NorthWestern (NWE) 10-Q24 Oct 132013 Q3 Quarterly reportFinancial data

Company Profile

Document_and_Document_Entity_I

Document and Document Entity Information	9 Months Ended
Document and Document Entity Information	Sep. 30, 2013	Oct. 18, 2013
Entity Information [Line Items]
Entity Registrant Name	NORTHWESTERN CORPORATION
Entity Central Index Key	73088
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	30-Sep-13
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		38,463,262
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEET (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets:
Cash and cash equivalents	$10,921	$9,822
Restricted cash	8,236	6,700
Accounts receivable, net	129,195	143,695
Inventories	62,623	54,161
Regulatory assets	26,142	40,301
Deferred income taxes	30,255	37,143
Other	13,289	11,306
Total current assets	280,661	303,128
Property, plant, and equipment, net	2,573,562	2,435,590
Goodwill	355,128	355,128
Regulatory assets	395,746	367,890
Other noncurrent assets	28,553	23,797
Total assets	3,633,650	3,485,533
Current Liabilities:
Current maturities of capital leases	1,659	1,612
Short-term borrowings	102,980	122,934
Accounts payable	63,390	83,746
Accrued expenses	209,719	192,548
Regulatory liabilities	40,216	48,425
Total current liabilities	417,964	449,265
Long-term capital leases	30,315	31,562
Long-term debt	1,055,091	1,055,074
Deferred income taxes	397,856	363,928
Noncurrent regulatory liabilities	343,597	276,618
Other noncurrent liabilities	384,545	375,054
Total liabilities	2,629,368	2,551,501
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 42,059,560, and 38,462,477 respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	421	408
Treasury stock at cost	-91,809	-90,702
Paid-in capital	896,242	849,218
Retained earnings	197,579	172,791
Accumulated other comprehensive income	1,849	2,317
Total shareholders' equity	1,004,282	934,032
Total liabilities and shareholders' equity	$3,633,650	$3,485,533

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL (USD $)	Sep. 30, 2013
Common Stock, Par or Stated Value Per Share	$0.01
Common Stock, Shares Authorized	200,000,000
Common Stock, Shares, Issued	42,059,560
Common Stock, Shares, Outstanding	38,462,477
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

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues
Electric	$227,103	$202,485	$637,667	$605,716
Gas	34,772	32,965	196,652	182,812
Other	373	416	1,110	1,041
Total Revenues	262,248	235,866	835,429	789,569
Operating Expenses
Cost of sales	104,298	93,061	343,407	327,884
Operating, general and administrative	72,540	63,056	208,741	195,725
Mountain States Transmission Intertie impairment	0	24,039	0	24,039
Property and other taxes	25,956	24,796	77,525	74,395
Depreciation	28,053	26,505	84,685	79,364
Total Operating Expenses	230,847	231,457	714,358	701,407
Operating Income	31,401	4,409	121,071	88,162
Interest Expense, net	-17,056	-17,743	-50,976	-49,598
Other Income	3,117	974	6,760	3,134
Income Before Income Taxes	17,462	-12,360	76,855	41,698
Income Tax Expense	-1,815	8,588	-8,965	-1,989
Net Income (Loss)	$15,647	($3,772)	$67,890	$39,709
Average Common Shares Outstanding	38,459,484	37,201,051	37,982,673	36,723,105
Basic Earnings per Average Common Share	$0.41	($0.10)	$1.79	$1.09
Diluted Earnings per Average Common Share	$0.40	($0.10)	$1.78	$1.08
Dividends Declared per Common Share	$0.38	$0.37	$1.14	$1.11

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income	$15,647	($3,772)	$67,890	$39,709
Other comprehensive (loss) income, net of tax:
Reclassification of net gains on derivative instruments to net income	-183	-178	-549	-552
Postretirement medical liability adjustment	0	0	0	205
Foreign currency translation	-54	-79	81	-80
Total Other Comprehensive Loss	-237	-257	-468	-427
Comprehensive Income	$15,410	($4,029)	$67,422	$39,282

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
OPERATING ACTIVITIES:
Net Income	$67,890	$39,709
Items not affecting cash:
Depreciation	84,685	79,364
Amortization of debt issue costs, discount and deferred hedge gain	290	273
Amortization of restricted stock	1,826	2,199
Equity portion of allowance for funds used during construction	-3,572	-3,311
Gain on disposition of assets	-761	-232
Deferred income taxes	41,159	21,663
Mountain States Transmission Intertie impairment	0	24,039
Changes in current assets and liabilities:
Restricted cash	-1,536	4,731
Accounts receivable	14,500	37,688
Inventories	-8,462	156
Other current assets	-1,983	-712
Accounts payable	-19,512	-9,604
Accrued expenses	22,358	29,139
Regulatory assets	9,384	-3,266
Regulatory liabilities	-8,209	10,573
Other noncurrent assets	-32,298	-13,400
Other noncurrent liabilities	5,579	3,619
Cash provided by operating activities	171,338	222,628
INVESTING ACTIVITIES:
Property, plant, and equipment additions	-153,951	-157,859
Asset acquisition	0	-18,384
Proceeds from sale of assets	3,887	262
Cash used in investing activities	-150,064	-175,981
FINANCING ACTIVITIES:
Treasury stock activity	-1,107	-557
Proceeds from issuance of common stock, net	44,102	28,477
Dividends on common stock	-43,103	-40,584
Issuance of long-term debt	0	150,000
Repayments on long-term debt	-113	-3,871
Repayments of short-term borrowings, net	-19,954	-166,934
Financing costs	0	-910
Cash used in financing activities	-20,175	-34,379
Increase in Cash and Cash Equivalents	1,099	12,268
Cash and Cash Equivalents, beginning of period	9,822	5,928
Cash and Cash Equivalents, end of period	10,921	18,196
Cash paid during the period for:
Income taxes	47	1,944
Interest	40,873	34,416
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	$11,245	$13,292

Nature_of_Operations_and_Basis

Nature of Operations and Basis of Consolidation	9 Months Ended
Nature of Operations and Basis of Consolidation	Sep. 30, 2013
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 673,200 customers in Montana, South Dakota and Nebraska.

	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to September 30, 2013, have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

	The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2012.

	Variable Interest Entities

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

	Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $291.8 million through 2024.

New_Accounting_Standards

New Accounting Standards	9 Months Ended
New Accounting Standards	Sep. 30, 2013
New Accounting Pronouncement or Change in Accounting Principle, Current Period Disclosures [Abstract]
New Accounting Pronouncements [Text Block]	New Accounting Standards

	Accounting Standards Issued

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

	Accounting Standards Adopted

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

Acquisitions

Acquisitions	9 Months Ended
Acquisitions	Sep. 30, 2013
Acquisitions [Abstract]
Property, Plant and Equipment, Schedule of Significant Acquisitions and Disposals [Table Text Block]	Acquisition Agreements

	Hydro Transaction

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

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

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

	On September 26, 2013, in connection with the Hydro Transaction, we signed a commitment letter with Credit Suisse Securities (USA) LLC and Bank of America, N.A., under which the lenders committed to provide a $900 million 364-day senior bridge term loan facility. The permanent financing for the Hydro Transaction is anticipated to be a combination of long-term debt, new equity issuance and cash flows from operations.

