NorthWestern (NWE) 10-Q 23 Oct 14 2014 Q3 Quarterly report Financial data

Document_and_Document_Entity_I

Document and Document Entity Information (USD $)	9 Months Ended
	Sep. 30, 2014	Oct. 17, 2014
Entity Information [Line Items]	'	'
Entity Registrant Name	'NORTHWESTERN CORPORATION	'
Entity Central Index Key	'0000073088	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Document Type	'10-Q	'
Document Period End Date	30-Sep-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Amendment Flag	'false	'
Entity Common Stock, Shares Outstanding	'	39,143,732
Entity Well-known Seasoned Issuer	'Yes	'
Entity Voluntary Filers	'No	'
Entity Current Reporting Status	'Yes	'
Entity Public Float	$1,534,085,000	'

CONDENSED_CONSOLIDATED_BALANCE

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

CONDENSED_CONSOLIDATED_BALANCE1

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

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

CONDENSED_CONSOLIDATED_STATEME1

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

CONDENSED_CONSOLIDATED_STATEME2

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

CONSOLIDATED_STATEMENT_OF_SHAR

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

Nature_of_Operations_and_Basis

Nature of Operations and Basis of Consolidation	9 Months Ended
	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]	'
	Nature of Operations and Basis of Consolidation
	NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 678,200 customers in Montana, South Dakota and Nebraska.
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to September 30, 2014, have been evaluated as to their potential impact to the Financial Statements through the date of issuance.
	The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2013.
	Variable Interest Entities
	A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.
	Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $268.9 million through 2024.

New_Accounting_Standards

New Accounting Standards	9 Months Ended
	Sep. 30, 2014
New Accounting Pronouncement or Change in Accounting Principle, Current Period Disclosures [Abstract]	'
New Accounting Pronouncements [Text Block]	'
	New Accounting Standards
	Accounting Standards Issued
	In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance will be effective for us in our first quarter of 2017. Early adoption is not permitted. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures.
	Accounting Standards Adopted
	There have been no new accounting pronouncements or changes in accounting pronouncements adopted during the nine months ended September 30, 2014 that are of significance, or potential significance, to us.

Hydro_Transaction

Hydro Transaction	9 Months Ended
	Sep. 30, 2014
Acquisitions [Abstract]	'
Property, Plant and Equipment, Schedule of Significant Acquisitions and Disposals [Table Text Block]	'
	Hydro Transaction
	On September 26, 2013, we entered into an agreement with PPL Montana, LLC (PPL Montana), a wholly owned subsidiary of PPL Corporation, to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity and one storage reservoir, for a purchase price of $900 million (Hydro Transaction). The purchase price will be subject to adjustment for proration of operating expenses, performance of planned capital expenditures, and termination of certain power purchase agreements.
	The addition of hydro-electric generation is intended to provide long-term supply diversity to our portfolio and reduce risks associated with variable fuel prices. We expect the Hydro Transaction to allow us to reduce our reliance on third party power purchase agreements and spot market purchases, more closely matching our electric generation resources with forecasted customer demand. With reduced amounts of purchased power, we believe we will be less exposed to market volatility and will be better positioned to control the cost of supplying electricity to our customers. Assuming the Hydro Transaction is completed, and ownership of the Kerr Project is transferred as discussed below, we will own generation facilities that provide approximately 60% of our average electric load serving requirements in Montana.
	Regulatory Approvals - Completion of the Hydro Transaction is subject to customary conditions and approvals, including approval from the Montana Public Service Commission (MPSC). In December 2013, we submitted a filing with the MPSC requesting approval of the Hydro Transaction, to include the hydro assets in rate base, and to issue the securities necessary to complete the purchase. On September 26, 2014, the MPSC issued a final order (MPSC Order) approving the application, subject to certain conditions, including the following:
	•	Inclusion of $870 million of the $900 million purchase price for the hydro assets in our Montana jurisdictional rate base with a 50-year life;
	•	Return on equity of 9.8%, a cost of debt of 4.25%, and a capital structure of 52% debt and 48% equity, resulting in an associated first year annual retail revenue requirement of approximately $117 million;
	•	Authorized issuance in aggregate of $900 million of securities necessary to complete the purchase, with the debt portion of the financing to have a term of 30 years and not to exceed 4.25%;
	•	A final compliance filing in December 2015 to reflect post-closing adjustments, the conveyance of the Kerr Project as discussed below and the actual property tax expense for the Hydroelectric facilities; and
	•	Tracking of revenue credits on a portfolio basis through our electricity supply cost tracker.
	Following receipt of the MPSC Order, in September 2014, we requested the final necessary approval from the Federal Energy Regulatory Commission (FERC), which is authority to issue securities in connection with the Hydro Transaction. If the FERC's decision is consistent with our request, we anticipate closing of the Hydro Transaction to occur before the end of 2014. We have obtained approval from other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act. Either we or PPL Montana may terminate the agreement if the closing does not occur by March 26, 2015.
	Financing - The permanent financing for the Hydro Transaction is anticipated to be a combination of up to $450 million of long-term debt, up to $400 million of equity and up to $50 million of cash flows from operations. In September 2014, we entered into forward starting interest rate swaps to effectively fix the benchmark interest rate associated with the anticipated $450 million debt issuance at a rate we anticipate will meet the conditions in the MPSC Order.
	The Hydro Transaction is supported by a fully committed $900 million 364-day senior bridge credit facility, which expires on March 26, 2015, if unused. The bridge facility is meant to be a short-term backup source of financing in case capital markets are not accessible at the time of closing of the Hydro Transaction. If the permanent financing is not in place at the time of closing, the bridge facility may be used temporarily in a single draw to finance the Hydro Transaction and pay related fees and expenses pending completion of the permanent financing. Any advance under the bridge facility is subject to certain conditions including regulatory approval of the Hydro Transaction, and would be due and payable within one year of borrowing.
	Kerr Project - The Hydro Transaction includes the Kerr Project, a 194 megawatt hydro-electric generating facility that we expect will be transferred to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) in September 2015, in accordance with its FERC license, which gives the CSKT the right to acquire the project between September 2015 and September 2025. The CSKT have formally provided notice of their intent to acquire the Kerr Project and designated September 5, 2015, as the date for conveyance to occur. PPL Montana and the CSKT previously conducted an arbitration over the conveyance price of the Kerr Project. In March 2014, an arbitration panel set an estimated conveyance price of approximately $18.3 million. Under our agreement with PPL Montana, the $900 million purchase price for the Hydro Transaction includes a $30 million reference price for the Kerr Project. If the CSKT complete the acquisition and pay $18.3 million for the Kerr Project, PPL Montana will pay the difference of $11.7 million to us. If the Hydro Transaction is completed, we expect to sell any excess generation from the Kerr Project in the market and provide revenue credits to our Montana retail customers until the CSKT exercises their right to acquire the Kerr Project. The MPSC Order provides that customers will have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT.
	During the nine months ended September 30, 2014, we incurred approximately $2.3 million of legal and professional fees associated with the Hydro Transaction, which are included in operating, general and administrative expense, and approximately $5.6 million of expenses related to the bridge credit facility included in interest expense.

