MDU Resources (MDU) 10-K 20 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Document and entity information [Abstract]
Entity Registrant Name	MDU RESOURCES GROUP INC
Entity Central Index Key	67716
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$6,795,350,628
Entity Common Stock, Shares Outstanding		194,420,095
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$1,366,356		$1,264,574		$1,131,626
Exploration and production, construction materials and contracting, construction services and other	3,304,202		3,197,830		2,943,805
Total operating revenues	4,670,558		4,462,404		4,075,431
Operating expenses:
Fuel and purchased power	89,312		83,528		72,380
Purchased natural gas sold	570,041		505,065		425,220
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services	303,822		269,825		254,194
Exploration and production, construction materials and contracting, construction services and other	2,625,228		2,535,872		2,377,285
Depreciation, depletion and amortization	401,368		386,856		359,205
Taxes, other than income	192,562		188,359		176,140
Write-downs of oil and natural gas properties (Note 1)	0		0		391,800
Total operating expenses	4,182,333		3,969,505		4,056,224
Operating income	488,225		492,899		19,207
Earnings (loss) from equity method investments	-41		-132		5,383
Other income	9,962		6,768		6,642
Interest expense	87,016		83,917		76,699
Income (loss) before income taxes	411,130		415,618		-45,467
Income taxes	119,969		136,736		-31,146
Income (loss) from continuing operations	291,161		278,882		-14,321
Income (loss) from discontinued operations, net of tax (Note 3)	3,177	[1]	-312	[1]	13,567	[1]
Net income (loss)	294,338		278,570		-754
Net loss attributable to noncontrolling interest	-3,895		-363		0
Dividends declared on preferred stocks	685		685		685
Earnings (loss) on common stock	$297,548		$278,248		($1,439)
Earnings (loss) per common share - basic:
Earnings (loss) before discontinued operations	$1.53		$1.47		($0.08)
Discontinued operations, net of tax	$0.02		$0		$0.07
Earnings (loss) per common share - basic	$1.55		$1.47		($0.01)
Earnings (loss) per common share - diluted:
Earnings (loss) before discontinued operations	$1.53		$1.47		($0.08)
Discontinued operations, net of tax	$0.02		$0		$0.07
Earnings (loss) per common share - diluted	$1.55		$1.47		($0.01)
Weighted average common shares outstanding - basic	192,507		188,855		188,826
Weighted average common shares outstanding - diluted	192,587		189,693		188,826
[1]	Reflected in the Other category.

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income (loss)	$294,338	$278,570	($754)
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $0, $(3,116) and $4,829 in 2014, 2013 and 2012, respectively	0	-5,594	8,497
Reclassification adjustment for (gain) loss on derivative instruments included in net income, net of tax of $413, $(2,548) and $(5,141) in 2014, 2013 and 2012, respectively	694	-4,189	-8,754
Net unrealized gain (loss) on derivative instruments qualifying as hedges	694	-9,783	-257
Postretirement liability adjustment:
Postretirement liability gains (losses) arising during the period, net of tax of $(7,665), $11,818 and $(2,060) in 2014, 2013 and 2012, respectively	-12,409	18,539	-3,106
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $492, $1,276 and $1,379 in 2014, 2013 and 2012, respectively	796	2,001	2,079
Reclassification of postretirement liability adjustment to regulatory asset, net of tax of $4,509, $0 and $0 in 2014, 2013 and 2012, respectively	7,202	0	0
Postretirement liability adjustment	-4,411	20,540	-1,027
Foreign currency translation adjustment:
Foreign currency translation adjustment recognized during the period, net of tax of $(99), $(177) and $(296) in 2014, 2013 and 2012, respectively	-162	-299	-476
Reclassification adjustment for (gain) loss on foreign currency translation adjustment included in net income, net of tax of $0, $70 and $2 in 2014, 2013 and 2012, respectively	0	143	3
Foreign currency translation adjustment	-162	-156	-473
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(83), $(105) and $(52) in 2014, 2013 and 2012, respectively	-154	-194	-97
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $73, $59 and $72 in 2014, 2013 and 2012, respectively	135	109	134
Net unrealized gain (loss) on available-for-sale investments	-19	-85	37
Other comprehensive income (loss)	-3,898	10,516	-1,720
Comprehensive income (loss)	290,440	289,086	-2,474
Comprehensive loss attributable to noncontrolling interest	-3,895	-363	0
Comprehensive income (loss) attributable to common stockholders	294,335	289,449	-2,474
Other Comprehensive Income (Loss), Tax, Parenthetical Disclosures [Abstract]
Net unrealized gain (loss) on derivative instruments arising during the period, tax	0	-3,116	4,829
Reclassification adjustment for (gain) loss on derivative instruments included in net income, tax	413	-2,548	-5,141
Postretirement liability gains (losses) arising during the period, tax	-7,665	11,818	-2,060
Amortization of postretirement liability losses included in net periodic benefit cost, tax	492	1,276	1,379
Reclassification of postretirement liability adjustment to regulatory asset, tax	4,509	0	0
Foreign currency translation adjustment recognized during the period, tax	-99	-177	-296
Reclassification adjustment for (gain) loss on foreign currency translation adjustment included in net income, tax	0	70	2
Net unrealized gains (losses) on available-for-sale investments arising during the period, tax	-83	-105	-52
Reclassification adjustments for (gain) loss on available-for-sale investments included in net income, tax	$73	$59	$72

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$81,855		$45,225
Receivables, net	693,318		713,067
Inventories	300,811		282,391
Deferred income taxes	23,806		25,048
Commodity derivative instruments	18,335		1,447
Prepayments and other current assets	76,848		49,510
Total current assets	1,194,973		1,116,688
Investments	117,920		112,939
Property, plant and equipment (Note 1)	9,693,171		8,803,866
Less accumulated depreciation, depletion and amortization	4,166,407		3,872,487
Net property, plant and equipment	5,526,764		4,931,379
Deferred charges and other assets:
Goodwill (Note 5)	635,204	[1]	636,039	[1]
Other intangible assets, net (Note 5)	9,840		13,099
Other	325,277		251,188
Total deferred charges and other assets	970,321		900,326
Total assets	7,809,978		7,061,332
Current liabilities:
Short-term borrowings (Note 9)	0		11,500
Long-term debt due within one year	269,449		12,277
Accounts payable	382,671		404,961
Taxes payable	45,631		74,175
Dividends payable	35,607		33,737
Accrued compensation	62,775		69,661
Commodity derivative instruments	0		7,483
Other accrued liabilities	172,561		171,106
Total current liabilities	968,694		784,900
Long-term debt (Note 9)	1,825,278		1,842,286
Deferred credits and other liabilities:
Deferred income taxes	952,413		859,306
Other liabilities	813,809		718,938
Total deferred credits and other liabilities	1,766,222		1,578,244
Equity:
Preferred stocks (Note 11)	15,000		15,000
Common stockholders' equity:
Common stock (Note 12) Authorized - 500,000,000 shares, $1.00 par value Issued - 194,754,812 shares in 2014 and 189,868,780 shares in 2013	194,755		189,869
Other paid-in capital	1,207,188		1,056,996
Retained earnings	1,762,827		1,603,130
Accumulated other comprehensive loss	-42,103		-38,205
Treasury stock at cost - 538,921 shares	-3,626		-3,626
Total common stockholders' equity	3,119,041		2,808,164
Total stockholders' equity	3,134,041		2,823,164
Noncontrolling interest	115,743		32,738
Total equity	3,249,784		2,855,902
Total liabilities and equity	$7,809,978		$7,061,332
[1]	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Stockholders' equity:
Common stock, shares authorized	500,000,000	500,000,000
Common stock, par value	$1	$1
Common stock, shares issued	194,754,812	189,868,780
Treasury stock, shares	538,921	538,921

Consolidated_Statements_of_Equ

Consolidated Statements of Equity (USD $)	Total	Preferred stock	Common Stock	Other Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Treasury Stock	Noncontrolling interest
In Thousands, except Share data
Balance at Dec. 31, 2011	$2,775,567	$15,000	$189,332	$1,035,739	$1,586,123	($47,001)	($3,626)
Balance (in shares) at Dec. 31, 2011		150,000
Balance (in shares) at Dec. 31, 2011			189,332,485
Treasury stock (in shares) at Dec. 31, 2011							-538,921
Net income (loss) attributable to parent					-754
Net loss attributable to noncontrolling interest	0
Net income (loss)	-754
Other comprehensive income (loss)	-1,720					-1,720
Dividends declared on preferred stocks	-685				-685
Dividends declared on common stock	-127,538				-127,538
Stock-based compensation - shares			25,743
Stock-based compensation	5,120		26	5,094
Excess tax benefit (deficit) on stock-based compensation	-1,958			-1,958
Issuance of common stock - shares			11,222
Issuance of common stock	216		11	205
Balance at Dec. 31, 2012	2,648,248	15,000	189,369	1,039,080	1,457,146	-48,721	-3,626
Balance (in shares) at Dec. 31, 2012		150,000
Treasury stock (in shares) at Dec. 31, 2012							-538,921
Balance (in shares) at Dec. 31, 2012			189,369,450
Net income (loss) attributable to parent					278,933
Net loss attributable to noncontrolling interest	-363							-363
Net income (loss)	278,570
Other comprehensive income (loss)	10,516					10,516
Dividends declared on preferred stocks	-685				-685
Dividends declared on common stock	-132,264				-132,264
Stock-based compensation	5,281			5,281
Excess tax benefit (deficit) on stock-based compensation	-1,419			-1,419
Issuance of common stock - shares			499,330
Issuance of common stock	14,554		500	14,054
Contribution from non-controlling interest	33,101							33,101
Balance at Dec. 31, 2013	2,855,902	15,000	189,869	1,056,996	1,603,130	-38,205	-3,626	32,738
Balance (in shares) at Dec. 31, 2013		150,000
Treasury stock (in shares) at Dec. 31, 2013	-538,921						-538,921
Balance (in shares) at Dec. 31, 2013	189,868,780		189,868,780
Net income (loss) attributable to parent					298,233
Net loss attributable to noncontrolling interest	-3,895							-3,895
Net income (loss)	294,338
Other comprehensive income (loss)	-3,898					-3,898
Dividends declared on preferred stocks	-685				-685
Dividends declared on common stock	-137,851				-137,851
Stock-based compensation	6,191			6,191
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings			326,122
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	-5,564		326	-5,890
Excess tax benefit (deficit) on stock-based compensation	4,729			4,729
Issuance of common stock - shares			4,559,910
Issuance of common stock	149,722		4,560	145,162
Contribution from non-controlling interest	86,900							86,900
Balance at Dec. 31, 2014	$3,249,784	$15,000	$194,755	$1,207,188	$1,762,827	($42,103)	($3,626)	$115,743
Balance (in shares) at Dec. 31, 2014		150,000
Treasury stock (in shares) at Dec. 31, 2014	-538,921						-538,921
Balance (in shares) at Dec. 31, 2014	194,754,812		194,754,812

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Operating activities:
Net income (loss)	$294,338		$278,570		($754)
Income (loss) from discontinued operations, net of tax	3,177	[1]	-312	[1]	13,567	[1]
Income (loss) from continuing operations	291,161		278,882		-14,321
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	401,368		386,856		359,205
Earnings (loss), net of distributions, from equity method investments	550		2,281		-618
Deferred income taxes	87,015		86,778		-7,503
Unrealized (gain) loss on commodity derivatives	-23,400		6,267		624
Write-downs of oil and natural gas properties (Note 1)	0		0		391,800
Excess tax benefit on stock-based compensation	-4,729		0		-26
Changes in current assets and liabilities, net of acquisitions:
Receivables	6,166		-40,669		-13,416
Inventories	-18,738		30,452		-42,334
Other current assets	-25,997		-9,474		297
Accounts payable	-45,065		15,084		6,352
Other current liabilities	-23,515		29,392		-59,001
Other noncurrent changes	-29,193		-43,937		-33,639
Net cash provided by continuing operations	615,623		741,912		587,420
Net cash provided by (used in) discontinued operations	159		281		-2,680
Net cash provided by operating activities	615,782		742,193		584,740
Investing activities:
Capital expenditures	-972,102		-909,400		-872,920
Acquisitions, net of cash acquired	-209,213		0		-67,261
Net proceeds from sale or disposition of property and other	276,415		124,541		40,110
Investments	709		302		9,725
Proceeds from sale of equity method investments	0		1,896		2,394
Net cash used in continuing operations	-904,191		-782,661		-887,952
Net cash provided by discontinued operations	0		0		0
Net cash used in investing activities	-904,191		-782,661		-887,952
Financing activities:
Issuance of short-term borrowings	0		9,500		20,100
Repayment of short-term borrowings	-11,500		0		0
Issuance of long-term debt	606,084		507,924		467,957
Repayment of long-term debt	-368,803		-423,707		-138,775
Proceeds from issuance of common stock	150,060		14,554		88
Dividends paid	-136,712		-98,405		-159,768
Excess tax benefit on stock-based compensation	4,729		0		26
Tax withholding on stock-based compensation	-5,564		0		0
Contribution from noncontrolling interest	86,900		27,000		0
Net cash provided by continuing operations	325,194		36,866		189,628
Net cash provided by discontinued operations	0		0		0
Net cash provided by financing activities	325,194		36,866		189,628
Effect of exchange rate changes on cash and cash equivalents	-155		-215		-146
Increase (decrease) in cash and cash equivalents	36,630		-3,817		-113,730
Cash and cash equivalents - beginning of year	45,225		49,042		162,772
Cash and cash equivalents - end of year	$81,855		$45,225		$49,042
[1]	Reflected in the Other category.

Summary_of_significant_account

Summary of significant accounting policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of significant accounting policies	Summary of Significant Accounting Policies
	Basis of presentation
	The abbreviations and acronyms used throughout are defined following the Notes to Consolidated Financial Statements. The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline and energy services, exploration and production, construction materials and contracting, construction services and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Exploration and production, construction materials and contracting, construction services and other are nonregulated. For further descriptions of the Company's businesses, see Note 15. Intercompany balances and transactions have been eliminated in consolidation, except for certain transactions related to the Company's regulated operations in accordance with GAAP. The statements also include the ownership interests in the assets, liabilities and expenses of jointly owned electric generating facilities.
	The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by the Company's nonregulated businesses.
	The Company's regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals.
	Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.
	Management has also evaluated the impact of events occurring after December 31, 2014, up to the date of issuance of these consolidated financial statements.
	Cash and cash equivalents
	The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
	Accounts receivable and allowance for doubtful accounts
	Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. For more information, see Percentage-of-completion method in this note. The total balance of receivables past due 90 days or more was $30.9 million and $36.4 million at December 31, 2014 and 2013, respectively.
	The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at December 31, 2014 and 2013, was $9.5 million and $10.1 million, respectively.
	Inventories and natural gas in storage
	Inventories, other than natural gas in storage for the Company's regulated operations, were stated at the lower of average cost or market value. Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories. Inventories at December 31 consisted of:
		2014			2013
		(In thousands)
	Aggregates held for resale	$	108,161		$	101,568
	Materials and supplies	65,683			69,808
	Asphalt oil	42,135			38,099
	Merchandise for resale	24,420			21,720
	Natural gas in storage (current)	19,302			16,417
	Other	41,110			34,779
	Total	$	300,811		$	282,391
	The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $49.3 million and $48.3 million at December 31, 2014 and 2013, respectively.
	Investments
	The Company's investments include its equity method and cost method investments as discussed in Note 4, the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company measures its investment in the insurance contract at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated other comprehensive income (loss). For more information, see Notes 8 and 16.
	Property, plant and equipment
	Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for exploration and production properties as described in Oil and natural gas properties in this note, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, at the exploration and production segment only on costs that have been excluded from the full cost amortization pool and on certain construction projects associated with its other operations. The amount of AFUDC and interest capitalized for the years ended December 31 were as follows:
		2014			2013			2012
					(In thousands)
	Interest capitalized	$	8,586		$	6,033		$	8,659
	AFUDC - borrowed	$	3,022		$	2,767		$	2,483
	AFUDC - equity	$	5,803		$	3,322		$	4,530
	Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable aggregate reserves, which are depleted based on the units-of-production method, and exploration and production properties, which are amortized on the units-of-production method based on total proved reserves. The Company collects removal costs for plant assets in regulated utility rates. These amounts are recorded as regulatory liabilities, which are included in other liabilities.
	Property, plant and equipment at December 31 was as follows:
		2014			2013			Weighted
								Average
								Depreciable
								Life in Years
		(Dollars in thousands, where applicable)
	Regulated:
	Electric:
	Generation	$	627,952		$	570,394		42
	Distribution	343,692			308,202			39
	Transmission	229,997			196,824			48
	Construction in progress	150,445			141,365			-
	Other	105,015			99,037			15
	Natural gas distribution:
	Distribution	1,481,390			1,384,587			40
	Construction in progress	59,310			46,763			-
	Other	364,059			345,551			27
	Pipeline and energy services:
	Transmission	449,276			418,594			53
	Gathering	39,595			39,597			20
	Storage	43,994			42,939			60
	Construction in progress	5,386			6,937			-
	Other	39,910			39,504			33
	Nonregulated:
	Pipeline and energy services:
	Midstream	227,598			213,063			16
	Construction in progress	314,304			188,641			-
	Other	100,170			12,897			18
	Exploration and production:
	Oil and natural gas properties	3,337,177			3,017,879			*
Other	65,702			42,969			8
Construction materials and contracting:
Land	125,372			125,551			-
Buildings and improvements	70,566			70,000			19
Machinery, vehicles and equipment	921,564			906,774			12
Construction in progress	8,709			13,315			-
Aggregate reserves	403,731			394,715			**
Construction services:
Land	5,265			4,821			-
Buildings and improvements	17,936			16,628			20
Machinery, vehicles and equipment	112,973			105,991			6
Other	8,221			7,508			4
Other:
Land	2,837			2,837			-
Other	48,100			47,160			23
Eliminations	(17,075		)	(7,177		)
Less accumulated depreciation, depletion and amortization	4,166,407			3,872,487
Net property, plant and equipment	$	5,526,764		$	4,931,379
*	Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $21.17, $17.41 and $15.28 for the years ended December 31, 2014, 2013 and 2012, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $132.1 million and $124.9 million were excluded from amortization at December 31, 2014 and 2013, respectively.
**	Depleted on the units-of-production method.
Impairment of long-lived assets
The Company reviews the carrying values of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. In 2013 and 2012, the Company recognized impairments of $9.0 million (after tax) and $1.7 million (after tax), respectively, which are recorded in operation and maintenance expense on the Consolidated Statements of Income. The impairments are related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a significant decline in natural gas development and production activity largely due to low natural gas prices. The coalbed natural gas gathering assets were written down to fair value that was determined using the income approach. For more information on this nonrecurring fair value measurement, see Note 8.
No significant impairment losses were recorded in 2014. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired.
The goodwill impairment test is a two-step process performed at the reporting unit level. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. For more information on the Company's operating segments, see Note 15. The first step of the impairment test involves comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the years ended December 31, 2014, 2013 and 2012, there were no significant impairment losses recorded. At December 31, 2014, the fair value substantially exceeded the carrying value at all reporting units.
Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the Company's future revenue, profitability and cash flows, amount and timing of estimated capital expenditures, inflation rates, weighted average cost of capital, operational plans, and current and future economic conditions, among others. The fair value of each reporting unit is determined using a weighted combination of income and market approaches. The Company uses a discounted cash flow methodology for its income approach. Under the income approach, the discounted cash flow model determines fair value based on the present value of projected cash flows over a specified period and a residual value related to future cash flows beyond the projection period. Both values are discounted using a rate which reflects the best estimate of the weighted average cost of capital at each reporting unit. The weighted average cost of capital, which varies by reporting unit and is in the range of 5 percent to 9 percent, and a long-term growth rate projection of approximately 3 percent were utilized in the goodwill impairment test performed in the fourth quarter of 2014. Under the market approach, the Company estimates fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants. The Company believes that the estimates and assumptions used in its impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.
Oil and natural gas properties
The Company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized.
Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash outflows associated with asset retirement obligations that have been accrued on the balance sheet. If capitalized costs, less accumulated amortization and related deferred income taxes, exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.
SEC Defined Prices for each quarter in 2014 were as follows:
SEC Defined Prices for the 12 months ended	NYMEX			Henry Hub			Ventura
	Oil Price			Gas Price			Gas Price
	(per Bbl)			(per MMBtu)			(per MMBtu)
December 31, 2014	$	94.99		$	4.34		$	7.71
September 30, 2014	99.08			4.24			7.6
June 30, 2014	100.27			4.1			7.47
March 31, 2014	98.46			3.99			7.33
For purposes of comparison, first-of-the-month prices were as follows:
	NYMEX			Henry Hub			Ventura
	Oil Price			Gas Price			Gas Price
	(per Bbl)			(per MMBtu)			(per MMBtu)
Jan-15	$	53.27		$	3		$	3.06
Feb-15	48.24			2.68			2.78
Given the current oil and natural gas pricing environment, the Company believes it is likely it will have noncash write-downs of its oil and natural gas properties in future quarters until such time as commodity prices begin to recover.
At December 31, 2014 and 2013, the Company's full-cost ceiling exceeded the Company's capitalized cost. Various factors, including lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in future noncash write-downs of the Company's oil and natural gas properties.
The Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at September 30, 2012 and December 31, 2012. SEC Defined Prices, adjusted for market differentials, are used to calculate the ceiling test. SEC Defined Prices as of September 30, 2012 and December 31, 2012, were $94.97 per Bbl for NYMEX oil and $2.83 per MMBtu for Henry Hub natural gas and $94.71 per Bbl for NYMEX oil and $2.76 per MMBtu for Henry Hub natural gas, respectively. Accordingly, the Company was required to write down its oil and natural gas producing properties. The noncash write-downs amounted to $160.1 million and $231.7 million ($100.9 million and $145.9 million after tax) for the three months ended September 30, 2012 and December 31, 2012, respectively.
The Company hedged a portion of its oil and natural gas production and the effects of the cash flow hedges were used in determining the full-cost ceiling at September 30, 2012 and December 31, 2012. The Company would have recognized additional write-downs of its oil and natural gas properties of $19.5 million ($12.3 million after tax) at September 30, 2012, and $20.8 million ($13.1 million after tax) at December 31, 2012, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 7.
The following table summarizes the Company's oil and natural gas properties not subject to amortization at December 31, 2014, in total and by the year in which such costs were incurred:
				Year Costs Incurred
	Total			2014			2013			2012			2011
													and prior
	(In thousands)
Acquisition	$	97,795		$	82,233		$	1,528		$	475		$	13,559
Development	14,312			3,361			9,928			484			539
Exploration	18,221			10,961			3,126			3,885			249
Capitalized interest	1,813			1,343			203			67			200
Total costs not subject to amortization	$	132,141		$	97,898		$	14,785		$	4,911		$	14,547
Costs not subject to amortization as of December 31, 2014, consisted primarily of unevaluated leaseholds and development costs in the Powder River Basin and the Paradox Basin. The Company expects that the majority of these costs will be evaluated within the next five years and included in the amortization base as the properties are evaluated and/or developed.
Revenue recognition
Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is reasonably assured. The Company recognizes utility revenue each month based on the services provided to all utility customers during the month. Accrued unbilled revenue which is included in receivables, net, represents revenues recognized in excess of amounts billed. Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain was $99.7 million and $107.4 million at December 31, 2014 and 2013, respectively. The Company recognizes construction contract revenue at its construction businesses using the percentage-of-completion method as discussed later. The Company recognizes revenue from exploration and production properties only on that portion of production sold and allocable to the Company's ownership interest in the related properties. The Company recognizes all other revenues when services are rendered or goods are delivered. The Company presents revenues net of taxes collected from customers at the time of sale to be remitted to governmental authorities, including sales and use taxes.
Percentage-of-completion method
The Company recognizes construction contract revenue from fixed-price and modified fixed-price construction contracts at its construction businesses using the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract. If a loss is anticipated on a contract, the loss is immediately recognized.
Costs and estimated earnings in excess of billings on uncompleted contracts represent revenues recognized in excess of amounts billed and were included in receivables, net. Billings in excess of costs and estimated earnings on uncompleted contracts represent billings in excess of revenues recognized and were included in accounts payable. Costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings on uncompleted contracts at December 31, were as follows:
	2014			2013
	(In thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	58,243		$	60,828
Billings in excess of costs and estimated earnings on uncompleted contracts	$	47,011		$	84,189
Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31, were as follows:
	2014			2013
	(In thousands)
Short-term retainage*	$	47,551		$	55,906
Long-term retainage**	1,053			4,229
Total retainage	$	48,604		$	60,135
*	Expected to be paid within one year or less and included in receivables, net.
**	Included in deferred charges and other assets - other.
Derivative instruments
The Company's policy allows the use of derivative instruments as part of an overall energy price and interest rate risk management program to efficiently manage and minimize commodity price and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions, and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties.
The Company's policy generally allows the hedging of monthly forecasted sales of oil and natural gas production at Fidelity for a period up to 42 months from the time the Company enters into the hedge. The Company's policy requires that interest rate derivative instruments not exceed a period of 24 months and allows the hedging of monthly forecasted purchases of natural gas at Cascade and Intermountain for a period up to three years.
The Company's policy requires that each month as physical oil and natural gas production at Fidelity occurs and the commodity is sold, the related portion of the derivative agreement for that month's production must settle with its counterparties. Settlements represent the exchange of cash between the Company and its counterparties based on the notional quantities and prices for each month's physical delivery as specified within the agreements. The fair value of the remaining notional amounts on the derivative agreements is recorded on the balance sheet as an asset or liability measured at fair value. The Company's policy also requires settlement of natural gas derivative instruments at Cascade and Intermountain monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days. The Company has policies and procedures that management believes minimize credit-risk exposure. Accordingly, the Company does not anticipate any material effect on its financial position or results of operations as a result of nonperformance by counterparties. For more information on derivative instruments, see Note 7.
Asset retirement obligations
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its nonregulated operations or incurs a regulatory asset or liability at its regulated operations. For more information on asset retirement obligations, see Note 10.
Legal costs
The Company expenses external legal fees as they are incurred.
Natural gas costs recoverable or refundable through rate adjustments
Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within a period ranging from 12 to 28 months from the time such costs are paid. Natural gas costs refundable through rate adjustments were $13.2 million and $16.9 million at December 31, 2014 and 2013, respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $19.6 million and $12.1 million at December 31, 2014 and 2013, respectively, which is included in prepayments and other current assets.
Income taxes
The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.
The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.
Tax positions taken or expected to be taken in an income tax return are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.
Foreign currency translation adjustment
The functional currency of the Company's investment in ECTE, as discussed in Note 4, is the Brazilian Real. Translation from the Brazilian Real to the U.S. dollar for assets and liabilities is performed using the exchange rate in effect at the balance sheet date. Revenues and expenses are translated on a year-to-date basis using an average of the daily exchange rates.
Transaction gains and losses resulting from the effect of exchange rate changes on transactions denominated in a currency other than the functional currency of the reporting entity would be recorded in income.
Earnings (loss) per common share
Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding performance share awards. In 2014 and 2013, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the year ended December 31, 2012, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the year. Due to the loss on common stock for the year ended December 31, 2012, the effect of outstanding performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury. Net income (loss) was the same for both the basic and diluted earnings (loss) per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings (loss) per share calculation was as follows:
	2014		2013		2012
			(In thousands)
Weighted average common shares outstanding - basic	192,507		188,855		188,826
Effect of dilutive performance share awards	80		838		—
Weighted average common shares outstanding - diluted	192,587		189,693		188,826
Shares excluded from the calculation of diluted earnings per share	—		—		58
Use of estimates
The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as impairment testing of long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; oil, NGL and natural gas proved reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Cash flow information
Cash expenditures for interest and income taxes for the years ended December 31 were as follows:
	2014			2013			2012
				(In thousands)
Interest, net of amount capitalized	$	81,351		$	81,689		$	74,378
Income taxes paid, net	$	69,087		$	24,857		$	3,277
Noncash investing transactions at December 31 were as follows:
	2014			2013			2012
				(In thousands)
Property, plant and equipment additions in accounts payable	$	103,327		$	67,129		$	76,205
New accounting standards
Revenue from Contracts with Customers In May 2014, the FASB issued guidance on accounting for revenue from contracts with customers. The guidance provides for a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry specific guidance. This guidance will be effective for the Company on January 1, 2017. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting the guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. In addition, the modified approach will require additional disclosures. The Company is evaluating the effects the adoption of the new revenue guidance will have on its results of operations, financial position, cash flows and disclosures, as well as its method of adoption.
Variable interest entities
The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.
A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.
The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement.
Comprehensive income (loss)
Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges, postretirement liability adjustments, foreign currency translation adjustments and gains (losses) on available-for-sale investments. For more information on derivative instruments, see Note 7.
The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2014, 2013 and 2012, were as follows:
	Net			Post-			Foreign			Net			Total
	Unrealized			retirement			Currency			Unrealized			Accumulated
	Gain (Loss) on			Liability Adjustment			Translation			Gain (Loss) on			Other
	Derivative						Adjustment			Available-			Comprehensive
	Instruments									for-sale			Loss
	Qualifying									Investments
	as Hedges
							(In thousands)
Balance at December 31, 2012	$	6,018		$	(54,347	)	$	(511	)	$	119		$	(48,721	)
Other comprehensive income (loss) before reclassifications	(5,594		)	18,539			(299		)	(194		)	12,452
Amounts reclassified from accumulated other comprehensive loss	(4,189		)	2,001			143			109			(1,936		)
Net current-period other comprehensive income (loss)	(9,783		)	20,540			(156		)	(85		)	10,516
Balance at December 31, 2013	(3,765		)	(33,807		)	(667		)	34			(38,205		)
Other comprehensive income (loss) before reclassifications	—			(12,409		)	(162		)	(154		)	(12,725		)
Amounts reclassified from accumulated other comprehensive loss	694			796			—			135			1,625
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	—			7,202			—			—			7,202
Net current-period other comprehensive income (loss)	694			(4,411		)	(162		)	(19		)	(3,898		)
Balance at December 31, 2014	$	(3,071	)	$	(38,218	)	$	(829	)	$	15		$	(42,103	)
Reclassifications out of accumulated other comprehensive loss for the year ended December 31 were as follows:
	2014			2013			Location on Consolidated
							Statements of Income
	(In thousands)
Reclassification adjustment for gain (loss) on derivative
instruments included in net income:
Commodity derivative instruments	$	(468	)	$	7,803		Operating revenues
Interest rate derivative instruments	(639		)	(1,066		)	Interest expense
	(1,107		)	6,737
	413			(2,548		)	Income taxes
	(694		)	4,189
Amortization of postretirement liability losses included	(1,288		)	(3,277		)	(a)
in net periodic benefit cost
	492			1,276			Income taxes
	(796		)	(2,001		)
Reclassification adjustment for loss on foreign currency	—			(213		)	Earnings (loss) from
translation adjustment included in net income							equity method investments
	—			70			Earnings (loss) from
							equity method investments
	—			(143		)
Reclassification adjustment for loss on available-for-sale	(208		)	(168		)	Other income
investments included in net income
	73			59			Income taxes
	(135		)	(109		)
Total reclassifications	$	(1,625	)	$	1,936
(a)	Included in net periodic benefit cost (credit). For more information, see Note 16.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions	Acquisitions
	On February 10, 2014, the Company entered into agreements to purchase working interests and leasehold positions in oil and natural gas production assets in the southern Powder River Basin of Wyoming. The effective date of the acquisition was October 1, 2013, and the closing occurred on March 6, 2014.
	The total purchase price, including purchase price adjustments, for acquisitions in 2014 was approximately $209.2 million, including the above acquisition.
	In 2012, the Company acquired a 50 percent undivided interest in natural gas and oil midstream assets in western North Dakota. The acquisition includes a natural gas processing plant and a natural gas gathering pipeline system, along with an oil gathering system, an oil storage terminal and an oil pipeline. The total purchase consideration for acquisitions was approximately $67.5 million, including the Company's interest in the above facilities and contingent consideration related to an acquisition made prior to 2012. The Company recognizes its proportionate share of the assets, liabilities, revenues and expenses related to the natural gas and oil midstream assets acquisition.
	The acquisitions were accounted for under the acquisition method of accounting and, accordingly, the acquired assets and liabilities assumed have been recorded at their respective fair values as of the date of acquisition. The results of operations of the acquired businesses and properties are included in the financial statements since the date of each acquisition. Pro forma financial amounts reflecting the effects of the acquisitions are not presented, as such acquisitions were not material to the Company's financial position or results of operations.