	Natural Gas Production Assets

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

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

Regulatory_Matters

Regulatory Matters	9 Months Ended
Regulatory Matters	Sep. 30, 2013
Regulated Operations [Abstract]
Public Utilities Disclosure [Text Block]	Regulatory Matters

	Dave Gates Generating Station at Mill Creek (DGGS)

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

	We do not know when the FERC will consider the matter and issue its decision. The FERC is not obligated to follow any of the ALJ's findings and conclusions, and the FERC can accept or reject the decision in whole or in part. If the FERC upholds the ALJ's decision and a portion of the costs are effectively disallowed, we would be required to assess DGGS for impairment. If we disagree with a decision issued by the FERC, we may pursue full appellate rights through rehearing and appeal to a United States Circuit Court of Appeals, which could extend into 2015 or beyond. We continue to bill FERC jurisdictional customers interim rates that have been in effect since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC.

	Montana Electric and Natural Gas Tracker Filings

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

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

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

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

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

	Natural Gas Production Assets

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

Income_Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes

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


		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Federal statutory rate	35	%		35	%		35	%		35	%
	Flow-through repairs deductions	(17.7	)		14.6			(16.8	)		(22.9	)

	Flow-through of state bonus depreciation deduction	(4.5	)		2.2			(4.3	)		(5.2	)

	Production tax credits	(2.8	)		—			(2.8	)		—

	Prior year permanent return to accrual adjustments	—			15			0.6			(4.5	)

	Recognition of state net operating loss benefit / valuation allowance release	—			0.4			—			(0.1	)

	State income tax and other, net	0.4			2.3			—			2.5

		10.4	%		69.5	%		11.7	%		4.8	%

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


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


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


	Permanent or flow through adjustments:
	Flow-through repairs deductions	(3,086		)		(1,808		)		(12,898		)	(9,547		)
	Flow-through of state bonus depreciation deduction	(786		)		(276		)		(3,287		)	(2,159		)
	Production tax credits	(482		)		—				(2,152		)	—

	Prior year permanent return to accrual adjustments	—				(1,857		)		541			(1,857		)

	Recognition of state net operating loss benefit / valuation allowance release	—				(51		)		—			(51		)

	State income tax and other, net	57				(270		)		(138		)	1,009

		$	(4,297	)		$	(4,262	)		$	(17,934	)	$	(12,605	)

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


	Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of bonus depreciation deductions and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

	Uncertain Tax Positions

	We have unrecognized tax benefits of approximately $114.0 million as of September 30, 2013, including approximately $79.1 million that, if recognized, would impact our effective tax rate. It is reasonably possible that a significant portion of our unrecognized tax benefits may decrease in the next 12 months due to the expiration of statutes of limitation.

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

	The Internal Revenue Service (IRS) issued guidance during the third quarter of 2011 providing a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. That guidance was updated in the third quarter of 2012 to allow companies additional time to adopt the safe harbor method. We are evaluating whether or not we want to elect the safe harbor method, which may result in a change in related repairs deductions and unrecognized tax benefits. In September 2013, the IRS issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. We continue to evaluate what impact the adoption of the regulations will have on our consolidated financial statements. We do not expect the adoption of the regulations to have a material impact on our consolidated financial statements.

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

Goodwill

Goodwill	9 Months Ended
	Sep. 30, 2013
Goodwill [Abstract]
Goodwill Disclosure [Text Block]	Goodwill

	We completed our annual goodwill impairment test as of April 1, 2013, and no impairments were identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.

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



	Electric	$	241,100

	Natural gas	114,028

		$	355,128

Comprehensive_Loss_Income

Comprehensive (Loss) Income	9 Months Ended
	Sep. 30, 2013
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, 2013
		Three Months Ended												Nine Months Ended
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit			Net-of-Tax Amount
	Foreign currency translation adjustment	$	(54	)		$	—			$	(54	)		$	81			$	—		$	81

	Reclassification of net gains on derivative instruments to net income	(297		)		114				(183		)		(891		)		342			(549		)

	Other comprehensive loss	$	(351	)		$	114			$	(237	)		$	(810	)		$	342		$	(468	)




		September 30, 2012
		Three Months Ended												Nine Months Ended
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit			Net-of-Tax Amount
	Foreign currency translation adjustment	$	(79	)		$	—			$	(79	)		$	(80	)		$	—		$	(80	)

	Reclassification of net gains on derivative instruments to net income	(297		)		119				(178		)		(891		)		339			(552		)

	Pension and postretirement medical liability adjustment	—				—				—				333				(128		)	205

	Other comprehensive loss	$	(376	)		$	119			$	(257	)		$	(638	)		$	211		$	(427	)


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



		September 30, 2013				December 31, 2012
	Foreign currency translation	$	447			$	366

	Derivative instruments designated as cash flow hedges	3,694				4,243

	Pension and postretirement medical plans	(2,292		)		(2,292		)
	Accumulated other comprehensive income	$	1,849			$	2,317


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



				30-Sep-13
				Nine Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Gains on Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	4,243			$	(2,292	)		$	366			$	2,317

	Other comprehensive income before reclassifications			—				—				81				81

	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(549		)		—				—				(549		)

	Net current-period other comprehensive (loss) income			(549		)		—				81				(468		)

	Ending balance			$	3,694			$	(2,292	)		$	447			$	1,849

Risk_Management_and_Hedging_Ac

Risk Management and Hedging Activities

9 Months Ended

Sep. 30, 2013

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, in the past we have used and in the future we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

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

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to most of our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Financial Statements at September 30, 2013 and December 31, 2012. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

Mark-to-Market Accounting

Certain contracts for the purchase of natural gas associated with our gas utility operations do not qualify for NPNS. These are typically forward purchase contracts for natural gas where we lock in a fixed price, settle the contracts financially and do not take physical delivery of the natural gas. We use the mark-to-market method of accounting for these derivative contracts as we do not elect hedge accounting. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements; therefore, we record a regulatory asset or liability based on changes in market value.

The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 9.

Mark-to-Market Transactions

Balance Sheet Location

September 30, 2013

December 31, 2012

Natural gas net derivative liability

Accrued Expenses

653

5,428

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

Unrealized gain recognized in Regulatory Assets

Three Months Ended

Nine Months Ended

Derivatives Subject to Regulatory Deferral

September 30, 2013

September 30, 2012

September 30, 2013

September 30, 2012

Natural gas

1,624

5,527

4,775

12,743

Credit Risk

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

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

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

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

Interest Rate Swaps Designated as Cash Flow Hedges

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

Location of gain reclassified from AOCI to Income

Nine Months Ended September 30, 2013 and 2012

Amount of gain reclassified from AOCI

Interest Expense

891

Approximately $6.0 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of September 30, 2013, and we expect to reclassify approximately $1.2 million from AOCI into interest expense during the next twelve months. These gains relate to swaps previously terminated, and we have no current interest rate swaps outstanding.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Fair Value Measurements

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

	A fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs has been established by the applicable accounting guidance. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:


	•	Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;

	•	Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and

	•	Level 3 – Significant inputs that are generally not observable from market activity.

	We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. See Note 8 for further discussion.