Regulatory_Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 2014
Regulated Operations [Abstract]	'
Public Utilities Disclosure [Text Block]	'
	Regulatory Matters
	Hydro Transaction
	See Note 3 - Hydro Transaction.
	Dave Gates Generating Station at Mill Creek (DGGS)
	FERC Filing - In April 2014, the FERC issued an order affirming a FERC Administrative Law Judge's (ALJ) initial decision in September 2012, regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded we should allocate only a fraction of the costs we believe, based on facts and the law, should be allocated to FERC jurisdictional customers. We have been recognizing revenue consistent with the ALJ's initial decision. As of September 30, 2014, we have cumulative deferred revenue of approximately $27.3 million, which is subject to refund and recorded within current regulatory liabilities in the Condensed Consolidated Balance Sheets. The order included a requirement to issue customer refunds (included in deferred revenue) within 30 days.
	In May 2014, we filed a request for rehearing, which remains pending. In our request for rehearing, we have argued that no refunds are due even if the cost allocation method is modified prospectively. The timing for FERC to act on our rehearing petition is uncertain, but could occur during the fourth quarter of 2014. Customer refunds, if any, will not be due until 30 days after a FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal could, depending on when the FERC issues a rehearing order, extend into 2016 or beyond.
	The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We continue to evaluate options to use DGGS in combination with other generation resources, including the pending Hydro Transaction, to ensure cost recovery. Any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change.
	Montana Electric and Natural Gas Tracker Filings
	Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended
	June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas supply procurement activities were prudent.
	In May 2014, we filed our annual natural gas supply tracker filing for the 2013/2014 tracker period. During June 2014, the MPSC approved this filing on an interim basis and consolidated it with our pending natural gas filing for the 2012/2013 tracker period. Discovery is currently in process and a hearing is scheduled for January 2015.
	In May 2014, we filed our annual electric supply tracker filing for the 2013/2014 tracker period. The MPSC approved this filing on an interim basis and consolidated it with our pending electric supply filing for the 2012/2013 tracker period. Our 2014 electric tracker filing includes market purchases made between July 2013 and January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion of these costs in the tracker filing is consistent with the treatment of replacement power during previous outages. During a June 2014 MPSC work session, approximately $11 million of these incremental market purchases related to the Colstrip Unit 4 outage were identified by the MPSC for additional prudency review. In July 2014, the Montana Environmental Information Center and Sierra Club filed a petition to intervene in the consolidated 2013 and 2014 tracker dockets to challenge our recovery of costs associated with Colstrip Unit 4, particularly the costs incurred as a result of the outage, as imprudent. A procedural schedule has not yet been established for the consolidated electric supply tracker docket.
	Demand-side management (DSM) lowers our sales to customers. In 2005, the MPSC created a Lost Revenue Adjustment Mechanism (LRAM) by which we collect revenue that we would have collected without any DSM. In an order issued in October 2013, which was related to our 2012 electric supply tracker, the MPSC required us to lower our LRAM revenue recovery and imposed a new burden of proof on us for future LRAM recovery. We appealed the October 2013 order to Montana District Court. The appeal is pending. The District Court approved a partial settlement of our appeal, in which the MPSC agreed to remove from the October 2013 order the sentence that imposed the new burden and to initiate a separate docket to review lost revenue policy issues. The MPSC initiated the new proceeding in June 2014, but has not issued a procedural order.
	Based on the MPSC's October 2013 order, we expect to be able to collect at least $7.1 million of DSM lost revenues for each annual tracker period; however, since the 2012/2013 annual tracker filing is still subject to final approval, the MPSC may ultimately require us to refund a portion of the DSM lost revenues we have recognized since July 2012.
	Natural Gas Production Assets
	In 2012 and 2013, we purchased natural gas production interests in northern Montana's Bear Paw Basin (Bear Paw). We are collecting the cost of service for natural gas produced from these assets, including a return on our investment, through our natural gas supply tracker on an interim basis. As a result, we do not expect to file an application with the MPSC to place these assets in natural gas rate base until our next natural gas rate case. We are recognizing Bear Paw related revenue based on the precedent established by the MPSC's approval of Battle Creek in the fourth quarter of 2012. Since acquisition, we have recognized approximately $22.8 million of revenue that is subject to refund.

Income_Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Income Tax Disclosure [Text Block]	'
	Income Taxes
	The following table summarizes the significant differences in income tax (benefit) expense based on the differences between our effective tax rate and the federal statutory rate (in thousands):
		Three Months Ended September 30,
		2014					2013
	Income Before Income Taxes	$	11,754				$	17,462
	Income tax calculated at 35% federal statutory rate	4,114			35	%	6,112			35	%
	Permanent or flow through adjustments:
	State income, net of federal provisions	(108		)	(0.9	)	(671		)	(4.0	)
	Release of unrecognized tax benefit	(12,607		)	(107.3	)	—			—
	Prior year permanent return to accrual adjustments	(5,172		)	(44.0	)	—			—
	Flow-through repairs deductions	(3,413		)	(29.0	)	(3,085		)	(17.7	)
	Plant and depreciation of flow through items	(685		)	(5.8	)	—			—
	Production tax credits	(300		)	(2.6	)	(482		)	(2.9	)
	Other, net	(266		)	(2.3	)	(59		)	—
		(22,551		)	(191.9	)	(4,297		)	(24.6	)
	Income tax (benefit) expense	$	(18,437	)	(156.9	)%	$	1,815		10.4	%
		Nine Months Ended September 30,
		2014					2013
	Income Before Income Taxes	$	74,277				$	76,855
	Income tax calculated at 35% federal statutory rate	25,997			35	%	26,899			35	%
	Permanent or flow through adjustments:
	State income, net of federal provisions	257			0.3		(2,615		)	(3.4	)
	Flow-through repairs deductions	(14,885		)	(20.0	)	(12,897		)	(16.8	)
	Release of unrecognized tax benefit	(12,607		)	(17.0	)	—			—
	Prior year permanent return to accrual adjustments	(5,172		)	(7.0	)	541			0.7
	Production tax credits	(2,054		)	(2.8	)	(2,152		)	(2.8	)
	Plant and depreciation of flow through items	(182		)	(0.2	)	49			—
	Other, net	(594		)	(0.7	)	(860		)	(1.0	)
		(35,237		)	(47.4	)	(17,934		)	(23.3	)
	Income tax (benefit) expense	$	(9,240	)	(12.4	)%	$	8,965		11.7	%
	We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of bonus depreciation deductions and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.
	The income tax benefit for 2014 reflects the release of approximately $12.6 million of unrecognized tax benefits, including approximately $0.4 million of accrued interest and penalties due to the lapse of statutes of limitation in the third quarter of 2014.
	In September 2013, the Internal Revenue Service (IRS) issued final tangible property regulations, which included guidance on a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. The regulations were effective January 1, 2014. During the third quarter of 2014, we elected the safe harbor method and recorded an income tax benefit of approximately $4.3 million for the cumulative adjustment for years prior to 2014, which is included in the prior year permanent return to accrual adjustment in the table above.
	Uncertain Tax Positions
	After the releases discussed above, we have unrecognized tax benefits of approximately $96.0 million as of September 30, 2014, including approximately $66.2 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.
	Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As discussed above, during the nine months ended September 30, 2014, we released $0.4 million of accrued interest in the Condensed Consolidated Statements of Income. As of September 30, 2014 we do not have any amounts accrued for the payment of interest and penalties. As of December 31, 2013, we had $0.4 million of interest accrued in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2013, we did not recognize expense for interest or penalties and did not have any amounts accrued for the payment of interest and penalties.
	Our federal tax returns from 2000 forward remain subject to examination by the IRS.

