900
Transaction costs	2.3
Debt related commitment fees and debt issuance costs	$ 5.6

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Fair Value Recurring Basis (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Fair value, assets, level 1 to level 2 transfers, amount	$ 0	$ 0
Fair value, assets, level 2 to level 1 transfers, amount	0	0
Fair value, liabilities, level 1 to level 2 transfers, amount	0	0
Fair value, liabilities, level 2 to level 1 transfers, amount	0	0
Fair Value, transfers into (out of) level 3	0	0
Fair Value, Measurements, Recurring [Member] | Total Net Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	17,018	6,650
Rabbi trust investments	19,819	16,477
Interest rate derivative liability	(1,644)
Total	35,193	23,127
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	17,018	6,650
Rabbi trust investments	19,819	16,477
Interest rate derivative liability	0
Total	36,837	23,127
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs(Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Interest rate derivative liability	(1,644)
Total	(1,644)	0
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs(Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Interest rate derivative liability	0
Total	0	0
Fair Value, Measurements, Recurring [Member] | Margin Cash Collateral Offset
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0
Rabbi trust investments	0
Interest rate derivative liability	0
Total	$ 0

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CONDENSED CONSOLIDATED BALANCE SHEET (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current Assets:
Cash and cash equivalents	$ 17,731	$ 16,557
Restricted cash	38,363	6,896
Accounts receivable, net	120,713	174,913
Inventories	62,966	55,609
Regulatory assets	46,167	37,719
Deferred income taxes	25,872	14,301
Other	8,668	14,961
Total current assets	320,480	320,956
Property, plant, and equipment, net	2,799,823	2,690,128
Goodwill	355,128	355,128
Regulatory assets	349,153	316,952
Other noncurrent assets	49,714	32,096
Total assets	3,874,298	3,715,260
Current Liabilities:
Current maturities of capital leases	1,707	1,662
Short-term borrowings	169,944	140,950
Accounts payable	61,942	92,957
Accrued expenses	206,864	181,613
Regulatory liabilities	52,613	46,406
Total current liabilities	493,070	463,588
Long-term capital leases	28,605	29,895
Long-term debt	1,182,092	1,155,097
Deferred income taxes	435,465	395,333
Noncurrent regulatory liabilities	360,209	348,053
Other noncurrent liabilities	293,171	292,624
Total liabilities	2,792,612	2,684,590
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 42,753,751 and 39,143,568 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	428	423
Treasury stock at cost	(92,625)	(91,744)
Paid-in capital	926,390	910,184
Retained earnings	246,182	209,091
Accumulated other comprehensive income	1,311	2,716
Total shareholders' equity	1,081,686	1,030,670
Total liabilities and shareholders' equity	$ 3,874,298	$ 3,715,260

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Employee Benefit Plans Net Periodic Benefit Cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Pension Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	$ 2,708	$ 3,367	$ 8,123	$ 10,100
Interest cost	6,536	5,680	19,610	17,040
Expected return on plan assets	(7,377)	(8,123)	(22,130)	(24,369)
Amortization of prior service cost	62	62	185	185
Recognized actuarial loss	530	2,911	1,589	8,735
Net Periodic Benefit Cost (Income)	2,459	3,897	7,377	11,691
Other Postretirement Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	116	135	349	406
Interest cost	214	219	644	658
Expected return on plan assets	(245)	(254)	(736)	(764)
Amortization of prior service cost	(500)	(500)	(1,499)	(1,499)
Recognized actuarial loss	87	242	261	728
Net Periodic Benefit Cost (Income)	$ (328)	$ (158)	$ (981)	$ (471)

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
OPERATING ACTIVITIES:
Net Income	$ 83,517	$ 67,890
Items not affecting cash:
Depreciation and depletion	91,139	84,685
Amortization of debt issue costs, discount and deferred hedge gain	4,856	290
Amortization of restricted stock	2,238	1,826
Equity portion of allowance for funds used during construction	(4,393)	(3,572)
Gain on disposition of assets	(347)	(761)
Deferred income taxes	29,537	41,159
Changes in current assets and liabilities:
Restricted cash	(10,286)	(1,536)
Accounts receivable	55,388	14,500
Inventories	(7,357)	(8,462)
Other current assets	5,086	(1,983)
Accounts payable	(30,298)	(19,512)
Accrued expenses	26,257	22,358
Regulatory assets	(8,448)	9,384
Regulatory liabilities	6,207	(8,209)
Other noncurrent assets	(34,650)	(32,298)
Other noncurrent liabilities	(3,480)	5,579
Cash provided by operating activities	204,966	171,338
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(186,085)	(153,951)
Change in restricted cash	(21,180)	0
Investment in New Market Tax Credit Program	(18,169)	0
Asset acquisitions	1,367	0
Proceeds from sale of assets	390	3,887
Cash used in investing activities	(223,677)	(150,064)
FINANCING ACTIVITIES:
Treasury stock activity	(881)	(1,107)
Proceeds from issuance of common stock, net	13,320	44,102
Dividends on common stock	(46,426)	(43,103)
Issuance of long-term debt	25,789	0
Repayments on long-term debt	(80)	(113)
Issuance (Repayments) of short-term borrowings, net	28,995	(19,954)
Financing costs	(832)	0
Cash provided by (used in) financing activities	19,885	(20,175)
Increase in Cash and Cash Equivalents	1,174	1,099
Cash and Cash Equivalents, beginning of period	16,557	9,822
Cash and Cash Equivalents, end of period	17,731	10,921
Cash paid during the period for:
Income taxes	28	47
Interest	44,170	40,873
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	$ 7,989	$ 11,245