Discontinued_operations

Discontinued operations	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Discontinued operations	Discontinued Operations
	In 2007, Centennial Resources sold CEM to Bicent. In connection with the sale, Centennial Resources agreed to indemnify Bicent and its affiliates from certain third party claims arising out of or in connection with Centennial Resources' ownership or operation of CEM prior to the sale. In addition, Centennial had previously guaranteed CEM's obligations under a construction contract. In the fourth quarter of 2011, the Company accrued $21.0 million ($13.0 million after tax) related to the guarantee as a result of an arbitration award against CEM. In the second quarter of 2012, discontinued operations reflected the settlement of certain liabilities and estimated insurance recoveries resulting in a net benefit related to this matter. In the fourth quarter of 2012, the Company reversed its previously recorded accrual for the arbitration charge due to a favorable court ruling, which was partially offset by the reversal of estimated insurance recoveries. The Company incurred legal expenses and had a benefit related to the resolution of this matter in the second quarter of 2014. The Company also had a benefit related to income taxes, including the resolution of certain income tax matters, in the fourth quarter of 2014. These items are reflected as discontinued operations in the consolidated financial statements and accompanying notes. Discontinued operations are included in the Other category.

Equity_method_investments

Equity method investments	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity method investments	Equity Method Investments
	Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. At December 31, 2014 and 2013, the Company had no significant equity method investments.
	In August 2006, MDU Brasil acquired ownership interests in the Brazilian Transmission Lines. The electric transmission lines are primarily in northeastern and southern Brazil. The transmission contracts provide for revenues denominated in the Brazilian Real, annual inflation adjustments and change in tax law adjustments. The functional currency for the Brazilian Transmission Lines is the Brazilian Real.
	In 2009, multiple sales agreements were signed with three separate parties for the Company to sell its ownership interests in the Brazilian Transmission Lines. In November 2010, the Company completed the sale of its entire ownership interest in ENTE and ERTE and 59.96 percent of the Company's ownership interest in ECTE. The Company's remaining interest in ECTE is being sold over a multi-year period. In August 2013 and 2012, and November 2011, the Company completed the sale of one-fourth of the remaining interest in each year. The Company recognized immaterial gains in 2013 and 2012. The Company's remaining ownership interest in ECTE at December 31, 2014, accounted for under the cost method, was subsequently sold on January 26, 2015.

Goodwill_and_other_intangible_

Goodwill and other intangible assets	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and other intangible assets	Goodwill and Other Intangible Assets
	The changes in the carrying amount of goodwill for the year ended December 31, 2014, were as follows:
		Balance at January 1, 2014			*	Goodwill			Balance at December 31, 2014		*
						Acquired
						During the
						Year/Other
		(In thousands)
	Natural gas distribution	$	345,736			$	—		$	345,736
	Pipeline and energy services	9,737				—			9,737
	Construction materials and contracting	176,290				—			176,290
	Construction services	104,276				(835		)	103,441
	Total	$	636,039			$	(835	)	$	635,204
	*	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
	The changes in the carrying amount of goodwill for the year ended December 31, 2013, were as follows:
		Balance at January 1, 2013			*	Goodwill Acquired			Balance at December 31, 2013		*
						During
						the Year
		(In thousands)
	Natural gas distribution	$	345,736			$	—		$	345,736
	Pipeline and energy services	9,737				—			9,737
	Construction materials and contracting	176,290				—			176,290
	Construction services	104,276				—			104,276
	Total	$	636,039			$	—		$	636,039
	*	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
	Other amortizable intangible assets at December 31 were as follows:
		2014			2013
		(In thousands)
	Customer relationships	$	21,310		$	21,310
	Accumulated amortization	(15,556		)	(13,726		)
		5,754			7,584
	Noncompete agreements	5,080			6,186
	Accumulated amortization	(4,098		)	(4,840		)
		982			1,346
	Other	10,921			10,995
	Accumulated amortization	(7,817		)	(6,826		)
		3,104			4,169
	Total	$	9,840		$	13,099
	Amortization expense for amortizable intangible assets for the years ended December 31, 2014, 2013 and 2012, was $3.2 million, $4.0 million and $3.8 million, respectively. Estimated amortization expense for intangible assets is $2.5 million in 2015, $2.1 million in 2016, $1.9 million in 2017, $1.0 million in 2018, $900,000 in 2019 and $1.4 million thereafter.

Regulatory_assets_and_liabilit

Regulatory assets and liabilities	12 Months Ended
	Dec. 31, 2014
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory assets and liabilities	Regulatory Assets and Liabilities
	The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:
		Estimated Recovery	*	2014			2013
		Period
				(In thousands)
	Regulatory assets:
	Pension and postretirement benefits (a)	(e)		$	182,565		$	105,123
	Taxes recoverable from customers (a)	Over plant lives		22,910			18,266
	Manufactured gas plant sites remediation (a)	Up to 3 years		17,548			15,797
	Natural gas costs recoverable through rate adjustments (b)	Up to 28 months		19,575			12,060
	Long-term debt refinancing costs (a)	Up to 23 years		7,864			8,697
	Costs related to identifying generation development (a)	Up to 12 years		4,165			4,512
	Other (a) (b)	Largely within 1- 4 years		14,959			15,311
	Total regulatory assets			269,586			179,766
	Regulatory liabilities:
	Plant removal and decommissioning costs (c)			338,641			308,431
	Taxes refundable to customers (c)			17,772			20,180
	Natural gas costs refundable through rate adjustments (d)			13,238			16,932
	Other (c) (d)			16,601			21,868
	Total regulatory liabilities			386,252			367,411
	Net regulatory position			$	(116,666	)	$	(187,645	)
	*	Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.
	(a)	Included in deferred charges and other assets - other on the Consolidated Balance Sheets.
	(b)	Included in prepayments and other current assets on the Consolidated Balance Sheets.
	(c)	Included in other liabilities on the Consolidated Balance Sheets.
	(d)	Included in other accrued liabilities on the Consolidated Balance Sheets.
	(e)	Recovered as expense is incurred or cash contributions are made.
	The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. As of December 31, 2014 and 2013, approximately $229.6 million and $163.7 million, respectively, of regulatory assets were not earning a rate of return.
	If, for any reason, the Company's regulated businesses cease to meet the criteria for application of regulatory accounting for all or part of their operations, the regulatory assets and liabilities relating to those portions ceasing to meet such criteria would be removed from the balance sheet and included in the statement of income or accumulated other comprehensive income (loss) in the period in which the discontinuance of regulatory accounting occurs.

Derivative_instruments

Derivative instruments	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative instruments	Derivative Instruments
	Derivative instruments, including certain derivative instruments embedded in other contracts, are required to be recorded on the balance sheet as either an asset or liability measured at fair value. The Company's policy is to not offset fair value amounts for derivative instruments and, as a result, the Company's derivative assets and liabilities are presented gross on the Consolidated Balance Sheets. Changes in the derivative instrument's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Accounting for qualifying hedges allows derivative gains and losses to offset the related results on the hedged item in the income statement and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
	In the event a derivative instrument being accounted for as a cash flow hedge does not qualify for hedge accounting because it is no longer highly effective in offsetting changes in cash flows of a hedged item; if the derivative instrument expires or is sold, terminated or exercised; or if management determines that designation of the derivative instrument as a hedge instrument is no longer appropriate, hedge accounting would be discontinued and the derivative instrument would continue to be carried at fair value with changes in its fair value recognized in earnings. In these circumstances, the net gain or loss at the time of discontinuance of hedge accounting would remain in accumulated other comprehensive income (loss) until the period or periods during which the hedged forecasted transaction affects earnings, at which time the net gain or loss would be reclassified into earnings. In the event a cash flow hedge is discontinued because it is unlikely that a forecasted transaction will occur, the derivative instrument would continue to be carried on the balance sheet at its fair value, and gains and losses that had accumulated in other comprehensive income (loss) would be recognized immediately in earnings. The Company's policy requires approval to terminate a derivative instrument prior to its original maturity.
	The fair value of the derivative instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or liability.
	The Company evaluates counterparty credit risk on its derivative assets and the Company's credit risk on its derivative liabilities. As of December 31, 2014 and 2013, credit risk was not material.
	Fidelity
	At December 31, 2014 and 2013, Fidelity held oil swap agreements with total forward notional volumes of 270,000 and 2.9 million Bbl, respectively, and natural gas swap agreements with total forward notional volumes of 5.0 million and 18.3 million MMBtu, respectively. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on its forecasted sales of oil and natural gas production.
	Effective April 1, 2013, Fidelity elected to de-designate all commodity derivative contracts previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively for all of its commodity derivative instruments. When the criteria for hedge accounting is not met or when hedge accounting is not elected, realized gains and losses and unrealized gains and losses are both recorded in operating revenues on the Consolidated Statements of Income. As a result of discontinuing hedge accounting on commodity derivative instruments, gains and losses on the oil and natural gas derivative instruments remain in accumulated other comprehensive income (loss) as of the de-designation date and are reclassified into earnings in future periods as the underlying hedged transactions affect earnings. At April 1, 2013, accumulated other comprehensive income (loss) included $1.8 million of unrealized gains, representing the mark-to-market value of the Company's commodity derivative instruments that qualified as cash flow hedges as of the balance sheet date, which the Company has subsequently reclassified into earnings.
	Prior to April 1, 2013, changes in the fair value attributable to the effective portion of the hedging instruments, net of tax, were recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). To the extent that the hedges were not effective or did not qualify for hedge accounting, the ineffective portion of the changes in fair market value was recorded directly in earnings. Gains and losses on the oil and natural gas derivative instruments were reclassified from accumulated other comprehensive income (loss) into operating revenues on the Consolidated Statements of Income at the date the oil and natural gas quantities were settled.
	Certain of Fidelity's derivative instruments contain cross-default provisions that state if Fidelity or any of its affiliates fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of derivative instruments in liability positions. Fidelity had no derivative instruments that were in a liability position with credit-risk-related contingent features at December 31, 2014. The aggregate fair value of Fidelity's derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2013, was $7.5 million. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on December 31, 2013, was $7.5 million.
	Centennial
	Centennial has historically entered into interest rate derivative instruments to manage a portion of its interest rate exposure on the forecasted issuance of long-term debt. At December 31, 2014 and 2013, Centennial had no outstanding interest rate swap agreements.
	Fidelity and Centennial
	There were no components of the derivative instruments' gain or loss excluded from the assessment of hedge effectiveness. Gains and losses must be reclassified into earnings as a result of the discontinuance of cash flow hedges if it is probable that the original forecasted transactions will not occur, and there were no such reclassifications.
	The gains and losses on derivative instruments for the years ended December 31 were as follows:
		2014			2013			2012
					(In thousands)
	Commodity derivatives designated as cash flow hedges:
	Amount of gain (loss) recognized in accumulated other	$	—		$	(6,153	)	$	10,209
	comprehensive loss (effective portion), net of tax
	Amount of (gain) loss reclassified from accumulated other comprehensive	295			(4,916		)	(8,788		)
	loss into operating revenues (effective portion), net of tax
	Amount of loss recognized in operating revenues	—			(1,422		)	(730		)
	(ineffective portion), before tax
	Interest rate derivatives designated as cash flow hedges:
	Amount of gain (loss) recognized in accumulated other	—			559			(1,712		)
	comprehensive loss (effective portion), net of tax
	Amount of loss reclassified from accumulated other comprehensive	399			727			34
	loss into interest expense (effective portion), net of tax
	Amount of loss recognized in interest expense (ineffective portion), before tax	—			(769		)	—
	Commodity derivatives not designated as hedging instruments:
	Amount of gain (loss) recognized in operating revenues, before tax	23,400			(4,845		)	106
	Over the next 12 months net losses of approximately $400,000 (after tax) are estimated to be reclassified from accumulated other comprehensive income (loss) into earnings, as the hedged transactions affect earnings.
	The location and fair value of the Company's derivative instruments on the Consolidated Balance Sheets were as follows:
	Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2014			Fair Value at December 31, 2013
			(In thousands)
	Not designated as hedges:
	Commodity derivatives	Commodity derivative instruments	$	18,335		$	1,447
		Other assets - noncurrent	—			503
	Total asset derivatives		$	18,335		$	1,950
	Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2014			Fair Value at December 31, 2013
			(In thousands)
	Not designated as hedges:
	Commodity derivatives	Commodity derivative instruments	$	—		$	7,483
	Total liability derivatives		$	—		$	7,483
	All of the Company's commodity derivative instruments at December 31, 2014 and 2013, were subject to legally enforceable master netting agreements. However, the Company's policy is to not offset fair value amounts for derivative instruments and, as a result, the Company's derivative assets and liabilities are presented gross on the Consolidated Balance Sheets. The gross derivative assets and liabilities (excluding settlement receivables and payables that may be subject to the same master netting agreements) presented on the Consolidated Balance Sheets and the amount eligible for offset under the master netting agreements is presented in the following table:
	December 31, 2014	Gross Amounts Recognized on the			Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
		Consolidated Balance Sheets
		(In thousands)
	Assets:
	Commodity derivatives	$	18,335		$	—		$	18,335
	Total assets	$	18,335		$	—		$	18,335
	31-Dec-13	Gross Amounts Recognized on the			Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
		Consolidated Balance Sheets
		(In thousands)
	Assets:
	Commodity derivatives	$	1,950		$	(1,950	)	$	—
	Total assets	$	1,950		$	(1,950	)	$	—
	Liabilities:
	Commodity derivatives	$	7,483		$	(1,950	)	$	5,533
	Total liabilities	$	7,483		$	(1,950	)	$	5,533

Fair_value_measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair value measurements	Fair Value Measurements
	The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of an insurance contract, to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $65.8 million and $62.4 million as of December 31, 2014 and 2013, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gains on these investments for the years ended December 31, 2014, 2013 and 2012, were $3.4 million, $13.5 million and $5.2 million, respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income.
	The Company did not elect the fair value option, which records gains and losses in income, for its available-for-sale securities, which include mortgage-backed securities and U.S. Treasury securities. These available-for-sale securities are recorded at fair value and are classified as Investments on the Consolidated Balance Sheets. Unrealized gains or losses are recorded in accumulated other comprehensive income (loss). Details of available-for-sale securities were as follows:
	December 31, 2014	Cost		Gross		Gross			Fair Value
				Unrealized		Unrealized
				Gains		Losses
		(In thousands)
	Mortgage-backed securities	$	6,594	$	60	$	(18	)	$	6,636
	U.S. Treasury securities	3,574		—		(19		)	3,555
	Total	$	10,168	$	60	$	(37	)	$	10,191
	31-Dec-13	Cost		Gross		Gross			Fair Value
				Unrealized		Unrealized
				Gains		Losses
		(In thousands)
	Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193
	U.S. Treasury securities	1,906		15		(4		)	1,917
	Total	$	10,057	$	84	$	(31	)	$	10,110
	The fair value of the Company's money market funds approximates cost.
	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs.
	The estimated fair values of the Company's assets and liabilities measured on a recurring basis are determined using the market approach.
	The Company's Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company's Level 2 mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources.
	The estimated fair value of the Company's Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.
	The estimated fair value of the Company's Level 2 commodity derivative instruments is based upon futures prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company's and the counterparties' nonperformance risk is also evaluated.
	Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2014 and 2013, there were no transfers between Levels 1 and 2.
	The Company's assets and liabilities measured at fair value on a recurring basis were as follows:
		Fair Value Measurements
		at December 31, 2014, Using
		Quoted Prices		Significant		Significant			Balance at December 31, 2014
		in Active		Other		Unobservable
		Markets for		Observable		Inputs
		Identical		Inputs		(Level 3)
		Assets		(Level 2)
		(Level 1)
		(In thousands)
	Assets:
	Money market funds	$	—	$	18,473	$	—		$	18,473
	Insurance contract*	—		65,831		—			65,831
	Available-for-sale securities:
	Mortgage-backed securities	—		6,636		—			6,636
	U.S. Treasury securities	—		3,555		—			3,555
	Commodity derivative instruments	—		18,335		—			18,335
	Total assets measured at fair value	$	—	$	112,830	$	—		$	112,830
	*	The insurance contract invests approximately 20 percent in common stock of mid-cap companies, 18 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies, 32 percent in fixed-income investments and 1 percent in cash equivalents.
		Fair Value Measurements
		at December 31, 2013, Using
		Quoted Prices		Significant		Significant Unobservable Inputs			Balance at December 31, 2013
		in Active		Other		(Level 3)
		Markets for		Observable
		Identical		Inputs
		Assets		(Level 2)
		(Level 1)
		(In thousands)
	Assets:
	Money market funds	$	—	$	19,227	$	—		$	19,227
	Insurance contract*	—		62,370		—			62,370
	Available-for-sale securities:
	Mortgage-backed securities	—		8,193		—			8,193
	U.S. Treasury securities	—		1,917		—			1,917
	Commodity derivative instruments	—		1,950		—			1,950
	Total assets measured at fair value	$	—	$	93,657	$	—		$	93,657
	Liabilities:
	Commodity derivative instruments	$	—	$	7,483	$	—		$	7,483
	Total liabilities measured at fair value	$	—	$	7,483	$	—		$	7,483
	*	The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 15 percent in fixed-income investments.
The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including long-lived asset impairments. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company reviews the carrying value of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying amounts may not be recoverable. During the second quarters of 2013 and 2012, coalbed natural gas gathering assets were reviewed for impairment and found to be impaired and were written down to their estimated fair value using the income approach. Under this approach, fair value is determined by using the present value of future estimated cash flows. The factors used to determine the estimated future cash flows include, but are not limited to, internal estimates of gathering revenue, future commodity prices and operating costs and equipment salvage values. The estimated cash flows are discounted using a rate that approximates the weighted average cost of capital of a market participant. These fair value inputs are not typically observable. At June 30, 2013, certain coalbed natural gas gathering assets were written down to the nonrecurring fair value measurement of $9.7 million. The fair value of these coalbed natural gas gathering assets have been categorized as Level 3 (Significant Unobservable Inputs) in the fair value hierarchy.
The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The fair value was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt at December 31 was as follows:
	2014				2013
	Carrying		Fair		Carrying			Fair
	Amount		Value		Amount			Value
	(In thousands)
Long-term debt	$	2,094,727	$	2,239,445	$	1,854,563		$	1,912,590
The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt	Debt
	Certain debt instruments of the Company and its subsidiaries, including those discussed later, contain restrictive covenants and cross-default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions. In the event the Company and its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.
	The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries:
	Company	Facility	Facility				Amount Outstanding at December 31, 2014			Amount Outstanding at December 31,			Letters of			Expiration
			Limit							2013			Credit at December 31, 2014			Date
			(In millions)
	MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement (a)	$	175			$	77.5	(b)	$	78.9	(b)	$	—		5/8/19
	Cascade Natural Gas Corporation	Revolving credit agreement	$	50		(c)	$	—		$	11.5		$	2.2	(d)	7/9/18
	Intermountain Gas Company	Revolving credit agreement	$	65		(e)	$	21		$	3		$	—		7/13/18
	Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement (f)	$	650			$	211	(b)	$	75	(b)	$	—		5/8/19
	Dakota Prairie Refining, LLC	Revolving credit agreement	$	50		(g)	$	—		$	—		$	1	(d)	12/1/15
	(a)	The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $225.0 million). There were no amounts outstanding under the credit agreement.
	(b)	Amount outstanding under commercial paper program.
	(c)	Certain provisions allow for increased borrowings, up to a maximum of $75.0 million.
	(d)	An outstanding letter of credit reduces the amount available under the credit agreement.
	(e)	Certain provisions allow for increased borrowings, up to a maximum of $90.0 million.
	(f)	The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $800.0 million). There were no amounts outstanding under the credit agreement.
	(g)	Certain provisions allow for increased borrowings up to a maximum of $75.0 million.
	The Company's and Centennial's respective commercial paper programs are supported by revolving credit agreements. While the amount of commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, the Company and Centennial do not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreements.
	The following includes information related to the preceding table.
	Short-term borrowings
	Dakota Prairie Refining, LLC On December 1, 2014, Dakota Prairie Refining entered into a $50.0 million revolving credit agreement with an expiration date of December 1, 2015.
	The credit agreement contains customary covenants and provisions, including a covenant of Dakota Prairie Refining and its subsidiaries not to permit, as of the end of any fiscal quarter, the ratio of indebtedness to consolidated capitalization to be greater than 65 percent and a covenant of WBI Holdings and all of its subsidiaries not to permit, as of the end of any fiscal quarter, the ratio of funded debt to capitalization (determined on a consolidated basis) to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness, limitations on distributions and the making of certain investments.
	Dakota Prairie Refining's credit agreement also contains cross-default provisions. These provisions state that if Dakota Prairie Refining or WBI Holdings fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the agreement will be in default.
	Long-term debt
	MDU Resources Group, Inc. On May 8, 2014, the Company amended the revolving credit agreement to increase the borrowing limit to $175.0 million and extend the termination date to May 8, 2019. The Company's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings.
	The credit agreement contains customary covenants and provisions, including covenants of the Company not to permit, as of the end of any fiscal quarter, (A) the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent or (B) the ratio of funded debt to capitalization (determined with respect to the Company alone, excluding its subsidiaries) to be greater than 65 percent. Other covenants include limitations on the sale of certain assets and on the making of certain loans and investments.
	There are no credit facilities that contain cross-default provisions between the Company and any of its subsidiaries.
	MDU Energy Capital, LLC The ability to request additional borrowings under the master shelf agreement expired; however, there is debt outstanding that is reflected in the following table of long-term debt outstanding. The master shelf agreement contains customary covenants and provisions, including covenants of MDU Energy Capital not to permit (A) the ratio of its total debt (on a consolidated basis) to adjusted total capitalization to be greater than 70 percent, or (B) the ratio of subsidiary debt to subsidiary capitalization to be greater than 65 percent, or (C) the ratio of Intermountain’s total debt (determined on a consolidated basis) to total capitalization to be greater than 65 percent. The agreement also includes a covenant requiring the ratio of MDU Energy Capital earnings before interest and taxes to interest expense (on a consolidated basis), for the 12-month period ended each fiscal quarter, to be greater than 1.5 to 1. In addition, payment obligations under the master shelf agreement may be accelerated upon the occurrence of an event of default (as described in the agreement).
	Cascade Natural Gas Corporation Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.
	The credit agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments.
	Cascade's credit agreement also contains cross-default provisions. These provisions state that if Cascade fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, Cascade will be in default under the revolving credit agreement.
	On January 15, 2015, Cascade issued $25.0 million of Senior Notes with due dates ranging from January 15, 2045 to January 15, 2055 at a weighted average interest rate of 4.2 percent.
	Intermountain Gas Company Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.
	The credit agreement contains customary covenants and provisions, including a covenant of Intermountain not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments.
	Intermountain's credit agreement also contains cross-default provisions. These provisions state that if Intermountain fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, or certain conditions result in an early termination date under any swap contract that is in excess of a specified amount, then Intermountain will be in default under the revolving credit agreement.
	Centennial Energy Holdings, Inc. On May 8, 2014, Centennial entered into an amended and restated revolving credit agreement which increased the borrowing limit to $650.0 million and extended the termination date to May 8, 2019. Centennial's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings.
	Centennial's revolving credit agreement and certain debt outstanding under an expired uncommitted long-term master shelf agreement contain customary covenants and provisions, including a covenant of Centennial, not to permit, as of the end of any fiscal quarter, the ratio of total consolidated debt to total consolidated capitalization to be greater than 65 percent (for the revolving credit agreement) and a covenant of Centennial and certain of its subsidiaries, not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 60 percent (for the master shelf agreement). The master shelf agreement also includes a covenant that does not permit the ratio of Centennial's EBITDA to interest expense, for the 12-month period ended each fiscal quarter, to be less than 1.75 to 1. Other covenants include restrictions on the sale of certain assets, limitations on subsidiary indebtedness, minimum consolidated net worth, limitations on priority debt and the making of certain loans and investments.
	Certain of Centennial's financing agreements contain cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the applicable agreements will be in default.
	On January 9, 2015, Centennial amended its letter of credit agreement for the issuance of up to approximately $28.0 million of letters of credit to extend the termination date to January 11, 2016.
	WBI Energy Transmission, Inc. WBI Energy Transmission has a $175.0 million amended and restated uncommitted long-term private shelf agreement with an expiration date of September 12, 2016. WBI Energy Transmission had $100.0 million of notes outstanding at December 31, 2014, which reduced capacity under this uncommitted private shelf agreement. This agreement contains customary covenants and provisions, including a covenant of WBI Energy Transmission not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 55 percent. Other covenants include a limitation on priority debt and restrictions on the sale of certain assets and the making of certain investments.
	Long-term Debt Outstanding Long-term debt outstanding at December 31 was as follows:
		2014			2013
		(In thousands)
	Senior Notes at a weighted average rate of 5.43%, due on dates ranging from June 19, 2015 to November 24, 2055	$	1,636,662		$	1,545,078
	Commercial paper at a weighted average rate of .37%, supported by revolving credit agreements	288,500			153,924
	Term Loan Agreements at a weighted average rate of 2.12%, due on dates ranging from April 22, 2018 to April 22, 2023	72,000			75,000
	Medium-Term Notes at a weighted average rate of 7.32%, due on dates ranging from September 15, 2027 to March 16, 2029	35,000			35,000
	Other notes at a weighted average rate of 5.23%, due on dates ranging from September 1, 2020 to February 1, 2035	39,662			39,863
	Credit agreements at a weighted average rate of 3.47%, due on dates ranging from February 10, 2015 to November 30, 2038	22,939			5,701
	Discount	(36		)	(3		)
	Total long-term debt	2,094,727			1,854,563
	Less current maturities	269,449			12,277
	Net long-term debt	$	1,825,278		$	1,842,286
	The amounts of scheduled long-term debt maturities for the five years and thereafter following December 31, 2014, aggregate $269.4 million in 2015; $293.8 million in 2016; $51.0 million in 2017; $148.2 million in 2018; $345.7 million in 2019 and $986.6 million thereafter.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Asset retirement obligations	Asset Retirement Obligations
	The Company records obligations related to the plugging and abandonment of oil and natural gas wells, decommissioning of certain electric generating facilities, reclamation of certain aggregate properties, special handling and disposal of hazardous materials at certain electric generating facilities, natural gas distribution facilities and buildings, and certain other obligations as asset retirement obligations.
	A reconciliation of the Company's liability, which is included in other accrued liabilities and other liabilities on the Consolidated Balance Sheets, for the years ended December 31 was as follows:
		2014			2013
		(In thousands)
	Balance at beginning of year	$	98,529		$	102,545
	Liabilities incurred	5,416			5,610
	Liabilities acquired	1,414			—
	Liabilities settled	(18,388		)	(22,257		)
	Accretion expense	4,605			4,574
	Revisions in estimates	884			7,671
	Other	379			386
	Balance at end of year	$	92,839		$	98,529
	The Company believes that largely all expenses related to asset retirement obligations at the Company's regulated operations will be recovered in rates over time and, accordingly, defers such expenses as regulatory assets.
	The fair value of assets that are legally restricted for purposes of settling asset retirement obligations at December 31, 2014 and 2013, was $2.3 million and $4.1 million, respectively. The legally restricted assets consist primarily of money market funds and are reflected in other assets on the Consolidated Balance Sheets.