			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)			Margin Cash Collateral Offset		Total Net Fair Value
			(in thousands)
	September 30, 2013
	Restricted cash		$	7,987		$	—			$	—		$	—	$	7,987

	Rabbi trust investments		16,835			—				—			—		16,835

	Derivative liability (1)		—			(653		)		—			—		(653		)

	Total		$	24,822		$	(653	)		$	—		$	—	$	24,169


	December 31, 2012
	Restricted cash		$	6,392		$	—			$	—		$	—	$	6,392

	Rabbi trust investments		10,522			—				—			—		10,522

	Derivative liability (1)		—			(5,428		)		—			—		(5,428		)

	Total		$	16,914		$	(5,428	)		$	—		$	—	$	11,486

	_________________________

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

	We present our derivative assets and liabilities on a net basis in the Condensed Consolidated Balance Sheets. The table above disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required and classifies each individual asset or liability within the appropriate level in the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts. These gross balances are intended solely to provide information on sources of inputs to fair value and do not represent our actual credit exposure or net economic exposure. Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices.

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

	Financial Instruments

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



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


	Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

	We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

Financing_Activities

Financing Activities	9 Months Ended
Financing Activities	Sep. 30, 2013
Financing Activities [Abstract]
Debt Disclosure [Text Block]	Financing Activities

	In April 2012, we entered into an Equity Distribution Agreement pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. Since inception, 1,917,996 shares of our common stock at an average price of $38.38 per share have been issued, for net proceeds of $72.6 million. During the three and nine months ended September 30, 2013, we sold 8,400 and 1,102,580 shares, of our common stock at an average price of $40.00 and $40.45 per share, respectively. Proceeds received during the three and nine months ended September 30, 2013, were approximately $0.3 million and $44.1 million, which are net of sales commissions of approximately $15,000 and $0.5 million, respectively, and other fees.

Segment_Information

Segment Information	9 Months Ended
	Sep. 30, 2013
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
	30-Sep-13	Electric				Gas				Other				Eliminations			Total
	Operating revenues	$	227,103			$	34,772			$	373			$	—		$	262,248

	Cost of sales	95,264				9,034				—				—			104,298

	Gross margin	131,839				25,738				373				—			157,950

	Operating, general and administrative	49,155				18,521				4,864				—			72,540

	Property and other taxes	19,381				6,572				3				—			25,956

	Depreciation	22,150				5,895				8				—			28,053

	Operating income (loss)	41,153				(5,250		)		(4,502		)		—			31,401

	Interest expense	(14,302		)		(2,560		)		(194		)		—			(17,056		)

	Other income	2,213				878				26				—			3,117

	Income tax (expense) benefit	(8,412		)		3,520				3,077				—			(1,815		)

	Net income (loss)	$	20,652			$	(3,412	)		$	(1,593	)		$	—		$	15,647

	Total assets	$	2,542,068			$	1,082,294			$	9,288			$	—		$	3,633,650

	Capital expenditures	$	55,579			$	9,823			$	—			$	—		$	65,402




	Three Months Ended
	30-Sep-12	Electric				Gas				Other				Eliminations			Total
	Operating revenues	$	202,485			$	32,965			$	416			$	—		$	235,866

	Cost of sales	83,814				9,247				—				—			93,061

	Gross margin	118,671				23,718				416				—			142,805

	Operating, general and administrative	44,711				17,452				893				—			63,056

	MSTI impairment	24,039				—				—				—			24,039

	Property and other taxes	18,621				6,172				3				—			24,796

	Depreciation	21,636				4,860				9				—			26,505

	Operating income (loss)	9,664				(4,766		)		(489		)		—			4,409

	Interest expense	(15,181		)		(2,363		)		(199		)		—			(17,743		)

	Other income	405				541				28				—			974

	Income tax benefit (expense)	5,762				3,102				(276		)		—			8,588

	Net income (loss)	$	650			$	(3,486	)		$	(936	)		$	—		$	(3,772	)

Total assets	$	2,319,856			$	976,152			$	10,938			$	—		$	3,306,946

Capital expenditures	$	45,932			$	32,499			$	—			$	—		$	78,431





Nine Months Ended
September 30, 2013	Electric				Gas				Other				Eliminations			Total
Operating revenues	$	637,667			$	196,652			$	1,110			$	—		$	835,429

Cost of sales	260,879				82,528				—				—			343,407

Gross margin	376,788				114,124				1,110				—			492,022

Operating, general and administrative	142,594				56,899				9,248				—			208,741

Property and other taxes	57,549				19,968				8				—			77,525

Depreciation	67,454				17,206				25				—			84,685

Operating income (loss)	109,191				20,051				(8,171		)		—			121,071

Interest expense	(42,840		)		(7,553		)		(583		)		—			(50,976		)

Other income	4,926				1,753				81				—			6,760

Income tax (expense) benefit	(12,792		)		(153		)		3,980				—			(8,965		)

Net income (loss)	$	58,485			$	14,098			$	(4,693	)		$	—		$	67,890

Total assets	$	2,542,068			$	1,082,294			$	9,288			$	—		$	3,633,650

Capital expenditures	$	130,585			$	23,366			$	—			$	—		$	153,951





Nine Months Ended
September 30, 2012	Electric				Gas				Other				Eliminations			Total
Operating revenues	$	605,716			$	182,812			$	1,041			$	—		$	789,569

Cost of sales	244,902				82,982				—				—			327,884

Gross margin	360,814				99,830				1,041				—			461,685

Operating, general and administrative	137,753				55,397				2,575				—			195,725

MSTI impairment	24,039				—				—				—			24,039

Property and other taxes	55,628				18,759				8				—			74,395

Depreciation	64,770				14,569				25				—			79,364

Operating income (loss)	78,624				11,105				(1,567		)		—			88,162

Interest expense	(42,257		)		(6,660		)		(681		)		—			(49,598		)

Other income	1,818				1,235				81				—			3,134

Income tax (expense) benefit	(3,322		)		522				811				—			(1,989		)

Net income (loss)	$	34,863			$	6,202			$	(1,356	)		$	—		$	39,709

Total assets	$	2,319,856			$	976,152			$	10,938			$	—		$	3,306,946

Capital expenditures	$	130,723			$	45,520			$	—			$	—		$	176,243

Earnings_Per_Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]
Earnings Per Share [Text Block]	Earnings Per Share

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

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


		Three Months Ended
		30-Sep-13	30-Sep-12
	Basic computation	38,459,484	37,201,051

	Dilutive effect of

	Restricted stock and performance share awards (1) (2)	186,192	—


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





		Nine Months Ended
		September 30, 2013	September 30, 2012

	Basic computation	37,982,673	36,723,105

	Dilutive effect of
	Restricted stock and performance share awards (1)	181,462	70,848


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

	_________________
	(1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.
	(2) In periods in which a net loss has been incurred, all potentially dilutive shares are considered antidilutive and thus are
	excluded from the calculation. For the three months ended September 30, 2012, we had 173,624 potentially dilutive restricted stock and performance share awards which were not included in the calculation.