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Income Taxes Effective Tax Rate Reconciliation (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Effective tax rate reconciliation
Income Before Income Taxes	$ 11,754	$ 17,462	$ 74,277	$ 76,855
Income tax calculated at 35% federal statutory rate	4,114	6,112	25,997	26,899
Income tax calculated at 35% federal statutory rate	35.00%	35.00%	35.00%	35.00%
State income, net of federal provisions	(108)	(671)	257	(2,615)
State income, net of federal provisions	(0.90%)	(4.00%)	0.30%	(3.40%)
Release of unrecognized tax benefit	(12,607)	0	(12,607)	0
Release of unrecognized tax benefit	(107.30%)	0.00%	(17.00%)	0.00%
Prior year permanent return to accrual adjustments	(5,172)	0	(5,172)	541
Prior year permanent return to accrual adjustments	(44.00%)	0.00%	(7.00%)	0.70%
Flow-through repairs deductions	(3,413)	(3,085)	(14,885)	(12,897)
Flow-through repairs deductions	(29.00%)	(17.70%)	(20.00%)	(16.80%)
Plant and depreciation of flow through items	(685)	0	(182)	49
Plant and depreciation of flow through items	(5.80%)	0.00%	(0.20%)	0.00%
Production tax credits	(300)	(482)	(2,054)	(2,152)
Production tax credits	(2.60%)	(2.90%)	(2.80%)	(2.80%)
Other, net	(266)	(59)	(594)	(860)
Other, net	(2.30%)	0.00%	(0.70%)	(1.00%)
Total reconciling items, amount	(22,551)	(4,297)	(35,237)	(17,934)
Total reconciling items, percent	(191.90%)	(24.60%)	(47.40%)	(23.30%)
Income tax (benefit) expense	$ (18,437)	$ 1,815	$ (9,240)	$ 8,965
Income tax (benefit) expense	(156.90%)	10.40%	(12.40%)	11.70%
Internal Revenue Service (IRS) [Member]
Effective tax rate reconciliation
Income tax calculated at 35% federal statutory rate			35.00%

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Nature of Operations and Basis of Consolidation (Policies)

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation, Variable Interest Entity [Policy Text Block]

Variable Interest Entities

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

Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $268.9 million through 2024.

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Goodwill (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Goodwill [Line Items]
Change in goodwill	$ 0
Goodwill	355,128	355,128
Electric [Member]
Goodwill [Line Items]
Goodwill	241,100	241,100
Natural gas [Member]
Goodwill [Line Items]
Goodwill	$ 114,028	$ 114,028

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Goodwill (Tables)

9 Months Ended

Sep. 30, 2014

Goodwill [Abstract]

Schedule of Goodwill [Table Text Block]

Goodwill by segment is as follows for both September 30, 2014 and December 31, 2013 (in thousands):

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

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CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY Statement (USD $) In Thousands, except Per Share data, unless otherwise specified	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Shareholders' Equity [Member]
Balance, beginning of period at Dec. 31, 2012		$ 408	$ 849,218	$ (90,702)	$ 172,791	$ 2,317	$ 934,032
Balance, shares at Dec. 31, 2012		40,792		3,571
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	67,890	0	0	0	67,890	0	67,890
Foreign currency translation	81	0	0	0	0	81	81
Reclassification of net gains on derivative instruments	(549)	0	0	0	0	(549)	(549)
Unrealized loss on cash flow hedging derivatives, net of tax	0
Stock based compensation, shares		165		32
Stock based compensation, value		0	2,809	(1,294)	0	0	1,515
Issuance of shares		1,103
Issuance of shares, value		13	44,215		0	0	44,415
Dividends on common stock		0	0	0	(43,102)	0	(43,102)
Issuance of shares, treasury stock				(6)
Issuance of shares, treasury stock, value				187
Dividends per share	$ 1.14
Balance, end of period at Sep. 30, 2013		421	896,242	(91,809)	197,579	1,849	1,004,282
Balance, shares at Sep. 30, 2013		42,060		3,597
Balance, beginning of period at Dec. 31, 2013	1,030,670	423	910,184	(91,744)	209,091	2,716	1,030,670
Balance, shares at Dec. 31, 2013		42,340		3,595
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	83,517	0	0	0	83,517	0	83,517
Foreign currency translation	155	0	0	0	0	155	155
Reclassification of net gains on derivative instruments	(549)	0	0	0	0	(549)	(549)
Unrealized loss on cash flow hedging derivatives, net of tax	(1,011)	0	0	0	0	(1,011)	(1,011)
Stock based compensation, shares		118		0
Stock based compensation, value		0	2,727	(922)	0	0	1,805
Issuance of shares		296
Issuance of shares, value		5	13,479		0	0	13,525
Dividends on common stock		0	0	0	(46,426)	0	(46,426)
Issuance of shares, treasury stock				15
Issuance of shares, treasury stock, value				41
Dividends per share	$ 1.20
Balance, end of period at Sep. 30, 2014	$ 1,081,686	$ 428	$ 926,390	$ (92,625)	$ 246,182	$ 1,311	$ 1,081,686
Balance, shares at Sep. 30, 2014		42,754		3,610

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CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL (USD $)	Sep. 30, 2014
Common Stock, Par or Stated Value Per Share	$ 0.01
Common Stock, Shares Authorized	200,000,000
Common Stock, Shares, Issued	42,753,751
Common Stock, Shares, Outstanding	39,143,568
Preferred Stock, Par or Stated Value Per Share	$ 0.01
Preferred Stock, Shares Authorized	50,000,000
Preferred Stock, Shares Issued	0
Preferred Stock, Shares Outstanding	0

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Financing Activities

9 Months Ended

Sep. 30, 2014

Financing Activities [Abstract]

Debt Disclosure [Text Block]

Financing Activities

In April 2012, we entered into an Equity Distribution Agreement pursuant to which we were able to 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 March 31, 2014, we sold 295,979 shares of our common stock at an average price of $45.65 per share, with proceeds of approximately $13.4 million, which are net of sales commissions of approximately $147,000 and other fees. This concluded our sales pursuant to the Equity Distribution Agreement. Total shares issued under the Equity Distribution Agreement were 2,492,889 at an average price of $40.11, for net proceeds of $98.7 million.