Preferred_Stocks

Preferred Stocks	12 Months Ended
	Dec. 31, 2014
Class of Stock Disclosures [Abstract]
Preferred stocks	Preferred Stocks
	Preferred stocks at December 31 were as follows:
		2014		2013
	(In thousands, except shares
	and per share amounts)
	Authorized:
	Preferred -
	500,000 shares, cumulative, par value $100, issuable in series
	Preferred stock A -
	1,000,000 shares, cumulative, without par value, issuable in series (none outstanding)
	Preference -
	500,000 shares, cumulative, without par value, issuable in series (none outstanding)
	Outstanding:
	4.50% Series - 100,000 shares	$	10,000	$	10,000
	4.70% Series - 50,000 shares	5,000		5,000
	Total preferred stocks	$	15,000	$	15,000
	For the years 2014, 2013 and 2012, dividends declared on the 4.50% Series and 4.70% Series preferred stocks were $4.50 and $4.70 per share, respectively. The 4.50% Series and 4.70% Series preferred stocks outstanding are subject to redemption, in whole or in part, at the option of the Company with certain limitations on 30 days notice on any quarterly dividend date at a redemption price, plus accrued dividends, of $105 per share and $102 per share, respectively.
	In the event of a voluntary or involuntary liquidation, all preferred stock series holders are entitled to $100 per share, plus accrued dividends.
	The affirmative vote of two-thirds of a series of the Company's outstanding preferred stock is necessary for amendments to the Company's charter or bylaws that adversely affect that series; creation of or increase in the amount of authorized stock ranking senior to that series (or an affirmative majority vote where the authorization relates to a new class of stock that ranks on parity with such series); a voluntary liquidation or sale of substantially all of the Company's assets; a merger or consolidation, with certain exceptions; or the partial retirement of that series of preferred stock when all dividends on that series of preferred stock have not been paid. The consent of the holders of a particular series is not required for such corporate actions if the equivalent vote of all outstanding series of preferred stock voting together has consented to the given action and no particular series is affected differently than any other series.
	Subject to the foregoing, the holders of common stock exclusively possess all voting power. However, if cumulative dividends on preferred stock are in arrears, in whole or in part, for one year, the holders of preferred stock would obtain the right to one vote per share until all dividends in arrears have been paid and current dividends have been declared and set aside.

Common_Stock

Common Stock	12 Months Ended
	Dec. 31, 2014
Class of Stock Disclosures [Abstract]
Common Stock	Common Stock
	For the years 2014, 2013 and 2012, dividends declared on common stock were $.7150, $.6950 and $.6750 per common share, respectively.
	The Stock Purchase Plan provides interested investors the opportunity to make optional cash investments and to reinvest all or a percentage of their cash dividends in shares of the Company's common stock. The K-Plan is partially funded with the Company's common stock. From January 2014 to December 2014, the Stock Purchase Plan and K-Plan, with respect to Company stock, were funded with shares of authorized but unissued common stock. From January 2012 through December 2013, purchases of shares of common stock on the open market were used to fund the Stock Purchase Plan and K-Plan. At December 31, 2014, there were 14.9 million shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan.
	The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on common stock. The declaration and payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by the Company's credit agreements, federal and state laws, and applicable regulatory limitations. In addition, the Company and Centennial are generally restricted to paying dividends out of capital accounts or net assets. The following discusses the most restrictive limitations.
	Pursuant to a covenant under a credit agreement, Centennial may only make distributions to the Company in an amount up to 100 percent of Centennial's consolidated net income after taxes, excluding noncash write-downs, for the immediately preceding fiscal year. Intermountain and Cascade have regulatory limitations on the amount of dividends each can pay. Based on these limitations, approximately $2.3 billion of the net assets of the Company's subsidiaries were restricted from being used to transfer funds to the Company at December 31, 2014. In addition, the Company's credit agreement also contains restrictions on dividend payments. The most restrictive limitation requires the Company not to permit the ratio of funded debt to capitalization (determined with respect to the Company alone, excluding its subsidiaries) to be greater than 65 percent. Based on this limitation, approximately $259 million of the Company's (excluding its subsidiaries) net assets, which represents common stockholders' equity including retained earnings, would be restricted from use for dividend payments at December 31, 2014. In addition, state regulatory commissions may require the Company to maintain certain capitalization ratios. These requirements are not expected to affect the Company's ability to pay dividends in the near term.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2014
Share-based Compensation [Abstract]
Stock-based compensation	Stock-Based Compensation
	The Company has several stock-based compensation plans under which it is currently authorized to grant restricted stock and stock. As of December 31, 2014, there are 5.6 million remaining shares available to grant under these plans. The Company generally issues new shares of common stock to satisfy restricted stock, stock and performance share awards.
	Total stock-based compensation expense (after tax) was $4.4 million, $3.9 million and $4.0 million in 2014, 2013 and 2012, respectively.
	As of December 31, 2014, total remaining unrecognized compensation expense related to stock-based compensation was approximately $8.0 million (before income taxes) which will be amortized over a weighted average period of 1.6 years.
	Stock awards
	Nonemployee directors may receive shares of common stock instead of cash in payment for directors' fees under the nonemployee director stock compensation plan. There were 43,088 shares with a fair value of $1.1 million, 36,713 shares with a fair value of $1.1 million and 53,888 shares with a fair value of $1.1 million issued under this plan during the years ended December 31, 2014, 2013 and 2012, respectively.
	A key employee of the Company received an award of 43,103 shares of common stock under a long-term incentive plan with a fair value of $930,000 during the year ended December 31, 2012.
	Performance share awards
	Since 2003, key employees of the Company have been awarded performance share awards each year. Entitlement to performance shares is based on the Company's total shareholder return over designated performance periods as measured against a selected peer group.
	Target grants of performance shares outstanding at December 31, 2014, were as follows:
	Grant Date	Performance	Target Grant
		Period	of Shares
	Feb-12	2012-2014	251,196
	Mar-13	2013-2015	240,419
	Feb-14	2014-2016	196,840
	Participants may earn from zero to 200 percent of the target grant of shares based on the Company's total shareholder return relative to that of the selected peer group. Compensation expense is based on the grant-date fair value as determined by Monte Carlo simulation. The blended volatility term structure ranges are comprised of 50 percent historical volatility and 50 percent implied volatility. Risk-free interest rates were based on U.S. Treasury security rates in effect as of the grant date. Assumptions used for grants of performance shares issued in 2014, 2013 and 2012 were:
					2014						2013						2012
	Grant-date fair value					$41.13						$29.01						$17.18
	Blended volatility range	18.94	%	–	20.43		%	16.1	%	–	19.39		%	24.29	%	–	25.81		%
	Risk-free interest rate range	0.03	%	–	0.74		%	0.09	%	–	0.4		%	0.1	%	–	0.35		%
	Discounted dividends per share					$2.15						$2.12						$1.19
	The fair value of the performance shares that vested during the year ended December 31, 2014, was $16.6 million. There were no performance shares that vested in 2013 or 2012.
	A summary of the status of the performance share awards for the year ended December 31, 2014, was as follows:
		Number of		Weighted
		Shares		Average
				Grant-Date
				Fair Value
	Nonvested at beginning of period	749,991		$	21.99
	Granted	196,840		41.13
	Additional performance shares earned	236,699		19.99
	Vested	(491,213	)	19.99
	Forfeited	(3,862	)	29.01
	Nonvested at end of period	688,455		$	28.16

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	The components of income (loss) before income taxes from continuing operations for each of the years ended December 31 were as follows:
		2014			2013			2012
					(In thousands)
	United States	$	411,182		$	415,202		$	(47,175	)
	Foreign	(52		)	416			1,708
	Income (loss) before income taxes from continuing operations	$	411,130		$	415,618		$	(45,467	)
	Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:
		2014			2013			2012
					(In thousands)
	Current:
	Federal	$	32,726		$	45,518		$	(26,858	)
	State	5,390			4,311			858
	Foreign	—			(29		)	(75		)
		38,116			49,800			(26,075		)
	Deferred:
	Income taxes:
	Federal	81,017			78,953			(1,224		)
	State	4,989			8,031			(6,323		)
	Investment tax credit - net	1,009			(206		)	44
		87,015			86,778			(7,503		)
	Change in uncertain tax positions	(5,183		)	—			1,974
	Change in accrued interest	21			158			458
	Total income tax expense (benefit)	$	119,969		$	136,736		$	(31,146	)
	Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:
		2014			2013
		(In thousands)
	Deferred tax assets:
	Regulatory matters	$	134,567		$	125,607
	Accrued pension costs	97,690			74,320
	Alternative minimum tax credit carryforward	23,844			33,304
	Compensation-related	38,654			31,550
	Asset retirement obligations	34,296			29,578
	Legal and environmental contingencies	10,049			10,710
	Other	59,389			45,101
	Total deferred tax assets	398,489			350,170
	Deferred tax liabilities:
	Depreciation and basis differences on property, plant and equipment	906,455			813,597
	Basis differences on oil and natural gas producing properties	270,939			266,168
	Regulatory matters	97,521			64,914
	Intangible asset amortization	22,505			13,579
	Other	29,676			26,170
	Total deferred tax liabilities	1,327,096			1,184,428
	Net deferred income tax liability	$	(928,607	)	$	(834,258	)
	As of December 31, 2014 and 2013, no valuation allowance has been recorded associated with the previously identified deferred tax assets. The alternative minimum tax credit carryforwards do not expire.
	The following table reconciles the change in the net deferred income tax liability from December 31, 2013, to December 31, 2014, to deferred income tax expense:
		2014
	(In thousands)
	Change in net deferred income tax liability from the preceding table	$	94,349
	Deferred taxes associated with other comprehensive loss	2,360
	Other	(9,694		)
	Deferred income tax expense for the period	$	87,015
	Total income tax expense (benefit) differs from the amount computed by applying the statutory federal income tax rate to income (loss) before taxes. The reasons for this difference were as follows:
	Years ended December 31,	2014					2013					2012
		Amount			%		Amount			%		Amount			%
		(Dollars in thousands)
	Computed tax at federal statutory rate	$	143,895		35		$	145,466		35		$	(15,914	)	35
	Increases (reductions) resulting from:
	State income taxes, net of federal income tax	10,483			2.5		10,524			2.5		2,469			(5.4	)
	Domestic production activities	(5,460		)	(1.3	)	(677		)	(.2	)	—			—
	Nonqualified benefit plans	(1,624		)	(.4	)	(5,173		)	(1.2	)	(2,359		)	5.2
	Depletion allowance	(4,010		)	(1.0	)	(3,764		)	(.9	)	(3,728		)	8.2
	Federal renewable energy credit	(3,655		)	(.9	)	(3,404		)	(.8	)	(3,401		)	7.5
	Deductible K-Plan dividends	(2,062		)	(.5	)	(1,593		)	(.4	)	(2,829		)	6.2
AFUDC equity	(2,031		)	(.5	)	(1,074		)	(.3	)	(1,500		)	3.3
Resolution of tax matters and uncertain tax positions	(7,367		)	(1.8	)	(859		)	(.2	)	2,559			(5.6	)
Deferred tax rate changes	9			—		741			0.2		(3,083		)	6.8
Other	(8,209		)	(1.9	)	(3,451		)	(.8	)	(3,360		)	7.3
Total income tax expense (benefit)	$	119,969		29.2		$	136,736		32.9		$	(31,146	)	68.5
The income tax benefit in 2012 resulted largely from the Company's write-downs of oil and natural gas properties, as discussed in Note 1.
Deferred income taxes have been accrued with respect to temporary differences related to the Company's foreign operations. The amount of cumulative undistributed earnings for which there are temporary differences is approximately $3.6 million at December 31, 2014. The amount of deferred tax liability, net of allowable foreign tax credits, associated with the undistributed earnings at December 31, 2014, was approximately $1.4 million.
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state, local and foreign jurisdictions. The Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years ending prior to 2007. The Company and the Internal Revenue Service have agreed to a settlement for the 2007 through 2009 tax years.
A reconciliation of the unrecognized tax benefits (excluding interest) for the years ended December 31 was as follows:
	2014			2013			2012
				(In thousands)
Balance at beginning of year	$	14,914		$	14,914		$	11,206
Additions for tax positions of prior years	—			—			3,708
Settlements	(14,777		)	—			—
Balance at end of year	$	137		$	14,914		$	14,914
Included in the balance of unrecognized tax benefits at December 31, 2013, was $8.4 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate was $155,000, including approximately $18,000 for the payment of interest and penalties at December 31, 2014, and was $9.0 million, including approximately $2.5 million for the payment of interest and penalties at December 31, 2013.
It is likely that substantially all of the unrecognized tax benefits, as well as interest, at December 31, 2014, will be settled in the next twelve months.
For the years ended December 31, 2014, 2013 and 2012, the Company recognized approximately $1.8 million, $1.2 million and $740,000, respectively, in interest expense. Penalties were not material in 2014, 2013 and 2012. The Company recognized interest income of approximately $540,000, $660,000 and $290,000 for the years ended December 31, 2014, 2013 and 2012, respectively. The Company had accrued liabilities of approximately $1.8 million and $2.8 million at December 31, 2014 and 2013, respectively, for the payment of interest.