Goodwill

Goodwill	9 Months Ended
	Sep. 30, 2014
Goodwill [Abstract]	'
Goodwill Disclosure [Text Block]	'
	Goodwill
	We completed our annual goodwill impairment test as of April 1, 2014, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.
	There were no changes in our goodwill during the nine months ended September 30, 2014. Goodwill by segment is as follows for both September 30, 2014 and December 31, 2013 (in thousands):
	Electric	$	241,100
	Natural gas	114,028
		$	355,128

Comprehensive_Loss_Income

Comprehensive (Loss) Income	9 Months Ended
	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]	'
Comprehensive Income (Loss) Note [Text Block]	'
	Comprehensive (Loss) Income
	The following tables display the components of Other Comprehensive (Loss) Income (in thousands):
		September 30, 2014
		Three Months Ended												Nine Months Ended
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit		Net-of-Tax Amount
	Foreign currency translation adjustment	$	134			$	—			$	134			$	155			$	—	$	155
	Reclassification of net gains on derivative instruments	(297		)		114				$	(183	)		(891		)		342		(549		)
	Unrealized loss on cash flow hedging derivatives	(1,644		)		633				$	(1,011	)		(1,644		)		633		(1,011		)
	Other comprehensive loss	$	(1,807	)		$	747			$	(1,060	)		$	(2,380	)		$	975	$	(1,405	)
		September 30, 2013
		Three Months Ended												Nine Months Ended
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit		Net-of-Tax Amount
	Foreign currency translation adjustment	$	(54	)		$	—			$	(54	)		$	81			$	—	$	81
	Reclassification of net gains on derivative instruments	(297		)		114				(183		)		(891		)		342		(549		)
	Other comprehensive loss	$	(351	)		$	114			$	(237	)		$	(810	)		$	342	$	(468	)
	Balances by classification included within accumulated other comprehensive income (AOCI) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands):
		September 30, 2014				December 31, 2013
	Foreign currency translation	$	687			$	532
	Derivative instruments designated as cash flow hedges	1,953				3,513
	Pension and postretirement medical plans	(1,329		)		(1,329		)
	Accumulated other comprehensive income	$	1,311			$	2,716
	The following tables display the changes in AOCI by component, net of tax (in thousands):
				30-Sep-14
				Three Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Interest Rate Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	3,147			$	(1,329	)		$	553			$	2,371
	Other comprehensive income before reclassifications			(1,011		)		—				134				(877		)
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(183		)		—				—				(183		)
	Net current-period other comprehensive (loss) income			(1,194		)		—				134				(1,060		)
	Ending balance			$	1,953			$	(1,329	)		$	687			$	1,311
				30-Sep-13
				Three Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Interest Rate Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	3,877			$	(2,292	)		$	501			$	2,086
	Other comprehensive income before reclassifications			—				—				(54		)		(54		)
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(183		)		—				—				(183		)
	Net current-period other comprehensive loss			(183		)		—				(54		)		(237		)
	Ending balance			$	3,694			$	(2,292	)		$	447			$	1,849
				30-Sep-14
				Nine Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Interest Rate Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	3,513			$	(1,329	)		$	532			$	2,716
	Other comprehensive income before reclassifications			(1,011		)		—				155				(856		)
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(549		)		—				—				(549		)
	Net current-period other comprehensive (loss) income			(1,560		)		—				155				(1,405		)
	Ending balance			$	1,953			$	(1,329	)		$	687			$	1,311
				30-Sep-13
				Nine Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Interest Rate Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	4,243			$	(2,292	)		$	366			$	2,317
	Other comprehensive income before reclassifications			—				—				81				81
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(549		)		—				—				(549		)
	Net current-period other comprehensive (loss) income			(549		)		—				81				(468		)
	Ending balance			$	3,694			$	(2,292	)		$	447			$	1,849

Risk_Management_and_Hedging_Ac

Risk Management and Hedging Activities	9 Months Ended
	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments and Hedging Activities Disclosure [Text Block]	'
	Risk Management and Hedging Activities
	Nature of Our Business and Associated Risks
	We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a large portion of our electric and natural gas supply requirements within the Montana market. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.
	Objectives and Strategies for Using Derivatives
	To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts, such as fixed-price forward purchase and sales contracts. The objective of these transactions is to fix the price for a portion of anticipated energy purchases to supply our customers. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines.
	In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.
	Accounting for Derivative Instruments
	We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
	Normal Purchases and Normal Sales
	We have applied the normal purchase and normal sale scope exception (NPNS) to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Financial Statements at September 30, 2014 and December 31, 2013. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
	Credit Risk
	Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.
	We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.
	Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.
	Interest Rate Swaps Designated as Cash Flow Hedges
	In the third quarter of 2014, we entered into two forward starting swaps of $225 million each at 3.217% and 3.227% to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the anticipated debt issuance of $450 million associated with the Hydro Transaction. At September 30, 2014, we had net unrealized pre-tax losses of $1.6 million recorded in other current liabilities and AOCI based on the market value of our interest rate swaps. These hedging instruments are assessed on a quarterly basis to determine if they are effective in offsetting the interest rate risk associated with the forecasted transaction and as of September 30, 2014, we had no hedge ineffectiveness on these swaps.
	These forward starting interest rate swaps were designated as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated the forward starting interest rate swaps are being recorded as a component of AOCI. When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of AOCI and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred will be reported as a component of interest expense.
	We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCI. We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these derivative instruments on the Financial Statements (in thousands):
		Location of gain reclassified from AOCI to Income	Nine Months Ended September 30, 2014 and 2013
	Amount of gain reclassified from AOCI	Interest Expense	$	891
	Approximately $4.8 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of September 30, 2014, and we expect to reclassify approximately $1.2 million from AOCI into interest expense during the next twelve months.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Disclosures [Text Block]	'
	Fair Value Measurements
	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.
	Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:
	•	Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;
	•	Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and
	•	Level 3 – Significant inputs that are generally not observable from market activity.
	We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 8 - Risk Management and Hedging Activities for further discussion.
	We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.
			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)			Margin Cash Collateral Offset		Total Net Fair Value
			(in thousands)
	September 30, 2014
	Restricted cash		$	17,018		$	—			$	—		$	—	$	17,018
	Rabbi trust investments		19,819			—				—			—		19,819
	Interest rate derivative liability		—			(1,644		)		—			—		(1,644		)
	Total		$	36,837		$	(1,644	)		$	—		$	—	$	35,193
	December 31, 2013
	Restricted cash		$	6,650		$	—			$	—		$	—	$	6,650
	Rabbi trust investments		16,477			—				—			—		16,477
	Total		$	23,127		$	—			$	—		$	—	$	23,127
	Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Fair value for the interest rate derivatives was determined based on models using quoted three-month rates.
	Financial Instruments
	The estimated fair value of financial instruments is summarized as follows (in thousands):
		September 30, 2014							December 31, 2013
		Carrying Amount			Fair Value				Carrying Amount			Fair Value
	Liabilities:
	Long-term debt	$	1,182,092		$	1,309,855			$	1,155,097		$	1,237,151
	Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.
	We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