During 2014 we entered into a New Market Tax Credit (NMTC) financing agreement, pursuant to Section 45D of the Internal Revenue Code of 1986 as amended, to take advantage of a tax credit program related to the development and construction of a new office building in Butte, Montana. This financing agreement was structured with unrelated third party financial institutions (the Investor) and their wholly-owned community development entities (CDEs) in connection with our participation in qualified transactions under the NMTC program. Upon closing of this transaction, we entered into two loans totaling $27.0 million payable to the CDEs sponsoring the project, and provided an $18.2 million investment to the Investor. The loans have a term of thirty years with an interest rate of approximately 1.146%. In exchange for substantially all of the benefits derived from the tax credits, the Investor contributed approximately $8.8 million to the project. The NMTC is subject to recapture for a period of seven years. If the expected tax benefits are delivered without risk of recapture to the Investor and our performance obligation is relieved, we expect $7.9 million of the loan to be forgiven in July 2021. If we do not meet the conditions for loan forgiveness, we would be required to repay $27.0 million and would concurrently receive the return of our $18.2 million investment. As we are the primary beneficiary of the entities created in relation to the NMTC transaction, they have been consolidated as variable interest entities. The loans of $27.0 million are recorded in long-term debt and the investment of $18.2 million is recorded in other assets in the Condensed Consolidated Balance Sheets.

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Document and Document Entity Information (USD $)	9 Months Ended
	Sep. 30, 2014	Oct. 17, 2014
Entity Information [Line Items]
Entity Registrant Name	NORTHWESTERN CORPORATION
Entity Central Index Key	0000073088
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		39,143,732
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float	$ 1,534,085,000

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Segment Information

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

Segment Information

Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which is not considered a business unit. Other primarily consists of 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, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	212,430		$	39,482		$	—		$	—	$	251,912
Cost of sales	84,720			9,872			—			—		94,592
Gross margin	127,710			29,610			—			—		157,320
Operating, general and administrative	48,528			21,005			(1,425		)	—		68,108
Property and other taxes	20,413			7,357			3			—		27,773
Depreciation and depletion	23,174			7,270			8			—		30,452
Operating income (loss)	35,595			(6,022		)	1,414			—		30,987
Interest expense	(14,025		)	(2,627		)	(2,142		)	—		(18,794		)
Other income (expense)	1,337			336			(2,112		)	—		(439		)
Income tax benefit	5,235			926			12,276			—		18,437
Net income (loss)	$	28,142		$	(7,387	)	$	9,436		$	—	$	30,191
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
Capital expenditures	$	62,054		$	12,011		$	—		$	—	$	74,065

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 and depletion	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

Nine Months Ended
September 30, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	652,951		$	238,965		$	—		$	—	$	891,916
Cost of sales	273,754			100,740			—			—		374,494
Gross margin	379,197			138,225			—			—		517,422
Operating, general and administrative	144,933			66,254			3,370			—		214,557
Property and other taxes	61,322			22,961			9			—		84,292
Depreciation and depletion	69,398			21,716			25			—		91,139
Operating income (loss)	103,544			27,294			(3,404		)	—		127,434
Interest expense	(43,663		)	(7,979		)	(6,245		)	—		(57,887		)
Other income	3,204			876			650			—		4,730
Income tax (expense) benefit	(575		)	(3,334		)	13,149			—		9,240
Net income	$	62,510		$	16,857		$	4,150		$	—	$	83,517
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
Capital expenditures	$	161,718		$	24,367		$	—		$	—	$	186,085

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 and depletion	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

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues
Electric	$ 212,430	$ 227,103	$ 652,951	$ 637,667
Gas	39,482	34,772	238,965	196,652
Other	0	373	0	1,110
Total Revenues	251,912	262,248	891,916	835,429
Operating Expenses
Cost of sales	94,592	104,298	374,494	343,407
Operating, general and administrative	68,108	72,540	214,557	208,741
Property and other taxes	27,773	25,956	84,292	77,525
Depreciation and depletion	30,452	28,053	91,139	84,685
Total Operating Expenses	220,925	230,847	764,482	714,358
Operating Income	30,987	31,401	127,434	121,071
Interest Expense, net	(18,794)	(17,056)	(57,887)	(50,976)
Other (Expense) Income	(439)	3,117	4,730	6,760
Income Before Income Taxes	11,754	17,462	74,277	76,855
Income Tax Benefit (Expense)	18,437	(1,815)	9,240	(8,965)
Net Income	$ 30,191	$ 15,647	$ 83,517	$ 67,890
Average Common Shares Outstanding	39,141,148	38,459,484	39,045,790	37,982,673
Basic Earnings per Average Common Share	$ 0.77	$ 0.41	$ 2.14	$ 1.79
Diluted Earnings per Average Common Share	$ 0.77	$ 0.40	$ 2.13	$ 1.78
Dividends Declared per Common Share	$ 0.40	$ 0.38	$ 1.20	$ 1.14

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Income Taxes

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

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

	Three Months Ended September 30,
	2014					2013
Income Before Income Taxes	$	11,754				$	17,462
Income tax calculated at 35% federal statutory rate	4,114			35.0	%	6,112			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(108		)	(0.9	)	(671		)	(4.0	)
Release of unrecognized tax benefit	(12,607		)	(107.3	)	—			—
Prior year permanent return to accrual adjustments	(5,172		)	(44.0	)	—			—
Flow-through repairs deductions	(3,413		)	(29.0	)	(3,085		)	(17.7	)
Plant and depreciation of flow through items	(685		)	(5.8	)	—			—
Production tax credits	(300		)	(2.6	)	(482		)	(2.9	)
Other, net	(266		)	(2.3	)	(59		)	—
	(22,551		)	(191.9	)	(4,297		)	(24.6	)
Income tax (benefit) expense	$	(18,437	)	(156.9	)%	$	1,815		10.4	%