Business_segment_data

Business segment data	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Business segment data	Business Segment Data
	The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The internal reporting of these operating segments is defined based on the reporting and review process used by the Company's chief executive officer. The vast majority of the Company's operations are located within the United States. The Company also has an investment in a foreign country, which consists of Centennial Resources' investment in ECTE. For more information, see Note 4.
	The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added services.
	The pipeline and energy services segment provides natural gas transportation, underground storage, processing and gathering services, as well as oil gathering, through regulated and nonregulated pipeline systems and processing facilities primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment is constructing Dakota Prairie Refinery in conjunction with Calumet to refine crude oil and also provides cathodic protection and other energy-related services.
	The exploration and production segment is engaged in oil and natural gas development and production activities in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States. The Company intends to market its exploration and production business in the future. The plan to market this business has been delayed due to low oil prices.
	The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services. This segment operates in the central, southern and western United States and Alaska and Hawaii.
	The construction services segment specializes in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment.
	The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies' general liability, automobile liability and pollution liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' investment in ECTE.
	The information below follows the same accounting policies as described in the Summary of Significant Accounting Policies. Information on the Company's businesses as of December 31 and for the years then ended was as follows:
		2014			2013			2012
					(In thousands)
	External operating revenues:
	Electric	$	277,874		$	257,260		$	236,895
	Natural gas distribution	921,986			851,945			754,848
	Pipeline and energy services	166,496			155,369			139,883
		1,366,356			1,264,574			1,131,626
	Exploration and production	500,526			490,924			412,651
	Construction materials and contracting	1,740,089			1,675,444			1,597,257
	Construction services	1,062,055			1,029,909			932,013
	Other	1,532			1,553			1,884
		3,304,202			3,197,830			2,943,805
	Total external operating revenues	$	4,670,558		$	4,462,404		$	4,075,431
	Intersegment operating revenues:
	Electric	$	—		$	—		$	—
	Natural gas distribution	—			—			—
	Pipeline and energy services	49,372			46,699			53,274
	Exploration and production	47,045			45,099			35,966
	Construction materials and contracting	25,241			36,693			20,168
	Construction services	57,474			9,930			6,545
	Other	7,832			8,067			8,486
	Intersegment eliminations	(186,964		)	(146,488		)	(124,439		)
	Total intersegment operating revenues	$	—		$	—		$	—
	Depreciation, depletion and amortization:
	Electric	$	35,008		$	32,789		$	32,509
	Natural gas distribution	54,700			50,031			45,731
	Pipeline and energy services	30,645			29,119			27,684
	Exploration and production	198,199			186,458			160,681
	Construction materials and contracting	68,557			74,470			79,527
	Construction services	12,874			11,939			11,063
	Other	2,196			2,050			2,010
	Intersegment eliminations	(811		)	—			—
	Total depreciation, depletion and amortization	$	401,368		$	386,856		$	359,205
		2014			2013			2012
					(In thousands)
	Interest expense:
	Electric	$	15,595		$	12,590		$	12,421
	Natural gas distribution	27,217			25,123			28,726
	Pipeline and energy services	10,048			10,330			7,742
	Exploration and production	13,834			14,315			9,018
	Construction materials and contracting	16,368			17,394			15,211
	Construction services	4,176			4,306			4,435
	Other	15			15			13
	Intersegment eliminations	(237		)	(156		)	(867		)
	Total interest expense	$	87,016		$	83,917		$	76,699
	Income taxes:
	Electric	$	12,442		$	9,683		$	8,975
	Natural gas distribution	11,350			16,633			12,005
	Pipeline and energy services	9,699			3,390			15,291
	Exploration and production	47,739			53,197			(108,264		)
	Construction materials and contracting	18,586			24,765			14,099
	Construction services	24,753			29,504			24,128
	Other	(1,119		)	2,433			2,620
	Intersegment eliminations	(3,481		)	(2,869		)	—
	Total income taxes	$	119,969		$	136,736		$	(31,146	)
Earnings (loss) on common stock:
Electric	$	36,731		$	34,837		$	30,634
Natural gas distribution	30,484			37,656			29,409
Pipeline and energy services	22,628			7,629			26,588
Exploration and production	96,733			94,450			(177,283		)
Construction materials and contracting	51,510			50,946			32,420
Construction services	54,432			52,213			38,429
Other	7,461			5,136			4,797
Intersegment eliminations	(5,608		)	(4,307		)	—
Earnings (loss) on common stock before income (loss)	294,371			278,560			(15,006		)
from discontinued operations
Income (loss) from discontinued operations, net of tax*	3,177			(312		)	13,567
Total earnings (loss) on common stock	$	297,548		$	278,248		$	(1,439	)
Capital expenditures:
Electric	$	185,121		$	168,557		$	112,035
Natural gas distribution	120,613			101,279			130,178
Pipeline and energy services	177,409			127,092			133,787
Exploration and production	600,572			391,315			554,528
Construction materials and contracting	37,896			34,607			45,083
Construction services	26,942			15,102			14,835
Other	2,131			2,249			791
Net proceeds from sale or disposition of property and other	(306,994		)	(112,131		)	(57,460		)
Total net capital expenditures	$	843,690		$	728,070		$	933,777
Assets:
Electric**	$	1,030,611		$	884,283		$	760,324
Natural gas distribution**	1,931,908			1,786,068			1,703,459
Pipeline and energy services	1,081,902			798,701			622,470
Exploration and production	1,738,064			1,616,131			1,539,017
Construction materials and contracting	1,272,231			1,305,808			1,371,252
Construction services	454,602			450,614			429,547
Other***	300,660			219,727			256,422
Total assets	$	7,809,978		$	7,061,332		$	6,682,491
	2014			2013			2012
				(In thousands)
Property, plant and equipment:
Electric**	$	1,457,101		$	1,315,822		$	1,150,584
Natural gas distribution**	1,904,759			1,776,901			1,689,950
Pipeline and energy services	1,220,233			962,172			816,533
Exploration and production	3,402,879			3,060,848			2,764,560
Construction materials and contracting	1,529,942			1,510,355			1,504,981
Construction services	144,395			134,948			130,624
Other	50,937			49,997			50,519
Eliminations	(17,075		)	(7,177		)	—
Less accumulated depreciation, depletion and amortization	4,166,407			3,872,487			3,608,912
Net property, plant and equipment	$	5,526,764		$	4,931,379		$	4,498,839
*	Reflected in the Other category.
**	Includes allocations of common utility property.
***	Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).
Note:	The results reflect $391.8 million ($246.8 million after tax) of noncash write-downs of oil and natural gas properties in 2012.
Excluding the impairments of the coalbed natural gas gathering assets of $9.0 million (after tax) and $1.7 million (after tax) in 2013 and 2012, respectively, and the reversal of the charge related to natural gas gathering operations litigation of $1.5 million (after tax) and $15.0 million (after tax) in 2013 and 2012, respectively, as discussed in Notes 1 and 19, respectively, earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from exploration and production, construction materials and contracting, construction services and other are all from nonregulated operations.
Capital expenditures for 2014, 2013 and 2012 include noncash capital expenditure-related accounts payable and exclude capital expenditures of the noncontrolling interest related to Dakota Prairie Refinery. The net transactions were $(61.2) million in 2014, $(56.8) million in 2013 and $33.7 million in 2012.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Employee Benefit Plans	Employee Benefit Plans
	Pension and other postretirement benefit plans
	The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans.
	Defined pension plan benefits to all nonunion and certain union employees hired after December 31, 2005, were discontinued. In 2010, all benefit and service accruals for nonunion and certain union plans were frozen. In 2011 and 2012, all benefit and service accruals for certain additional union employees were frozen. These employees will be eligible to receive additional defined contribution plan benefits.
	Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company's businesses. Employees who had attained age 55 with 10 years of continuous service by December 31, 2010, will be provided the current retiree medical insurance benefits or can elect the new benefit, if desired, regardless of when they retire. All other current employees must meet the new eligibility criteria of age 60 and 10 years of continuous service at the time they retire. These employees will be eligible for a specified company funded Retiree Reimbursement Account. Employees hired after December 31, 2009, will not be eligible for retiree medical benefits at certain of the Company's businesses.
	In 2012, the Company modified health care coverage for certain retirees. Effective January 1, 2013, post-65 coverage was replaced by a fixed-dollar subsidy for retirees and spouses to be used to purchase individual insurance through an exchange.
	Changes in benefit obligation and plan assets for the years ended December 31, 2014 and 2013, and amounts recognized in the Consolidated Balance Sheets at December 31, 2014 and 2013, were as follows:
		Pension Benefits						Other
								Postretirement Benefits
		2014			2013			2014			2013
		(In thousands)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	402,772		$	459,111		$	81,726		$	103,358
	Service cost	129			155			1,518			1,675
	Interest cost	17,682			16,249			3,521			3,215
	Plan participants' contributions	—			—			1,399			1,472
	Actuarial (gain) loss	80,520			(44,551		)	18,024			(20,985		)
	Benefits paid	(25,766		)	(28,192		)	(7,176		)	(7,009		)
	Benefit obligation at end of year	475,337			402,772			99,012			81,726
	Change in net plan assets:
	Fair value of plan assets at beginning of year	334,844			309,184			84,543			74,361
	Actual gain on plan assets	24,500			35,539			7,527			13,819
	Employer contribution	20,785			18,313			1,293			1,900
	Plan participants' contributions	—			—			1,399			1,472
	Benefits paid	(25,766		)	(28,192		)	(7,176		)	(7,009		)
	Fair value of net plan assets at end of year	354,363			334,844			87,586			84,543
	Funded status - (under) over	$	(120,974	)	$	(67,928	)	$	(11,426	)	$	2,817
	Amounts recognized in the Consolidated
	Balance Sheets at December 31:
	Other assets (noncurrent)	$	—		$	—		$	4,345		$	9,679
	Other accrued liabilities (current)	—			—			(322		)	(381		)
	Other liabilities (noncurrent)	(120,974		)	(67,928		)	(15,449		)	(6,481		)
	Net amount recognized	$	(120,974	)	$	(67,928	)	$	(11,426	)	$	2,817
	Amounts recognized in accumulated other
	comprehensive (income) loss consist of:
	Actuarial loss	$	207,430		$	135,061		$	25,779		$	11,314
	Prior service cost (credit)	294			365			(15,744		)	(17,137		)
	Total	$	207,724		$	135,426		$	10,035		$	(5,823	)
	Employer contributions and benefits paid in the preceding table include only those amounts contributed directly to, or paid directly from, plan assets. Accumulated other comprehensive (income) loss in the above table includes amounts related to regulated operations, which are recorded as regulatory assets (liabilities) and are expected to be reflected in rates charged to customers over time. For more information on regulatory assets (liabilities), see Note 6.
	Unrecognized pension actuarial losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets are amortized on a straight-line basis over the expected average remaining service lives of active participants for non-frozen plans and over the average life expectancy of plan participants for frozen plans. The market-related value of assets is determined using a five-year average of assets. Unrecognized postretirement net transition obligation was amortized over a 20-year period ending 2012.
	The pension plans all have accumulated benefit obligations in excess of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for these plans at December 31 were as follows:
		2014			2013
		(In thousands)
	Projected benefit obligation	$	475,337		$	402,772
	Accumulated benefit obligation	$	475,337		$	402,772
	Fair value of plan assets	$	354,363		$	334,844
	Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows:
		Pension Benefits									Other
											Postretirement Benefits
		2014			2013			2012			2014			2013			2012
		(In thousands)
	Components of net periodic benefit cost (credit):
	Service cost	$	129		$	155		$	1,078		$	1,518		$	1,675		$	1,747
	Interest cost	17,682			16,249			17,598			3,521			3,215			4,166
	Expected return on assets	(21,218		)	(19,917		)	(23,536		)	(4,617		)	(4,343		)	(4,890		)
	Amortization of prior service cost (credit)	71			71			(46		)	(1,393		)	(1,457		)	(1,438		)
	Recognized net actuarial loss	4,869			7,173			7,070			649			1,814			2,134
	Curtailment gain	—			—			(1,023		)	—			—			—
	Amortization of net transition obligation	—			—			—			—			—			2,128
	Net periodic benefit cost (credit), including amount capitalized	1,533			3,731			1,141			(322		)	904			3,847
	Less amount capitalized	388			727			937			(21		)	164			910
	Net periodic benefit cost (credit)	1,145			3,004			204			(301		)	740			2,937
	Other changes in plan assets and benefit
	obligations recognized in accumulated other
comprehensive (income) loss:
Net (gain) loss	77,238			(60,173		)	19,982			15,114			(30,461		)	1,863
Prior service credit	—			—			—			—			—			(11,418		)
Amortization of actuarial loss	(4,869		)	(7,173		)	(7,070		)	(649		)	(1,814		)	(2,134		)
Amortization of prior service (cost) credit	(71		)	(71		)	1,069			1,393			1,457			1,438
Amortization of net transition obligation	—			—			—			—			—			(2,128		)
Total recognized in accumulated other	72,298			(67,417		)	13,981			15,858			(30,818		)	(12,379		)
comprehensive (income) loss
Total recognized in net periodic benefit cost (credit) and	$	73,443		$	(64,413	)	$	14,185		$	15,557		$	(30,078	)	$	(9,442	)
accumulated other comprehensive (income) loss
The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2015 are $7.1 million and $71,000, respectively. The estimated net loss and prior service credit for the other postretirement benefit plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2015 are $1.8 million and $1.4 million, respectively. Prior service cost is amortized on a straight line basis over the average remaining service period of active participants.
Weighted average assumptions used to determine benefit obligations at December 31 were as follows:
	Pension Benefits				Other
					Postretirement Benefits
	2014		2013		2014		2013
Discount rate	3.7	%	4.53	%	3.74	%	4.48	%
Expected return on plan assets	7	%	7	%	6	%	6	%
Rate of compensation increase	N/A		N/A		3	%	3	%
Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows:
	Pension Benefits				Other
					Postretirement Benefits
	2014		2013		2014		2013
Discount rate	4.53	%	3.65	%	4.48	%	3.67	%
Expected return on plan assets	7	%	7	%	6	%	6	%
Rate of compensation increase	N/A		N/A		3	%	4	%
The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2014, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 40 percent to 50 percent equity securities and 50 percent to 60 percent fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 65 percent to 75 percent equity securities and 25 percent to 35 percent fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.
Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:
				2014					2013
Health care trend rate assumed for next year	4	%	–	7	%	6	%	–	7	%
Health care cost trend rate - ultimate	5	%	–	6	%	5	%	–	6	%
Year in which ultimate trend rate achieved				2017					2017
The Company's other postretirement benefit plans include health care and life insurance benefits for certain retirees. The plans underlying these benefits may require contributions by the retiree depending on such retiree's age and years of service at retirement or the date of retirement. The accounting for the health care plans anticipates future cost-sharing changes that are consistent with the Company's expressed intent to generally increase retiree contributions each year by the excess of the expected health care cost trend rate over six percent.
Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates would have had the following effects at December 31, 2014:
	1 Percentage			1 Percentage
	Point Increase			Point Decrease
	(In thousands)
Effect on total of service and interest cost components	$	247		$	(207	)
Effect on postretirement benefit obligation	$	4,489		$	(3,832	)
The Company's pension assets are managed by 15 outside investment managers. The Company's other postretirement assets are managed by one outside investment manager. The Company's investment policy with respect to pension and other postretirement assets is to make investments solely in the interest of the participants and beneficiaries of the plans and for the exclusive purpose of providing benefits accrued and defraying the reasonable expenses of administration. The Company strives to maintain investment diversification to assist in minimizing the risk of large losses. The Company's policy guidelines allow for investment of funds in cash equivalents, fixed-income securities and equity securities. The guidelines prohibit investment in commodities and futures contracts, equity private placement, employer securities, leveraged or derivative securities, options, direct real estate investments, precious metals, venture capital and limited partnerships. The guidelines also prohibit short selling and margin transactions. The Company's practice is to periodically review and rebalance asset categories based on its targeted asset allocation percentage policy.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs.
The estimated fair values of the Company's pension plans' assets are determined using the market approach.
The carrying value of the pension plans' Level 2 cash equivalents approximates fair value and is determined using observable inputs in active markets or the net asset value of shares held at year end, which is determined using other observable inputs including pricing from outside sources. Units of this fund can be redeemed on a daily basis at their net asset value and have no redemption restrictions. The assets are invested in high quality, short-term instruments of domestic and foreign issuers. There are no unfunded commitments related to this fund.
The estimated fair value of the pension plans' Level 1 equity securities is based on the closing price reported on the active market on which the individual securities are traded.
The estimated fair value of the pension plans' Level 1 and Level 2 collective and mutual funds are based on the net asset value of shares held at year end, based on either published market quotations on active markets or other known sources including pricing from outside sources. Units of these funds can be redeemed on a daily basis at their net asset value and have no redemption restrictions. There are no unfunded commitments related to these funds.
The estimated fair value of the pension plans' Level 2 corporate and municipal bonds is determined using other observable inputs, including benchmark yields, reported trades, broker/dealer quotes, bids, offers, future cash flows and other reference data.
The estimated fair value of the pension plans' Level 1 U.S. Government securities are valued based on quoted prices on an active market.
The estimated fair value of the pension plans' Level 2 U.S. Government securities are valued mainly using other observable inputs, including benchmark yields, reported trades, broker/dealer quotes, bids, offers, to be announced prices, future cash flows and other reference data. Some of these securities are valued using pricing from outside sources.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2014 and 2013, there were no transfers between Levels 1 and 2.
The fair value of the Company's pension plans' assets (excluding cash) by class were as follows:
	Fair Value Measurements
	at December 31, 2014, Using
	Quoted Prices			Significant			Significant Unobservable			Balance at December 31, 2014
	in Active			Other			Inputs
	Markets for			Observable			(Level 3)
	Identical			Inputs
	Assets			(Level 2)
	(Level 1)
	(In thousands)
Assets:
Cash equivalents	$	—		$	5,631		$	—		$	5,631
Equity securities:
U.S. companies	39,077			—			—			39,077
International companies	5,189			—			—			5,189
Collective and mutual funds*	132,403			77,449			—			209,852
Corporate bonds	—			59,471			—			59,471
Municipal bonds	—			10,462			—			10,462
U.S. Government securities	15,001			6,849			—			21,850
Total assets measured at fair value	$	191,670		$	159,862		$	—		$	351,532
*	Collective and mutual funds invest approximately 13 percent in common stock of large-cap U.S. companies, 13 percent in U.S. Government securities, 23 percent in corporate bonds, 33 percent in common stock of international companies and 18 percent in other investments.
	Fair Value Measurements
	at December 31, 2013, Using
	Quoted Prices			Significant			Significant Unobservable			Balance at December 31, 2013
	in Active			Other			Inputs
	Markets for			Observable			(Level 3)
	Identical			Inputs
	Assets			(Level 2)
	(Level 1)
	(In thousands)
Assets:
Cash equivalents	$	—		$	9,406		$	—		$	9,406
Equity securities:
U.S. companies	62,599			—			—			62,599
International companies	39,437			—			—			39,437
Collective and mutual funds*	116,265			42,483			—			158,748
Corporate bonds	—			42,721			—			42,721
Municipal bonds	—			7,561			—			7,561
U.S. Government securities	7,487			4,335			—			11,822
Total assets measured at fair value	$	225,788		$	106,506		$	—		$	332,294
*	Collective and mutual funds invest approximately 11 percent in common stock of mid-cap U.S. companies, 19 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Government securities, 27 percent in corporate bonds, 13 percent in common stock of international companies and 18 percent in other investments.
The estimated fair values of the Company's other postretirement benefit plans' assets are determined using the market approach.
The estimated fair value of the other postretirement benefit plans' Level 2 cash equivalents is valued at the net asset value of shares held at year end, based on published market quotations on active markets, or using other known sources including pricing from outside sources. Units of this fund can be redeemed on a daily basis at their net asset value and have no redemption restrictions. The assets are invested in high-quality, short-term money market instruments that consist of municipal obligations. There are no unfunded commitments related to this fund.
The estimated fair value of the other postretirement benefit plans' Level 1 equity securities is based on the closing price reported on the active market on which the individual securities are traded.
The estimated fair value of the other postretirement benefit plans' Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2014 and 2013, there were no transfers between Levels 1 and 2.
The fair value of the Company's other postretirement benefit plans' assets (excluding cash) by asset class were as follows:
	Fair Value Measurements
	at December 31, 2014, Using
	Quoted Prices			Significant			Significant Unobservable			Balance at December 31, 2014
	in Active			Other			Inputs
	Markets for			Observable			(Level 3)
	Identical			Inputs
	Assets			(Level 2)
	(Level 1)
	(In thousands)
Assets:
Cash equivalents	$	—		$	2,097		$	—		$	2,097
Equity securities:
U.S. companies	2,614			—			—			2,614
International companies	25			—			—			25
Insurance contract*	—			82,846			—			82,846
Total assets measured at fair value	$	2,639		$	84,943		$	—		$	87,582
*The insurance contract invests approximately 54 percent in common stock of large-cap U.S. companies, 11 percent in U.S. Government securities, 10 percent in mortgage-backed securities, 10 percent in corporate bonds and 15 percent in other investments.
	Fair Value Measurements
	at December 31, 2013, Using
	Quoted Prices			Significant			Significant Unobservable			Balance at December 31, 2013
	in Active			Other			Inputs
	Markets for			Observable			(Level 3)
	Identical			Inputs
	Assets			(Level 2)
	(Level 1)
	(In thousands)
Assets:
Cash equivalents	$	—		$	2,142		$	—		$	2,142
Equity securities:
U.S. companies	2,802			—			—			2,802
International companies	221			—			—			221
Insurance contract*	—			79,374			—			79,374
Total assets measured at fair value	$	3,023		$	81,516		$	—		$	84,539
*	The insurance contract invests approximately 55 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Government securities, 8 percent in mortgage-backed securities, 8 percent in common stock of mid-cap U.S. companies, 9 percent in corporate bonds and 8 percent in other investments.
The Company expects to contribute approximately $3.9 million to its defined benefit pension plans and approximately $400,000 to its postretirement benefit plans in 2015.
The following benefit payments, which reflect future service, as appropriate, and expected Medicare Part D subsidies are as follows:
Years	Pension			Other			Expected
	Benefits			Postretirement Benefits			Medicare
							Part D Subsidy
				(In thousands)
2015	$	23,769		$	5,162		$	218
2016	24,025			5,186			213
2017	24,621			5,262			207
2018	25,064			5,329			200
2019	25,498			5,344			193
2020 - 2024	133,935			26,714			836
Nonqualified benefit plans
In addition to the qualified plan defined pension benefits reflected in the table at the beginning of this note, the Company also has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for these plans was $6.6 million, $7.3 million and $8.1 million in 2014, 2013 and 2012, respectively. The total projected benefit obligation for these plans was $115.6 million and $106.9 million at December 31, 2014 and 2013, respectively. The accumulated benefit obligation for these plans was $108.2 million and $99.7 million at December 31, 2014 and 2013, respectively. A weighted average discount rate of 3.51 percent and 4.32 percent at December 31, 2014 and 2013, respectively, and a rate of compensation increase of 4.00 percent and 4.00 percent at December 31, 2014 and 2013, were used to determine benefit obligations. A discount rate of 4.32 percent and 3.44 percent at December 31, 2014 and 2013, respectively, and a rate of compensation increase of 4.00 percent and 3.00 percent at December 31, 2014 and 2013, were used to determine net periodic benefit cost.
The amount of benefit payments for the unfunded, nonqualified benefit plans are expected to aggregate $6.6 million in 2015; $6.5 million in 2016; $6.7 million in 2017; $7.1 million in 2018; $7.3 million in 2019 and $37.9 million for the years 2020 through 2024.
In 2012, the Company established a nonqualified defined contribution plan for certain key management employees. Expenses incurred under this plan for 2014 and 2013 were $104,000 and $25,000, respectively.
The Company had investments of $101.4 million and $98.1 million at December 31, 2014 and 2013, respectively, consisting of equity securities of $54.9 million and $53.5 million, respectively, life insurance carried on plan participants (payable upon the employee's death) of $32.8 million and $31.4 million, respectively, and other investments of $13.7 million and $13.2 million, respectively. The Company anticipates using these investments to satisfy obligations under these plans.
Defined contribution plans
The Company sponsors various defined contribution plans for eligible employees and the costs incurred under these plans were $34.4 million in 2014, $33.2 million in 2013 and $29.3 million in 2012.
Multiemployer plans
The Company contributes to a number of multiemployer defined benefit pension plans under the terms of collective-bargaining agreements that cover its union-represented employees. The risks of participating in these multiemployer plans are different from single-employer plans in the following aspects:
•	Assets contributed to the MEPP by one employer may be used to provide benefits to employees of other participating employers
•	If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers
•	If the Company chooses to stop participating in some of its MEPPs, the Company may be required to pay those plans an amount based on the underfunded status of the plan, referred to as a withdrawal liability
The Company's participation in these plans is outlined in the following table. Unless otherwise noted, the most recent Pension Protection Act zone status available in 2014 and 2013 is for the plan's year-end at December 31, 2013, and December 31, 2012, respectively. The zone status is based on information that the Company received from the plan and is certified by the plan's actuary. Among other factors, plans in the red zone are generally less than 65 percent funded, plans in the yellow zone are between 65 percent and 80 percent funded, and plans in the green zone are at least 80 percent funded.
	EIN/Pension Plan Number	Pension Protection Act Zone Status				FIP/RP Status Pending/Implemented	Contributions									Surcharge Imposed	Expiration Date of Collective Bargaining Agreement
Pension Fund		2014		2013			2014			2013			2012
							(In thousands)
Edison Pension Plan	93-6061681-001	Green as of 12/31/2014		Green as of 12/31/2013		No	$	9,061		$	6,358		$	5,171		No	12/31/2014*
IBEW Local 38 Pension Plan	34-6574238-001	Yellow as of 4/30/2014		Yellow as of 4/30/2013		Implemented	777			1,041			2,771			No	4/23/17
IBEW Local No. 82 Pension Plan	31-6127268-001	Red as of 6/30/2014		Red as of 6/30/2013		Implemented	1,392			1,284			1,093			No	11/29/15
IBEW Local No. 246 Pension Plan	34-6582842-001	Yellow as of 5/31/2014		Yellow as of 5/31/2013		Implemented	694			1,848			1			No	10/31/17
IBEW Local 648 Pension Plan	31-6134845-001	Red as of 2/28/2014		Red as of 2/28/2013		Implemented	1,110			1,489			564			No	8/31/15
Laborers Pension Trust Fund for Northern California	94-6277608-001	Yellow as of 5/31/2014		Yellow as of 5/31/2013		Implemented	663			921			567			No	6/30/16
National Electrical Benefit Fund	53-0181657-001	Green		Green		No	6,476			5,883			5,603			No	11/30/19
OE Pension Trust Fund	94-6090764-001	Red as of 12/31/2014		Yellow		Implemented	1,445			1,510			1,156			No	6/15/2015–
																	6/30/16
Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan	83-6011320-001	Red as of 12/31/2014		Red as of 12/31/2013		Implemented	68			76			91			No	10/31/2005*
for Wyoming**
Operating Engineers Pension Trust	95-6032478-001	Red as of 6/30/2014		Red as of 6/30/2013		Implemented	612			493			761			No	7/1/16
Sheet Metal Workers' Pension Plan of Southern CA, AZ and NV	95-6052257-001	Red as of 12/31/2014		Red as of 12/31/2013		Implemented	676			512			467			No	6/30/15
Southwest Marine Pension Trust	95-6123404-001	Red as of 12/31/2014		Red as of 12/31/2013		Implemented	31			42			76			No	1/31/2014*–
																	1/31/19
Other funds							19,812			17,803			16,458
Total contributions							$	42,817		$	39,260		$	34,779
*	Plan includes collective bargaining agreements which have expired. The agreements contain provisions that automatically renew the existing contracts in lieu of a new negotiated collective bargaining agreement.
**	The Company withdrew from the plan as of October 26, 2014, as discussed below.
The Company was listed in the plans' Forms 5500 as providing more than 5 percent of the total contributions for the following plans and plan years:
Pension Fund	Year Contributions to Plan Exceeded More Than 5 Percent
	of Total Contributions (as of December 31 of the Plan's Year-End)
Edison Pension Plan	2013 and 2012
IBEW Local 38 Pension Plan	2012
IBEW Local No. 82 Pension Plan	2013 and 2012
Local Union No. 124 IBEW Pension Trust Fund	2013 and 2012
Local Union 212 IBEW Pension Trust Fund	2013 and 2012
IBEW Local Union No. 357 Pension Plan A	2013 and 2012
IBEW Local 648 Pension Plan	2013 and 2012
Idaho Plumbers and Pipefitters Pension Plan	2012
Minnesota Teamsters Construction Division Pension Fund	2013 and 2012
Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming*	2013 and 2012
Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525	2013 and 2012
*	The Company withdrew from the plan as of October 26, 2014, as discussed below.
On September 24, 2014, Knife River provided notice to the Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming that it was withdrawing from the plan effective October 26, 2014. The plan administrator will determine Knife River's withdrawal liability, which the Company currently estimates at approximately $14 million (approximately $8.4 million after tax). The assessed withdrawal liability for this plan may be significantly different from the current estimate.
The Company also contributes to a number of multiemployer other postretirement plans under the terms of collective-bargaining agreements that cover its union-represented employees. These plans provide benefits such as health insurance, disability insurance and life insurance to retired union employees. Many of the multiemployer other postretirement plans are combined with active multiemployer health and welfare plans. The Company's total contributions to its multiemployer other postretirement plans, which also includes contributions to active multiemployer health and welfare plans, were $34.6 million, $37.1 million and $31.4 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Amounts contributed in 2014, 2013 and 2012 to defined contribution multiemployer plans were $22.0 million, $20.6 million and $18.7 million, respectively.

Jointly_owned_facilities

Jointly owned facilities	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Jointly owned facilities	Jointly Owned Facilities
	The consolidated financial statements include the Company's ownership interests in the assets, liabilities and expenses of the Big Stone Station, Coyote Station and Wygen III. Each owner of the stations is responsible for financing its investment in the jointly owned facilities.
	The Company's share of the stations operating expenses was reflected in the appropriate categories of operating expenses (fuel, operation and maintenance and taxes, other than income) in the Consolidated Statements of Income.
	At December 31, the Company's share of the cost of utility plant in service and related accumulated depreciation for the stations was as follows:
		2014		2013
		(In thousands)
	Big Stone Station:
	Utility plant in service	$	64,283	$	63,890
	Less accumulated depreciation	43,043		41,323
		$	21,240	$	22,567
	Coyote Station:
	Utility plant in service	$	138,810	$	138,261
	Less accumulated depreciation	94,443		89,528
		$	44,367	$	48,733
	Wygen III:
	Utility plant in service	$	65,597	$	64,332
	Less accumulated depreciation	5,928		4,639
		$	59,669	$	59,693

Regulatory_Matters_and_Revenue

Regulatory Matters and Revenues Subject to Refund	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Regulatory matters and revenues subject to refund	Regulatory Matters and Revenues Subject to Refund
	On August 11, 2014, Montana-Dakota filed an application with the MTPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $3.0 million annually or approximately 3.6 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, depreciation and taxes associated with the increased investment as well as an increase in Montana-Dakota's operation and maintenance expenses. On February 3, 2015, the MTPSC approved an interim increase of $2.0 million or approximately 2.3 percent, subject to refund, to be effective with service rendered on and after February 6, 2015. The MTPSC has scheduled a hearing for this matter on March 25, 2015.
	On October 3, 2014, Montana-Dakota filed an application with the WYPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $788,000 annually or approximately 4.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities and the associated operation and maintenance expenses, depreciation and taxes associated with the increase in investment. The WYPSC has scheduled a hearing for this matter on May 19, 2015.
	On November 14, 2014, Montana-Dakota filed an application with the NDPSC for approval to implement the rate adjustment associated with the electric generation resource recovery rider approved by the NDPSC on August 20, 2014. On January 7, 2015, the NDPSC approved the rate adjustments of $5.3 million annually to be effective with service rendered on and after January 9, 2015.
	On December 22, 2014, Montana-Dakota filed an application for advance determination of prudence and a certificate of public convenience and necessity with the NDPSC for the Thunder Spirit Wind project. This project will provide energy, capacity and renewable energy credits to Montana-Dakota's electric customers in North Dakota, Montana and South Dakota.
	On February 6, 2015, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $4.3 million annually or approximately 3.4 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, depreciation and taxes associated with the increased investment as well as an increase in Montana-Dakota's operation and maintenance expenses. Montana-Dakota requested an interim increase of $4.3 million or 3.4 percent, subject to refund. This matter is pending before the NDPSC.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss. The Company had accrued liabilities of $27.6 million and $29.5 million for contingencies, including litigation, production taxes, royalty claims and environmental matters at December 31, 2014 and 2013, respectively, which include amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note.
	Litigation
	Construction Materials Until the fall of 2011 when it discontinued active mining operations at the pit, JTL operated the Target Range Gravel Pit in Missoula County, Montana under a 1975 reclamation contract pursuant to the Montana Opencut Mining Act. In September 2009, the Montana DEQ sent a letter asserting JTL was in violation of the Montana Opencut Mining Act by conducting mining operations outside a permitted area. JTL filed a complaint in Montana First Judicial District Court in June 2010, seeking a declaratory order that the reclamation contract is a valid permit under the Montana Opencut Mining Act. The Montana DEQ filed an answer and counterclaim to the complaint in August 2011, alleging JTL was in violation of the Montana Opencut Mining Act and requesting imposition of penalties of not more than $3.7 million plus not more than $5,000 per day from the date of the counterclaim. The Company believes the operation of the Target Range Gravel Pit was conducted under a valid permit; however, the imposition of civil penalties is reasonably possible. The Company filed an application for amendment of its opencut mining permit and intends to resolve this matter through settlement or continuation of the Montana First Judicial District Court litigation.
	Former Employee Litigation On August 6, 2012, a former employee and his spouse filed actions against Connolly-Pacific and others in California Superior Court alleging the former employee contracted acute myelogenous leukemia from exposure to substances while employed as a seaman by the defendants. The plaintiffs request compensatory damages of approximately $23.8 million plus punitive damages, costs and interest. Connolly-Pacific is contesting the claims and believes it has meritorious defenses to them. Connolly-Pacific will seek insurance coverage for defense costs and any liability incurred in the litigation.
	Natural Gas Gathering Operations In January 2010, SourceGas filed an application with the Colorado State District Court to compel WBI Energy Midstream to arbitrate a dispute regarding operating pressures under a natural gas gathering contract on one of WBI Energy Midstream's pipeline gathering systems in Montana. WBI Energy Midstream resisted the application and sought a declaratory order interpreting the gathering contract. In May 2010, the Colorado State District Court granted the application and ordered WBI Energy Midstream into arbitration. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. As a result, WBI Energy Midstream, which is included in the pipeline and energy services segment, recorded a $26.6 million charge ($16.5 million after tax) in the third quarter of 2010. On April 20, 2011, the Colorado State District Court confirmed the arbitration award as a court judgment. WBI Energy Midstream filed an appeal from the Colorado State District Court's order and judgment to the Colorado Court of Appeals. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. As a result of the Colorado Court of Appeals decision, in the second quarter of 2012, WBI Energy Midstream changed its estimated loss related to this matter. This resulted in a reduction of expense of $24.1 million ($15.0 million after tax), which was largely reflected in operation and maintenance expense on the Consolidated Statements of Income. On August 2, 2012, SourceGas filed a petition for writ of certiorari with the Colorado Supreme Court for review of the Colorado Court of Appeals decision which was denied on July 22, 2013. On remand of the matter to the Colorado State District Court, SourceGas may assert claims similar to those asserted in the arbitration proceeding.
	In a related matter, Omimex filed a complaint against WBI Energy Midstream in Montana Seventeenth Judicial District Court in July 2010 alleging WBI Energy Midstream breached a separate gathering contract with Omimex as a result of the increased operating pressures demanded by SourceGas on the same natural gas gathering system. In December 2011, Omimex filed an amended complaint alleging WBI Energy Midstream breached obligations to operate its gathering system as a common carrier under United States and Montana law. WBI Energy Midstream removed the action to the United States District Court for the District of Montana. The parties subsequently settled the breach of contract claim and, subject to final determination on liability, stipulated to the damages on the common carrier claim, for amounts that are not material. A trial on the common carrier claim was held during July 2013. On December 9, 2014, the United States District Court for the District of Montana issued an order determining WBI Energy Midstream breached its obligations as a common carrier and ordered judgment in favor of Omimex for the amount of the stipulated damages. WBI Energy Midstream filed an appeal from the United States District Court for the District of Montana's order and judgment.
	Exploration and Production During the ordinary course of its business, Fidelity is subject to audit for various production related taxes by certain state and federal tax authorities for varying periods as well as claims for royalty obligations under lease agreements for oil and gas production. Disputes may exist regarding facts and questions of law relating to the tax and royalty obligations.
	On May 15, 2013, Austin Holdings, LLC filed an action against Fidelity in Wyoming State District Court alleging Fidelity violated the Wyoming Royalty Payment Act and implied lease covenants by deducting production costs from and by failing to properly report and pay royalties for coalbed methane gas production in Wyoming. The plaintiff, in addition to declaratory and injunctive relief, seeks class certification for similarly situated persons and an unspecified amount of monetary damages on behalf of the class for unpaid royalties, interest, reporting violations and attorney fees. The Company reached a settlement of the matter, subject to court approval, for an amount that is not material.
	The Company also is subject to other litigation, and actual and potential claims in the ordinary course of its business which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. Accruals are based on the best information available but actual losses in future periods are affected by various factors making them uncertain. After taking into account liabilities accrued for the foregoing matters, management believes that the outcomes with respect to the above issues and other probable and reasonably possible losses in excess of the amounts accrued, while uncertain, will not have a material effect upon the Company's financial position, results of operations or cash flows.
	Environmental matters
	Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include Knife River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. Knife River - Northwest also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Portland Harbor Natural Resource Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.
	Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, Knife River - Northwest does not believe it is a Responsible Party. In addition, Knife River - Northwest has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement. Knife River - Northwest has entered into an agreement tolling the statute of limitations in connection with the LWG's potential claim for contribution to the costs of the remedial investigation and feasibility study. By letter in March 2009, LWG stated its intent to file suit against Knife River - Northwest and others to recover LWG's investigation costs to the extent Knife River - Northwest cannot demonstrate its non-liability for the contamination or is unwilling to participate in an alternative dispute resolution process that has been established to address the matter. At this time, Knife River - Northwest has agreed to participate in the alternative dispute resolution process.
	The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced administrative action.
	Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade's predecessors.
	The first claim is for contamination at a site in Eugene, Oregon which was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. The Oregon DEQ released a ROD in January 2015 that selected a remediation alternative for the site as recommended in an earlier staff report. It is not known at this time what share of the cleanup costs will actually be borne by Cascade; however, Cascade anticipates its proportional share could be approximately 50 percent. Cascade has accrued $1.7 million for remediation of this site. In January 2013, the OPUC approved Cascade's application to defer environmental remediation costs at the Eugene site for a period of 12 months starting November 30, 2012. Cascade received orders reauthorizing the deferred accounting for the 12-month periods starting November 30, 2013 and December 1, 2014.
	The second claim is for contamination at a site in Bremerton, Washington which was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to $6.4 million. Data developed through the assessment and previous investigations indicates the contamination likely derived from multiple, different sources and multiple current and former owners of properties and businesses in the vicinity of the site may be responsible for the contamination. In April 2010, the Washington Department of Ecology issued notice it considered Cascade a PRP for hazardous substances at the site. In May 2012, the EPA added the site to the National Priorities List of Superfund sites. Cascade has entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. Cascade has accrued $12.5 million for the remedial investigation, feasibility study and remediation of this site. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.
	The third claim is for contamination at a site in Bellingham, Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade and its predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. Other PRPs have reached an agreed order and work plan with the Washington Department of Ecology for completion of a remedial investigation and feasibility study for the site. A report documenting the initial phase of the remedial investigation was completed in June 2011. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim although Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, it converted the plant to a propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas.
	Cascade has received notices from and entered into agreement with certain of its insurance carriers that they will participate in defense of Cascade for these contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers. The accruals related to these matters are reflected in regulatory assets. For more information, see Note 6.
	Operating leases
	The Company leases certain equipment, facilities and land under operating lease agreements. The amounts of annual minimum lease payments due under these leases as of December 31, 2014, were $48.1 million in 2015, $43.5 million in 2016, $34.3 million in 2017, $28.1 million in 2018, $19.7 million in 2019 and $78.7 million thereafter. Rent expense was $53.7 million, $48.1 million and $42.9 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Purchase commitments
	The Company has entered into various commitments, largely construction, natural gas and coal supply, purchased power, natural gas transportation and storage, service, shipping and construction materials supply contracts, some of which are subject to variability in volume and price, and a purchase agreement of electric wind generation. These commitments range from one to 46 years. The commitments under these contracts as of December 31, 2014, were $694.7 million in 2015, $304.6 million in 2016, $161.0 million in 2017, $91.0 million in 2018, $86.4 million in 2019 and $910.6 million thereafter. These commitments were not reflected in the Company's consolidated financial statements. Amounts purchased under various commitments for the years ended December 31, 2014, 2013 and 2012, were $925.2 million, $861.8 million and $718.4 million, respectively.
	Guarantees
	In connection with the sale of the Brazilian Transmission Lines, as discussed in Note 4, Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines.
	WBI Holdings has guaranteed certain of Fidelity's oil and natural gas swap agreement obligations. There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices. The amount of derivative activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap agreements at December 31, 2014, expire in the year 2015; however, Fidelity may continue to enter into additional derivative instruments and, as a result, WBI Holdings from time to time may issue additional guarantees on these derivative instruments. There were no amounts outstanding by Fidelity at December 31, 2014. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees.
	Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts and certain other guarantees. At December 31, 2014, the fixed maximum amounts guaranteed under these agreements aggregated $86.7 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $66.9 million in 2015; $700,000 in 2016; $600,000 in 2017; $500,000 in 2018; $500,000 in 2019; $13.5 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $200,000 and was reflected on the Consolidated Balance Sheet at December 31, 2014. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.
	Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At December 31, 2014, the fixed maximum amounts guaranteed under these letters of credit, aggregated $36.4 million and are scheduled to expire in 2015. There were no amounts outstanding under the above letters of credit at December 31, 2014.
	Centennial and WBI Holdings have guaranteed certain debt obligations of Dakota Prairie Refining. For more information, see Variable interest entities in this note.
	WBI Holdings has an outstanding guarantee to WBI Energy Transmission. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of Prairielands. At December 31, 2014, the fixed maximum amount guaranteed under this agreement was $4.0 million and is scheduled to expire in 2016. In the event of Prairielands' default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $1.1 million. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at December 31, 2014, because this intercompany transaction was eliminated in consolidation.
	In addition, Centennial, Knife River and MDU Construction Services have issued guarantees to third parties related to the routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under these obligations, Centennial, Knife River and MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these guarantees were reflected on the Consolidated Balance Sheet at December 31, 2014.
	In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. As of December 31, 2014, approximately $423.5 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.
	Variable interest entities
	The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. For more information, see Note 1.
	Dakota Prairie Refining, LLC On February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate Dakota Prairie Refinery in southwestern North Dakota. WBI Energy and Calumet each have a 50 percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments, based on a total project cost of $300 million, under the agreement are $150 million and $75 million, respectively. Capital commitments in excess of $300 million are expected to be shared equally between WBI Energy and Calumet. The total project cost is currently estimated at more than $400 million. Dakota Prairie Refining entered into a term loan for project debt financing of $75 million on April 22, 2013. The operating agreement provides for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt will be allocated to Calumet. Calumet's future cash distributions from Dakota Prairie Refining will be decreased by the principal and interest to be paid on the project debt, while the cash distributions to WBI Energy will not be decreased. Pursuant to the operating agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan.
	On December 1, 2014, Dakota Prairie Refining entered into a $50 million revolving credit agreement with an expiration date of December 1, 2015. Pursuant to the revolving credit agreement, WBI Holdings has guaranteed 50 percent of the credit agreement and Calumet has issued a letter of credit supporting 50 percent of the credit agreement. The credit agreement is used to meet the operational needs of the facility.
	Dakota Prairie Refining has been determined to be a VIE, and the Company has determined that it is the primary beneficiary as it has an obligation to absorb losses that could be potentially significant to the VIE through WBI Energy's equity investment and Centennial's guarantee of the third-party term loan. Accordingly, the Company consolidates Dakota Prairie Refining in its financial statements and records a noncontrolling interest for Calumet's ownership interest.
	Construction of Dakota Prairie Refinery began in early 2013 and the plant is not yet operational. Therefore, the results of operations of Dakota Prairie Refining did not have a material effect on the Company's Consolidated Statements of Income. The assets of Dakota Prairie Refining shall be used solely for the benefit of Dakota Prairie Refining. The total assets and liabilities of Dakota Prairie Refining reflected on the Company's Consolidated Balance Sheets at December 31 were as follows:
		2014		2013
		(In thousands)
	Assets
	Current assets:
	Cash and cash equivalents	$	21,376	$	4,774
	Accounts receivable	2,759		—
	Inventories	5,311		—
	Other current assets	4,019		26
	Total current assets	33,465		4,800
	Net property, plant and equipment	398,984		172,073
	Deferred charges and other assets:
	Other	3,400		—
	Total deferred charges and other assets	3,400		—
	Total assets	$	435,849	$	176,873
	Liabilities
	Current liabilities:
	Long-term debt due within one year	$	3,000	$	3,000
	Accounts payable	55,089		8,904
	Taxes payable	648		5
	Accrued compensation	727		26
	Other accrued liabilities	899		461
	Total current liabilities	60,363		12,396
	Long-term debt	69,000		72,000
	Total liabilities	$	129,363	$	84,396
	Fuel Contract On October 10, 2012, the Coyote Station entered into a new coal supply agreement with Coyote Creek that will replace a coal supply agreement expiring in May 2016. The new agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for the period May 2016 through December 2040.
	The new coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal will cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station, with no primary beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements.
At December 31, 2014, Coyote Creek was not yet operational. The assets and liabilities of Coyote Creek and exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, at December 31, 2014, was $15.8 million.