Employee_Benefit_Plans

Employee Benefit Plans	9 Months Ended
	Sep. 30, 2013
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						Three Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Components of Net Periodic Benefit Cost (Income)
	Service cost	$	3,367		$	2,586		$	135		$	162

	Interest cost	5,680			6,016			219			309

	Expected return on plan assets	(8,123		)	(7,501		)	(254		)	(253		)
	Amortization of prior service cost	62			62			(500		)	(500		)

	Recognized actuarial loss	2,911			2,291			242			234

	Net Periodic Benefit Cost (Income)	$	3,897		$	3,454		$	(158	)	$	(48	)




		Pension Benefits						Other Postretirement Benefits
		Nine Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Components of Net Periodic Benefit Cost (Income)
	Service cost	$	10,100		$	8,616		$	406		$	406

	Interest cost	17,040			17,867			658			875

	Expected return on plan assets	(24,369		)	(22,497		)	(764		)	(766		)
	Amortization of prior service cost	185			185			(1,499		)	(1,499		)

	Recognized actuarial loss	8,735			6,485			728			593

	Net Periodic Benefit Cost (Income)	$	11,691		$	10,656		$	(471	)	$	(391	)

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2013
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 $27.7 million to $35.7 million, primarily for manufactured gas plants discussed below. As of September 30, 2013, we have a reserve of approximately $28.7 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or ongoing operations.

	Manufactured Gas Plants - Approximately $24.0 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources (DENR). Our current reserve for remediation costs at this site is approximately $11.7 million, and we estimate that approximately $8.1 million of this amount will be incurred during the next five years.

	We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. During 2006, the NDEQ released to us the Phase II Limited Subsurface Assessments performed by the NDEQ's environmental consulting firm for Kearney and Grand Island. In February 2011, NDEQ completed an Abbreviated Preliminary Assessment and Site Investigation Report for Grand Island, which recommended additional ground water testing. In April of 2012, we received a letter from NDEQ regarding a recently completed Vapor Intrusion Assessment Report and an invitation to join NDEQ's Voluntary Cleanup Program (VCP). We declined NDEQ's offer to join its VCP at this time and also committed to conducting a limited soil vapor investigation. We will work independently to fully characterize the nature and extent of impacts associated with the former manufactured gas plant. After the site has been fully characterized, we will discuss the possibility of joining NDEQ's VCP. Our reserve estimate includes assumptions for additional ground water testing. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

	In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to excess regulated pollutants in the groundwater. Voluntary soil and coal tar removals were conducted in the past at the Butte and Helena locations in accordance with MDEQ requirements. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the conditions at these sites; however, additional groundwater monitoring will be necessary. Monitoring of groundwater at the Helena site is ongoing and will be necessary for an extended period of time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site or if any additional actions beyond monitored natural attenuation will be required.

	Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide. These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four electric generating plants, all of which are coal fired and operated by other companies. We have undivided interests in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

	While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating GHG emissions of the very largest emitters, including large power plants, under the Clean Air Act, and specifically under the Prevention of Significant Deterioration (PSD) pre-construction permit and Title V operating permit programs.

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

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

	Physical impacts of climate change may present potential risks for severe weather, such as floods and tornadoes, in the locations where we operate or have interests. Furthermore, requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance and increase our costs of procuring electricity. In addition, we believe future legislation and regulations that affect GHG emissions from power plants are likely, although technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. We cannot predict with any certainty whether these risks will have a material impact on our operations.

	Coal Combustion Residuals (CCRs) - In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and scrubber wastes. Under one approach, the EPA would regulate CCRs as special wastes subject to regulation under subtitle C, the hazardous waste provisions, of RCRA. This approach would have significant impacts on coal-fired plants, and would require plants to retrofit their operations to comply with hazardous waste requirements from the generation of CCRs and associated waste waters through transportation and disposal. This could also have a negative impact on the beneficial use of CCRs and the current markets associated with such use. The second approach would regulate CCRs as a solid waste under Subtitle D of RCRA. This approach would only affect disposal, most significantly any wet disposal, of CCRs. The EPA has not issued a final CCR rule and is currently reviewing comments on additional data submitted during the public comment period, which closed in September 2013. In an order dated September 30, 2013, a federal district judge in the case Appalachian Voices v. McCarthy, indicated that he will issue an opinion in the next 30 days in favor of the environmental group plaintiffs, which could include a schedule for the EPA to promulgate the final CCR rule. In addition, legislation was introduced in Congress to regulate coal ash. We cannot predict at this time the final requirements of any CCR regulations or legislation and what impact, if any, they would have on us, but the costs of complying with any such requirements could be significant.

	Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act (CWA) requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. Permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA takes action to address several court decisions that rejected portions of previous rules and confirmed that the EPA has discretion to consider costs relative to benefits in developing cooling water intake structure regulations. In March 2011, the EPA proposed a rule to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. The EPA has indicated that it expects to issue the final rule in November 2013. When a final rule is issued and implemented, additional capital and/or increased operating costs may be incurred. The costs of complying with any such final water intake standards are not currently determinable, but could be significant.

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

	Clean Air Act Rules and Associated Emission Control Equipment Expenditures

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

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

	In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS), which was formerly the proposed Maximum Achievable Control Technology standards for hazardous air pollutant emissions from new and existing electric generating units. Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants. Facilities that are subject to the MATS must come into compliance within three years after the effective date of the rule (or by 2015) unless a one year extension is granted on a case-by-case basis. In March 2013, the EPA finalized updates to emission limits under MATS for new power plants. Numerous challenges to the MATS have been filed with the EPA and in Federal court and we cannot predict the outcome of such challenges.

	In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) were to be required beginning in 2012. In an order issued on June 24, 2013, the Supreme Court granted certiorari to review the D.C. Circuit's 2012 decision which vacated the CSAPR, and briefs have been filed with the Court. The Clean Air Interstate Rule remains in effect until the EPA issues a valid replacement.

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

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

	We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to various regulations that have been issued or proposed under the Clean Air Act, as discussed below.

	South Dakota. The South Dakota DENR determined that the Big Stone Plant, of which we have a 23.4% ownership, is subject to the BART requirements of the Regional Haze Rule. South Dakota DENR's State Implementation Plan (SIP) was approved by the EPA in May 2012. Under the SIP, the Big Stone plant must install and operate a new BART compliant air quality control system (AQCS) to reduce SO2, NOx and particulate emissions as expeditiously as practicable, but no later than five years after the EPA's approval of the SIP. The current project cost for the AQCS is estimated to be approximately $405 million (our share is 23.4%) and it is expected to be operational by 2016. As of September 30, 2013, we have capitalized costs of approximately $27.6 million million related to this project.

	Our incremental capital expenditure projections include amounts related to our share of the BART at Big Stone based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process. The South Dakota Public Utilities Commission has historically allowed timely recovery of the costs of environmental improvements; however, there is no precedent on a project of this size.

	Based on the finalized MATS, it appears that Big Stone would meet the requirements by installing the AQCS system and using mercury control technology such as activated carbon injection. In August 2013, the South Dakota DENR granted Big Stone a one year extension to comply with MATS, such that the new compliance deadline is April 16, 2016. Mercury emissions monitoring equipment is already installed at Big Stone, but its operation has been put on hold pending additional regulatory direction. The equipment will need to be reevaluated for operability under the final rule.

	North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, of which we have 10% ownership, to reduce its NOx emissions. Coyote must install control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown, beginning on July 1, 2018. The current estimate of the total cost of the project is approximately $9 million (our share is 10.0%).