	Nine Months Ended September 30,
	2014					2013
Income Before Income Taxes	$	74,277				$	76,855
Income tax calculated at 35% federal statutory rate	25,997			35.0	%	26,899			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	257			0.3		(2,615		)	(3.4	)
Flow-through repairs deductions	(14,885		)	(20.0	)	(12,897		)	(16.8	)
Release of unrecognized tax benefit	(12,607		)	(17.0	)	—			—
Prior year permanent return to accrual adjustments	(5,172		)	(7.0	)	541			0.7
Production tax credits	(2,054		)	(2.8	)	(2,152		)	(2.8	)
Plant and depreciation of flow through items	(182		)	(0.2	)	49			—
Other, net	(594		)	(0.7	)	(860		)	(1.0	)
	(35,237		)	(47.4	)	(17,934		)	(23.3	)
Income tax (benefit) expense	$	(9,240	)	(12.4	)%	$	8,965		11.7	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% 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.

The income tax benefit for 2014 reflects the release of approximately $12.6 million of unrecognized tax benefits, including approximately $0.4 million of accrued interest and penalties due to the lapse of statutes of limitation in the third quarter of 2014.

In September 2013, the Internal Revenue Service (IRS) issued final tangible property regulations, which included guidance on a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. The regulations were effective January 1, 2014. During the third quarter of 2014, we elected the safe harbor method and recorded an income tax benefit of approximately $4.3 million for the cumulative adjustment for years prior to 2014, which is included in the prior year permanent return to accrual adjustment in the table above.

Uncertain Tax Positions

After the releases discussed above, we have unrecognized tax benefits of approximately $96.0 million as of September 30, 2014, including approximately $66.2 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As discussed above, during the nine months ended September 30, 2014, we released $0.4 million of accrued interest in the Condensed Consolidated Statements of Income. As of September 30, 2014 we do not have any amounts accrued for the payment of interest and penalties. As of December 31, 2013, we had $0.4 million of interest accrued in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2013, we did not recognize expense for interest or penalties and did not have any amounts accrued for the payment of interest and penalties.

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

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Regulatory Matters

9 Months Ended

Sep. 30, 2014

Regulated Operations [Abstract]

Public Utilities Disclosure [Text Block]

Regulatory Matters

Hydro Transaction

See Note 3 - Hydro Transaction.

Dave Gates Generating Station at Mill Creek (DGGS)

FERC Filing - In April 2014, the FERC issued an order affirming a FERC Administrative Law Judge's (ALJ) initial decision in September 2012, regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded we should allocate only a fraction of the costs we believe, based on facts and the law, should be allocated to FERC jurisdictional customers. We have been recognizing revenue consistent with the ALJ's initial decision. As of September 30, 2014, we have cumulative deferred revenue of approximately $27.3 million, which is subject to refund and recorded within current regulatory liabilities in the Condensed Consolidated Balance Sheets. The order included a requirement to issue customer refunds (included in deferred revenue) within 30 days.

In May 2014, we filed a request for rehearing, which remains pending. In our request for rehearing, we have argued that no refunds are due even if the cost allocation method is modified prospectively. The timing for FERC to act on our rehearing petition is uncertain, but could occur during the fourth quarter of 2014. Customer refunds, if any, will not be due until 30 days after a FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal could, depending on when the FERC issues a rehearing order, extend into 2016 or beyond.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We continue to evaluate options to use DGGS in combination with other generation resources, including the pending Hydro Transaction, to ensure cost recovery. Any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change.

Montana Electric and Natural Gas Tracker Filings

Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended

June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas supply procurement activities were prudent.

In May 2014, we filed our annual natural gas supply tracker filing for the 2013/2014 tracker period. During June 2014, the MPSC approved this filing on an interim basis and consolidated it with our pending natural gas filing for the 2012/2013 tracker period. Discovery is currently in process and a hearing is scheduled for January 2015.

In May 2014, we filed our annual electric supply tracker filing for the 2013/2014 tracker period. The MPSC approved this filing on an interim basis and consolidated it with our pending electric supply filing for the 2012/2013 tracker period. Our 2014 electric tracker filing includes market purchases made between July 2013 and January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion of these costs in the tracker filing is consistent with the treatment of replacement power during previous outages. During a June 2014 MPSC work session, approximately $11 million of these incremental market purchases related to the Colstrip Unit 4 outage were identified by the MPSC for additional prudency review. In July 2014, the Montana Environmental Information Center and Sierra Club filed a petition to intervene in the consolidated 2013 and 2014 tracker dockets to challenge our recovery of costs associated with Colstrip Unit 4, particularly the costs incurred as a result of the outage, as imprudent. A procedural schedule has not yet been established for the consolidated electric supply tracker docket.

Demand-side management (DSM) lowers our sales to customers. In 2005, the MPSC created a Lost Revenue Adjustment Mechanism (LRAM) by which we collect revenue that we would have collected without any DSM. In an order issued in October 2013, which was related to our 2012 electric supply tracker, the MPSC required us to lower our LRAM revenue recovery and imposed a new burden of proof on us for future LRAM recovery. We appealed the October 2013 order to Montana District Court. The appeal is pending. The District Court approved a partial settlement of our appeal, in which the MPSC agreed to remove from the October 2013 order the sentence that imposed the new burden and to initiate a separate docket to review lost revenue policy issues. The MPSC initiated the new proceeding in June 2014, but has not issued a procedural order.

Based on the MPSC's October 2013 order, we expect to be able to collect at least $7.1 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.