Financing_Activities

Financing Activities	9 Months Ended
	Sep. 30, 2014
Financing Activities [Abstract]	'
Debt Disclosure [Text Block]	'
	Financing Activities
	In April 2012, we entered into an Equity Distribution Agreement pursuant to which we were able to offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During the three months ended March 31, 2014, we sold 295,979 shares of our common stock at an average price of $45.65 per share, with proceeds of approximately $13.4 million, which are net of sales commissions of approximately $147,000 and other fees. This concluded our sales pursuant to the Equity Distribution Agreement. Total shares issued under the Equity Distribution Agreement were 2,492,889 at an average price of $40.11, for net proceeds of $98.7 million.
	During 2014 we entered into a New Market Tax Credit (NMTC) financing agreement, pursuant to Section 45D of the Internal Revenue Code of 1986 as amended, to take advantage of a tax credit program related to the development and construction of a new office building in Butte, Montana. This financing agreement was structured with unrelated third party financial institutions (the Investor) and their wholly-owned community development entities (CDEs) in connection with our participation in qualified transactions under the NMTC program. Upon closing of this transaction, we entered into two loans totaling $27.0 million payable to the CDEs sponsoring the project, and provided an $18.2 million investment to the Investor. The loans have a term of thirty years with an interest rate of approximately 1.146%. In exchange for substantially all of the benefits derived from the tax credits, the Investor contributed approximately $8.8 million to the project. The NMTC is subject to recapture for a period of seven years. If the expected tax benefits are delivered without risk of recapture to the Investor and our performance obligation is relieved, we expect $7.9 million of the loan to be forgiven in July 2021. If we do not meet the conditions for loan forgiveness, we would be required to repay $27.0 million and would concurrently receive the return of our $18.2 million investment. As we are the primary beneficiary of the entities created in relation to the NMTC transaction, they have been consolidated as variable interest entities. The loans of $27.0 million are recorded in long-term debt and the investment of $18.2 million is recorded in other assets in the Condensed Consolidated Balance Sheets.

Segment_Information

Segment Information	9 Months Ended
	Sep. 30, 2014
Segment Reporting [Abstract]	'
Segment Reporting Disclosure [Text Block]	'
	Segment Information
	Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which is not considered a business unit. Other primarily consists of the wind down of our captive insurance subsidiary and our unallocated corporate costs.
	We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments are as follows (in thousands):
	Three Months Ended
	30-Sep-14	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	212,430		$	39,482		$	—		$	—	$	251,912
	Cost of sales	84,720			9,872			—			—		94,592
	Gross margin	127,710			29,610			—			—		157,320
	Operating, general and administrative	48,528			21,005			(1,425		)	—		68,108
	Property and other taxes	20,413			7,357			3			—		27,773
	Depreciation and depletion	23,174			7,270			8			—		30,452
	Operating income (loss)	35,595			(6,022		)	1,414			—		30,987
	Interest expense	(14,025		)	(2,627		)	(2,142		)	—		(18,794		)
	Other income (expense)	1,337			336			(2,112		)	—		(439		)
	Income tax benefit	5,235			926			12,276			—		18,437
	Net income (loss)	$	28,142		$	(7,387	)	$	9,436		$	—	$	30,191
	Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
	Capital expenditures	$	62,054		$	12,011		$	—		$	—	$	74,065
	Three Months Ended
	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 and depletion	22,150			5,895			8			—		28,053
	Operating income (loss)	41,153			(5,250		)	(4,502		)	—		31,401
	Interest expense	(14,302		)	(2,560		)	(194		)	—		(17,056		)
	Other income	2,213			878			26			—		3,117
	Income tax (expense) benefit	(8,412		)	3,520			3,077			—		(1,815		)
	Net income (loss)	$	20,652		$	(3,412	)	$	(1,593	)	$	—	$	15,647
	Total assets	$	2,542,068		$	1,082,294		$	9,288		$	—	$	3,633,650
	Capital expenditures	$	55,579		$	9,823		$	—		$	—	$	65,402
	Nine Months Ended
	September 30, 2014	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	652,951		$	238,965		$	—		$	—	$	891,916
	Cost of sales	273,754			100,740			—			—		374,494
	Gross margin	379,197			138,225			—			—		517,422
	Operating, general and administrative	144,933			66,254			3,370			—		214,557
	Property and other taxes	61,322			22,961			9			—		84,292
	Depreciation and depletion	69,398			21,716			25			—		91,139
	Operating income (loss)	103,544			27,294			(3,404		)	—		127,434
	Interest expense	(43,663		)	(7,979		)	(6,245		)	—		(57,887		)
	Other income	3,204			876			650			—		4,730
	Income tax (expense) benefit	(575		)	(3,334		)	13,149			—		9,240
	Net income	$	62,510		$	16,857		$	4,150		$	—	$	83,517
	Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
	Capital expenditures	$	161,718		$	24,367		$	—		$	—	$	186,085
	Nine Months Ended
	September 30, 2013	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	637,667		$	196,652		$	1,110		$	—	$	835,429
	Cost of sales	260,879			82,528			—			—		343,407
	Gross margin	376,788			114,124			1,110			—		492,022
	Operating, general and administrative	142,594			56,899			9,248			—		208,741
	Property and other taxes	57,549			19,968			8			—		77,525
	Depreciation and depletion	67,454			17,206			25			—		84,685
	Operating income (loss)	109,191			20,051			(8,171		)	—		121,071
	Interest expense	(42,840		)	(7,553		)	(583		)	—		(50,976		)
	Other income	4,926			1,753			81			—		6,760
	Income tax (expense) benefit	(12,792		)	(153		)	3,980			—		(8,965		)
	Net income (loss)	$	58,485		$	14,098		$	(4,693	)	$	—	$	67,890
	Total assets	$	2,542,068		$	1,082,294		$	9,288		$	—	$	3,633,650
	Capital expenditures	$	130,585		$	23,366		$	—		$	—	$	153,951

Earnings_Per_Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Abstract]	'
Earnings Per Share [Text Block]	'
	Earnings Per Share
	Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards.
	Average shares used in computing the basic and diluted earnings per share are as follows:
		Three Months Ended
		30-Sep-14	30-Sep-13
	Basic computation	39,141,148	38,459,484
	Dilutive effect of
	Restricted stock and performance share awards (1)	139,655	186,192
	Diluted computation	39,280,803	38,645,676
		Nine Months Ended
		September 30, 2014	September 30, 2013
	Basic computation	39,045,790	37,982,673
	Dilutive effect of
	Restricted stock and performance share awards (1)	141,560	181,462
	Diluted computation	39,187,350	38,164,135
	_______________
	(1)          Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