Quarterly_Data_Unaudited

Quarterly Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Supplementary financial information-quarterly data (Unaudited)	Supplementary Financial Information
	Quarterly Data (Unaudited)
	The following unaudited information shows selected items by quarter for the years 2014 and 2013:
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(In thousands, except per share amounts)
	2014
	Operating revenues	$	1,042,853		$	1,094,046		$	1,370,455		$	1,163,204
	Operating expenses	939,949			995,112			1,193,690			1,053,582
	Operating income	102,904			98,934			176,765			109,622
	Income from continuing operations	56,184			52,780			102,118			80,079
	Income (loss) from discontinued operations, net of tax	(45		)	547			3			2,672
	Net income attributable to the Company	56,662			54,106			103,209			84,256
	Earnings per common share - basic:
	Earnings before discontinued operations	0.3			0.28			0.53			0.42
	Discontinued operations, net of tax	—			—			—			0.01
	Earnings per common share - basic	0.3			0.28			0.53			0.43
	Earnings per common share - diluted:
	Earnings before discontinued operations	0.3			0.28			0.53			0.42
	Discontinued operations, net of tax	—			—			—			0.01
	Earnings per common share - diluted	0.3			0.28			0.53			0.43
	Weighted average common shares outstanding:
	Basic	189,820			192,060			193,949			194,136
	Diluted	190,432			192,659			194,300			194,219
	2013
	Operating revenues	$	931,604		$	1,060,595		$	1,285,782		$	1,184,423
	Operating expenses	827,073			969,217			1,135,909			1,037,306
	Operating income	104,531			91,378			149,873			147,117
	Income from continuing operations	56,592			46,392			84,550			91,348
	Loss from discontinued operations, net of tax	(77		)	(59		)	(118		)	(58		)
	Net income attributable to the Company	56,515			46,512			84,456			91,450
	Earnings per common share - basic:
	Earnings before discontinued operations	0.3			0.25			0.45			0.48
	Discontinued operations, net of tax	—			—			—			—
	Earnings per common share - basic	0.3			0.25			0.45			0.48
	Earnings per common share - diluted:
	Earnings before discontinued operations	0.3			0.24			0.44			0.48
	Discontinued operations, net of tax	—			—			—			—
	Earnings per common share - diluted	0.3			0.24			0.44			0.48
	Weighted average common shares outstanding:
	Basic	188,831			188,831			188,831			188,929
	Diluted	189,222			189,463			189,638			189,766
	Notes:
	•	First quarter 2014 reflects an unrealized loss on commodity derivatives of $4.3 million (after tax). First quarter 2013 reflects an unrealized loss on commodity derivatives of $3.7 million (after tax).
	•	Second quarter 2014 reflects an unrealized loss on commodity derivatives of $3.3 million (after tax). Second quarter 2013 reflects an impairment of coalbed natural gas gathering assets of $9.0 million (after tax) and an unrealized gain on commodity derivatives of $8.2 million (after tax). For more information, see Note 1.
	•	Third quarter 2014 reflects an unrealized gain on commodity derivatives of $18.1 million (after tax). Third quarter 2013 reflects an unrealized loss on commodity derivatives of $7.9 million (after tax).
	•	Fourth quarter 2014 reflects a MEPP withdrawal liability of $8.4 million (after tax) and an unrealized gain on commodity derivatives of $4.1 million (after tax). Fourth quarter 2013 reflects a net benefit of $1.5 million (after tax) related to natural gas gathering operations litigation and an unrealized loss on commodity derivatives of $500,000 (after tax). For more information, see Notes 16 and 19.
	Certain Company operations are highly seasonal and revenues from and certain expenses for such operations may fluctuate significantly among quarterly periods. Accordingly, quarterly financial information may not be indicative of results for a full year.

Exploration_and_Production_Act

Exploration and Production Activities (Unaudited) (Notes)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Exploration and Production Activities	Exploration and Production Activities (Unaudited)
	Fidelity is involved in the development and production of oil and natural gas resources. Fidelity shares revenues and expenses from the development of specified properties in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States in proportion to its ownership interests.
	The information that follows includes Fidelity's proportionate share of all its oil and natural gas interests.
	The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31:
		2014			2013			2012
		(In thousands)
	Subject to amortization	$	3,205,036		$	2,893,010		$	2,531,562
	Not subject to amortization	132,141			124,869			191,794
	Total capitalized costs	3,337,177			3,017,879			2,723,356
	Less accumulated depreciation, depletion and amortization	1,752,566			1,562,116			1,383,386
	Net capitalized costs	$	1,584,611		$	1,455,763		$	1,339,970
	Note:	Net capitalized costs reflect noncash write-downs of the Company's oil and natural gas properties, as discussed in Note 1.
	Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities were as follows:
	Years ended December 31,	2014			*	2013			*	2012		*
		(In thousands)
	Acquisitions:
	Proved properties	$	87,919			$	1,817			$	839
	Unproved properties	138,683				4,608				31,109
	Exploration	16,879				26,975				235,906
	Development	331,400				355,421				275,959
	Total capital expenditures	$	574,881			$	388,821			$	543,813
	*	Excludes net additions/(reductions) to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of oil and natural gas wells, as discussed in Note 10, of $(9.0) million, $(10.7) million and $(200,000) for the years ended December 31, 2014, 2013 and 2012, respectively.
	The preceding table excludes proceeds from the sales of oil and natural gas properties of $246.6 million, $83.6 million and $6.0 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	The following summary reflects income resulting from the Company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs:
	Years ended December 31,	2014			2013			2012
					(In thousands)
	Revenues:
	Sales to affiliates	$	47,045		$	45,099		$	35,966
	Sales to external customers	468,668			497,018			379,647
	Realized gain on commodity derivatives	8,458			173			33,628
	Unrealized gain (loss) on commodity derivatives	23,400			(6,267		)	(624		)
	Production costs	146,793			144,136			134,795
	Depreciation, depletion and amortization*	193,944			182,352			157,078
	Write-downs of oil and natural gas properties	—			—			391,800
	Pretax income (loss)	206,834			209,535			(235,056		)
	Income tax expense (benefit)	75,483			75,836			(88,612		)
	Results of operations for producing activities	$	131,351		$	133,699		$	(146,444	)
	*Includes accretion of discount for asset retirement obligations of $3.5 million, $3.6 million and $3.3 million for the years ended December 31, 2014, 2013 and 2012, respectively, as discussed in Note 10.
	Estimates of proved reserves were prepared in accordance with guidelines established by the industry and the SEC. The estimates are arrived at using actual historical wellhead production trends and/or standard reservoir engineering methods utilizing available geological, geophysical, engineering and economic data. The proved reserve estimates as of December 31, 2014, 2013 and 2012, were calculated using SEC Defined Prices. Other factors used in the proved reserve estimates are current estimates of well operating and future development costs (which include asset retirement costs), taxes, timing of operations, and the interests owned by the Company in the properties. These estimates are refined as new information becomes available.
	The reserve estimates are prepared by internal engineers assigned to an asset team by geographic area. Senior management reviews and approves the reserve estimates to ensure they are materially accurate. In addition, the Company engaged Ryder Scott, an independent third party, to audit its proved reserve quantity estimates.
	Estimates of economically recoverable oil, NGL and natural gas reserves and future net revenues therefrom are based upon a number of variable factors and assumptions. For these reasons, estimates of economically recoverable reserves and future net revenues may vary from actual results.
	The Company's interests in oil, NGL and natural gas reserves are located in the United States and in and around the Gulf of Mexico.
	The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2014, were as follows:
		Oil		NGL		Natural Gas		Total
		(MBbls)		(MBbls)		(MMcf)		(MBOE)
	Proved developed and undeveloped reserves:
	Balance at beginning of year	41,019		6,602		198,445		80,695
	Production	(4,919	)	(609	)	(20,822	)	(8,998	)
	Extensions and discoveries	9,654		3,634		64,420		24,025
	Improved recovery	—		—		—		—
	Purchases of proved reserves	5,463		—		7,711		6,748
	Sales of proved reserves	(4,945	)	(3,109	)	(40,451	)	(14,796	)
	Revisions of previous estimates	(2,354	)	669		35,708		4,266
	Balance at end of year	43,918		7,187		245,011		91,940
	Significant changes in proved reserves for the year ended December 31, 2014, include:
	•	Extensions and discoveries of 24.0 MMBOE, primarily due to drilling activity at the Company's East Texas, Bakken and Powder River Basin properties
	•	Purchases of proved reserves of 6.7 MMBOE, primarily due to the purchase of working interests and leasehold positions in the Powder River Basin
	•	Sales of proved reserves of (14.8) MMBOE, primarily at the Company's South Texas and Bakken properties
	•	Revisions of previous estimates of 4.3 MMBOE, largely the result of higher natural gas prices and well performance revisions
	The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2013, were as follows:
		Oil		NGL		Natural Gas		Total
		(MBbls)		(MBbls)		(MMcf)		(MBOE)
	Proved developed and undeveloped reserves:
	Balance at beginning of year	33,453		7,153		239,278		80,486
Production	(4,815	)	(781	)	(28,008	)	(10,264	)
Extensions and discoveries	13,313		1,333		26,428		19,050
Improved recovery	—		—		—		—
Purchases of proved reserves	—		—		—		—
Sales of proved reserves	(1,286	)	(25	)	(40,055	)	(7,987	)
Revisions of previous estimates	354		(1,078	)	802		(590	)
Balance at end of year	41,019		6,602		198,445		80,695
Significant changes in proved reserves for the year ended December 31, 2013, include:
•	Extension and discoveries of 19.1 MMBOE, primarily due to drilling activity and new PUD locations at the Company's Bakken and Paradox Basin properties, as well as new PUD locations at Big Horn and East Texas
•	Sales of proved reserves of (8.0) MMBOE, primarily at the Company's Green River Basin property
The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2012, were as follows:
	Oil		NGL		Natural Gas		Total
	(MBbls)		(MBbls)		(MMcf)		(MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	27,005		7,342		379,827		97,651
Production	(3,694	)	(828	)	(33,214	)	(10,058	)
Extensions and discoveries	9,874		1,817		18,386		14,756
Improved recovery	—		—		—		—
Purchases of proved reserves	—		—		—		—
Sales of proved reserves	(39	)	—		(2,307	)	(423	)
Revisions of previous estimates	307		(1,178	)	(123,414	)	(21,440	)
Balance at end of year	33,453		7,153		239,278		80,486
Significant changes in proved reserves for the year ended December 31, 2012, include:
•	Extensions and discoveries of 14.8 MMBOE, primarily due to drilling activity at the Company's Bakken, South Texas and Paradox properties
•	Revisions of previous estimates of (21.4) MMBOE, largely the result of lower natural gas prices resulting in a reduction of PDP and PUD reserves principally in the Company's Coalbed, Baker, Bowdoin, East Texas and Green River Basin natural gas properties
The following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31:
	2014		2013		2012
Proved developed reserves:
Oil (MBbls)	30,130		31,394		27,412
NGL (MBbls)	4,217		5,322		5,342
Natural Gas (MMcf)	184,437		176,546		218,259
Total (MBOE)	65,086		66,140		69,131
PUD reserves:
Oil (MBbls)	13,788		9,625		6,041
NGL (MBbls)	2,970		1,280		1,811
Natural Gas (MMcf)	60,574		21,899		21,019
Total (MBOE)	26,854		14,555		11,355
Total proved reserves:
Oil (MBbls)	43,918		41,019		33,453
NGL (MBbls)	7,187		6,602		7,153
Natural Gas (MMcf)	245,011		198,445		239,278
Total (MBOE)	91,940		80,695		80,486
As of December 31, 2014, the Company had 26.9 MMBOE of PUD reserves, which is an increase of 12.3 MMBOE from December 31, 2013. The increase relates to the Company adding 21.2 MMBOE of new PUD reserves and acquiring 3.9 MMBOE. This was partially offset by the Company converting 3.7 MMBOE, requiring $98.3 million of drilling and completion capital in 2014, divesting of 6.4 MMBOE, and negative PUD revisions of 2.7 MMBOE. At December 31, 2014, the Company did not have any PUD locations that remained undeveloped for five years or more. Future development costs estimated to be spent in each of the next three years to develop PUD reserves at December 31, 2014, are $141.8 million in 2015, $157.4 million in 2016 and $120.9 million in 2017. The future development costs are prepared using year-end costs and assuming continuation of existing economic and operating conditions and are not necessarily reflective of the Company’s expectations. The timing of marketing the exploration and production business may also affect future development costs.
The standardized measure of the Company's estimated discounted future net cash flows of total proved reserves associated with its various oil and natural gas interests at December 31 was as follows:
	2014			2013			2012
				(In thousands)
Future cash inflows	$	5,185,500		$	4,507,000		$	3,696,200
Future production costs	1,856,900			1,734,800			1,536,500
Future development costs	570,200			403,000			301,600
Future net cash flows before income taxes	2,758,400			2,369,200			1,858,100
Future income tax expense	686,100			545,200			304,900
Future net cash flows	2,072,300			1,824,000			1,553,200
10% annual discount for estimated timing of cash flows	997,400			810,000			669,800
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$	1,074,900		$	1,014,000		$	883,400
The following are the sources of change in the standardized measure of discounted future net cash flows by year:
	2014			2013			2012
				(In thousands)
Beginning of year	$	1,014,000		$	883,400		$	978,800
Net revenues from production	(368,900		)	(398,000		)	(280,800		)
Net change in sales prices and production costs related to future production	86,300			162,200			(406,300		)
Extensions and discoveries, net of future production-related costs	231,900			366,500			355,300
Improved recovery, net of future production-related costs	—			—			—
Purchases of proved reserves, net of future production-related costs	103,800			—			—
Sales of proved reserves	(219,300		)	(37,800		)	(2,600		)
Changes in estimated future development costs	65,100			6,700			37,600
Development costs incurred during the current year	104,600			141,500			77,700
Accretion of discount	109,400			94,600			121,400
Net change in income taxes	(33,400		)	(141,400		)	110,000
Revisions of previous estimates	(16,300		)	(55,800		)	(100,700		)
Other	(2,300		)	(7,900		)	(7,000		)
Net change	60,900			130,600			(95,400		)
End of year	$	1,074,900		$	1,014,000		$	883,400
The estimated discounted future cash inflows from estimated future production of proved reserves were computed using prices as previously discussed. Future production and development costs, which include asset retirement costs, attributable to proved reserves were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying statutory tax rates to the estimated net future pretax cash flows less the tax basis of the oil and gas properties, adjusted for permanent differences and tax credits.
The standardized measure of discounted future net cash flows does not purport to represent the fair market value of oil and natural gas properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. In addition, future realization of oil, NGL and natural gas prices over the remaining reserve lives may vary significantly from SEC Defined Prices.

Schedule_ICondensed_Financial_

Schedule I-Condensed Financial Information of Registrant	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule I-Condensed Financial Information of Registrant	Summary of Significant Accounting Policies
	Basis of presentation The condensed financial information reported in Schedule I is being presented to comply with Rule 12-04 of Regulation S-X. The information is unconsolidated and is presented for the parent company only, which is comprised of MDU Resources Group, Inc. (the Company) and Montana-Dakota and Great Plains, public utility divisions of the Company. In Schedule I, investments in subsidiaries are presented under the equity method of accounting where the assets and liabilities of the subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded on the Condensed Balance Sheets. The income (loss) from subsidiaries is reported as equity in earnings (loss) of subsidiaries on the Condensed Statements of Income. The consolidated financial statements of MDU Resources Group, Inc. reflect certain businesses as discontinued operations. In Schedule I, amounts from discontinued operations have not been separately stated. These statements should be read in conjunction with the consolidated financial statements and notes thereto of MDU Resources Group, Inc.
	Earnings (loss) per common share Please refer to the Consolidated Statements of Income of the registrant for earnings (loss) per common share. In addition, see Note 1 of Notes to Consolidated Financial Statements for information on the computation of earnings (loss) per common share.
	Note 2 - Debt The Company has long-term debt obligations outstanding of $508.3 million at December 31, 2014, with annual maturities of $100,000 in 2015, $50.1 million in 2016, $100,000 in 2017, $100.0 million in 2018, $77.5 million in 2019 and $280.5 million scheduled to mature in years after 2019.
	For more information on debt, see Note 9 of Notes to Consolidated Financial Statements.
	Note 3 - Dividends The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on common stock. Cash dividends paid to the Company by subsidiaries were $105.6 million, $77.6 million and $125.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Schedule_II_Valuation_and_Qual

Schedule II Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2014
Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts	Consolidated Valuation and Qualifying Accounts
	For the years ended December 31, 2014, 2013 and 2012
				Additions
	Description	Balance at Beginning of Year		Charged to Costs and Expenses		Other		*	Deductions		**	Balance at End of Year
		(In thousands)
	Allowance for doubtful accounts:
	2014	$	10,085	$	8,548	$	1,335		$	10,457		$	9,511
	2013	10,818		5,725		1,395			7,853			10,085
	2012	12,407		7,064		1,754			10,407			10,818
	* Recoveries.
	** Uncollectible accounts written off.
	All other schedules are omitted because of the absence of the conditions under which they are required, or because the information required is included in the Company's Consolidated Financial Statements and Notes thereto.