Natural Gas Production Assets

In 2012 and 2013, we purchased natural gas production interests in northern Montana's Bear Paw Basin (Bear Paw). 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. We are recognizing Bear Paw related revenue based on the precedent established by the MPSC's approval of Battle Creek in the fourth quarter of 2012. Since acquisition, we have recognized approximately $22.8 million of revenue that is subject to refund.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

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

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

	Three Months Ended September 30,
	2014					2013
Income Before Income Taxes	$	11,754				$	17,462
Income tax calculated at 35% federal statutory rate	4,114			35.0	%	6,112			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(108		)	(0.9	)	(671		)	(4.0	)
Release of unrecognized tax benefit	(12,607		)	(107.3	)	—			—
Prior year permanent return to accrual adjustments	(5,172		)	(44.0	)	—			—
Flow-through repairs deductions	(3,413		)	(29.0	)	(3,085		)	(17.7	)
Plant and depreciation of flow through items	(685		)	(5.8	)	—			—
Production tax credits	(300		)	(2.6	)	(482		)	(2.9	)
Other, net	(266		)	(2.3	)	(59		)	—
	(22,551		)	(191.9	)	(4,297		)	(24.6	)
Income tax (benefit) expense	$	(18,437	)	(156.9	)%	$	1,815		10.4	%

	Nine Months Ended September 30,
	2014					2013
Income Before Income Taxes	$	74,277				$	76,855
Income tax calculated at 35% federal statutory rate	25,997			35.0	%	26,899			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	257			0.3		(2,615		)	(3.4	)
Flow-through repairs deductions	(14,885		)	(20.0	)	(12,897		)	(16.8	)
Release of unrecognized tax benefit	(12,607		)	(17.0	)	—			—
Prior year permanent return to accrual adjustments	(5,172		)	(7.0	)	541			0.7
Production tax credits	(2,054		)	(2.8	)	(2,152		)	(2.8	)
Plant and depreciation of flow through items	(182		)	(0.2	)	49			—
Other, net	(594		)	(0.7	)	(860		)	(1.0	)
	(35,237		)	(47.4	)	(17,934		)	(23.3	)
Income tax (benefit) expense	$	(9,240	)	(12.4	)%	$	8,965		11.7	%

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Earnings Per Share

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

Earnings Per Share

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

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

	Three Months Ended
	September 30, 2014	September 30, 2013
Basic computation	39,141,148	38,459,484
Dilutive effect of
Restricted stock and performance share awards (1)	139,655	186,192
Diluted computation	39,280,803	38,645,676

	Nine Months Ended
	September 30, 2014	September 30, 2013
Basic computation	39,045,790	37,982,673
Dilutive effect of
Restricted stock and performance share awards (1)	141,560	181,462
Diluted computation	39,187,350	38,164,135

_______________

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

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Risk Management and Hedging Activities

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

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

Objectives and Strategies for Using Derivatives

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

In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

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

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to 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, 2014 and December 31, 2013. 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.

Credit Risk

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 limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.

We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. 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.

Interest Rate Swaps Designated as Cash Flow Hedges

In the third quarter of 2014, we entered into two forward starting swaps of $225 million each at 3.217% and 3.227% to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the anticipated debt issuance of $450 million associated with the Hydro Transaction. At September 30, 2014, we had net unrealized pre-tax losses of $1.6 million recorded in other current liabilities and AOCI based on the market value of our interest rate swaps. These hedging instruments are assessed on a quarterly basis to determine if they are effective in offsetting the interest rate risk associated with the forecasted transaction and as of September 30, 2014, we had no hedge ineffectiveness on these swaps.

These forward starting interest rate swaps were designated as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated the forward starting interest rate swaps are being recorded as a component of AOCI. When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of AOCI and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred will be reported as a component of interest expense.

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):

	Location of gain reclassified from AOCI to Income	Nine Months Ended September 30, 2014 and 2013
Amount of gain reclassified from AOCI	Interest Expense	$	891

Approximately $4.8 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of September 30, 2014, and we expect to reclassify approximately $1.2 million from AOCI into interest expense during the next twelve months.

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Goodwill

9 Months Ended

Sep. 30, 2014

Goodwill [Abstract]

Goodwill Disclosure [Text Block]

Goodwill

We completed our annual goodwill impairment test as of April 1, 2014, and no impairment was 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, 2014. Goodwill by segment is as follows for both September 30, 2014 and December 31, 2013 (in thousands):

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

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Comprehensive (Loss) Income

9 Months Ended

Sep. 30, 2014

Statement of Comprehensive Income [Abstract]

Comprehensive Income (Loss) Note [Text Block]

Comprehensive (Loss) Income

The following tables display the components of Other Comprehensive (Loss) Income (in thousands):

	September 30, 2014
	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	$	134		$	—	$	134		$	155		$	—	$	155
Reclassification of net gains on derivative instruments	(297		)	114		$	(183	)	(891		)	342		(549		)
Unrealized loss on cash flow hedging derivatives	(1,644		)	633		$	(1,011	)	(1,644		)	633		(1,011		)
Other comprehensive loss	$	(1,807	)	$	747	$	(1,060	)	$	(2,380	)	$	975	$	(1,405	)

	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	(297		)	114		(183		)	(891		)	342		(549		)
Other comprehensive loss	$	(351	)	$	114	$	(237	)	$	(810	)	$	342	$	(468	)

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, 2014			December 31, 2013
Foreign currency translation	$	687		$	532
Derivative instruments designated as cash flow hedges	1,953			3,513
Pension and postretirement medical plans	(1,329		)	(1,329		)
Accumulated other comprehensive income	$	1,311		$	2,716

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

		September 30, 2014
		Three Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	3,147		$	(1,329	)	$	553	$	2,371
Other comprehensive income before reclassifications		(1,011		)	—			134		(877		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(183		)	—			—		(183		)
Net current-period other comprehensive (loss) income		(1,194		)	—			134		(1,060		)
Ending balance		$	1,953		$	(1,329	)	$	687	$	1,311

		September 30, 2013
		Three Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	3,877		$	(2,292	)	$	501		$	2,086
Other comprehensive income before reclassifications		—			—			(54		)	(54		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(183		)	—			—			(183		)
Net current-period other comprehensive loss		(183		)	—			(54		)	(237		)
Ending balance		$	3,694		$	(2,292	)	$	447		$	1,849

		September 30, 2014
		Nine Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	3,513		$	(1,329	)	$	532	$	2,716
Other comprehensive income before reclassifications		(1,011		)	—			155		(856		)
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(549		)	—			—		(549		)
Net current-period other comprehensive (loss) income		(1,560		)	—			155		(1,405		)
Ending balance		$	1,953		$	(1,329	)	$	687	$	1,311

		September 30, 2013
		Nine Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate 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

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Fair Value Measurements

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Fair Value Measurements

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

Applicable accounting guidance establishes a 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. 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. See Note 8 - Risk Management and Hedging Activities for further discussion.