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

	Iowa. The Neal 4 generating facility, of which we have an 8.7% ownership, is installing a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system to comply with national ambient air quality standards and the MATS. Capital expenditures for such equipment are currently estimated to be approximately $270 million (our share is 8.7%). The plant began incurring such costs in 2011 and the project is expected to be complete in 2014. As of September 30, 2013, we have capitalized costs of approximately $20.8 million related to this project.

	Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is currently controlling emissions of mercury under regulations issued by the State of Montana, which are stricter than the Federal MATS. The owners do not believe additional equipment will be necessary to meet the MATS for mercury, and anticipate meeting all other expected MATS emissions limitations required by the rule without additional costs except those costs related to increased monitoring frequency. These additional costs are not expected to be significant.

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

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

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


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


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

LEGAL PROCEEDINGS

Colstrip Litigation

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

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

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

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

Other Legal Proceedings

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

Nature_of_Operations_and_Basis1

Nature of Operations and Basis of Consolidation (Policies)	9 Months Ended
Nature of Operations and Basis of Consolidation (Policies)	Sep. 30, 2013
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 $291.8 million through 2024.

Income_Taxes_Tables

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The following table reconciles our effective income tax rate to the federal statutory rate:


		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Federal statutory rate	35	%		35	%		35	%		35	%
	Flow-through repairs deductions	(17.7	)		14.6			(16.8	)		(22.9	)

	Flow-through of state bonus depreciation deduction	(4.5	)		2.2			(4.3	)		(5.2	)

	Production tax credits	(2.8	)		—			(2.8	)		—

	Prior year permanent return to accrual adjustments	—			15			0.6			(4.5	)

	Recognition of state net operating loss benefit / valuation allowance release	—			0.4			—			(0.1	)

	State income tax and other, net	0.4			2.3			—			2.5

		10.4	%		69.5	%		11.7	%		4.8	%

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


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


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


	Permanent or flow through adjustments:
	Flow-through repairs deductions	(3,086		)		(1,808		)		(12,898		)	(9,547		)
	Flow-through of state bonus depreciation deduction	(786		)		(276		)		(3,287		)	(2,159		)
	Production tax credits	(482		)		—				(2,152		)	—

	Prior year permanent return to accrual adjustments	—				(1,857		)		541			(1,857		)

	Recognition of state net operating loss benefit / valuation allowance release	—				(51		)		—			(51		)

	State income tax and other, net	57				(270		)		(138		)	1,009

		$	(4,297	)		$	(4,262	)		$	(17,934	)	$	(12,605	)

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

Goodwill_Tables

Goodwill (Tables)	9 Months Ended
	Sep. 30, 2013
Goodwill [Abstract]
Schedule of Goodwill [Table Text Block]	Goodwill by segment is as follows for both September 30, 2013 and December 31, 2012 (in thousands):



	Electric	$	241,100

	Natural gas	114,028

		$	355,128

Comprehensive_Loss_Income_Tabl

Comprehensive (Loss) Income (Tables)	9 Months Ended
	Sep. 30, 2013
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, 2013
		Three Months Ended												Nine Months Ended
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit			Net-of-Tax Amount
	Foreign currency translation adjustment	$	(54	)		$	—			$	(54	)		$	81			$	—		$	81

	Reclassification of net gains on derivative instruments to net income	(297		)		114				(183		)		(891		)		342			(549		)

	Other comprehensive loss	$	(351	)		$	114			$	(237	)		$	(810	)		$	342		$	(468	)




		September 30, 2012
		Three Months Ended												Nine Months Ended
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit			Net-of-Tax Amount
	Foreign currency translation adjustment	$	(79	)		$	—			$	(79	)		$	(80	)		$	—		$	(80	)

	Reclassification of net gains on derivative instruments to net income	(297		)		119				(178		)		(891		)		339			(552		)

	Pension and postretirement medical liability adjustment	—				—				—				333				(128		)	205

	Other comprehensive loss	$	(376	)		$	119			$	(257	)		$	(638	)		$	211		$	(427	)


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, 2013				December 31, 2012
	Foreign currency translation	$	447			$	366

	Derivative instruments designated as cash flow hedges	3,694				4,243

	Pension and postretirement medical plans	(2,292		)		(2,292		)
	Accumulated other comprehensive income	$	1,849			$	2,317

Accumulated Other Comprehensive Income [Table Text Block]	The following table displays the changes in AOCI by component, net of tax (in thousands):



				30-Sep-13
				Nine Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Gains on Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	4,243			$	(2,292	)		$	366			$	2,317

	Other comprehensive income before reclassifications			—				—				81				81

	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(549		)		—				—				(549		)

	Net current-period other comprehensive (loss) income			(549		)		—				81				(468		)

	Ending balance			$	3,694			$	(2,292	)		$	447			$	1,849

Risk_Management_and_Hedging_Ac1

Risk Management and Hedging Activities (Tables)	9 Months Ended
Risk Management and Hedging Activities (Tables)	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 9.



	Mark-to-Market Transactions	Balance Sheet Location	September 30, 2013				December 31, 2012

	Natural gas net derivative liability	Accrued Expenses	$	653			$	5,428
	Natural gas net derivative liability	Accrued Expenses	$	653			$	5,428
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The following table represents the net change in fair value for these derivatives (in thousands):



		Unrealized gain recognized in Regulatory Assets							Unrealized gain recognized in Regulatory Assets
		Three Months Ended							Nine Months Ended
	Derivatives Subject to Regulatory Deferral	September 30, 2013				September 30, 2012			September 30, 2013		September 30, 2012

	Natural gas	$	1,624			$	5,527		$	4,775	$	12,743
	Natural gas	$	1,624			$	5,527		$	4,775	$	12,743
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, 2013 and 2012

	Amount of gain reclassified from AOCI		Interest Expense		$	891
	Amount of gain reclassified from AOCI		Interest Expense		$	891

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2013
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. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. See Note 8 for further discussion.



			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)			Margin Cash Collateral Offset		Total Net Fair Value
			(in thousands)
	September 30, 2013
	Restricted cash		$	7,987		$	—			$	—		$	—	$	7,987

	Rabbi trust investments		16,835			—				—			—		16,835

	Derivative liability (1)		—			(653		)		—			—		(653		)

	Total		$	24,822		$	(653	)		$	—		$	—	$	24,169


	December 31, 2012
	Restricted cash		$	6,392		$	—			$	—		$	—	$	6,392

	Rabbi trust investments		10,522			—				—			—		10,522

	Derivative liability (1)		—			(5,428		)		—			—		(5,428		)

	Total		$	16,914		$	(5,428	)		$	—		$	—	$	11,486

	_________________________

	-1	The changes in the fair value of these derivatives are deferred as a regulatory asset or liability until the contracts are settled. Upon settlement, associated proceeds or costs are passed through the applicable cost tracking mechanism to customers.
Fair Value Financial Instruments [Table Text Block]	The estimated fair value of financial instruments is summarized as follows (in thousands):



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

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2013
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
	30-Sep-13	Electric				Gas				Other				Eliminations			Total
	Operating revenues	$	227,103			$	34,772			$	373			$	—		$	262,248