Summary_of_significant_account1

Summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of presentation	Basis of presentation
	The abbreviations and acronyms used throughout are defined following the Notes to Consolidated Financial Statements. The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline and energy services, exploration and production, construction materials and contracting, construction services and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Exploration and production, construction materials and contracting, construction services and other are nonregulated. For further descriptions of the Company's businesses, see Note 15. Intercompany balances and transactions have been eliminated in consolidation, except for certain transactions related to the Company's regulated operations in accordance with GAAP. The statements also include the ownership interests in the assets, liabilities and expenses of jointly owned electric generating facilities.
	The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by the Company's nonregulated businesses.
	The Company's regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals.
	Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.
	Management has also evaluated the impact of events occurring after December 31, 2014, up to the date of issuance of these consolidated financial statements.
Cash and cash equivalents	Cash and cash equivalents
	The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Accounts receivable and allowance for doubtful accounts	Accounts receivable and allowance for doubtful accounts
	Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. For more information, see Percentage-of-completion method in this note. The total balance of receivables past due 90 days or more was $30.9 million and $36.4 million at December 31, 2014 and 2013, respectively.
	The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at December 31, 2014 and 2013, was $9.5 million and $10.1 million, respectively.
Inventories and natural gas in storage	Inventories and natural gas in storage
	Inventories, other than natural gas in storage for the Company's regulated operations, were stated at the lower of average cost or market value. Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories. Inventories at December 31 consisted of:
		2014			2013
		(In thousands)
	Aggregates held for resale	$	108,161		$	101,568
	Materials and supplies	65,683			69,808
	Asphalt oil	42,135			38,099
	Merchandise for resale	24,420			21,720
	Natural gas in storage (current)	19,302			16,417
	Other	41,110			34,779
	Total	$	300,811		$	282,391
	The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $49.3 million and $48.3 million at December 31, 2014 and 2013, respectively.
Investments	Investments
	The Company's investments include its equity method and cost method investments as discussed in Note 4, the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company measures its investment in the insurance contract at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated other comprehensive income (loss). For more information, see Notes 8 and 16.
Property, plant and equipment	Property, plant and equipment
	Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for exploration and production properties as described in Oil and natural gas properties in this note, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, at the exploration and production segment only on costs that have been excluded from the full cost amortization pool and on certain construction projects associated with its other operations. The amount of AFUDC and interest capitalized for the years ended December 31 were as follows:
		2014			2013			2012
					(In thousands)
	Interest capitalized	$	8,586		$	6,033		$	8,659
	AFUDC - borrowed	$	3,022		$	2,767		$	2,483
	AFUDC - equity	$	5,803		$	3,322		$	4,530
	Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable aggregate reserves, which are depleted based on the units-of-production method, and exploration and production properties, which are amortized on the units-of-production method based on total proved reserves. The Company collects removal costs for plant assets in regulated utility rates. These amounts are recorded as regulatory liabilities, which are included in other liabilities.
	Property, plant and equipment at December 31 was as follows:
		2014			2013			Weighted
								Average
								Depreciable
								Life in Years
		(Dollars in thousands, where applicable)
	Regulated:
	Electric:
	Generation	$	627,952		$	570,394		42
	Distribution	343,692			308,202			39
	Transmission	229,997			196,824			48
	Construction in progress	150,445			141,365			-
	Other	105,015			99,037			15
	Natural gas distribution:
	Distribution	1,481,390			1,384,587			40
	Construction in progress	59,310			46,763			-
	Other	364,059			345,551			27
	Pipeline and energy services:
	Transmission	449,276			418,594			53
	Gathering	39,595			39,597			20
	Storage	43,994			42,939			60
	Construction in progress	5,386			6,937			-
	Other	39,910			39,504			33
	Nonregulated:
	Pipeline and energy services:
	Midstream	227,598			213,063			16
	Construction in progress	314,304			188,641			-
	Other	100,170			12,897			18
	Exploration and production:
	Oil and natural gas properties	3,337,177			3,017,879			*
	Other	65,702			42,969			8
	Construction materials and contracting:
	Land	125,372			125,551			-
	Buildings and improvements	70,566			70,000			19
	Machinery, vehicles and equipment	921,564			906,774			12
	Construction in progress	8,709			13,315			-
	Aggregate reserves	403,731			394,715			**
	Construction services:
	Land	5,265			4,821			-
	Buildings and improvements	17,936			16,628			20
	Machinery, vehicles and equipment	112,973			105,991			6
	Other	8,221			7,508			4
	Other:
	Land	2,837			2,837			-
	Other	48,100			47,160			23
	Eliminations	(17,075		)	(7,177		)
	Less accumulated depreciation, depletion and amortization	4,166,407			3,872,487
	Net property, plant and equipment	$	5,526,764		$	4,931,379
	*	Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $21.17, $17.41 and $15.28 for the years ended December 31, 2014, 2013 and 2012, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $132.1 million and $124.9 million were excluded from amortization at December 31, 2014 and 2013, respectively.
	**	Depleted on the units-of-production method.
Impairment of long-lived assets	Impairment of long-lived assets
	The Company reviews the carrying values of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. In 2013 and 2012, the Company recognized impairments of $9.0 million (after tax) and $1.7 million (after tax), respectively, which are recorded in operation and maintenance expense on the Consolidated Statements of Income. The impairments are related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a significant decline in natural gas development and production activity largely due to low natural gas prices. The coalbed natural gas gathering assets were written down to fair value that was determined using the income approach. For more information on this nonrecurring fair value measurement, see Note 8.
	No significant impairment losses were recorded in 2014. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.
Goodwill	Goodwill
	Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired.
	The goodwill impairment test is a two-step process performed at the reporting unit level. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. For more information on the Company's operating segments, see Note 15. The first step of the impairment test involves comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the years ended December 31, 2014, 2013 and 2012, there were no significant impairment losses recorded. At December 31, 2014, the fair value substantially exceeded the carrying value at all reporting units.
	Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the Company's future revenue, profitability and cash flows, amount and timing of estimated capital expenditures, inflation rates, weighted average cost of capital, operational plans, and current and future economic conditions, among others. The fair value of each reporting unit is determined using a weighted combination of income and market approaches. The Company uses a discounted cash flow methodology for its income approach. Under the income approach, the discounted cash flow model determines fair value based on the present value of projected cash flows over a specified period and a residual value related to future cash flows beyond the projection period. Both values are discounted using a rate which reflects the best estimate of the weighted average cost of capital at each reporting unit. The weighted average cost of capital, which varies by reporting unit and is in the range of 5 percent to 9 percent, and a long-term growth rate projection of approximately 3 percent were utilized in the goodwill impairment test performed in the fourth quarter of 2014. Under the market approach, the Company estimates fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants. The Company believes that the estimates and assumptions used in its impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.
Oil and natural gas properties	Oil and natural gas properties
	The Company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized.
	Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash outflows associated with asset retirement obligations that have been accrued on the balance sheet. If capitalized costs, less accumulated amortization and related deferred income taxes, exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.
	SEC Defined Prices for each quarter in 2014 were as follows:
	SEC Defined Prices for the 12 months ended	NYMEX			Henry Hub			Ventura
		Oil Price			Gas Price			Gas Price
		(per Bbl)			(per MMBtu)			(per MMBtu)
	December 31, 2014	$	94.99		$	4.34		$	7.71
	September 30, 2014	99.08			4.24			7.6
	June 30, 2014	100.27			4.1			7.47
	March 31, 2014	98.46			3.99			7.33
	For purposes of comparison, first-of-the-month prices were as follows:
		NYMEX			Henry Hub			Ventura
		Oil Price			Gas Price			Gas Price
		(per Bbl)			(per MMBtu)			(per MMBtu)
	Jan-15	$	53.27		$	3		$	3.06
	Feb-15	48.24			2.68			2.78
	Given the current oil and natural gas pricing environment, the Company believes it is likely it will have noncash write-downs of its oil and natural gas properties in future quarters until such time as commodity prices begin to recover.
	At December 31, 2014 and 2013, the Company's full-cost ceiling exceeded the Company's capitalized cost. Various factors, including lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in future noncash write-downs of the Company's oil and natural gas properties.
	The Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at September 30, 2012 and December 31, 2012. SEC Defined Prices, adjusted for market differentials, are used to calculate the ceiling test. SEC Defined Prices as of September 30, 2012 and December 31, 2012, were $94.97 per Bbl for NYMEX oil and $2.83 per MMBtu for Henry Hub natural gas and $94.71 per Bbl for NYMEX oil and $2.76 per MMBtu for Henry Hub natural gas, respectively. Accordingly, the Company was required to write down its oil and natural gas producing properties. The noncash write-downs amounted to $160.1 million and $231.7 million ($100.9 million and $145.9 million after tax) for the three months ended September 30, 2012 and December 31, 2012, respectively.
	The Company hedged a portion of its oil and natural gas production and the effects of the cash flow hedges were used in determining the full-cost ceiling at September 30, 2012 and December 31, 2012. The Company would have recognized additional write-downs of its oil and natural gas properties of $19.5 million ($12.3 million after tax) at September 30, 2012, and $20.8 million ($13.1 million after tax) at December 31, 2012, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 7.
	The following table summarizes the Company's oil and natural gas properties not subject to amortization at December 31, 2014, in total and by the year in which such costs were incurred:
					Year Costs Incurred
		Total			2014			2013			2012			2011
														and prior
		(In thousands)
	Acquisition	$	97,795		$	82,233		$	1,528		$	475		$	13,559
	Development	14,312			3,361			9,928			484			539
	Exploration	18,221			10,961			3,126			3,885			249
	Capitalized interest	1,813			1,343			203			67			200
	Total costs not subject to amortization	$	132,141		$	97,898		$	14,785		$	4,911		$	14,547
	Costs not subject to amortization as of December 31, 2014, consisted primarily of unevaluated leaseholds and development costs in the Powder River Basin and the Paradox Basin. The Company expects that the majority of these costs will be evaluated within the next five years and included in the amortization base as the properties are evaluated and/or developed.
Revenue recognition	Revenue recognition
	Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is reasonably assured. The Company recognizes utility revenue each month based on the services provided to all utility customers during the month. Accrued unbilled revenue which is included in receivables, net, represents revenues recognized in excess of amounts billed. Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain was $99.7 million and $107.4 million at December 31, 2014 and 2013, respectively. The Company recognizes construction contract revenue at its construction businesses using the percentage-of-completion method as discussed later. The Company recognizes revenue from exploration and production properties only on that portion of production sold and allocable to the Company's ownership interest in the related properties. The Company recognizes all other revenues when services are rendered or goods are delivered. The Company presents revenues net of taxes collected from customers at the time of sale to be remitted to governmental authorities, including sales and use taxes.
Percentage-of-completion method	Percentage-of-completion method
	The Company recognizes construction contract revenue from fixed-price and modified fixed-price construction contracts at its construction businesses using the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract. If a loss is anticipated on a contract, the loss is immediately recognized.
	Costs and estimated earnings in excess of billings on uncompleted contracts represent revenues recognized in excess of amounts billed and were included in receivables, net. Billings in excess of costs and estimated earnings on uncompleted contracts represent billings in excess of revenues recognized and were included in accounts payable. Costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings on uncompleted contracts at December 31, were as follows:
		2014			2013
		(In thousands)
	Costs and estimated earnings in excess of billings on uncompleted contracts	$	58,243		$	60,828
	Billings in excess of costs and estimated earnings on uncompleted contracts	$	47,011		$	84,189
	Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31, were as follows:
		2014			2013
		(In thousands)
	Short-term retainage*	$	47,551		$	55,906
	Long-term retainage**	1,053			4,229
	Total retainage	$	48,604		$	60,135
	*	Expected to be paid within one year or less and included in receivables, net.
	**	Included in deferred charges and other assets - other.
Derivative instruments	Derivative instruments
	The Company's policy allows the use of derivative instruments as part of an overall energy price and interest rate risk management program to efficiently manage and minimize commodity price and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions, and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties.
	The Company's policy generally allows the hedging of monthly forecasted sales of oil and natural gas production at Fidelity for a period up to 42 months from the time the Company enters into the hedge. The Company's policy requires that interest rate derivative instruments not exceed a period of 24 months and allows the hedging of monthly forecasted purchases of natural gas at Cascade and Intermountain for a period up to three years.
	The Company's policy requires that each month as physical oil and natural gas production at Fidelity occurs and the commodity is sold, the related portion of the derivative agreement for that month's production must settle with its counterparties. Settlements represent the exchange of cash between the Company and its counterparties based on the notional quantities and prices for each month's physical delivery as specified within the agreements. The fair value of the remaining notional amounts on the derivative agreements is recorded on the balance sheet as an asset or liability measured at fair value. The Company's policy also requires settlement of natural gas derivative instruments at Cascade and Intermountain monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days. The Company has policies and procedures that management believes minimize credit-risk exposure. Accordingly, the Company does not anticipate any material effect on its financial position or results of operations as a result of nonperformance by counterparties. For more information on derivative instruments, see Note 7.
Asset retirement obligations	Asset retirement obligations
	The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its nonregulated operations or incurs a regulatory asset or liability at its regulated operations. For more information on asset retirement obligations, see Note 10.
Legal costs	Legal costs
	The Company expenses external legal fees as they are incurred.
Natural gas costs recoverable or refundable through rate adjustments	Natural gas costs recoverable or refundable through rate adjustments
	Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within a period ranging from 12 to 28 months from the time such costs are paid. Natural gas costs refundable through rate adjustments were $13.2 million and $16.9 million at December 31, 2014 and 2013, respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $19.6 million and $12.1 million at December 31, 2014 and 2013, respectively, which is included in prepayments and other current assets.
Income taxes	Income taxes
	The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.
	The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.
	Tax positions taken or expected to be taken in an income tax return are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.
Foreign currency translation adjustment	Foreign currency translation adjustment
	The functional currency of the Company's investment in ECTE, as discussed in Note 4, is the Brazilian Real. Translation from the Brazilian Real to the U.S. dollar for assets and liabilities is performed using the exchange rate in effect at the balance sheet date. Revenues and expenses are translated on a year-to-date basis using an average of the daily exchange rates.
	Transaction gains and losses resulting from the effect of exchange rate changes on transactions denominated in a currency other than the functional currency of the reporting entity would be recorded in income.
Earnings (loss) per common share	Earnings (loss) per common share
	Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding performance share awards. In 2014 and 2013, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the year ended December 31, 2012, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the year. Due to the loss on common stock for the year ended December 31, 2012, the effect of outstanding performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury. Net income (loss) was the same for both the basic and diluted earnings (loss) per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings (loss) per share calculation was as follows:
		2014		2013		2012
				(In thousands)
	Weighted average common shares outstanding - basic	192,507		188,855		188,826
	Effect of dilutive performance share awards	80		838		—
	Weighted average common shares outstanding - diluted	192,587		189,693		188,826
	Shares excluded from the calculation of diluted earnings per share	—		—		58
Use of estimates	Use of estimates
	The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as impairment testing of long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; oil, NGL and natural gas proved reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
New accounting standards	New accounting standards
	Revenue from Contracts with Customers In May 2014, the FASB issued guidance on accounting for revenue from contracts with customers. The guidance provides for a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry specific guidance. This guidance will be effective for the Company on January 1, 2017. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting the guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. In addition, the modified approach will require additional disclosures. The Company is evaluating the effects the adoption of the new revenue guidance will have on its results of operations, financial position, cash flows and disclosures, as well as its method of adoption.
Variable interest entities	Variable interest entities
	The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.
	A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.
	The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement.
Comprehensive income (loss)	Comprehensive income (loss)
	Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges, postretirement liability adjustments, foreign currency translation adjustments and gains (losses) on available-for-sale investments. For more information on derivative instruments, see Note 7.
	The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2014, 2013 and 2012, were as follows:
		Net			Post-			Foreign			Net			Total
		Unrealized			retirement			Currency			Unrealized			Accumulated
		Gain (Loss) on			Liability Adjustment			Translation			Gain (Loss) on			Other
		Derivative						Adjustment			Available-			Comprehensive
		Instruments									for-sale			Loss
		Qualifying									Investments
		as Hedges
								(In thousands)
	Balance at December 31, 2012	$	6,018		$	(54,347	)	$	(511	)	$	119		$	(48,721	)
	Other comprehensive income (loss) before reclassifications	(5,594		)	18,539			(299		)	(194		)	12,452
	Amounts reclassified from accumulated other comprehensive loss	(4,189		)	2,001			143			109			(1,936		)
	Net current-period other comprehensive income (loss)	(9,783		)	20,540			(156		)	(85		)	10,516
	Balance at December 31, 2013	(3,765		)	(33,807		)	(667		)	34			(38,205		)
	Other comprehensive income (loss) before reclassifications	—			(12,409		)	(162		)	(154		)	(12,725		)
	Amounts reclassified from accumulated other comprehensive loss	694			796			—			135			1,625
	Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	—			7,202			—			—			7,202
	Net current-period other comprehensive income (loss)	694			(4,411		)	(162		)	(19		)	(3,898		)
	Balance at December 31, 2014	$	(3,071	)	$	(38,218	)	$	(829	)	$	15		$	(42,103	)
	Reclassifications out of accumulated other comprehensive loss for the year ended December 31 were as follows:
		2014			2013			Location on Consolidated
								Statements of Income
		(In thousands)
	Reclassification adjustment for gain (loss) on derivative
	instruments included in net income:
	Commodity derivative instruments	$	(468	)	$	7,803		Operating revenues
	Interest rate derivative instruments	(639		)	(1,066		)	Interest expense
		(1,107		)	6,737
		413			(2,548		)	Income taxes
		(694		)	4,189
	Amortization of postretirement liability losses included	(1,288		)	(3,277		)	(a)
	in net periodic benefit cost
		492			1,276			Income taxes
		(796		)	(2,001		)
	Reclassification adjustment for loss on foreign currency	—			(213		)	Earnings (loss) from
	translation adjustment included in net income							equity method investments
		—			70			Earnings (loss) from
								equity method investments
		—			(143		)
	Reclassification adjustment for loss on available-for-sale	(208		)	(168		)	Other income
	investments included in net income
		73			59			Income taxes
		(135		)	(109		)
	Total reclassifications	$	(1,625	)	$	1,936
	(a)	Included in net periodic benefit cost (credit). For more information, see Note 16.

Summary_of_significant_account2

Summary of significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Inventories	Inventories at December 31 consisted of:
		2014			2013
		(In thousands)
	Aggregates held for resale	$	108,161		$	101,568
	Materials and supplies	65,683			69,808
	Asphalt oil	42,135			38,099
	Merchandise for resale	24,420			21,720
	Natural gas in storage (current)	19,302			16,417
	Other	41,110			34,779
	Total	$	300,811		$	282,391
AFUDC and interest capitailized	The amount of AFUDC and interest capitalized for the years ended December 31 were as follows:
		2014			2013			2012
					(In thousands)
	Interest capitalized	$	8,586		$	6,033		$	8,659
	AFUDC - borrowed	$	3,022		$	2,767		$	2,483
	AFUDC - equity	$	5,803		$	3,322		$	4,530
Property, plant and equipment	Property, plant and equipment at December 31 was as follows:
		2014			2013			Weighted
								Average
								Depreciable
								Life in Years
		(Dollars in thousands, where applicable)
	Regulated:
	Electric:
	Generation	$	627,952		$	570,394		42
	Distribution	343,692			308,202			39
	Transmission	229,997			196,824			48
	Construction in progress	150,445			141,365			-
	Other	105,015			99,037			15
	Natural gas distribution:
	Distribution	1,481,390			1,384,587			40
	Construction in progress	59,310			46,763			-
	Other	364,059			345,551			27
	Pipeline and energy services:
	Transmission	449,276			418,594			53
	Gathering	39,595			39,597			20
	Storage	43,994			42,939			60
	Construction in progress	5,386			6,937			-
	Other	39,910			39,504			33
	Nonregulated:
	Pipeline and energy services:
	Midstream	227,598			213,063			16
	Construction in progress	314,304			188,641			-
	Other	100,170			12,897			18
	Exploration and production:
	Oil and natural gas properties	3,337,177			3,017,879			*
	Other	65,702			42,969			8
	Construction materials and contracting:
	Land	125,372			125,551			-
	Buildings and improvements	70,566			70,000			19
	Machinery, vehicles and equipment	921,564			906,774			12
	Construction in progress	8,709			13,315			-
	Aggregate reserves	403,731			394,715			**
	Construction services:
	Land	5,265			4,821			-
	Buildings and improvements	17,936			16,628			20
	Machinery, vehicles and equipment	112,973			105,991			6
	Other	8,221			7,508			4
	Other:
	Land	2,837			2,837			-
	Other	48,100			47,160			23
	Eliminations	(17,075		)	(7,177		)
	Less accumulated depreciation, depletion and amortization	4,166,407			3,872,487
	Net property, plant and equipment	$	5,526,764		$	4,931,379
	*	Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $21.17, $17.41 and $15.28 for the years ended December 31, 2014, 2013 and 2012, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $132.1 million and $124.9 million were excluded from amortization at December 31, 2014 and 2013, respectively.
	**	Depleted on the units-of-production method.
SEC Defined Pricing	SEC Defined Prices for each quarter in 2014 were as follows:
	SEC Defined Prices for the 12 months ended	NYMEX			Henry Hub			Ventura
		Oil Price			Gas Price			Gas Price
		(per Bbl)			(per MMBtu)			(per MMBtu)
	December 31, 2014	$	94.99		$	4.34		$	7.71
	September 30, 2014	99.08			4.24			7.6
	June 30, 2014	100.27			4.1			7.47
	March 31, 2014	98.46			3.99			7.33
	For purposes of comparison, first-of-the-month prices were as follows:
		NYMEX			Henry Hub			Ventura
		Oil Price			Gas Price			Gas Price
		(per Bbl)			(per MMBtu)			(per MMBtu)
	Jan-15	$	53.27		$	3		$	3.06
	Feb-15	48.24			2.68			2.78
Summary of natural gas and oil properties not subject to amortization	The following table summarizes the Company's oil and natural gas properties not subject to amortization at December 31, 2014, in total and by the year in which such costs were incurred:
					Year Costs Incurred
		Total			2014			2013			2012			2011
														and prior
		(In thousands)
	Acquisition	$	97,795		$	82,233		$	1,528		$	475		$	13,559
	Development	14,312			3,361			9,928			484			539
	Exploration	18,221			10,961			3,126			3,885			249
	Capitalized interest	1,813			1,343			203			67			200
	Total costs not subject to amortization	$	132,141		$	97,898		$	14,785		$	4,911		$	14,547
Percentage-of-completion method	Costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings on uncompleted contracts at December 31, were as follows:
		2014			2013
		(In thousands)
	Costs and estimated earnings in excess of billings on uncompleted contracts	$	58,243		$	60,828
	Billings in excess of costs and estimated earnings on uncompleted contracts	$	47,011		$	84,189
	Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31, were as follows:
		2014			2013
		(In thousands)
	Short-term retainage*	$	47,551		$	55,906
	Long-term retainage**	1,053			4,229
	Total retainage	$	48,604		$	60,135
	*	Expected to be paid within one year or less and included in receivables, net.
	**	Included in deferred charges and other assets - other.
Schedule of earnings per share reconciliation	Net income (loss) was the same for both the basic and diluted earnings (loss) per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings (loss) per share calculation was as follows:
		2014		2013		2012
				(In thousands)
	Weighted average common shares outstanding - basic	192,507		188,855		188,826
	Effect of dilutive performance share awards	80		838		—
	Weighted average common shares outstanding - diluted	192,587		189,693		188,826
	Shares excluded from the calculation of diluted earnings per share	—		—		58
Cash expenditures for interest and income taxes and noncash investing transactions	Cash expenditures for interest and income taxes for the years ended December 31 were as follows:
		2014			2013			2012
					(In thousands)
	Interest, net of amount capitalized	$	81,351		$	81,689		$	74,378
	Income taxes paid, net	$	69,087		$	24,857		$	3,277
	Noncash investing transactions at December 31 were as follows:
		2014			2013			2012
					(In thousands)
	Property, plant and equipment additions in accounts payable	$	103,327		$	67,129		$	76,205
After-tax changes in the components of accumulated other comprehensive income (loss)	The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2014, 2013 and 2012, were as follows:
		Net			Post-			Foreign			Net			Total
		Unrealized			retirement			Currency			Unrealized			Accumulated
		Gain (Loss) on			Liability Adjustment			Translation			Gain (Loss) on			Other
		Derivative						Adjustment			Available-			Comprehensive
		Instruments									for-sale			Loss
		Qualifying									Investments
		as Hedges
								(In thousands)
	Balance at December 31, 2012	$	6,018		$	(54,347	)	$	(511	)	$	119		$	(48,721	)
	Other comprehensive income (loss) before reclassifications	(5,594		)	18,539			(299		)	(194		)	12,452
	Amounts reclassified from accumulated other comprehensive loss	(4,189		)	2,001			143			109			(1,936		)
	Net current-period other comprehensive income (loss)	(9,783		)	20,540			(156		)	(85		)	10,516
	Balance at December 31, 2013	(3,765		)	(33,807		)	(667		)	34			(38,205		)
	Other comprehensive income (loss) before reclassifications	—			(12,409		)	(162		)	(154		)	(12,725		)
	Amounts reclassified from accumulated other comprehensive loss	694			796			—			135			1,625
	Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	—			7,202			—			—			7,202
	Net current-period other comprehensive income (loss)	694			(4,411		)	(162		)	(19		)	(3,898		)
	Balance at December 31, 2014	$	(3,071	)	$	(38,218	)	$	(829	)	$	15		$	(42,103	)
Reclassification out of accumulated other comprehensive income (loss)	Reclassifications out of accumulated other comprehensive loss for the year ended December 31 were as follows:
		2014			2013			Location on Consolidated
								Statements of Income
		(In thousands)
	Reclassification adjustment for gain (loss) on derivative
	instruments included in net income:
	Commodity derivative instruments	$	(468	)	$	7,803		Operating revenues
	Interest rate derivative instruments	(639		)	(1,066		)	Interest expense
		(1,107		)	6,737
		413			(2,548		)	Income taxes
		(694		)	4,189
	Amortization of postretirement liability losses included	(1,288		)	(3,277		)	(a)
	in net periodic benefit cost
		492			1,276			Income taxes
		(796		)	(2,001		)
	Reclassification adjustment for loss on foreign currency	—			(213		)	Earnings (loss) from
	translation adjustment included in net income							equity method investments
		—			70			Earnings (loss) from
								equity method investments
		—			(143		)
	Reclassification adjustment for loss on available-for-sale	(208		)	(168		)	Other income
	investments included in net income
		73			59			Income taxes
		(135		)	(109		)
	Total reclassifications	$	(1,625	)	$	1,936
	(a)	Included in net periodic benefit cost (credit). For more information, see Note 16.

Goodwill_and_other_intangible_1

Goodwill and other intangible assets (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill [Line Items]
Changes in the carrying amount of goodwill	The changes in the carrying amount of goodwill for the year ended December 31, 2014, were as follows:
		Balance at January 1, 2014			*	Goodwill			Balance at December 31, 2014		*
						Acquired
						During the
						Year/Other
		(In thousands)
	Natural gas distribution	$	345,736			$	—		$	345,736
	Pipeline and energy services	9,737				—			9,737
	Construction materials and contracting	176,290				—			176,290
	Construction services	104,276				(835		)	103,441
	Total	$	636,039			$	(835	)	$	635,204
	*	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
	The changes in the carrying amount of goodwill for the year ended December 31, 2013, were as follows:
		Balance at January 1, 2013			*	Goodwill Acquired			Balance at December 31, 2013		*
						During
						the Year
		(In thousands)
	Natural gas distribution	$	345,736			$	—		$	345,736
	Pipeline and energy services	9,737				—			9,737
	Construction materials and contracting	176,290				—			176,290
	Construction services	104,276				—			104,276
	Total	$	636,039			$	—		$	636,039
	*	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
Other amortizable intangible assets	Other amortizable intangible assets at December 31 were as follows:
		2014			2013
		(In thousands)
	Customer relationships	$	21,310		$	21,310
	Accumulated amortization	(15,556		)	(13,726		)
		5,754			7,584
	Noncompete agreements	5,080			6,186
	Accumulated amortization	(4,098		)	(4,840		)
		982			1,346
	Other	10,921			10,995
	Accumulated amortization	(7,817		)	(6,826		)
		3,104			4,169
	Total	$	9,840		$	13,099

Regulatory_assets_and_liabilit1

Regulatory assets and liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory assets	The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:
		Estimated Recovery	*	2014			2013
		Period
				(In thousands)
	Regulatory assets:
	Pension and postretirement benefits (a)	(e)		$	182,565		$	105,123
	Taxes recoverable from customers (a)	Over plant lives		22,910			18,266
	Manufactured gas plant sites remediation (a)	Up to 3 years		17,548			15,797
	Natural gas costs recoverable through rate adjustments (b)	Up to 28 months		19,575			12,060
	Long-term debt refinancing costs (a)	Up to 23 years		7,864			8,697
	Costs related to identifying generation development (a)	Up to 12 years		4,165			4,512
	Other (a) (b)	Largely within 1- 4 years		14,959			15,311
	Total regulatory assets			269,586			179,766
	Regulatory liabilities:
	Plant removal and decommissioning costs (c)			338,641			308,431
	Taxes refundable to customers (c)			17,772			20,180
	Natural gas costs refundable through rate adjustments (d)			13,238			16,932
	Other (c) (d)			16,601			21,868
	Total regulatory liabilities			386,252			367,411
	Net regulatory position			$	(116,666	)	$	(187,645	)
	*	Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.
	(a)	Included in deferred charges and other assets - other on the Consolidated Balance Sheets.
	(b)	Included in prepayments and other current assets on the Consolidated Balance Sheets.
	(c)	Included in other liabilities on the Consolidated Balance Sheets.
	(d)	Included in other accrued liabilities on the Consolidated Balance Sheets.
	(e)	Recovered as expense is incurred or cash contributions are made.
Regulatory liabilities	The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:
		Estimated Recovery	*	2014			2013
		Period
				(In thousands)
	Regulatory assets:
	Pension and postretirement benefits (a)	(e)		$	182,565		$	105,123
	Taxes recoverable from customers (a)	Over plant lives		22,910			18,266
	Manufactured gas plant sites remediation (a)	Up to 3 years		17,548			15,797
	Natural gas costs recoverable through rate adjustments (b)	Up to 28 months		19,575			12,060
	Long-term debt refinancing costs (a)	Up to 23 years		7,864			8,697
	Costs related to identifying generation development (a)	Up to 12 years		4,165			4,512
	Other (a) (b)	Largely within 1- 4 years		14,959			15,311
	Total regulatory assets			269,586			179,766
	Regulatory liabilities:
	Plant removal and decommissioning costs (c)			338,641			308,431
	Taxes refundable to customers (c)			17,772			20,180
	Natural gas costs refundable through rate adjustments (d)			13,238			16,932
	Other (c) (d)			16,601			21,868
	Total regulatory liabilities			386,252			367,411
	Net regulatory position			$	(116,666	)	$	(187,645	)
	*	Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.
	(a)	Included in deferred charges and other assets - other on the Consolidated Balance Sheets.
	(b)	Included in prepayments and other current assets on the Consolidated Balance Sheets.
	(c)	Included in other liabilities on the Consolidated Balance Sheets.
	(d)	Included in other accrued liabilities on the Consolidated Balance Sheets.
	(e)	Recovered as expense is incurred or cash contributions are made.