Employee_Benefit_Plans

Employee Benefit Plans	9 Months Ended
	Sep. 30, 2014
Compensation and Retirement Disclosure [Abstract]	'
Pension and Other Postretirement Benefits Disclosure [Text Block]	'
	Employee Benefit Plans
	Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands):
		Pension Benefits						Other Postretirement Benefits
		Three Months Ended September 30,						Three Months Ended September 30,
		2014			2013			2014			2013
	Components of Net Periodic Benefit Cost (Income)
	Service cost	$	2,708		$	3,367		$	116		$	135
	Interest cost	6,536			5,680			214			219
	Expected return on plan assets	(7,377		)	(8,123		)	(245		)	(254		)
	Amortization of prior service cost	62			62			(500		)	(500		)
	Recognized actuarial loss	530			2,911			87			242
	Net Periodic Benefit Cost (Income)	$	2,459		$	3,897		$	(328	)	$	(158	)
		Pension Benefits						Other Postretirement Benefits
		Nine Months Ended September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
	Components of Net Periodic Benefit Cost (Income)
	Service cost	$	8,123		$	10,100		$	349		$	406
	Interest cost	19,610			17,040			644			658
	Expected return on plan assets	(22,130		)	(24,369		)	(736		)	(764		)
	Amortization of prior service cost	185			185			(1,499		)	(1,499		)
	Recognized actuarial loss	1,589			8,735			261			728
	Net Periodic Benefit Cost (Income)	$	7,377		$	11,691		$	(981	)	$	(471	)

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies Disclosure [Text Block]	'
	Commitments and Contingencies
	ENVIRONMENTAL LIABILITIES AND REGULATION
	The operation of electric generating, transmission and distribution facilities, and gas gathering, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.
	Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.
	Our liability for environmental remediation obligations is estimated to range between $27.3 million to $35.0 million, primarily for manufactured gas plants discussed below. As of September 30, 2014, we have a reserve of approximately $28.7 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.
	Manufactured Gas Plants - Approximately $22.2 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies and implementing remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources (DENR). Our current reserve for remediation costs at this site is approximately $11.4 million, and we estimate that approximately $8.3 million of this amount will be incurred during the next five years.
	We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.
	In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Voluntary soil and coal tar removals were conducted in the past at the Butte and Helena locations in accordance with MDEQ requirements. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the conditions at these sites; however, additional groundwater monitoring will be necessary and additional monitoring wells will be installed at the Butte site. Monitoring of groundwater at the Helena site is ongoing and will be necessary for an extended period of time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site or if any additional actions beyond monitored natural attenuation will be required.
	Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide. These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four electric generating plants, all of which are coal fired and operated by other companies. We have undivided interests in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.
	While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating GHG emissions of the very largest emitters, including large power plants, under the Clean Air Act, and specifically under the Prevention of Significant Deterioration (PSD) pre-construction permit, the Title V operating permit programs and the New Source Performance Standards (NSPS). In 2014, the EPA reproposed NSPS that specify permissible levels of GHG emissions from newly-constructed fossil fuel-fired electric generating units.
	As directed by President Obama's Climate Action Plan, on June 2, 2014, the EPA proposed the Clean Power Plan (CPP) rule to control carbon dioxide emissions from existing fossil fuel fired electric generating units. The rule proposes the establishment of statewide reductions of GHG emissions for individual states based on the state's potential to shift generation to existing natural gas combined cycle plants, to develop new renewable energy, to achieve demand-side management savings, and to improve performance at existing coal-fired units. The comment period on the proposed rule has been extended to December 1, 2014. EPA intends to finalize those regulations and guidelines by June 1, 2015. Under the CPP proposed rule, States must submit individual plans for achieving GHG emission standards to EPA by June 30, 2016, although EPA is proposing a dual-phase submittal process for state plans that would allow for additional time to June 30, 2018 under certain circumstances. The initial performance period for compliance would commence in 2020, with full implementation by 2030.
	On June 23, 2014, the U.S. Supreme Court struck down the EPA's Tailoring Rule, which limited the sources subject to GHG permitting requirements to the largest fossil-fueled power plants, indicating that EPA had exceeded its authority under the Clean Air Act by "rewriting unambiguous statutory terms." However, the decision affirmed EPA's ability to regulate GHG emissions from sources already subject to regulation under the PSD program, which includes most electric generating units.
	Requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance and increase our costs of procuring electricity. Although there continues to be changes in legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. In addition, physical impacts of climate change may present potential risks for severe weather, such as floods and tornadoes, in the locations where we operate or have interests. We cannot predict with any certainty whether these risks will have a material impact on our operations.
	Coal Combustion Residuals (CCRs) - In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and scrubber wastes. Under one approach, the EPA would regulate CCRs as special wastes subject to regulation under subtitle C, the hazardous waste provisions, of RCRA. This approach would have significant impacts on coal-fired plants, and would require plants to alter their ash management operations to comply with hazardous waste requirements from the generation of CCRs and associated waste waters through transportation and disposal. This could also have a negative impact on the beneficial use of CCRs and the current markets associated with such use. The second approach would regulate CCRs as a solid waste under Subtitle D of RCRA. This approach would only affect disposal, most significantly any wet disposal, of CCRs. In a January 2014 consent decree in the case Appalachian Voices v. McCarthy, the EPA agreed to take final action with respect to the CCR regulations by December 19, 2014. In addition, legislation has been introduced in Congress to regulate coal ash. We cannot predict at this time the final requirements of any CCR regulations or legislation and what impact, if any, they would have on us, but the costs of complying with any such requirements could be significant.
	Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act (CWA) requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best technology available (BTA)” for minimizing environmental impacts. On May 19, 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule gives seven options for meeting BTA, and provides a more flexible compliance approach than the proposed rule. In August 2014, EPA published the final rule establishing national requirements applicable to cooling water intake structures, which became effective October 14, 2014. Permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements.
	In April 2013, the EPA proposed CWA regulations to address mercury, arsenic, lead, and selenium in water discharged from power plants. The proposed regulations include a variety of options for whether and how these different waste streams should be treated. The EPA is reviewing public comments on these options prior to enacting final regulations. Under the proposed approach, new requirements for existing power plants would be phased in between 2017 and 2022. The EPA is under a modified consent decree to take final action by September 30, 2015. The EPA estimates that over half of the existing power plants will not incur costs under any of the proposed options because many power plants already have the technology and procedures in place to meet the proposed pollution control standards; however, it is too early to determine whether the impacts of these rules will be material.
	Clean Air Act Rules and Associated Emission Control Equipment Expenditures
	The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants where we have joint ownership.
	The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in such 'Class I' areas.
	In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. Facilities that are subject to the MATS must come into compliance by April 2015, unless a one year extension is granted on a case-by-case basis. On April 15, 2014, the U.S. Court of Appeals for the D.C. Circuit upheld the MATS rule. The decision has been appealed by 23 states and industry groups to the Supreme Court, which has not yet decided whether to hear the case.
	In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) were to be required in certain states beginning in 2012. On April 29, 2014 the Supreme Court reversed and remanded the 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated the CSAPR. EPA has filed a motion in the U.S. Court of Appeals for the D.C. Circuit to lift the stay and allow EPA to implement the CSAPR.
	In October 2013, the Supreme Court denied certiorari in Luminant Generation Co v. EPA, which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions.
	In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. As finalized, Colstrip Unit 4 does not have to improve removal efficiency for pollutants that contribute to regional haze. By 2018, Montana, or EPA, must develop a revised Plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, National Parks Conservation Association, Montana Environmental Information Center, and Sierra Club jointly filed a petition for review of the Federal Implementation Plan in the U.S. Court of Appeals for the Ninth Circuit. Montana Environmental Information Center and Sierra Club have challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. The Ninth Circuit held oral argument on the petition on May 16, 2014. At this time, we cannot predict or determine the timing or outcome of this petition.
	We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to various regulations that have been issued or proposed under the Clean Air Act, as discussed below.
	South Dakota. The South Dakota DENR determined that the Big Stone Plant, of which we have a 23.4% ownership, is subject to the BART requirements of the Regional Haze Rule. South Dakota DENR's State Implementation Plan (SIP) was approved by the EPA in May 2012. Under the SIP, the Big Stone plant must install and operate a new BART compliant air quality control system (AQCS) to reduce SO2, NOx and particulate emissions as expeditiously as practicable, but no later than five years after the EPA's approval of the SIP. The estimated total project cost for the AQCS at the Big Stone plant is approximately $384 million (our share is 23.4%) and it is expected to be operational during the second half of 2015. As of September 30, 2014, we have capitalized costs of approximately $64.4 million related to this project.
	Our incremental capital expenditure projections include amounts related to our share of the BART at Big Stone based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process. The South Dakota Public Utilities Commission has historically allowed timely recovery of the costs of environmental improvements; however, there is no precedent on a project of this size.
	Based on the finalized MATS, Big Stone will meet the requirements by installing the AQCS system and using activated carbon injection for mercury control. In August 2013, the South Dakota DENR granted Big Stone a one year extension to comply with MATS, such that the new compliance deadline is April 16, 2016. New mercury emissions monitoring equipment will also be required.
	North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, of which we have 10% ownership, to reduce its NOx emissions. Coyote must install control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown, beginning on July 1, 2018. The current estimate of the total cost of the project is approximately $9.0 million (our share is 10.0%).
	Based on the finalized MATS, Coyote will meet the requirements by using activated carbon injection for mercury control.
	Iowa. The Neal #4 generating facility, of which we have an 8.7% ownership, installed a scrubber, a baghouse, and a selective non-catalytic reduction system to comply with national ambient air quality standards and the MATS. The project was substantially completed in 2013.
	Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is currently controlling emissions of mercury under regulations issued by the State of Montana, which are stricter than the Federal MATS. The owners do not believe additional equipment will be necessary to meet the MATS for mercury, and anticipate meeting all other expected MATS emissions limitations required by the rule without additional costs except those costs related to increased monitoring frequency. These additional costs are not expected to be significant.
	See 'Legal Proceedings - Colstrip Litigation' below for discussion of Sierra Club litigation.
	Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.
	We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:
	•	We may not know all sites for which we are alleged or will be found to be responsible for remediation; and
	•	Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.
	LEGAL PROCEEDINGS
	Colstrip Litigation
	On March 6, 2013, the Sierra Club and the MEIC (Plaintiffs) filed suit in the United States District Court for the District of Montana (Court) against the six individual owners of Colstrip, including us, as well as the operator or managing agent of the station (Defendants). On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief. The original complaint included 39 claims for relief based upon alleged violations of the Clean Air Act and the Montana State Implementation Plan. The Amended Complaint dropped claims associated with projects completed before 2001, the Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects.
	In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of SO2, NOx and particulate matter and (b) were “major modifications” subject to permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits.
	On May 3, 2013, the Colstrip owners and operator filed a partial motion to dismiss, seeking dismissal of 36 of the 39 claims asserted in the original complaint. The motion was not ruled upon and the Colstrip owners filed a second motion to dismiss the Amended Complaint on October 11, 2013, incorporating parts of the first motion and supplementing it with new authorities and with regard to new claims contained in the Amended Complaint.
	On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications.
	The parties filed a joint notice (Notice) on April 21, 2014 that advised the Court of Plaintiffs’ intent to file a Second Amended Complaint which dropped claims relating to 52 projects, and added one additional project. At the joint request of the parties, the Court extended various deadlines previously set and set a bench trial date for the liability portion of the case for June 8, 2015.
	On May 6, 2014, the Court held oral argument on Defendants' motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the Magistrate issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ motion to dismiss, but dismissed seven of Plaintiffs’ “best available control technology” claims and dismissed two of Plaintiffs' claims for injunctive relief. The Plaintiffs filed an objection to the Magistrate's findings and recommendations with the U.S. Federal District Court Judge, and on August 13, 2014, the Court adopted the Magistrate's findings and conclusions.
	On August 27, 2014, the Plaintiffs filed their Second Amended Complaint, which alleges a total of 13 claims covering eight projects and seeks injunctive and declaratory relief, civil penalties (including $100,000 of civil penalties to be used for beneficial environmental projects), and recovery of their attorney fees. Defendants filed their Answer to the Second Amended Complaint on September 26, 2014.
	We intend to vigorously defend this lawsuit. Due to the preliminary nature of the lawsuit, at this time, we cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse decision.
	Billings Refinery Outage Claim
	In August 2014, we received a demand letter from a refinery in Billings claiming damages in excess of $48.5 million allegedly resulting from an outage that occurred in January 2014. We have notified our insurance carrier of the claims and our policy has a $2 million retention. We intend to vigorously defend these claims. Due to the preliminary nature of the matter, at this time, we cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse result.
	Other Legal Proceedings
	We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.