	Cost of sales	95,264				9,034				—				—			104,298

	Gross margin	131,839				25,738				373				—			157,950

	Operating, general and administrative	49,155				18,521				4,864				—			72,540

	Property and other taxes	19,381				6,572				3				—			25,956

	Depreciation	22,150				5,895				8				—			28,053

	Operating income (loss)	41,153				(5,250		)		(4,502		)		—			31,401

	Interest expense	(14,302		)		(2,560		)		(194		)		—			(17,056		)

	Other income	2,213				878				26				—			3,117

	Income tax (expense) benefit	(8,412		)		3,520				3,077				—			(1,815		)

	Net income (loss)	$	20,652			$	(3,412	)		$	(1,593	)		$	—		$	15,647

	Total assets	$	2,542,068			$	1,082,294			$	9,288			$	—		$	3,633,650

	Capital expenditures	$	55,579			$	9,823			$	—			$	—		$	65,402




	Three Months Ended
	30-Sep-12	Electric				Gas				Other				Eliminations			Total
	Operating revenues	$	202,485			$	32,965			$	416			$	—		$	235,866

	Cost of sales	83,814				9,247				—				—			93,061

	Gross margin	118,671				23,718				416				—			142,805

	Operating, general and administrative	44,711				17,452				893				—			63,056

	MSTI impairment	24,039				—				—				—			24,039

	Property and other taxes	18,621				6,172				3				—			24,796

	Depreciation	21,636				4,860				9				—			26,505

	Operating income (loss)	9,664				(4,766		)		(489		)		—			4,409

	Interest expense	(15,181		)		(2,363		)		(199		)		—			(17,743		)

	Other income	405				541				28				—			974

	Income tax benefit (expense)	5,762				3,102				(276		)		—			8,588

	Net income (loss)	$	650			$	(3,486	)		$	(936	)		$	—		$	(3,772	)

	Total assets	$	2,319,856			$	976,152			$	10,938			$	—		$	3,306,946

	Capital expenditures	$	45,932			$	32,499			$	—			$	—		$	78,431





Nine Months Ended
September 30, 2013	Electric				Gas				Other				Eliminations			Total
Operating revenues	$	637,667			$	196,652			$	1,110			$	—		$	835,429

Cost of sales	260,879				82,528				—				—			343,407

Gross margin	376,788				114,124				1,110				—			492,022

Operating, general and administrative	142,594				56,899				9,248				—			208,741

Property and other taxes	57,549				19,968				8				—			77,525

Depreciation	67,454				17,206				25				—			84,685

Operating income (loss)	109,191				20,051				(8,171		)		—			121,071

Interest expense	(42,840		)		(7,553		)		(583		)		—			(50,976		)

Other income	4,926				1,753				81				—			6,760

Income tax (expense) benefit	(12,792		)		(153		)		3,980				—			(8,965		)

Net income (loss)	$	58,485			$	14,098			$	(4,693	)		$	—		$	67,890

Total assets	$	2,542,068			$	1,082,294			$	9,288			$	—		$	3,633,650

Capital expenditures	$	130,585			$	23,366			$	—			$	—		$	153,951





Nine Months Ended
September 30, 2012	Electric				Gas				Other				Eliminations			Total
Operating revenues	$	605,716			$	182,812			$	1,041			$	—		$	789,569

Cost of sales	244,902				82,982				—				—			327,884

Gross margin	360,814				99,830				1,041				—			461,685

Operating, general and administrative	137,753				55,397				2,575				—			195,725

MSTI impairment	24,039				—				—				—			24,039

Property and other taxes	55,628				18,759				8				—			74,395

Depreciation	64,770				14,569				25				—			79,364

Operating income (loss)	78,624				11,105				(1,567		)		—			88,162

Interest expense	(42,257		)		(6,660		)		(681		)		—			(49,598		)

Other income	1,818				1,235				81				—			3,134

Income tax (expense) benefit	(3,322		)		522				811				—			(1,989		)

Net income (loss)	$	34,863			$	6,202			$	(1,356	)		$	—		$	39,709

Total assets	$	2,319,856			$	976,152			$	10,938			$	—		$	3,306,946

Capital expenditures	$	130,723			$	45,520			$	—			$	—		$	176,243

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2013
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
		30-Sep-13	30-Sep-12
	Basic computation	38,459,484	37,201,051

	Dilutive effect of

	Restricted stock and performance share awards (1) (2)	186,192	—


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





		Nine Months Ended
		September 30, 2013	September 30, 2012

	Basic computation	37,982,673	36,723,105

	Dilutive effect of
	Restricted stock and performance share awards (1)	181,462	70,848


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

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

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2013
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						Three Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Components of Net Periodic Benefit Cost (Income)
	Service cost	$	3,367		$	2,586		$	135		$	162

	Interest cost	5,680			6,016			219			309

	Expected return on plan assets	(8,123		)	(7,501		)	(254		)	(253		)
	Amortization of prior service cost	62			62			(500		)	(500		)

	Recognized actuarial loss	2,911			2,291			242			234

	Net Periodic Benefit Cost (Income)	$	3,897		$	3,454		$	(158	)	$	(48	)




		Pension Benefits						Other Postretirement Benefits
		Nine Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Components of Net Periodic Benefit Cost (Income)
	Service cost	$	10,100		$	8,616		$	406		$	406

	Interest cost	17,040			17,867			658			875

	Expected return on plan assets	(24,369		)	(22,497		)	(764		)	(766		)
	Amortization of prior service cost	185			185			(1,499		)	(1,499		)

	Recognized actuarial loss	8,735			6,485			728			593

	Net Periodic Benefit Cost (Income)	$	11,691		$	10,656		$	(471	)	$	(391	)

Nature_of_Operations_and_Basis2

Nature of Operations and Basis of Consolidation (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	watts	customers
Number of customers		673,200
Number of megawatts of qualifying facility	35
Estimated aggregate gross contractual payments for qualifying facilities through 2024	$291.80

Acquisitions_Hydroelectric_Det

Acquisitions Hydro-electric (Details) (Hydro-electric Assets [Member], USD $)	Sep. 30, 2013	Sep. 26, 2013
In Millions, unless otherwise specified		days
		MMcf
Hydro-electric Assets [Member]
Significant Acquisitions and Disposals [Line Items]
Megawatts of hydro-electric generation capacity		633
Purchase price		$900
Owned average load serving requirement		60.00%
Transaction costs	3.3
Bridge term loan facility		$900
Bridge term loan facility agreement term		364

Acquisitions_Oil_and_Gas_Detai

Acquisitions Oil and Gas (Details) (Montana Natural Gas Production Assets [Member], USD $)	1 Months Ended
In Millions, unless otherwise specified	31-May-13	Jan. 02, 2013
	31-May-13	MMcf
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition of oil and gas properties with proved reserves	$70
Proved developed reserves (volume) associated with acquisition		64.6
Estimated increase in oil and gas production		28.00%
Percent owned oil and gas production		37.00%
Havre Pipeline Company, LLC [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition of oil and gas properties with proved reserves	$6
Ownership percentage in gas gathering systems	82.00%