Derivative_instruments_Tables

Derivative instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivative instruments, gain (losses)	The gains and losses on derivative instruments for the years ended December 31 were as follows:
		2014			2013			2012
					(In thousands)
	Commodity derivatives designated as cash flow hedges:
	Amount of gain (loss) recognized in accumulated other	$	—		$	(6,153	)	$	10,209
	comprehensive loss (effective portion), net of tax
	Amount of (gain) loss reclassified from accumulated other comprehensive	295			(4,916		)	(8,788		)
	loss into operating revenues (effective portion), net of tax
	Amount of loss recognized in operating revenues	—			(1,422		)	(730		)
	(ineffective portion), before tax
	Interest rate derivatives designated as cash flow hedges:
	Amount of gain (loss) recognized in accumulated other	—			559			(1,712		)
	comprehensive loss (effective portion), net of tax
	Amount of loss reclassified from accumulated other comprehensive	399			727			34
	loss into interest expense (effective portion), net of tax
	Amount of loss recognized in interest expense (ineffective portion), before tax	—			(769		)	—
	Commodity derivatives not designated as hedging instruments:
	Amount of gain (loss) recognized in operating revenues, before tax	23,400			(4,845		)	106
Derivative instruments	The location and fair value of the Company's derivative instruments on the Consolidated Balance Sheets were as follows:
	Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2014			Fair Value at December 31, 2013
			(In thousands)
	Not designated as hedges:
	Commodity derivatives	Commodity derivative instruments	$	18,335		$	1,447
		Other assets - noncurrent	—			503
	Total asset derivatives		$	18,335		$	1,950
	Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2014			Fair Value at December 31, 2013
			(In thousands)
	Not designated as hedges:
	Commodity derivatives	Commodity derivative instruments	$	—		$	7,483
	Total liability derivatives		$	—		$	7,483
Offsetting assets and liabilities master netting	The gross derivative assets and liabilities (excluding settlement receivables and payables that may be subject to the same master netting agreements) presented on the Consolidated Balance Sheets and the amount eligible for offset under the master netting agreements is presented in the following table:
	December 31, 2014	Gross Amounts Recognized on the			Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
		Consolidated Balance Sheets
		(In thousands)
	Assets:
	Commodity derivatives	$	18,335		$	—		$	18,335
	Total assets	$	18,335		$	—		$	18,335
	31-Dec-13	Gross Amounts Recognized on the			Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
		Consolidated Balance Sheets
		(In thousands)
	Assets:
	Commodity derivatives	$	1,950		$	(1,950	)	$	—
	Total assets	$	1,950		$	(1,950	)	$	—
	Liabilities:
	Commodity derivatives	$	7,483		$	(1,950	)	$	5,533
	Total liabilities	$	7,483		$	(1,950	)	$	5,533

Fair_value_measurements_Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Available-for-sale securities	Details of available-for-sale securities were as follows:
	December 31, 2014	Cost		Gross		Gross			Fair Value
				Unrealized		Unrealized
				Gains		Losses
		(In thousands)
	Mortgage-backed securities	$	6,594	$	60	$	(18	)	$	6,636
	U.S. Treasury securities	3,574		—		(19		)	3,555
	Total	$	10,168	$	60	$	(37	)	$	10,191
	31-Dec-13	Cost		Gross		Gross			Fair Value
				Unrealized		Unrealized
				Gains		Losses
		(In thousands)
	Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193
	U.S. Treasury securities	1,906		15		(4		)	1,917
	Total	$	10,057	$	84	$	(31	)	$	10,110
Assets and liabilities measured at fair value on a recurring basis	The Company's assets and liabilities measured at fair value on a recurring basis were as follows:
		Fair Value Measurements
		at December 31, 2014, Using
		Quoted Prices		Significant		Significant			Balance at December 31, 2014
		in Active		Other		Unobservable
		Markets for		Observable		Inputs
		Identical		Inputs		(Level 3)
		Assets		(Level 2)
		(Level 1)
		(In thousands)
	Assets:
	Money market funds	$	—	$	18,473	$	—		$	18,473
	Insurance contract*	—		65,831		—			65,831
	Available-for-sale securities:
	Mortgage-backed securities	—		6,636		—			6,636
	U.S. Treasury securities	—		3,555		—			3,555
	Commodity derivative instruments	—		18,335		—			18,335
	Total assets measured at fair value	$	—	$	112,830	$	—		$	112,830
	*	The insurance contract invests approximately 20 percent in common stock of mid-cap companies, 18 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies, 32 percent in fixed-income investments and 1 percent in cash equivalents.
		Fair Value Measurements
		at December 31, 2013, Using
		Quoted Prices		Significant		Significant Unobservable Inputs			Balance at December 31, 2013
		in Active		Other		(Level 3)
		Markets for		Observable
		Identical		Inputs
		Assets		(Level 2)
		(Level 1)
		(In thousands)
	Assets:
	Money market funds	$	—	$	19,227	$	—		$	19,227
	Insurance contract*	—		62,370		—			62,370
	Available-for-sale securities:
	Mortgage-backed securities	—		8,193		—			8,193
	U.S. Treasury securities	—		1,917		—			1,917
	Commodity derivative instruments	—		1,950		—			1,950
	Total assets measured at fair value	$	—	$	93,657	$	—		$	93,657
	Liabilities:
	Commodity derivative instruments	$	—	$	7,483	$	—		$	7,483
	Total liabilities measured at fair value	$	—	$	7,483	$	—		$	7,483
	*	The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 15 percent in fixed-income investments.
Fair value of long-term debt outstanding	The estimated fair value of the Company's Level 2 long-term debt at December 31 was as follows:
		2014				2013
		Carrying		Fair		Carrying			Fair
		Amount		Value		Amount			Value
		(In thousands)
	Long-term debt	$	2,094,727	$	2,239,445	$	1,854,563		$	1,912,590

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Outstanding credit facilities	The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries:
	Company	Facility	Facility				Amount Outstanding at December 31, 2014			Amount Outstanding at December 31,			Letters of			Expiration
			Limit							2013			Credit at December 31, 2014			Date
			(In millions)
	MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement (a)	$	175			$	77.5	(b)	$	78.9	(b)	$	—		5/8/19
	Cascade Natural Gas Corporation	Revolving credit agreement	$	50		(c)	$	—		$	11.5		$	2.2	(d)	7/9/18
	Intermountain Gas Company	Revolving credit agreement	$	65		(e)	$	21		$	3		$	—		7/13/18
	Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement (f)	$	650			$	211	(b)	$	75	(b)	$	—		5/8/19
	Dakota Prairie Refining, LLC	Revolving credit agreement	$	50		(g)	$	—		$	—		$	1	(d)	12/1/15
	(a)	The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $225.0 million). There were no amounts outstanding under the credit agreement.
	(b)	Amount outstanding under commercial paper program.
	(c)	Certain provisions allow for increased borrowings, up to a maximum of $75.0 million.
	(d)	An outstanding letter of credit reduces the amount available under the credit agreement.
	(e)	Certain provisions allow for increased borrowings, up to a maximum of $90.0 million.
	(f)	The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $800.0 million). There were no amounts outstanding under the credit agreement.
	(g)	Certain provisions allow for increased borrowings up to a maximum of $75.0 million.
Long term debt outstanding	Long-term debt outstanding at December 31 was as follows:
		2014			2013
		(In thousands)
	Senior Notes at a weighted average rate of 5.43%, due on dates ranging from June 19, 2015 to November 24, 2055	$	1,636,662		$	1,545,078
	Commercial paper at a weighted average rate of .37%, supported by revolving credit agreements	288,500			153,924
	Term Loan Agreements at a weighted average rate of 2.12%, due on dates ranging from April 22, 2018 to April 22, 2023	72,000			75,000
	Medium-Term Notes at a weighted average rate of 7.32%, due on dates ranging from September 15, 2027 to March 16, 2029	35,000			35,000
	Other notes at a weighted average rate of 5.23%, due on dates ranging from September 1, 2020 to February 1, 2035	39,662			39,863
	Credit agreements at a weighted average rate of 3.47%, due on dates ranging from February 10, 2015 to November 30, 2038	22,939			5,701
	Discount	(36		)	(3		)
	Total long-term debt	2,094,727			1,854,563
	Less current maturities	269,449			12,277
	Net long-term debt	$	1,825,278		$	1,842,286

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Reconciliation of the company's asset retirement obligation	A reconciliation of the Company's liability, which is included in other accrued liabilities and other liabilities on the Consolidated Balance Sheets, for the years ended December 31 was as follows:
		2014			2013
		(In thousands)
	Balance at beginning of year	$	98,529		$	102,545
	Liabilities incurred	5,416			5,610
	Liabilities acquired	1,414			—
	Liabilities settled	(18,388		)	(22,257		)
	Accretion expense	4,605			4,574
	Revisions in estimates	884			7,671
	Other	379			386
	Balance at end of year	$	92,839		$	98,529

Preferred_Stocks_Tables

Preferred Stocks (Tables)	12 Months Ended
	Dec. 31, 2014
Class of Stock Disclosures [Abstract]
Preferred stock	Preferred stocks at December 31 were as follows:
		2014		2013
	(In thousands, except shares
	and per share amounts)
	Authorized:
	Preferred -
	500,000 shares, cumulative, par value $100, issuable in series
	Preferred stock A -
	1,000,000 shares, cumulative, without par value, issuable in series (none outstanding)
	Preference -
	500,000 shares, cumulative, without par value, issuable in series (none outstanding)
	Outstanding:
	4.50% Series - 100,000 shares	$	10,000	$	10,000
	4.70% Series - 50,000 shares	5,000		5,000
	Total preferred stocks	$	15,000	$	15,000

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation [Abstract]
Target grants performance share	Target grants of performance shares outstanding at December 31, 2014, were as follows:
	Grant Date	Performance	Target Grant
		Period	of Shares
	Feb-12	2012-2014	251,196
	Mar-13	2013-2015	240,419
	Feb-14	2014-2016	196,840
Schedule of share-based payment award, performance shares, valuation assumptions	Assumptions used for grants of performance shares issued in 2014, 2013 and 2012 were:
					2014						2013						2012
	Grant-date fair value					$41.13						$29.01						$17.18
	Blended volatility range	18.94	%	–	20.43		%	16.1	%	–	19.39		%	24.29	%	–	25.81		%
	Risk-free interest rate range	0.03	%	–	0.74		%	0.09	%	–	0.4		%	0.1	%	–	0.35		%
	Discounted dividends per share					$2.15						$2.12						$1.19
Summary of the status of the performance share awards	A summary of the status of the performance share awards for the year ended December 31, 2014, was as follows:
		Number of		Weighted
		Shares		Average
				Grant-Date
				Fair Value
	Nonvested at beginning of period	749,991		$	21.99
	Granted	196,840		41.13
	Additional performance shares earned	236,699		19.99
	Vested	(491,213	)	19.99
	Forfeited	(3,862	)	29.01
	Nonvested at end of period	688,455		$	28.16

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Components of income (loss) before income taxes	The components of income (loss) before income taxes from continuing operations for each of the years ended December 31 were as follows:
		2014			2013			2012
					(In thousands)
	United States	$	411,182		$	415,202		$	(47,175	)
	Foreign	(52		)	416			1,708
	Income (loss) before income taxes from continuing operations	$	411,130		$	415,618		$	(45,467	)
Income tax expense (benefit)	Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:
		2014			2013			2012
					(In thousands)
	Current:
	Federal	$	32,726		$	45,518		$	(26,858	)
	State	5,390			4,311			858
	Foreign	—			(29		)	(75		)
		38,116			49,800			(26,075		)
	Deferred:
	Income taxes:
	Federal	81,017			78,953			(1,224		)
	State	4,989			8,031			(6,323		)
	Investment tax credit - net	1,009			(206		)	44
		87,015			86,778			(7,503		)
	Change in uncertain tax positions	(5,183		)	—			1,974
	Change in accrued interest	21			158			458
	Total income tax expense (benefit)	$	119,969		$	136,736		$	(31,146	)
Deferred tax assets and deferred tax liabilities	Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:
		2014			2013
		(In thousands)
	Deferred tax assets:
	Regulatory matters	$	134,567		$	125,607
	Accrued pension costs	97,690			74,320
	Alternative minimum tax credit carryforward	23,844			33,304
	Compensation-related	38,654			31,550
	Asset retirement obligations	34,296			29,578
	Legal and environmental contingencies	10,049			10,710
	Other	59,389			45,101
	Total deferred tax assets	398,489			350,170
	Deferred tax liabilities:
	Depreciation and basis differences on property, plant and equipment	906,455			813,597
	Basis differences on oil and natural gas producing properties	270,939			266,168
	Regulatory matters	97,521			64,914
	Intangible asset amortization	22,505			13,579
	Other	29,676			26,170
	Total deferred tax liabilities	1,327,096			1,184,428
	Net deferred income tax liability	$	(928,607	)	$	(834,258	)
Schedule of change in net deferred income tax liability reconciliation [Table Text Block]	The following table reconciles the change in the net deferred income tax liability from December 31, 2013, to December 31, 2014, to deferred income tax expense:
		2014
	(In thousands)
	Change in net deferred income tax liability from the preceding table	$	94,349
	Deferred taxes associated with other comprehensive loss	2,360
	Other	(9,694		)
	Deferred income tax expense for the period	$	87,015
Reconciliation of income tax expense (benefit) at statutory federal rate versus actual rate	Total income tax expense (benefit) differs from the amount computed by applying the statutory federal income tax rate to income (loss) before taxes. The reasons for this difference were as follows:
	Years ended December 31,	2014					2013					2012
		Amount			%		Amount			%		Amount			%
		(Dollars in thousands)
	Computed tax at federal statutory rate	$	143,895		35		$	145,466		35		$	(15,914	)	35
	Increases (reductions) resulting from:
	State income taxes, net of federal income tax	10,483			2.5		10,524			2.5		2,469			(5.4	)
	Domestic production activities	(5,460		)	(1.3	)	(677		)	(.2	)	—			—
	Nonqualified benefit plans	(1,624		)	(.4	)	(5,173		)	(1.2	)	(2,359		)	5.2
	Depletion allowance	(4,010		)	(1.0	)	(3,764		)	(.9	)	(3,728		)	8.2
	Federal renewable energy credit	(3,655		)	(.9	)	(3,404		)	(.8	)	(3,401		)	7.5
	Deductible K-Plan dividends	(2,062		)	(.5	)	(1,593		)	(.4	)	(2,829		)	6.2
	AFUDC equity	(2,031		)	(.5	)	(1,074		)	(.3	)	(1,500		)	3.3
	Resolution of tax matters and uncertain tax positions	(7,367		)	(1.8	)	(859		)	(.2	)	2,559			(5.6	)
	Deferred tax rate changes	9			—		741			0.2		(3,083		)	6.8
	Other	(8,209		)	(1.9	)	(3,451		)	(.8	)	(3,360		)	7.3
	Total income tax expense (benefit)	$	119,969		29.2		$	136,736		32.9		$	(31,146	)	68.5
Reconciliation of unrecognized tax benefits (excluding interest)	A reconciliation of the unrecognized tax benefits (excluding interest) for the years ended December 31 was as follows:
		2014			2013			2012
					(In thousands)
	Balance at beginning of year	$	14,914		$	14,914		$	11,206
	Additions for tax positions of prior years	—			—			3,708
	Settlements	(14,777		)	—			—
	Balance at end of year	$	137		$	14,914		$	14,914

Business_segment_data_Tables

Business segment data (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Information on the Company's businesses	The information below follows the same accounting policies as described in the Summary of Significant Accounting Policies. Information on the Company's businesses as of December 31 and for the years then ended was as follows:
		2014			2013			2012
					(In thousands)
	External operating revenues:
	Electric	$	277,874		$	257,260		$	236,895
	Natural gas distribution	921,986			851,945			754,848
	Pipeline and energy services	166,496			155,369			139,883
		1,366,356			1,264,574			1,131,626
	Exploration and production	500,526			490,924			412,651
	Construction materials and contracting	1,740,089			1,675,444			1,597,257
	Construction services	1,062,055			1,029,909			932,013
	Other	1,532			1,553			1,884
		3,304,202			3,197,830			2,943,805
	Total external operating revenues	$	4,670,558		$	4,462,404		$	4,075,431
	Intersegment operating revenues:
	Electric	$	—		$	—		$	—
	Natural gas distribution	—			—			—
	Pipeline and energy services	49,372			46,699			53,274
	Exploration and production	47,045			45,099			35,966
	Construction materials and contracting	25,241			36,693			20,168
	Construction services	57,474			9,930			6,545
	Other	7,832			8,067			8,486
	Intersegment eliminations	(186,964		)	(146,488		)	(124,439		)
	Total intersegment operating revenues	$	—		$	—		$	—
	Depreciation, depletion and amortization:
	Electric	$	35,008		$	32,789		$	32,509
	Natural gas distribution	54,700			50,031			45,731
	Pipeline and energy services	30,645			29,119			27,684
	Exploration and production	198,199			186,458			160,681
	Construction materials and contracting	68,557			74,470			79,527
	Construction services	12,874			11,939			11,063
	Other	2,196			2,050			2,010
	Intersegment eliminations	(811		)	—			—
	Total depreciation, depletion and amortization	$	401,368		$	386,856		$	359,205
		2014			2013			2012
					(In thousands)
	Interest expense:
	Electric	$	15,595		$	12,590		$	12,421
	Natural gas distribution	27,217			25,123			28,726
	Pipeline and energy services	10,048			10,330			7,742
	Exploration and production	13,834			14,315			9,018
	Construction materials and contracting	16,368			17,394			15,211
	Construction services	4,176			4,306			4,435
	Other	15			15			13
	Intersegment eliminations	(237		)	(156		)	(867		)
	Total interest expense	$	87,016		$	83,917		$	76,699
	Income taxes:
	Electric	$	12,442		$	9,683		$	8,975
	Natural gas distribution	11,350			16,633			12,005
	Pipeline and energy services	9,699			3,390			15,291
	Exploration and production	47,739			53,197			(108,264		)
	Construction materials and contracting	18,586			24,765			14,099
	Construction services	24,753			29,504			24,128
	Other	(1,119		)	2,433			2,620
	Intersegment eliminations	(3,481		)	(2,869		)	—
	Total income taxes	$	119,969		$	136,736		$	(31,146	)
	Earnings (loss) on common stock:
	Electric	$	36,731		$	34,837		$	30,634
	Natural gas distribution	30,484			37,656			29,409
	Pipeline and energy services	22,628			7,629			26,588
	Exploration and production	96,733			94,450			(177,283		)
	Construction materials and contracting	51,510			50,946			32,420
	Construction services	54,432			52,213			38,429
	Other	7,461			5,136			4,797
Intersegment eliminations	(5,608		)	(4,307		)	—
Earnings (loss) on common stock before income (loss)	294,371			278,560			(15,006		)
from discontinued operations
Income (loss) from discontinued operations, net of tax*	3,177			(312		)	13,567
Total earnings (loss) on common stock	$	297,548		$	278,248		$	(1,439	)
Capital expenditures:
Electric	$	185,121		$	168,557		$	112,035
Natural gas distribution	120,613			101,279			130,178
Pipeline and energy services	177,409			127,092			133,787
Exploration and production	600,572			391,315			554,528
Construction materials and contracting	37,896			34,607			45,083
Construction services	26,942			15,102			14,835
Other	2,131			2,249			791
Net proceeds from sale or disposition of property and other	(306,994		)	(112,131		)	(57,460		)
Total net capital expenditures	$	843,690		$	728,070		$	933,777
Assets:
Electric**	$	1,030,611		$	884,283		$	760,324
Natural gas distribution**	1,931,908			1,786,068			1,703,459
Pipeline and energy services	1,081,902			798,701			622,470
Exploration and production	1,738,064			1,616,131			1,539,017
Construction materials and contracting	1,272,231			1,305,808			1,371,252
Construction services	454,602			450,614			429,547
Other***	300,660			219,727			256,422
Total assets	$	7,809,978		$	7,061,332		$	6,682,491
	2014			2013			2012
				(In thousands)
Property, plant and equipment:
Electric**	$	1,457,101		$	1,315,822		$	1,150,584
Natural gas distribution**	1,904,759			1,776,901			1,689,950
Pipeline and energy services	1,220,233			962,172			816,533
Exploration and production	3,402,879			3,060,848			2,764,560
Construction materials and contracting	1,529,942			1,510,355			1,504,981
Construction services	144,395			134,948			130,624
Other	50,937			49,997			50,519
Eliminations	(17,075		)	(7,177		)	—
Less accumulated depreciation, depletion and amortization	4,166,407			3,872,487			3,608,912
Net property, plant and equipment	$	5,526,764		$	4,931,379		$	4,498,839
*	Reflected in the Other category.
**	Includes allocations of common utility property.
***	Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).
Note:	The results reflect $391.8 million ($246.8 million after tax) of noncash write-downs of oil and natural gas properties in 2012.

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule of amounts recognized in balance sheet	Changes in benefit obligation and plan assets for the years ended December 31, 2014 and 2013, and amounts recognized in the Consolidated Balance Sheets at December 31, 2014 and 2013, were as follows:
		Pension Benefits						Other
								Postretirement Benefits
		2014			2013			2014			2013
		(In thousands)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	402,772		$	459,111		$	81,726		$	103,358
	Service cost	129			155			1,518			1,675
	Interest cost	17,682			16,249			3,521			3,215
	Plan participants' contributions	—			—			1,399			1,472
	Actuarial (gain) loss	80,520			(44,551		)	18,024			(20,985		)
	Benefits paid	(25,766		)	(28,192		)	(7,176		)	(7,009		)
	Benefit obligation at end of year	475,337			402,772			99,012			81,726
	Change in net plan assets:
	Fair value of plan assets at beginning of year	334,844			309,184			84,543			74,361
	Actual gain on plan assets	24,500			35,539			7,527			13,819
	Employer contribution	20,785			18,313			1,293			1,900
	Plan participants' contributions	—			—			1,399			1,472
	Benefits paid	(25,766		)	(28,192		)	(7,176		)	(7,009		)
	Fair value of net plan assets at end of year	354,363			334,844			87,586			84,543
	Funded status - (under) over	$	(120,974	)	$	(67,928	)	$	(11,426	)	$	2,817
	Amounts recognized in the Consolidated
	Balance Sheets at December 31:
	Other assets (noncurrent)	$	—		$	—		$	4,345		$	9,679
	Other accrued liabilities (current)	—			—			(322		)	(381		)
	Other liabilities (noncurrent)	(120,974		)	(67,928		)	(15,449		)	(6,481		)
	Net amount recognized	$	(120,974	)	$	(67,928	)	$	(11,426	)	$	2,817
	Amounts recognized in accumulated other
	comprehensive (income) loss consist of:
	Actuarial loss	$	207,430		$	135,061		$	25,779		$	11,314
	Prior service cost (credit)	294			365			(15,744		)	(17,137		)
	Total	$	207,724		$	135,426		$	10,035		$	(5,823	)
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets	The pension plans all have accumulated benefit obligations in excess of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for these plans at December 31 were as follows:
		2014			2013
		(In thousands)
	Projected benefit obligation	$	475,337		$	402,772
	Accumulated benefit obligation	$	475,337		$	402,772
	Fair value of plan assets	$	354,363		$	334,844
Components of net periodic benefit cost	Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows:
		Pension Benefits									Other
											Postretirement Benefits
		2014			2013			2012			2014			2013			2012
		(In thousands)
	Components of net periodic benefit cost (credit):
	Service cost	$	129		$	155		$	1,078		$	1,518		$	1,675		$	1,747
	Interest cost	17,682			16,249			17,598			3,521			3,215			4,166
	Expected return on assets	(21,218		)	(19,917		)	(23,536		)	(4,617		)	(4,343		)	(4,890		)
	Amortization of prior service cost (credit)	71			71			(46		)	(1,393		)	(1,457		)	(1,438		)
	Recognized net actuarial loss	4,869			7,173			7,070			649			1,814			2,134
	Curtailment gain	—			—			(1,023		)	—			—			—
	Amortization of net transition obligation	—			—			—			—			—			2,128
	Net periodic benefit cost (credit), including amount capitalized	1,533			3,731			1,141			(322		)	904			3,847
	Less amount capitalized	388			727			937			(21		)	164			910
	Net periodic benefit cost (credit)	1,145			3,004			204			(301		)	740			2,937
	Other changes in plan assets and benefit
	obligations recognized in accumulated other
	comprehensive (income) loss:
	Net (gain) loss	77,238			(60,173		)	19,982			15,114			(30,461		)	1,863
	Prior service credit	—			—			—			—			—			(11,418		)
	Amortization of actuarial loss	(4,869		)	(7,173		)	(7,070		)	(649		)	(1,814		)	(2,134		)
	Amortization of prior service (cost) credit	(71		)	(71		)	1,069			1,393			1,457			1,438
	Amortization of net transition obligation	—			—			—			—			—			(2,128		)
	Total recognized in accumulated other	72,298			(67,417		)	13,981			15,858			(30,818		)	(12,379		)
	comprehensive (income) loss
	Total recognized in net periodic benefit cost (credit) and	$	73,443		$	(64,413	)	$	14,185		$	15,557		$	(30,078	)	$	(9,442	)
	accumulated other comprehensive (income) loss
Weighted average assumptions used to determine benefit obligations and net periodic benefit costs	Weighted average assumptions used to determine benefit obligations at December 31 were as follows:
		Pension Benefits				Other
						Postretirement Benefits
		2014		2013		2014		2013
	Discount rate	3.7	%	4.53	%	3.74	%	4.48	%
	Expected return on plan assets	7	%	7	%	6	%	6	%
	Rate of compensation increase	N/A		N/A		3	%	3	%
	Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows:
		Pension Benefits				Other
						Postretirement Benefits
		2014		2013		2014		2013
	Discount rate	4.53	%	3.65	%	4.48	%	3.67	%
	Expected return on plan assets	7	%	7	%	6	%	6	%
	Rate of compensation increase	N/A		N/A		3	%	4	%
Health care rate assumptions for the Company's other postretirement benefit plans	Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:
					2014					2013
	Health care trend rate assumed for next year	4	%	–	7	%	6	%	–	7	%
	Health care cost trend rate - ultimate	5	%	–	6	%	5	%	–	6	%
	Year in which ultimate trend rate achieved				2017					2017
Assumed health care cost trend rates	Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates would have had the following effects at December 31, 2014:
		1 Percentage			1 Percentage
		Point Increase			Point Decrease
		(In thousands)
	Effect on total of service and interest cost components	$	247		$	(207	)
	Effect on postretirement benefit obligation	$	4,489		$	(3,832	)
The fair value of the pension and postretirement net plan assets by class	The fair value of the Company's pension plans' assets (excluding cash) by class were as follows:
		Fair Value Measurements
		at December 31, 2014, Using
		Quoted Prices			Significant			Significant Unobservable			Balance at December 31, 2014
		in Active			Other			Inputs
		Markets for			Observable			(Level 3)
		Identical			Inputs
		Assets			(Level 2)
		(Level 1)
		(In thousands)
	Assets:
	Cash equivalents	$	—		$	5,631		$	—		$	5,631
	Equity securities:
	U.S. companies	39,077			—			—			39,077
	International companies	5,189			—			—			5,189
	Collective and mutual funds*	132,403			77,449			—			209,852
	Corporate bonds	—			59,471			—			59,471
	Municipal bonds	—			10,462			—			10,462
	U.S. Government securities	15,001			6,849			—			21,850
	Total assets measured at fair value	$	191,670		$	159,862		$	—		$	351,532
	*	Collective and mutual funds invest approximately 13 percent in common stock of large-cap U.S. companies, 13 percent in U.S. Government securities, 23 percent in corporate bonds, 33 percent in common stock of international companies and 18 percent in other investments.
		Fair Value Measurements
		at December 31, 2013, Using
		Quoted Prices			Significant			Significant Unobservable			Balance at December 31, 2013
		in Active			Other			Inputs
		Markets for			Observable			(Level 3)
		Identical			Inputs
		Assets			(Level 2)
		(Level 1)
		(In thousands)
	Assets:
	Cash equivalents	$	—		$	9,406		$	—		$	9,406
	Equity securities:
	U.S. companies	62,599			—			—			62,599
	International companies	39,437			—			—			39,437
	Collective and mutual funds*	116,265			42,483			—			158,748
	Corporate bonds	—			42,721			—			42,721
	Municipal bonds	—			7,561			—			7,561
	U.S. Government securities	7,487			4,335			—			11,822
	Total assets measured at fair value	$	225,788		$	106,506		$	—		$	332,294
	*	Collective and mutual funds invest approximately 11 percent in common stock of mid-cap U.S. companies, 19 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Government securities, 27 percent in corporate bonds, 13 percent in common stock of international companies and 18 percent in other investments.
	The estimated fair values of the Company's other postretirement benefit plans' assets are determined using the market approach.
	The estimated fair value of the other postretirement benefit plans' Level 2 cash equivalents is valued at the net asset value of shares held at year end, based on published market quotations on active markets, or using other known sources including pricing from outside sources. Units of this fund can be redeemed on a daily basis at their net asset value and have no redemption restrictions. The assets are invested in high-quality, short-term money market instruments that consist of municipal obligations. There are no unfunded commitments related to this fund.
	The estimated fair value of the other postretirement benefit plans' Level 1 equity securities is based on the closing price reported on the active market on which the individual securities are traded.
	The estimated fair value of the other postretirement benefit plans' Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.
	Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2014 and 2013, there were no transfers between Levels 1 and 2.
	The fair value of the Company's other postretirement benefit plans' assets (excluding cash) by asset class were as follows:
		Fair Value Measurements
		at December 31, 2014, Using
		Quoted Prices			Significant			Significant Unobservable			Balance at December 31, 2014
		in Active			Other			Inputs
		Markets for			Observable			(Level 3)
		Identical			Inputs
		Assets			(Level 2)
		(Level 1)
		(In thousands)
	Assets:
	Cash equivalents	$	—		$	2,097		$	—		$	2,097
	Equity securities:
	U.S. companies	2,614			—			—			2,614
	International companies	25			—			—			25
	Insurance contract*	—			82,846			—			82,846
	Total assets measured at fair value	$	2,639		$	84,943		$	—		$	87,582
	*The insurance contract invests approximately 54 percent in common stock of large-cap U.S. companies, 11 percent in U.S. Government securities, 10 percent in mortgage-backed securities, 10 percent in corporate bonds and 15 percent in other investments.
	Fair Value Measurements
	at December 31, 2013, Using
	Quoted Prices			Significant			Significant Unobservable			Balance at December 31, 2013
	in Active			Other			Inputs
	Markets for			Observable			(Level 3)
	Identical			Inputs
	Assets			(Level 2)
	(Level 1)
	(In thousands)
Assets:
Cash equivalents	$	—		$	2,142		$	—		$	2,142
Equity securities:
U.S. companies	2,802			—			—			2,802
International companies	221			—			—			221
Insurance contract*	—			79,374			—			79,374
Total assets measured at fair value	$	3,023		$	81,516		$	—		$	84,539
*	The insurance contract invests approximately 55 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Government securities, 8 percent in mortgage-backed securities, 8 percent in common stock of mid-cap U.S. companies, 9 percent in corporate bonds and 8 percent in other investments.
Benefit payments expected to be paid	The following benefit payments, which reflect future service, as appropriate, and expected Medicare Part D subsidies are as follows:
	Years	Pension			Other			Expected
		Benefits			Postretirement Benefits			Medicare
								Part D Subsidy
					(In thousands)
	2015	$	23,769		$	5,162		$	218
	2016	24,025			5,186			213
	2017	24,621			5,262			207
	2018	25,064			5,329			200
	2019	25,498			5,344			193
	2020 - 2024	133,935			26,714			836
Multiemployer plans
		EIN/Pension Plan Number	Pension Protection Act Zone Status				FIP/RP Status Pending/Implemented	Contributions									Surcharge Imposed	Expiration Date of Collective Bargaining Agreement
	Pension Fund		2014		2013			2014			2013			2012
								(In thousands)
	Edison Pension Plan	93-6061681-001	Green as of 12/31/2014		Green as of 12/31/2013		No	$	9,061		$	6,358		$	5,171		No	12/31/2014*
	IBEW Local 38 Pension Plan	34-6574238-001	Yellow as of 4/30/2014		Yellow as of 4/30/2013		Implemented	777			1,041			2,771			No	4/23/17
	IBEW Local No. 82 Pension Plan	31-6127268-001	Red as of 6/30/2014		Red as of 6/30/2013		Implemented	1,392			1,284			1,093			No	11/29/15
	IBEW Local No. 246 Pension Plan	34-6582842-001	Yellow as of 5/31/2014		Yellow as of 5/31/2013		Implemented	694			1,848			1			No	10/31/17
	IBEW Local 648 Pension Plan	31-6134845-001	Red as of 2/28/2014		Red as of 2/28/2013		Implemented	1,110			1,489			564			No	8/31/15
	Laborers Pension Trust Fund for Northern California	94-6277608-001	Yellow as of 5/31/2014		Yellow as of 5/31/2013		Implemented	663			921			567			No	6/30/16
	National Electrical Benefit Fund	53-0181657-001	Green		Green		No	6,476			5,883			5,603			No	11/30/19
	OE Pension Trust Fund	94-6090764-001	Red as of 12/31/2014		Yellow		Implemented	1,445			1,510			1,156			No	6/15/2015–
																		6/30/16
	Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan	83-6011320-001	Red as of 12/31/2014		Red as of 12/31/2013		Implemented	68			76			91			No	10/31/2005*
	for Wyoming**
	Operating Engineers Pension Trust	95-6032478-001	Red as of 6/30/2014		Red as of 6/30/2013		Implemented	612			493			761			No	7/1/16
	Sheet Metal Workers' Pension Plan of Southern CA, AZ and NV	95-6052257-001	Red as of 12/31/2014		Red as of 12/31/2013		Implemented	676			512			467			No	6/30/15
	Southwest Marine Pension Trust	95-6123404-001	Red as of 12/31/2014		Red as of 12/31/2013		Implemented	31			42			76			No	1/31/2014*–
																		1/31/19
	Other funds							19,812			17,803			16,458
	Total contributions							$	42,817		$	39,260		$	34,779
	*	Plan includes collective bargaining agreements which have expired. The agreements contain provisions that automatically renew the existing contracts in lieu of a new negotiated collective bargaining agreement.
	**	The Company withdrew from the plan as of October 26, 2014, as discussed below.
	The Company was listed in the plans' Forms 5500 as providing more than 5 percent of the total contributions for the following plans and plan years:
	Pension Fund	Year Contributions to Plan Exceeded More Than 5 Percent
		of Total Contributions (as of December 31 of the Plan's Year-End)
	Edison Pension Plan	2013 and 2012
	IBEW Local 38 Pension Plan	2012
	IBEW Local No. 82 Pension Plan	2013 and 2012
	Local Union No. 124 IBEW Pension Trust Fund	2013 and 2012
	Local Union 212 IBEW Pension Trust Fund	2013 and 2012
	IBEW Local Union No. 357 Pension Plan A	2013 and 2012
	IBEW Local 648 Pension Plan	2013 and 2012
	Idaho Plumbers and Pipefitters Pension Plan	2012
	Minnesota Teamsters Construction Division Pension Fund	2013 and 2012
	Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming*	2013 and 2012
	Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525	2013 and 2012
	*	The Company withdrew from the plan as of October 26, 2014, as discussed below.