Nature_of_Operations_and_Basis1

Nature of Operations and Basis of Consolidation (Policies)	9 Months Ended
	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Consolidation, Variable Interest Entity [Policy Text Block]	'
	Variable Interest Entities
	A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.
	Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $268.9 million through 2024.

Income_Taxes_Tables

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	The following table summarizes the significant differences in income tax (benefit) expense based on the differences between our effective tax rate and the federal statutory rate (in thousands):
		Three Months Ended September 30,
		2014					2013
	Income Before Income Taxes	$	11,754				$	17,462
	Income tax calculated at 35% federal statutory rate	4,114			35	%	6,112			35	%
	Permanent or flow through adjustments:
	State income, net of federal provisions	(108		)	(0.9	)	(671		)	(4.0	)
	Release of unrecognized tax benefit	(12,607		)	(107.3	)	—			—
	Prior year permanent return to accrual adjustments	(5,172		)	(44.0	)	—			—
	Flow-through repairs deductions	(3,413		)	(29.0	)	(3,085		)	(17.7	)
	Plant and depreciation of flow through items	(685		)	(5.8	)	—			—
	Production tax credits	(300		)	(2.6	)	(482		)	(2.9	)
	Other, net	(266		)	(2.3	)	(59		)	—
		(22,551		)	(191.9	)	(4,297		)	(24.6	)
	Income tax (benefit) expense	$	(18,437	)	(156.9	)%	$	1,815		10.4	%
		Nine Months Ended September 30,
		2014					2013
	Income Before Income Taxes	$	74,277				$	76,855
	Income tax calculated at 35% federal statutory rate	25,997			35	%	26,899			35	%
	Permanent or flow through adjustments:
	State income, net of federal provisions	257			0.3		(2,615		)	(3.4	)
	Flow-through repairs deductions	(14,885		)	(20.0	)	(12,897		)	(16.8	)
	Release of unrecognized tax benefit	(12,607		)	(17.0	)	—			—
	Prior year permanent return to accrual adjustments	(5,172		)	(7.0	)	541			0.7
	Production tax credits	(2,054		)	(2.8	)	(2,152		)	(2.8	)
	Plant and depreciation of flow through items	(182		)	(0.2	)	49			—
	Other, net	(594		)	(0.7	)	(860		)	(1.0	)
		(35,237		)	(47.4	)	(17,934		)	(23.3	)
	Income tax (benefit) expense	$	(9,240	)	(12.4	)%	$	8,965		11.7	%