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Jun. 30, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012
In Millions, unless otherwise specified		Demand-side management (DSM) lost revenues [Member]	Montana Natural Gas Production Assets [Member]	Dave Gates Generating Station [Member]	Dave Gates Generating Station [Member]	Deferred Revenue Related To Prior Year [Member]	Deferred Revenue Related To Tracker Period 2012-2013 [Member]	Deferred Revenue Related To Tracker Period 2013-2014 [Member]	Bear Paw Basin [Member]
			Revenue Subject to Refund [Member]		Revenue Subject to Refund [Member]	Demand-side management (DSM) lost revenues [Member]	Demand-side management (DSM) lost revenues [Member]	Demand-side management (DSM) lost revenues [Member]	Montana Natural Gas Production Assets [Member]
Customer refund liability, current			$3.20		$22.50
Deferred revenue recognized		4.6				2.3	7.8	1.9
Demand side management expected lost revenue recovery	7.8
Incremental costs disallowed				$1.40
Proportionate ownership share in gas gathering systems									75.00%

Income_Taxes_Details

Income Taxes (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Income Tax Contingency [Line Items]
Unrecognized tax benefits	$114
Interest expense, uncertain tax positions	0.3	0
Accrued interest, uncertain tax positions	0.3		0
Unrecognized tax benefits that would impact effective tax rate	$79.10
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Earliest year subject to examination	2000

Income_Taxes_Effective_Tax_Rat

Income Taxes Effective Tax Rate Reconciliation (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Effective tax rate reconciliation
Federal statutory rate	35.00%	35.00%	35.00%	35.00%
Flow-through repairs deductions	-17.70%	14.60%	-16.80%	-22.90%
Flow-through of state bonus depreciaton deduction	-4.50%	2.20%	-4.30%	-5.20%
Production tax credits	-2.80%	0.00%	-2.80%	0.00%
Prior year permanent return to accrual adjustments	0.00%	15.00%	0.60%	-4.50%
Recognition of state net operating loss benefit / valuation allowance release	0.00%	0.40%	0.00%	-0.10%
State income tax and other, net	0.40%	2.30%	0.00%	2.50%
Effective income tax rate	10.40%	69.50%	11.70%	4.80%
Significant differences from federal statutory rate
Income (Loss) Before Income Taxes	$17,462	($12,360)	$76,855	$41,698
Income tax calculated at 35% federal statutory rate	6,112	-4,326	26,899	14,594
Permanent or flow through adjustments:
Flow-through repairs deductions	-3,086	-1,808	-12,898	-9,547
Flow-through of state bonus depreciation deduction	-786	-276	-3,287	-2,159
Production tax credits	-482	0	-2,152	0
Prior year permanent return to accrual adjustments	0	-1,857	541	-1,857
Recognition of state net operating loss benefit / valuation allowance release	0	-51	0	-51
State income tax and other, net	57	-270	-138	1,009
Total permanent or flow-through adjustments	-4,297	-4,262	-17,934	-12,605
Income tax expense (benefit)	$1,815	($8,588)	$8,965	$1,989
Internal Revenue Service (IRS) [Member]
Effective tax rate reconciliation
Federal statutory rate			35.00%

Goodwill_Details

Goodwill (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
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

Comprehensive_Loss_Income_Deta

Comprehensive (Loss) Income (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Other Comprehensive Income (Loss), before Tax [Abstract]
Foreign currency translation adjustment	($54)	($79)	$81	($80)
Reclassification of net gains on derivative instruments to net income	-297	-297	-891	-891
Pension and postretirement medical liability adjustment	0	0	0	333
Other comprehensive loss	-351	-376	-810	-638
Other Comprehensive Income (Loss), Tax [Abstract]
Foreign currency translation adjustment	0	0	0	0
Reclassification of net gains on derivative instruments to net income	114	119	342	339
Pension and postretirement medical liability adjustment	0	0	0	-128
Other comprehensive loss	114	119	342	211
Other comprehensive (loss) income, net of tax:
Foreign currency translation	-54	-79	81	-80
Reclassification of net gains on derivative instruments to net income	-183	-178	-549	-552
Pension and postretirement medical liability adjustment	0	0	0	205
Total Other Comprehensive Loss	-237	-257	-468	-427
Accumulated Other Comprehensive Income [Abstract]
Foreign currency translation	447		447		366
Derivative instruments designated as cash flow hedges	3,694		3,694		4,243
Pension and postretirement medical plans	-2,292		-2,292		-2,292
Accumulated other comprehensive income	$1,849		$1,849		$2,317

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income by Component (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accumulated Other Comprehensive Income [Line Items]
Beginning balance, accumulated other comprehensive income			$2,317
Other comprehensive income before reclassifications	-54	-79	81	-80
Amounts reclassified from accumulated other comprehensive income	-183	-178	-549	-552
Total Other Comprehensive Loss	-237	-257	-468	-427
Ending balance, accumulated other comprehensive income	1,849		1,849
Gains on Derivative Instruments Designated as Cash Flow Hedges
Accumulated Other Comprehensive Income [Line Items]
Beginning balance, accumulated other comprehensive income			4,243
Other comprehensive income before reclassifications			0
Amounts reclassified from accumulated other comprehensive income			-549
Total Other Comprehensive Loss			-549
Ending balance, accumulated other comprehensive income	3,694		3,694
Pension and Postretirement Medical Plans
Accumulated Other Comprehensive Income [Line Items]
Beginning balance, accumulated other comprehensive income			-2,292
Other comprehensive income before reclassifications			0
Amounts reclassified from accumulated other comprehensive income			0
Total Other Comprehensive Loss			0
Ending balance, accumulated other comprehensive income	-2,292		-2,292
Foreign Currency Translation
Accumulated Other Comprehensive Income [Line Items]
Beginning balance, accumulated other comprehensive income			366
Other comprehensive income before reclassifications			81
Amounts reclassified from accumulated other comprehensive income			0
Total Other Comprehensive Loss			81
Ending balance, accumulated other comprehensive income	$447		$447

Risk_Management_and_Hedging_Ac2

Risk Management and Hedging Activities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012
			Commodity Contract [Member]	Commodity Contract [Member]	Commodity Contract [Member]	Commodity Contract [Member]	Commodity Contract [Member]	Commodity Contract [Member]	Interest Rate Swap [Member]	Interest Rate Swap [Member]	Interest Rate Swap [Member]
			Forward Contracts [Member]	Forward Contracts [Member]	Forward Contracts [Member]	Forward Contracts [Member]	Forward Contracts [Member]	Forward Contracts [Member]		Interest Expense [Member]	Interest Expense [Member]
							Not Designated as Hedging Instrument [Member]	Not Designated as Hedging Instrument [Member]
							Accrued Liabilities [Member]	Accrued Liabilities [Member]
Derivative [Line Items]
Natural gas net derivative liability							$653,000	$5,428,000
Natural gas derivative, unrealized gain recognized in regulatory assets			1,624,000	5,527,000	4,775,000	12,743,000
Amount of gain reclassified from AOCI										891,000	891,000
Pre-tax gain on cash flow hedges remaining in AOCI									6,000,000
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
Credit risk-related contingent features for forward purchase contracts not qualifying for NPNS			$0		$0