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.

	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, 2014
Restricted cash	$	17,018	$	—		$	—	$	—	$	17,018
Rabbi trust investments	19,819		—			—		—		19,819
Interest rate derivative liability	—		(1,644		)	—		—		(1,644		)
Total	$	36,837	$	(1,644	)	$	—	$	—	$	35,193
December 31, 2013
Restricted cash	$	6,650	$	—		$	—	$	—	$	6,650
Rabbi trust investments	16,477		—			—		—		16,477
Total	$	23,127	$	—		$	—	$	—	$	23,127

Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments 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 interest rate derivatives was determined based on models using quoted three-month rates.

Financial Instruments

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

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,182,092	$	1,309,855	$	1,155,097	$	1,237,151

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.

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Income Taxes (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Income Tax Contingency [Line Items]
Release of unrecognized tax benefits	$ (12,607,000)	$ 0	$ (12,607,000)	$ 0
Adoptation of safe harbor method, adjustment	4,300,000
Unrecognized tax benefits	96,000,000		96,000,000
Interest expense or penalties, uncertain tax positions			400,000	0
Accrued interest, uncertain tax positions	0	0	0	0	400,000
Unrecognized tax benefits that would impact effective tax rate	$ 66,200,000		$ 66,200,000
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Earliest year subject to examination			2000

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

Commitments and Contingencies

ENVIRONMENTAL LIABILITIES AND REGULATION

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

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

Our liability for environmental remediation obligations is estimated to range between $27.3 million to $35.0 million, primarily for manufactured gas plants discussed below. As of September 30, 2014, 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 results of operations.

Manufactured Gas Plants - Approximately $22.2 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 feasibility studies and implementing 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 $11.4 million, and we estimate that approximately $8.3 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. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. 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 soil and groundwater impacts. 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 and additional monitoring wells will be installed at the Butte site. 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, the Title V operating permit programs and the New Source Performance Standards (NSPS). In 2014, the EPA reproposed NSPS that specify permissible levels of GHG emissions from newly-constructed fossil fuel-fired electric generating units.

As directed by President Obama's Climate Action Plan, on June 2, 2014, the EPA proposed the Clean Power Plan (CPP) rule to control carbon dioxide emissions from existing fossil fuel fired electric generating units. The rule proposes the establishment of statewide reductions of GHG emissions for individual states based on the state's potential to shift generation to existing natural gas combined cycle plants, to develop new renewable energy, to achieve demand-side management savings, and to improve performance at existing coal-fired units. The comment period on the proposed rule has been extended to December 1, 2014. EPA intends to finalize those regulations and guidelines by June 1, 2015. Under the CPP proposed rule, States must submit individual plans for achieving GHG emission standards to EPA by June 30, 2016, although EPA is proposing a dual-phase submittal process for state plans that would allow for additional time to June 30, 2018 under certain circumstances. The initial performance period for compliance would commence in 2020, with full implementation by 2030.

On June 23, 2014, the U.S. Supreme Court struck down the EPA's Tailoring Rule, which limited the sources subject to GHG permitting requirements to the largest fossil-fueled power plants, indicating that EPA had exceeded its authority under the Clean Air Act by "rewriting unambiguous statutory terms." However, the decision affirmed EPA's ability to regulate GHG emissions from sources already subject to regulation under the PSD program, which includes most electric generating units.

Requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance and increase our costs of procuring electricity. Although there continues to be changes in legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. In addition, 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. 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 alter their ash management 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. In a January 2014 consent decree in the case Appalachian Voices v. McCarthy, the EPA agreed to take final action with respect to the CCR regulations by December 19, 2014. In addition, legislation has been 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 technology available (BTA)” for minimizing environmental impacts. On May 19, 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule gives seven options for meeting BTA, and provides a more flexible compliance approach than the proposed rule. In August 2014, EPA published the final rule establishing national requirements applicable to cooling water intake structures, which became effective October 14, 2014. Permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements.

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 reviewing public comments on 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 is under a modified consent decree to take final action by September 30, 2015. 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). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. Facilities that are subject to the MATS must come into compliance by April 2015, unless a one year extension is granted on a case-by-case basis. On April 15, 2014, the U.S. Court of Appeals for the D.C. Circuit upheld the MATS rule. The decision has been appealed by 23 states and industry groups to the Supreme Court, which has not yet decided whether to hear the case.

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 in certain states beginning in 2012. On April 29, 2014 the Supreme Court reversed and remanded the 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated the CSAPR. EPA has filed a motion in the U.S. Court of Appeals for the D.C. Circuit to lift the stay and allow EPA to implement the CSAPR.

In October 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. In November 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. Court of Appeals for the Ninth Circuit. 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. The Ninth Circuit held oral argument on the petition on May 16, 2014. At this time, we cannot predict or determine the timing or 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 estimated total project cost for the AQCS at the Big Stone plant is approximately $384 million (our share is 23.4%) and it is expected to be operational during the second half of 2015. As of September 30, 2014, we have capitalized costs of approximately $64.4 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, Big Stone will meet the requirements by installing the AQCS system and using activated carbon injection for mercury control. 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. New mercury emissions monitoring equipment will also be required.