Goodwill_Tables

Goodwill (Tables)	9 Months Ended
	Sep. 30, 2014
Goodwill [Abstract]	'
Schedule of Goodwill [Table Text Block]	'
	Goodwill by segment is as follows for both September 30, 2014 and December 31, 2013 (in thousands):
	Electric	$	241,100
	Natural gas	114,028
		$	355,128

Comprehensive_Loss_Income_Tabl

Comprehensive (Loss) Income (Tables)	9 Months Ended
	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]	'
Schedule of Comprehensive Income (Loss) [Table Text Block]	'
	The following tables display the components of Other Comprehensive (Loss) Income (in thousands):
		September 30, 2014
		Three Months Ended												Nine Months Ended
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit		Net-of-Tax Amount
	Foreign currency translation adjustment	$	134			$	—			$	134			$	155			$	—	$	155
	Reclassification of net gains on derivative instruments	(297		)		114				$	(183	)		(891		)		342		(549		)
	Unrealized loss on cash flow hedging derivatives	(1,644		)		633				$	(1,011	)		(1,644		)		633		(1,011		)
	Other comprehensive loss	$	(1,807	)		$	747			$	(1,060	)		$	(2,380	)		$	975	$	(1,405	)
		September 30, 2013
		Three Months Ended												Nine Months Ended
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit		Net-of-Tax Amount
	Foreign currency translation adjustment	$	(54	)		$	—			$	(54	)		$	81			$	—	$	81
	Reclassification of net gains on derivative instruments	(297		)		114				(183		)		(891		)		342		(549		)
	Other comprehensive loss	$	(351	)		$	114			$	(237	)		$	(810	)		$	342	$	(468	)
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	Balances by classification included within accumulated other comprehensive income (AOCI) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands):
		September 30, 2014				December 31, 2013
	Foreign currency translation	$	687			$	532
	Derivative instruments designated as cash flow hedges	1,953				3,513
	Pension and postretirement medical plans	(1,329		)		(1,329		)
	Accumulated other comprehensive income	$	1,311			$	2,716
Accumulated Other Comprehensive Income [Table Text Block]	'
	The following tables display the changes in AOCI by component, net of tax (in thousands):
				30-Sep-14
				Three Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Interest Rate Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	3,147			$	(1,329	)		$	553			$	2,371
	Other comprehensive income before reclassifications			(1,011		)		—				134				(877		)
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(183		)		—				—				(183		)
	Net current-period other comprehensive (loss) income			(1,194		)		—				134				(1,060		)
	Ending balance			$	1,953			$	(1,329	)		$	687			$	1,311
				30-Sep-13
				Three Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Interest Rate Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	3,877			$	(2,292	)		$	501			$	2,086
	Other comprehensive income before reclassifications			—				—				(54		)		(54		)
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(183		)		—				—				(183		)
	Net current-period other comprehensive loss			(183		)		—				(54		)		(237		)
	Ending balance			$	3,694			$	(2,292	)		$	447			$	1,849
				30-Sep-14
				Nine Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Interest Rate Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	3,513			$	(1,329	)		$	532			$	2,716
	Other comprehensive income before reclassifications			(1,011		)		—				155				(856		)
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(549		)		—				—				(549		)
	Net current-period other comprehensive (loss) income			(1,560		)		—				155				(1,405		)
	Ending balance			$	1,953			$	(1,329	)		$	687			$	1,311
				30-Sep-13
				Nine Months Ended
		Affected Line Item in the Condensed Consolidated Statements of Income		Interest Rate Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	4,243			$	(2,292	)		$	366			$	2,317
	Other comprehensive income before reclassifications			—				—				81				81
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(549		)		—				—				(549		)
	Net current-period other comprehensive (loss) income			(549		)		—				81				(468		)
	Ending balance			$	3,694			$	(2,292	)		$	447			$	1,849

Risk_Management_and_Hedging_Ac1

Risk Management and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	The following table shows the effect of these derivative instruments on the Financial Statements (in thousands):
		Location of gain reclassified from AOCI to Income	Nine Months Ended September 30, 2014 and 2013
	Amount of gain reclassified from AOCI	Interest Expense	$	891

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	'
	The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 8 - Risk Management and Hedging Activities for further discussion.
	We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.
			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)			Margin Cash Collateral Offset		Total Net Fair Value
			(in thousands)
	September 30, 2014
	Restricted cash		$	17,018		$	—			$	—		$	—	$	17,018
	Rabbi trust investments		19,819			—				—			—		19,819
	Interest rate derivative liability		—			(1,644		)		—			—		(1,644		)
	Total		$	36,837		$	(1,644	)		$	—		$	—	$	35,193
	December 31, 2013
	Restricted cash		$	6,650		$	—			$	—		$	—	$	6,650
	Rabbi trust investments		16,477			—				—			—		16,477
	Total		$	23,127		$	—			$	—		$	—	$	23,127
Fair Value Financial Instruments [Table Text Block]	'
	The estimated fair value of financial instruments is summarized as follows (in thousands):
		September 30, 2014							December 31, 2013
		Carrying Amount			Fair Value				Carrying Amount			Fair Value
	Liabilities:
	Long-term debt	$	1,182,092		$	1,309,855			$	1,155,097		$	1,237,151

Segment_Information_Tables

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

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Abstract]	'
Schedule of Weighted Average Number of Shares [Table Text Block]	'
	Average shares used in computing the basic and diluted earnings per share are as follows:
		Three Months Ended
		30-Sep-14	30-Sep-13
	Basic computation	39,141,148	38,459,484
	Dilutive effect of
	Restricted stock and performance share awards (1)	139,655	186,192
	Diluted computation	39,280,803	38,645,676
		Nine Months Ended
		September 30, 2014	September 30, 2013
	Basic computation	39,045,790	37,982,673
	Dilutive effect of
	Restricted stock and performance share awards (1)	141,560	181,462
	Diluted computation	39,187,350	38,164,135
	_______________
	(1)          Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2014
Compensation and Retirement Disclosure [Abstract]	'
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	'
	Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands):
		Pension Benefits						Other Postretirement Benefits
		Three Months Ended September 30,						Three Months Ended September 30,
		2014			2013			2014			2013
	Components of Net Periodic Benefit Cost (Income)
	Service cost	$	2,708		$	3,367		$	116		$	135
	Interest cost	6,536			5,680			214			219
	Expected return on plan assets	(7,377		)	(8,123		)	(245		)	(254		)
	Amortization of prior service cost	62			62			(500		)	(500		)
	Recognized actuarial loss	530			2,911			87			242
	Net Periodic Benefit Cost (Income)	$	2,459		$	3,897		$	(328	)	$	(158	)
		Pension Benefits						Other Postretirement Benefits
		Nine Months Ended September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
	Components of Net Periodic Benefit Cost (Income)
	Service cost	$	8,123		$	10,100		$	349		$	406
	Interest cost	19,610			17,040			644			658
	Expected return on plan assets	(22,130		)	(24,369		)	(736		)	(764		)
	Amortization of prior service cost	185			185			(1,499		)	(1,499		)
	Recognized actuarial loss	1,589			8,735			261			728
	Net Periodic Benefit Cost (Income)	$	7,377		$	11,691		$	(981	)	$	(471	)