Fair_Value_Recurring_Basis_Det

Fair Value Recurring Basis (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
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, Measurements, Recurring [Member] \| Total Net Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	7,987		6,392
Rabbi trust investments	16,835		10,522
Derivative liability (1)	-653	[1]	-5,428	[1]
Total	24,169		11,486
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	7,987		6,392
Rabbi trust investments	16,835		10,522
Derivative liability (1)	0	[1]	0
Total	24,822		16,914
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
Derivative liability (1)	-653	[1]	-5,428
Total	-653		-5,428
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
Derivative liability (1)	0	[1]	0
Total	0		0
Fair Value, Measurements, Recurring [Member] \| Margin Cash Collateral Offset [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0		0
Rabbi trust investments	0		0
Derivative liability (1)	0	[1]	0
Total	$0		$0

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

Fair_Value_Measurements_Fair_V

Fair Value Measurements Fair Value Finanical Insruments (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion), carrying value	$1,055,091	$1,055,074
Long-term debt (including current portion), fair value	$1,160,253	$1,229,233

Financing_Activities_Details

Financing Activities (Details) (Equity Distribution Agreement [Member], USD $)	3 Months Ended	9 Months Ended	18 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Apr. 02, 2012
Common Stock [Member]
Debt Instrument [Line Items]
Common stock, aggregate gross sales price				$100,000,000
Stock issued inception to date, shares issued			1,917,996
Common stock average share price since inception			$38.38
Proceeds received from new issues, inception to date			72,600,000
Stock issued during period, shares, new issues	8,400	1,102,580
Common stock average share price during the period	$40	$40.45
Proceeds received from new issues during the period	300,000	44,100,000
Additional Paid-in Capital [Member]
Debt Instrument [Line Items]
Sales commissons and fees	$15,000	$500,000

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating revenues	$262,248	$235,866	$835,429	$789,569
Cost of sales	104,298	93,061	343,407	327,884
Gross margin	157,950	142,805	492,022	461,685
Operating, general and administrative	72,540	63,056	208,741	195,725
MSTI impairment	0	24,039	0	24,039
Property and other taxes	25,956	24,796	77,525	74,395
Depreciation	28,053	26,505	84,685	79,364
Operating income (loss)	31,401	4,409	121,071	88,162
Interest expense	-17,056	-17,743	-50,976	-49,598
Other income	3,117	974	6,760	3,134
Income tax (expense) benefit	-1,815	8,588	-8,965	-1,989
Net Income (Loss)	15,647	-3,772	67,890	39,709
Total assets	3,633,650	3,306,946	3,633,650	3,306,946	3,485,533
Capital expenditures	65,402	78,431	153,951	176,243
Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues	227,103	202,485	637,667	605,716
Cost of sales	95,264	83,814	260,879	244,902
Gross margin	131,839	118,671	376,788	360,814
Operating, general and administrative	49,155	44,711	142,594	137,753
MSTI impairment		24,039		24,039
Property and other taxes	19,381	18,621	57,549	55,628
Depreciation	22,150	21,636	67,454	64,770
Operating income (loss)	41,153	9,664	109,191	78,624
Interest expense	-14,302	-15,181	-42,840	-42,257
Other income	2,213	405	4,926	1,818
Income tax (expense) benefit	-8,412	5,762	-12,792	-3,322
Net Income (Loss)	20,652	650	58,485	34,863
Total assets	2,542,068	2,319,856	2,542,068	2,319,856
Capital expenditures	55,579	45,932	130,585	130,723
Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues	34,772	32,965	196,652	182,812
Cost of sales	9,034	9,247	82,528	82,982
Gross margin	25,738	23,718	114,124	99,830
Operating, general and administrative	18,521	17,452	56,899	55,397
MSTI impairment		0		0
Property and other taxes	6,572	6,172	19,968	18,759
Depreciation	5,895	4,860	17,206	14,569
Operating income (loss)	-5,250	-4,766	20,051	11,105
Interest expense	-2,560	-2,363	-7,553	-6,660
Other income	878	541	1,753	1,235
Income tax (expense) benefit	3,520	3,102	-153	522
Net Income (Loss)	-3,412	-3,486	14,098	6,202
Total assets	1,082,294	976,152	1,082,294	976,152
Capital expenditures	9,823	32,499	23,366	45,520
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	373	416	1,110	1,041
Cost of sales	0	0	0	0
Gross margin	373	416	1,110	1,041
Operating, general and administrative	4,864	893	9,248	2,575
MSTI impairment		0		0
Property and other taxes	3	3	8	8
Depreciation	8	9	25	25
Operating income (loss)	-4,502	-489	-8,171	-1,567
Interest expense	-194	-199	-583	-681
Other income	26	28	81	81
Income tax (expense) benefit	3,077	-276	3,980	811
Net Income (Loss)	-1,593	-936	-4,693	-1,356
Total assets	9,288	10,938	9,288	10,938
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	0	0
MSTI impairment		0		0
Property and other taxes	0	0	0	0
Depreciation	0	0	0	0
Operating income (loss)	0	0	0	0
Interest expense	0	0	0	0
Other income	0	0	0	0
Income tax (expense) benefit	0	0	0	0
Net Income (Loss)	0	0	0	0
Total assets	0	0	0	0
Capital expenditures	$0	$0	$0	$0

Earnings_Per_Share_Details

Earnings Per Share (Details)	3 Months Ended		9 Months Ended
Earnings Per Share (Details)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Basic computation	38,459,484	37,201,051	37,982,673	36,723,105
Dilutive effect of restricted stock and performance share awards (1) (2)	186,192	0	181,462	70,848
Diluted computation	38,645,676	37,201,051	38,164,135	36,793,953
Potentially dilutive shares excluded from calculation				173,624

Employee_Benefit_Plans_Net_Per

Employee Benefit Plans Net Periodic Benefit Cost (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	$3,367	$2,586	$10,100	$8,616
Interest cost	5,680	6,016	17,040	17,867
Expected return on plan assets	-8,123	-7,501	-24,369	-22,497
Amortization of prior service cost	62	62	185	185
Recognized actuarial loss	2,911	2,291	8,735	6,485
Net Periodic Benefit Cost (Income)	3,897	3,454	11,691	10,656
Other Postretirement Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	135	162	406	406
Interest cost	219	309	658	875
Expected return on plan assets	-254	-253	-764	-766
Amortization of prior service cost	-500	-500	-1,499	-1,499
Recognized actuarial loss	242	234	728	593
Net Periodic Benefit Cost (Income)	($158)	($48)	($471)	($391)

Commitments_and_Contingencies_

Commitments and Contingencies Environmental (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Jul. 01, 2018	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
In Millions, unless otherwise specified		Colstrip Unit 4 [Member]	Neal 4 Generating Facility [Member]	Coyote Generating Facility [Member]	Coyote Generating Facility [Member]	Big Stone Generating Facility [Member]	Manufactured Gas Plants [Member]	Aberdeen South Dakota Site [Member]
								Manufactured Gas Plants [Member]
Environmental remediation obligation, minimum	$27.70
Environmental remediation obligation, maximum	35.7
Accrual for environmental loss contingencies	28.7						24	11.7
Environmental remediation obligation next 5 years								8.1
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			270		9	405
Joint ownership share of capitalized project costs			$20.80			$27.60
Site contingency, time frame of disbursements			scheduled to commence in 2011 and be spread over the next three years.
Number of years for environmental remediation obligation to be incurred								5 years