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 $9.0 million (our share is 10.0%).

Based on the finalized MATS, Coyote will meet the requirements by using activated carbon injection for mercury control.

Iowa. The Neal #4 generating facility, of which we have an 8.7% ownership, installed a scrubber, a baghouse, and a selective non-catalytic reduction system to comply with national ambient air quality standards and the MATS. The project was substantially completed in 2013.

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 (Court) against the six individual owners of Colstrip, including us, as well as the operator or managing agent of the station (Defendants). 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 dropped claims associated with projects completed before 2001, the Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects.

In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of SO₂, NOx and particulate matter and (b) were “major modifications” subject to permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits. 

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. 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.

On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications.

The parties filed a joint notice (Notice) on April 21, 2014 that advised the Court of Plaintiffs’ intent to file a Second Amended Complaint which dropped claims relating to 52 projects, and added one additional project. At the joint request of the parties, the Court extended various deadlines previously set and set a bench trial date for the liability portion of the case for June 8, 2015.

On May 6, 2014, the Court held oral argument on Defendants' motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the Magistrate issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ motion to dismiss, but dismissed seven of Plaintiffs’ “best available control technology” claims and dismissed two of Plaintiffs' claims for injunctive relief. The Plaintiffs filed an objection to the Magistrate's findings and recommendations with the U.S. Federal District Court Judge, and on August 13, 2014, the Court adopted the Magistrate's findings and conclusions.

On August 27, 2014, the Plaintiffs filed their Second Amended Complaint, which alleges a total of 13 claims covering eight projects and seeks 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. Defendants filed their Answer to the Second Amended Complaint on September 26, 2014.

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 or range of loss, if any, that would be associated with an adverse decision.

Billings Refinery Outage Claim

In August 2014, we received a demand letter from a refinery in Billings claiming damages in excess of $48.5 million allegedly resulting from an outage that occurred in January 2014. We have notified our insurance carrier of the claims and our policy has a $2 million retention. We intend to vigorously defend these claims. Due to the preliminary nature of the matter, at this time, we cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse result.

Other Legal Proceedings

We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.

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Risk Management and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

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

	Location of gain reclassified from AOCI to Income	Nine Months Ended September 30, 2014 and 2013
Amount of gain reclassified from AOCI	Interest Expense	$	891

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Fair Value Measurements Fair Value Finanical Insruments (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying value	$ 1,182,092	$ 1,155,097
Long-term debt, fair value	1,309,855	1,237,151
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	(1,644)
Restricted cash	17,018	6,650
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	0
Restricted cash	17,018	6,650
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	(1,644)
Restricted cash	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	0
Restricted cash	0	0
Fair Value, Measurements, Recurring [Member] | Margin Cash Collateral Offset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	0
Restricted cash	$ 0

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Net Income	$ 30,191	$ 15,647	$ 83,517	$ 67,890
Other comprehensive (loss) income, net of tax:
Foreign currency translation	134	(54)	155	81
Unrealized loss on cash flow hedging derivatives	(1,011)	0	(1,011)	0
Reclassification of net gains on derivative instruments	(183)	(183)	(549)	(549)
Total Other Comprehensive Loss	(1,060)	(237)	(1,405)	(468)
Comprehensive Income	$ 29,131	$ 15,410	$ 82,112	$ 67,422

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Hydro Transaction

9 Months Ended

Sep. 30, 2014

Acquisitions [Abstract]

Property, Plant and Equipment, Schedule of Significant Acquisitions and Disposals [Table Text Block]

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 and one storage reservoir, 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.

The addition of hydro-electric generation is intended to provide long-term supply diversity to our portfolio and reduce risks associated with variable fuel prices. We expect the Hydro Transaction to allow us to reduce our reliance on third party power purchase agreements and spot market purchases, more closely matching our electric generation resources with forecasted customer demand. With reduced amounts of purchased power, we believe we will be less exposed to market volatility and will be better positioned to control the cost of supplying electricity to our customers. Assuming the Hydro Transaction is completed, and ownership of the Kerr Project is transferred as discussed below, we will own generation facilities that provide approximately 60% of our average electric load serving requirements in Montana.

Regulatory Approvals - Completion of the Hydro Transaction is subject to customary conditions and approvals, including approval from the Montana Public Service Commission (MPSC). In December 2013, we submitted a filing with the MPSC requesting approval of the Hydro Transaction, to include the hydro assets in rate base, and to issue the securities necessary to complete the purchase. On September 26, 2014, the MPSC issued a final order (MPSC Order) approving the application, subject to certain conditions, including the following:

• Inclusion of $870 million of the $900 million purchase price for the hydro assets in our Montana jurisdictional rate base with a 50-year life;

• Return on equity of 9.8%, a cost of debt of 4.25%, and a capital structure of 52% debt and 48% equity, resulting in an associated first year annual retail revenue requirement of approximately $117 million;

• Authorized issuance in aggregate of $900 million of securities necessary to complete the purchase, with the debt portion of the financing to have a term of 30 years and not to exceed 4.25%;

• A final compliance filing in December 2015 to reflect post-closing adjustments, the conveyance of the Kerr Project as discussed below and the actual property tax expense for the Hydroelectric facilities; and

• Tracking of revenue credits on a portfolio basis through our electricity supply cost tracker.

Following receipt of the MPSC Order, in September 2014, we requested the final necessary approval from the Federal Energy Regulatory Commission (FERC), which is authority to issue securities in connection with the Hydro Transaction. If the FERC's decision is consistent with our request, we anticipate closing of the Hydro Transaction to occur before the end of 2014. We have obtained approval from other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act. Either we or PPL Montana may terminate the agreement if the closing does not occur by March 26, 2015.