Nature_of_Operations_and_Basis2

Nature of Operations and Basis of Consolidation (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	watts	customers
Number of customers	'	678,200
Number of megawatts of qualifying facility	35	'
Estimated aggregate gross contractual payments for qualifying facilities through 2024	$268.90	'

Hydro_Transaction_Hydroelectri

Hydro Transaction Hydro-electric (Details) (USD $)	9 Months Ended			3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 26, 2013	Sep. 26, 2013	Dec. 31, 2014
		days	Kerr Project [Member]	Scenario, Forecast [Member]
		watts	watts
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Megawatts of hydro-electric generation capacity	'	633	194	'
Purchase price	'	$900	$30	'
Owned average load serving requirement	60.00%	'	'	'
Estimated rate base, Hydro Electric	870	'	'	'
Authorized return on equity	9.80%	'	'	'
Hydro assets, useful life	'50 years	'	'	'
Authorized cost of debt	4.25%	'	'	'
Capital structure, percentage of debt	52.00%	'	'	'
Capitalized structure, percentage of equity	48.00%	'	'	'
Annual revenue requirement increase	117	'	'	'
Debt instrument, term	'30 years	'	'	'
Long term debt, Hydro financing	27	'	'	450
Common stock, aggregate gross sales price	'	'	'	400
Estimated cash from operating activities	'	'	'	50
Bridge term loan facility	'	900	'	'
Bridge term loan facility agreement term	'	364	'	'
Estimated conveyance price of hydro facility	'	'	18.3	'
Estimated reference price less conveyance price	'	'	11.7	'
Authorized issuance of securities	'	900	'	'
Transaction costs	2.3	'	'	'
Debt related commitment fees and debt issuance costs	$5.60	'	'	'

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
In Millions, unless otherwise specified		Montana Natural Gas Production Assets [Member]	Dave Gates Generating Station [Member]	Regulatory Reviews of Filings [Member]
		Revenue Subject to Refund [Member]	Revenue Subject to Refund [Member]
Customer refund liability, current	'	'	$27.30	'
CU4 incremental market purchases identified for further review	'	'	'	11
Revenue recognized, subject to refund	'	22.8	'	'
Demand side management expected lost revenue recovery	$7.10	'	'	'

Income_Taxes_Details

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

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

Goodwill_Details

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

Comprehensive_Loss_Income_Deta

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

Accumulated_Other_Comprehensiv

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

Risk_Management_and_Hedging_Ac2

Risk Management and Hedging Activities (Details) (USD $)	9 Months Ended			9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Dec. 31, 2014
	swaps		Interest rate swap at 3.217% [Member]	Interest Rate Swap [Member]	Interest Rate Swap [Member]	Interest Rate Swap [Member]	Interest rate swap at 3.227% [Member]	Scenario, Forecast [Member]
					Interest Expense [Member]	Interest Expense [Member]
Derivative [Line Items]	'	'	'	'	'	'	'	'
Number of forward starting swaps	2	'	'	'	'	'	'	'
Derivative, Amount of Hedged Item	$225,000,000	'	'	'	'	'	'	'
Derivative, Fixed Interest Rate	'	'	3.22%	'	'	'	3.23%	'
Other long-term debt	27,000,000	'	'	'	'	'	'	450,000,000
Amount of gain reclassified from AOCI	'	'	'	'	891,000	891,000	'	'
Pre-tax gain on cash flow hedges remaining in AOCI	1,600,000	'	'	4,800,000	'	'	'	'
Pre-tax gain on cash flow hedge to be reclassified within twelve months from AOCI to interest expense	'	'	'	1,200,000	'	'	'	'
Interest rate swaps outstanding	0	'	'	'	'	'	'	'
Physical purchase and sale of gas and electricity at fixed prices	0	0	'	'	'	'	'	'
Hedge ineffectiveness on interest rate swaps	$0	'	'	'	'	'	'	'

Fair_Value_Recurring_Basis_Det

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

Fair_Value_Measurements_Fair_V

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

Financing_Activities_Details

Financing Activities (Details) (USD $)	9 Months Ended		3 Months Ended	24 Months Ended		3 Months Ended		3 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Mar. 31, 2014	Mar. 31, 2014	Apr. 02, 2012	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2021	Dec. 31, 2014
			Equity Distribution Agreement [Member]	Equity Distribution Agreement [Member]	Equity Distribution Agreement [Member]	Unrelated third party investment [Member]	New Market Tax Credit [Member]	Scenario, Forecast [Member]	Scenario, Forecast [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'
Common stock, aggregate gross sales price	'	'	'	'	$100,000,000	'	'	'	$400,000,000
Stock issued during period, shares, new issues	'	'	295,979	2,492,889	'	'	'	'	'
Common stock average share price during the period	'	'	$45.65	$40.11	'	'	'	'	'
Proceeds received from new issues during the period	'	'	13,400,000	98,700,000	'	'	'	'	'
Sales commissons and fees	'	'	147,000	'	'	'	'	'	'
Investments	'	'	'	'	'	'	18,200,000	'	'
Debt instrument, term	'30 years	'	'	'	'	'	'	'	'
Debt instrument, interest rate, percentage	1.15%	'	'	'	'	'	'	'	'
Investment in New Market Tax Credit Program	18,169,000	0	'	'	'	8,800,000	'	'	'
Debt instrument, decrease, forgiveness	'	'	'	'	'	'	'	7,900,000	'
Other long-term debt	$27,000,000	'	'	'	'	'	'	'	$450,000,000

Segment_Information_Details

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

Earnings_Per_Share_Details

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

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

Commitments_and_Contingencies_

Commitments and Contingencies Environmental (Details) (USD $)	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Jul. 01, 2018
In Millions, unless otherwise specified		Colstrip Unit 4 [Member]	Neal 4 Generating Facility [Member]	Coyote Generating Facility [Member]	Big Stone Generating Facility [Member]	Manufactured Gas Plants [Member]	Aberdeen South Dakota Site [Member]	Scenario, Forecast [Member]
							Manufactured Gas Plants [Member]	Coyote Generating Facility [Member]
Environmental remediation obligation, minimum	$27.30	'	'	'	'	'	'	'
Environmental remediation obligation, maximum	35	'	'	'	'	'	'	'
Accrual for environmental loss contingencies	28.7	'	'	'	'	22.2	11.4	'
Environmental remediation obligation next 5 years	'	'	'	'	'	'	8.3	'
Jointly owned utility plant ownership percentage	'	30.00%	8.70%	10.00%	23.40%	'	'	'
NOx emissions per million Btu as calculated on a 30 day rolling average basis	'	'	'	'	'	'	'	0.5
Estimated capital expenditures for environmental obligations	'	'	'	9	384	'	'	'
Joint ownership share of capitalized project costs	'	'	'	'	$64.40	'	'	'
Number of years for environmental remediation obligation to be incurred	'	'	'	'	'	'	'5 years	'

Commitments_and_Contingencies_1

Commitments and Contingencies Litigation (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Damages sought, value	$48.50
Deductible amount	$2