Financing - The permanent financing for the Hydro Transaction is anticipated to be a combination of up to $450 million of long-term debt, up to $400 million of equity and up to $50 million of cash flows from operations. In September 2014, we entered into forward starting interest rate swaps to effectively fix the benchmark interest rate associated with the anticipated $450 million debt issuance at a rate we anticipate will meet the conditions in the MPSC Order.

The Hydro Transaction is supported by a fully committed $900 million364-day senior bridge credit facility, which expires on March 26, 2015, if unused. The bridge facility is meant to be a short-term backup source of financing in case capital markets are not accessible at the time of closing of the Hydro Transaction. If the permanent financing is not in place at the time of closing, the bridge facility may be used temporarily in a single draw to finance the Hydro Transaction and pay related fees and expenses pending completion of the permanent financing. Any advance under the bridge facility is subject to certain conditions including regulatory approval of the Hydro Transaction, and would be due and payable within one year of borrowing.

Kerr Project - The Hydro Transaction includes the Kerr Project, a 194 megawatt hydro-electric generating facility that we expect will be transferred to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) in September 2015, in accordance with its FERC license, which gives the CSKT the right to acquire the project between September 2015 and September 2025. The CSKT have formally provided notice of their intent to acquire the Kerr Project and designated September 5, 2015, as the date for conveyance to occur. PPL Montana and the CSKT previously conducted an arbitration over the conveyance price of the Kerr Project. In March 2014, an arbitration panel set an estimated conveyance price of approximately $18.3 million. Under our agreement with PPL Montana, the $900 million purchase price for the Hydro Transaction includes a $30 million reference price for the Kerr Project. If the CSKT complete the acquisition and pay $18.3 million for the Kerr Project, PPL Montana will pay the difference of $11.7 million to us. If the Hydro Transaction is completed, we expect to sell any excess generation from the Kerr Project in the market and provide revenue credits to our Montana retail customers until the CSKT exercises their right to acquire the Kerr Project. The MPSC Order provides that customers will have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT.

During the nine months ended September 30, 2014, we incurred approximately $2.3 million of legal and professional fees associated with the Hydro Transaction, which are included in operating, general and administrative expense, and approximately $5.6 million of expenses related to the bridge credit facility included in interest expense.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

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

The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 8 - Risk Management and Hedging Activities for further discussion.

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.

	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, 2014
Restricted cash	$	17,018	$	—		$	—	$	—	$	17,018
Rabbi trust investments	19,819		—			—		—		19,819
Interest rate derivative liability	—		(1,644		)	—		—		(1,644		)
Total	$	36,837	$	(1,644	)	$	—	$	—	$	35,193
December 31, 2013
Restricted cash	$	6,650	$	—		$	—	$	—	$	6,650
Rabbi trust investments	16,477		—			—		—		16,477
Total	$	23,127	$	—		$	—	$	—	$	23,127

Fair Value Financial Instruments [Table Text Block]

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

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,182,092	$	1,309,855	$	1,155,097	$	1,237,151

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Accumulated Other Comprehensive Income by Component (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Accumulated Other Comprehensive Income [Line Items]
Beginning balance			$ 2,716
Total Other Comprehensive Loss	(1,060)	(237)	(1,405)	(468)
Ending balance	1,311		1,311
Gains on Derivative Instruments Designated as Cash Flow Hedges
Accumulated Other Comprehensive Income [Line Items]
Beginning balance	3,147	3,877	3,513	4,243
Other comprehensive income before reclassifications	(1,011)	0	(1,011)	0
Amounts reclassified from accumulated other comprehensive income	(183)	(183)	(549)	(549)
Total Other Comprehensive Loss	(1,194)	(183)	(1,560)	(549)
Ending balance	1,953	3,694	1,953	3,694
Pension and Postretirement Medical Plans
Accumulated Other Comprehensive Income [Line Items]
Beginning balance	(1,329)	(2,292)	(1,329)	(2,292)
Other comprehensive income before reclassifications	0	0	0	0
Amounts reclassified from accumulated other comprehensive income	0	0	0	0
Total Other Comprehensive Loss	0	0	0	0
Ending balance	(1,329)	(2,292)	(1,329)	(2,292)
Foreign Currency Translation
Accumulated Other Comprehensive Income [Line Items]
Beginning balance	553	501	532	366
Other comprehensive income before reclassifications	134	(54)	155	81
Amounts reclassified from accumulated other comprehensive income	0	0	0	0
Total Other Comprehensive Loss	134	(54)	155	81
Ending balance	687	447	687	447
Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income [Line Items]
Beginning balance	2,371	2,086	2,716	2,317
Other comprehensive income before reclassifications	(877)	(54)	(856)	81
Amounts reclassified from accumulated other comprehensive income	(183)	(183)	(549)	(549)
Total Other Comprehensive Loss	(1,060)	(237)	(1,405)	(468)
Ending balance	$ 1,311	$ 1,849	$ 1,311	$ 1,849

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Employee Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,						Three Months Ended September 30,
	2014			2013			2014			2013
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,708		$	3,367		$	116		$	135
Interest cost	6,536			5,680			214			219
Expected return on plan assets	(7,377		)	(8,123		)	(245		)	(254		)
Amortization of prior service cost	62			62			(500		)	(500		)
Recognized actuarial loss	530			2,911			87			242
Net Periodic Benefit Cost (Income)	$	2,459		$	3,897		$	(328	)	$	(158	)

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Components of Net Periodic Benefit Cost (Income)
Service cost	$	8,123		$	10,100		$	349		$	406
Interest cost	19,610			17,040			644			658
Expected return on plan assets	(22,130		)	(24,369		)	(736		)	(764		)
Amortization of prior service cost	185			185			(1,499		)	(1,499		)
Recognized actuarial loss	1,589			8,735			261			728
Net Periodic Benefit Cost (Income)	$	7,377		$	11,691		$	(981	)	$	(471	)