Jointly_owned_facilities_Table

Jointly owned facilities (Tables)	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Company's share of the cost of utility plant in service and related accumulated depreciation for the stations	At December 31, the Company's share of the cost of utility plant in service and related accumulated depreciation for the stations was as follows:
		2014		2013
		(In thousands)
	Big Stone Station:
	Utility plant in service	$	64,283	$	63,890
	Less accumulated depreciation	43,043		41,323
		$	21,240	$	22,567
	Coyote Station:
	Utility plant in service	$	138,810	$	138,261
	Less accumulated depreciation	94,443		89,528
		$	44,367	$	48,733
	Wygen III:
	Utility plant in service	$	65,597	$	64,332
	Less accumulated depreciation	5,928		4,639
		$	59,669	$	59,693

Commitment_and_Contingencies_D

Commitment and Contingencies Disclosure (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Limited liability project reflected on consolidated balance sheet	The total assets and liabilities of Dakota Prairie Refining reflected on the Company's Consolidated Balance Sheets at December 31 were as follows:
		2014		2013
		(In thousands)
	Assets
	Current assets:
	Cash and cash equivalents	$	21,376	$	4,774
	Accounts receivable	2,759		—
	Inventories	5,311		—
	Other current assets	4,019		26
	Total current assets	33,465		4,800
	Net property, plant and equipment	398,984		172,073
	Deferred charges and other assets:
	Other	3,400		—
	Total deferred charges and other assets	3,400		—
	Total assets	$	435,849	$	176,873
	Liabilities
	Current liabilities:
	Long-term debt due within one year	$	3,000	$	3,000
	Accounts payable	55,089		8,904
	Taxes payable	648		5
	Accrued compensation	727		26
	Other accrued liabilities	899		461
	Total current liabilities	60,363		12,396
	Long-term debt	69,000		72,000
	Total liabilities	$	129,363	$	84,396

Quarterly_Financial_Informatio

Quarterly Financial Information Disclosure (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly financial data	The following unaudited information shows selected items by quarter for the years 2014 and 2013:
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(In thousands, except per share amounts)
	2014
	Operating revenues	$	1,042,853		$	1,094,046		$	1,370,455		$	1,163,204
	Operating expenses	939,949			995,112			1,193,690			1,053,582
	Operating income	102,904			98,934			176,765			109,622
	Income from continuing operations	56,184			52,780			102,118			80,079
	Income (loss) from discontinued operations, net of tax	(45		)	547			3			2,672
	Net income attributable to the Company	56,662			54,106			103,209			84,256
	Earnings per common share - basic:
	Earnings before discontinued operations	0.3			0.28			0.53			0.42
	Discontinued operations, net of tax	—			—			—			0.01
	Earnings per common share - basic	0.3			0.28			0.53			0.43
	Earnings per common share - diluted:
	Earnings before discontinued operations	0.3			0.28			0.53			0.42
	Discontinued operations, net of tax	—			—			—			0.01
	Earnings per common share - diluted	0.3			0.28			0.53			0.43
	Weighted average common shares outstanding:
	Basic	189,820			192,060			193,949			194,136
	Diluted	190,432			192,659			194,300			194,219
	2013
	Operating revenues	$	931,604		$	1,060,595		$	1,285,782		$	1,184,423
	Operating expenses	827,073			969,217			1,135,909			1,037,306
	Operating income	104,531			91,378			149,873			147,117
	Income from continuing operations	56,592			46,392			84,550			91,348
	Loss from discontinued operations, net of tax	(77		)	(59		)	(118		)	(58		)
	Net income attributable to the Company	56,515			46,512			84,456			91,450
	Earnings per common share - basic:
	Earnings before discontinued operations	0.3			0.25			0.45			0.48
	Discontinued operations, net of tax	—			—			—			—
	Earnings per common share - basic	0.3			0.25			0.45			0.48
	Earnings per common share - diluted:
	Earnings before discontinued operations	0.3			0.24			0.44			0.48
	Discontinued operations, net of tax	—			—			—			—
	Earnings per common share - diluted	0.3			0.24			0.44			0.48
	Weighted average common shares outstanding:
	Basic	188,831			188,831			188,831			188,929
	Diluted	189,222			189,463			189,638			189,766
	Notes:
	•	First quarter 2014 reflects an unrealized loss on commodity derivatives of $4.3 million (after tax). First quarter 2013 reflects an unrealized loss on commodity derivatives of $3.7 million (after tax).
	•	Second quarter 2014 reflects an unrealized loss on commodity derivatives of $3.3 million (after tax). Second quarter 2013 reflects an impairment of coalbed natural gas gathering assets of $9.0 million (after tax) and an unrealized gain on commodity derivatives of $8.2 million (after tax). For more information, see Note 1.
	•	Third quarter 2014 reflects an unrealized gain on commodity derivatives of $18.1 million (after tax). Third quarter 2013 reflects an unrealized loss on commodity derivatives of $7.9 million (after tax).
	•	Fourth quarter 2014 reflects a MEPP withdrawal liability of $8.4 million (after tax) and an unrealized gain on commodity derivatives of $4.1 million (after tax). Fourth quarter 2013 reflects a net benefit of $1.5 million (after tax) related to natural gas gathering operations litigation and an unrealized loss on commodity derivatives of $500,000 (after tax). For more information, see Notes 16 and 19.

Exploration_and_Production_Act1

Exploration and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31:
		2014			2013			2012
		(In thousands)
	Subject to amortization	$	3,205,036		$	2,893,010		$	2,531,562
	Not subject to amortization	132,141			124,869			191,794
	Total capitalized costs	3,337,177			3,017,879			2,723,356
	Less accumulated depreciation, depletion and amortization	1,752,566			1,562,116			1,383,386
	Net capitalized costs	$	1,584,611		$	1,455,763		$	1,339,970
	Note:	Net capitalized costs reflect noncash write-downs of the Company's oil and natural gas properties, as discussed in Note 1.
Cost incurred in oil and gas property acquisition, exploration, and development activities disclosure	Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities were as follows:
	Years ended December 31,	2014			*	2013			*	2012		*
		(In thousands)
	Acquisitions:
	Proved properties	$	87,919			$	1,817			$	839
	Unproved properties	138,683				4,608				31,109
	Exploration	16,879				26,975				235,906
	Development	331,400				355,421				275,959
	Total capital expenditures	$	574,881			$	388,821			$	543,813
	*	Excludes net additions/(reductions) to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of oil and natural gas wells, as discussed in Note 10, of $(9.0) million, $(10.7) million and $(200,000) for the years ended December 31, 2014, 2013 and 2012, respectively.
Results of operations for oil and gas producing activities disclosure	The following summary reflects income resulting from the Company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs:
	Years ended December 31,	2014			2013			2012
					(In thousands)
	Revenues:
	Sales to affiliates	$	47,045		$	45,099		$	35,966
	Sales to external customers	468,668			497,018			379,647
	Realized gain on commodity derivatives	8,458			173			33,628
	Unrealized gain (loss) on commodity derivatives	23,400			(6,267		)	(624		)
	Production costs	146,793			144,136			134,795
	Depreciation, depletion and amortization*	193,944			182,352			157,078
	Write-downs of oil and natural gas properties	—			—			391,800
	Pretax income (loss)	206,834			209,535			(235,056		)
	Income tax expense (benefit)	75,483			75,836			(88,612		)
	Results of operations for producing activities	$	131,351		$	133,699		$	(146,444	)
	*Includes accretion of discount for asset retirement obligations of $3.5 million, $3.6 million and $3.3 million for the years ended December 31, 2014, 2013 and 2012, respectively, as discussed in Note 10.
Schedule of proved developed and undeveloped oil and gas reserve quantities	The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2014, were as follows:
		Oil		NGL		Natural Gas		Total
		(MBbls)		(MBbls)		(MMcf)		(MBOE)
	Proved developed and undeveloped reserves:
	Balance at beginning of year	41,019		6,602		198,445		80,695
	Production	(4,919	)	(609	)	(20,822	)	(8,998	)
	Extensions and discoveries	9,654		3,634		64,420		24,025
	Improved recovery	—		—		—		—
	Purchases of proved reserves	5,463		—		7,711		6,748
	Sales of proved reserves	(4,945	)	(3,109	)	(40,451	)	(14,796	)
	Revisions of previous estimates	(2,354	)	669		35,708		4,266
	Balance at end of year	43,918		7,187		245,011		91,940
	Significant changes in proved reserves for the year ended December 31, 2014, include:
	•	Extensions and discoveries of 24.0 MMBOE, primarily due to drilling activity at the Company's East Texas, Bakken and Powder River Basin properties
	•	Purchases of proved reserves of 6.7 MMBOE, primarily due to the purchase of working interests and leasehold positions in the Powder River Basin
	•	Sales of proved reserves of (14.8) MMBOE, primarily at the Company's South Texas and Bakken properties
	•	Revisions of previous estimates of 4.3 MMBOE, largely the result of higher natural gas prices and well performance revisions
	The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2013, were as follows:
		Oil		NGL		Natural Gas		Total
		(MBbls)		(MBbls)		(MMcf)		(MBOE)
	Proved developed and undeveloped reserves:
	Balance at beginning of year	33,453		7,153		239,278		80,486
	Production	(4,815	)	(781	)	(28,008	)	(10,264	)
	Extensions and discoveries	13,313		1,333		26,428		19,050
	Improved recovery	—		—		—		—
	Purchases of proved reserves	—		—		—		—
	Sales of proved reserves	(1,286	)	(25	)	(40,055	)	(7,987	)
	Revisions of previous estimates	354		(1,078	)	802		(590	)
	Balance at end of year	41,019		6,602		198,445		80,695
	Significant changes in proved reserves for the year ended December 31, 2013, include:
	•	Extension and discoveries of 19.1 MMBOE, primarily due to drilling activity and new PUD locations at the Company's Bakken and Paradox Basin properties, as well as new PUD locations at Big Horn and East Texas
	•	Sales of proved reserves of (8.0) MMBOE, primarily at the Company's Green River Basin property
	The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2012, were as follows:
		Oil		NGL		Natural Gas		Total
		(MBbls)		(MBbls)		(MMcf)		(MBOE)
	Proved developed and undeveloped reserves:
	Balance at beginning of year	27,005		7,342		379,827		97,651
	Production	(3,694	)	(828	)	(33,214	)	(10,058	)
	Extensions and discoveries	9,874		1,817		18,386		14,756
	Improved recovery	—		—		—		—
	Purchases of proved reserves	—		—		—		—
	Sales of proved reserves	(39	)	—		(2,307	)	(423	)
	Revisions of previous estimates	307		(1,178	)	(123,414	)	(21,440	)
	Balance at end of year	33,453		7,153		239,278		80,486
	Significant changes in proved reserves for the year ended December 31, 2012, include:
	•	Extensions and discoveries of 14.8 MMBOE, primarily due to drilling activity at the Company's Bakken, South Texas and Paradox properties
	•	Revisions of previous estimates of (21.4) MMBOE, largely the result of lower natural gas prices resulting in a reduction of PDP and PUD reserves principally in the Company's Coalbed, Baker, Bowdoin, East Texas and Green River Basin natural gas properties
	The following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31:
		2014		2013		2012
	Proved developed reserves:
	Oil (MBbls)	30,130		31,394		27,412
	NGL (MBbls)	4,217		5,322		5,342
	Natural Gas (MMcf)	184,437		176,546		218,259
	Total (MBOE)	65,086		66,140		69,131
	PUD reserves:
	Oil (MBbls)	13,788		9,625		6,041
	NGL (MBbls)	2,970		1,280		1,811
	Natural Gas (MMcf)	60,574		21,899		21,019
	Total (MBOE)	26,854		14,555		11,355
	Total proved reserves:
	Oil (MBbls)	43,918		41,019		33,453
	NGL (MBbls)	7,187		6,602		7,153
	Natural Gas (MMcf)	245,011		198,445		239,278
	Total (MBOE)	91,940		80,695		80,486
Standardized measure of discounted future cash flows relating to proved reserves disclosure	The standardized measure of the Company's estimated discounted future net cash flows of total proved reserves associated with its various oil and natural gas interests at December 31 was as follows:
		2014			2013			2012
					(In thousands)
	Future cash inflows	$	5,185,500		$	4,507,000		$	3,696,200
	Future production costs	1,856,900			1,734,800			1,536,500
	Future development costs	570,200			403,000			301,600
	Future net cash flows before income taxes	2,758,400			2,369,200			1,858,100
	Future income tax expense	686,100			545,200			304,900
	Future net cash flows	2,072,300			1,824,000			1,553,200
	10% annual discount for estimated timing of cash flows	997,400			810,000			669,800
	Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$	1,074,900		$	1,014,000		$	883,400
	The following are the sources of change in the standardized measure of discounted future net cash flows by year:
		2014			2013			2012
					(In thousands)
	Beginning of year	$	1,014,000		$	883,400		$	978,800
	Net revenues from production	(368,900		)	(398,000		)	(280,800		)
	Net change in sales prices and production costs related to future production	86,300			162,200			(406,300		)
	Extensions and discoveries, net of future production-related costs	231,900			366,500			355,300
	Improved recovery, net of future production-related costs	—			—			—
	Purchases of proved reserves, net of future production-related costs	103,800			—			—
	Sales of proved reserves	(219,300		)	(37,800		)	(2,600		)
	Changes in estimated future development costs	65,100			6,700			37,600
	Development costs incurred during the current year	104,600			141,500			77,700
	Accretion of discount	109,400			94,600			121,400
	Net change in income taxes	(33,400		)	(141,400		)	110,000
	Revisions of previous estimates	(16,300		)	(55,800		)	(100,700		)
	Other	(2,300		)	(7,900		)	(7,000		)
	Net change	60,900			130,600			(95,400		)
	End of year	$	1,074,900		$	1,014,000		$	883,400

Accounts_receivable_and_allowa

Accounts receivable and allowance for doubtful accounts (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Accounting Policies [Abstract]
Balance of receivables past due 90 days or more	$30.90	$36.40
Allowance for doubtful accounts	$9.50	$10.10

Inventories_and_natural_gas_in

Inventories and natural gas in storage (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Aggregates held for resale	$108,161,000	$101,568,000
Materials and supplies	65,683,000	69,808,000
Asphalt oil	42,135,000	38,099,000
Merchandise for resale	24,420,000	21,720,000
Natural gas in storage (current)	19,302,000	16,417,000
Other	41,110,000	34,779,000
Total	300,811,000	282,391,000
Natural gas in storage noncurrent	$49,300,000	$48,300,000

Property_plant_and_equipment_D

Property, plant and equipment (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Property, plant and equipment [Line Items]
Interest capitalized	$8,586		$6,033		$8,659
AFUDC - borrowed	3,022		2,767		2,483
AFUDC - equity	5,803		3,322		4,530
Property, plant and equipment	9,693,171		8,803,866
Less accumulated depreciation, depletion and amortization	4,166,407		3,872,487		3,608,912
Net property, plant and equipment	5,526,764		4,931,379		4,498,839
BOE average rate for amortization under units-of-production method (in dollars per BOE)	21.17		17.41		15.28
Oil and natural gas properties not subject to amortization	132,141		124,869		191,794
Electric:
Property, plant and equipment [Line Items]
Property, plant and equipment	1,457,101	[1]	1,315,822	[1]	1,150,584	[1]
Natural gas distribution:
Property, plant and equipment [Line Items]
Property, plant and equipment	1,904,759	[1]	1,776,901	[1]	1,689,950	[1]
Pipeline and energy services:
Property, plant and equipment [Line Items]
Property, plant and equipment	1,220,233		962,172		816,533
Exploration and production:
Property, plant and equipment [Line Items]
Property, plant and equipment	3,402,879		3,060,848		2,764,560
Construction materials and contracting:
Property, plant and equipment [Line Items]
Property, plant and equipment	1,529,942		1,510,355		1,504,981
Construction services:
Property, plant and equipment [Line Items]
Property, plant and equipment	144,395		134,948		130,624
Other:
Property, plant and equipment [Line Items]
Property, plant and equipment	50,937		49,997		50,519
Regulated: | Electric: | Generation
Property, plant and equipment [Line Items]
Property, plant and equipment	627,952		570,394
Weighted average depreciable life in years	42 years
Regulated: | Electric: | Distribution
Property, plant and equipment [Line Items]
Property, plant and equipment	343,692		308,202
Weighted average depreciable life in years	39 years
Regulated: | Electric: | Transmission
Property, plant and equipment [Line Items]
Property, plant and equipment	229,997		196,824
Weighted average depreciable life in years	48 years
Regulated: | Electric: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	150,445		141,365
Regulated: | Electric: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	105,015		99,037
Weighted average depreciable life in years	15 years
Regulated: | Natural gas distribution: | Distribution
Property, plant and equipment [Line Items]
Property, plant and equipment	1,481,390		1,384,587
Weighted average depreciable life in years	40 years
Regulated: | Natural gas distribution: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	59,310		46,763
Regulated: | Natural gas distribution: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	364,059		345,551
Weighted average depreciable life in years	27 years
Regulated: | Pipeline and energy services: | Transmission
Property, plant and equipment [Line Items]
Property, plant and equipment	449,276		418,594
Weighted average depreciable life in years	53 years
Regulated: | Pipeline and energy services: | Gathering
Property, plant and equipment [Line Items]
Property, plant and equipment	39,595		39,597
Weighted average depreciable life in years	20 years
Regulated: | Pipeline and energy services: | Storage
Property, plant and equipment [Line Items]
Property, plant and equipment	43,994		42,939
Weighted average depreciable life in years	60 years
Regulated: | Pipeline and energy services: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	5,386		6,937
Regulated: | Pipeline and energy services: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	39,910		39,504
Weighted average depreciable life in years	33 years
Nonregulated: | Eliminations
Property, plant and equipment [Line Items]
Property, plant and equipment	-17,075		-7,177
Nonregulated: | Pipeline and energy services: | Midstream
Property, plant and equipment [Line Items]
Property, plant and equipment	227,598		213,063
Weighted average depreciable life in years	16 years
Nonregulated: | Pipeline and energy services: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	314,304		188,641
Nonregulated: | Pipeline and energy services: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	100,170		12,897
Weighted average depreciable life in years	18 years
Nonregulated: | Exploration and production: | Oil and natural gas properties
Property, plant and equipment [Line Items]
Property, plant and equipment	3,337,177	[2]	3,017,879	[2]
Nonregulated: | Exploration and production: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	65,702		42,969
Weighted average depreciable life in years	8 years
Nonregulated: | Construction materials and contracting: | Land
Property, plant and equipment [Line Items]
Property, plant and equipment	125,372		125,551
Nonregulated: | Construction materials and contracting: | Buildings and improvements
Property, plant and equipment [Line Items]
Property, plant and equipment	70,566		70,000
Weighted average depreciable life in years	19 years
Nonregulated: | Construction materials and contracting: | Machinery, vehicles and equipment
Property, plant and equipment [Line Items]
Property, plant and equipment	921,564		906,774
Weighted average depreciable life in years	12 years
Nonregulated: | Construction materials and contracting: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	8,709		13,315
Nonregulated: | Construction materials and contracting: | Aggregate reserves
Property, plant and equipment [Line Items]
Property, plant and equipment	403,731	[3]	394,715	[3]
Nonregulated: | Construction services: | Land
Property, plant and equipment [Line Items]
Property, plant and equipment	5,265		4,821
Nonregulated: | Construction services: | Buildings and improvements
Property, plant and equipment [Line Items]
Property, plant and equipment	17,936		16,628
Weighted average depreciable life in years	20 years
Nonregulated: | Construction services: | Machinery, vehicles and equipment
Property, plant and equipment [Line Items]
Property, plant and equipment	112,973		105,991
Weighted average depreciable life in years	6 years
Nonregulated: | Construction services: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	8,221		7,508
Weighted average depreciable life in years	4 years
Nonregulated: | Other: | Land
Property, plant and equipment [Line Items]
Property, plant and equipment	2,837		2,837
Nonregulated: | Other: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	$48,100		$47,160
Weighted average depreciable life in years	23 years
[1]	Includes allocations of common utility property.
[2]	Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $21.17, $17.41 and $15.28 for the years ended December 31, 2014, 2013 and 2012, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $132.1 million and $124.9 million were excluded from amortization at December 31, 2014 and 2013, respectively.
[3]	Depleted on the units-of-production method.

Impairment_of_longlived_assets

Impairment of long-lived assets (Details 4) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Asset impairment charges	$9	$9	$1.70

Goodwill_Details_5

Goodwill (Details 5)	3 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Fair value inputs discount rate, range bottom	5.00%
Fair value inputs, discount rate, range top	9.00%
Long-term growth rate projections	3.00%

Oil_and_natural_gas_properties

Oil and natural gas properties (Details 6) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Feb. 01, 2015	Jan. 01, 2015
Natural gas and oil properties [Abstract]
Discount rate used in calculating present value of future net cash flows from proved reserves (in hundredths)			10.00%
NYMEX oil price	94.71	94.97	94.99		94.71		99.08	100.27	98.46
Henry Hub natural gas price	2.76	2.83	4.34		2.76		4.24	4.1	3.99
Ventura natural gas price			7.71				7.6	7.47	7.33
Write-downs of oil and natural gas properties	$231,700,000	$160,100,000	$0	$0	$391,800,000
Noncash write-downs of oil and natural gas properties, after tax	145,900,000	100,900,000			246,800,000
Additional write-downs of its oil and natural gas properties that would have been recognized without effects of cash flow hedges	20,800,000	19,500,000			20,800,000
Additional write-downs of its oil and natural gas properties that would have been recognized without effects of cash flow hedges, after tax	13,100,000	12,300,000			13,100,000
Oil and natural gas properties not subject to amortization [Abstract]
Acquisition			97,795,000
Development			14,312,000
Exploration			18,221,000
Capitalized interest			1,813,000
Total costs not subject to amortization	191,794,000		132,141,000	124,869,000	191,794,000
Acquisition costs, period cost			82,233,000	1,528,000	475,000	13,559,000
Development costs, period cost			3,361,000	9,928,000	484,000	539,000
Exploration costs, period cost			10,961,000	3,126,000	3,885,000	249,000
Capitalized interest costs, period costs			1,343,000	203,000	67,000	200,000
Capitalized costs of unproved properties excluded from amortization, period cost			$97,898,000	$14,785,000	$4,911,000	$14,547,000
Time period for evaluating majority of costs not subject to amortization			5 years
Subsequent Event [Member]
Natural gas and oil properties [Abstract]
NYMEX oil price										48.24	53.27
Henry Hub natural gas price										2.68	3
Ventura natural gas price										2.78	3.06

Revenue_recognition_Details_7

Revenue recognition (Details 7) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Accounting Policies [Abstract]
Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain	$99.70	$107.40

Percentageofcompletion_method_

Percentage-of-completion method (Details 8) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Costs and estimated earnings in excess of billings on uncompleted contracts	$58,243		$60,828
Billings in excess of costs and estimated earnings on uncompleted contracts	47,011		84,189
Short-term retainage	47,551	[1]	55,906	[1]
Long-term retainage	1,053	[2]	4,229	[2]
Total retainage	$48,604		$60,135
[1]	Expected to be paid within one year or less and included in receivables, net.
[2]	Included in deferred charges and other assets - other.

Derivative_instruments_AP_Deta

Derivative instruments AP (Details 9)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Maximum length of time allowed to hedge forecasted sales	42 months
Maximum length of time allowed to hedge interest rate	24 months
Maximum length of time allowed to hedge forecasted purchases	three years
Maximum period for settlement of all interest rate derivative transactions	90 days

Natural_gas_costs_recoverable_

Natural gas costs recoverable or refundable through rate adjustments (Details 10) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Minimum period over which natural gas costs greater or less than amounts being recovered become recoverable or refundable through rate adjustments	12 months
Maximum period over which natural gas costs greater or less than amounts being recovered become recoverable or refundable through rate adjustments	28 months
Natural gas costs refundable	$13.20	$16.90
Natural gas costs recoverable	$19.60	$12.10

Income_taxes_Details_11

Income taxes (Details 11)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Threshold of likelihood of tax positions being realized upon ultimate settlement with a taxing authority	50.00%

Earnings_loss_percommon_share_

Earnings (loss) percommon share (Details 12)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Weighted average common shares outstanding - basic	194,136	193,949	192,060	189,820	188,929	188,831	188,831	188,831	192,507	188,855	188,826
Effect of dilutive performance share awards									80	838	0
Weighted average common shares outstanding - diluted	194,219	194,300	192,659	190,432	189,766	189,638	189,463	189,222	192,587	189,693	188,826
Shares excluded from the calculation of diluted earnings per share									0	0	58

Cash_flow_information_Details_

Cash flow information (Details 13) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Interest paid, net	$81,351	$81,689	$74,378
Income taxes paid, net	69,087	24,857	3,277
Capital expenditures incurred but not yet paid	$103,327	$67,129	$76,205

Comprehensive_income_loss_Deta

Comprehensive income (loss) (Details 14) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	($38,205)	($48,721)
Other comprehensive income (loss) before reclassifications	-12,725	12,452
Amounts reclassified from accumulated other comprehensive loss	1,625	-1,936
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	7,202
Net current-period other comprehensive income (loss)	-3,898	10,516	-1,720
Balance	-42,103	-38,205	-48,721
Net unrealized gain (loss) on derivative instruments qualifying as hedges
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	-3,765	6,018
Other comprehensive income (loss) before reclassifications	0	-5,594
Amounts reclassified from accumulated other comprehensive loss	694	-4,189
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	0
Net current-period other comprehensive income (loss)	694	-9,783
Balance	-3,071	-3,765
Postretirement liability adjustment
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	-33,807	-54,347
Other comprehensive income (loss) before reclassifications	-12,409	18,539
Amounts reclassified from accumulated other comprehensive loss	796	2,001
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	7,202
Net current-period other comprehensive income (loss)	-4,411	20,540
Balance	-38,218	-33,807
Foreign currency translation adjustment
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	-667	-511
Other comprehensive income (loss) before reclassifications	-162	-299
Amounts reclassified from accumulated other comprehensive loss	0	143
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	0
Net current-period other comprehensive income (loss)	-162	-156
Balance	-829	-667
Net unrealized gains on available-for-sale investments
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	34	119
Other comprehensive income (loss) before reclassifications	-154	-194
Amounts reclassified from accumulated other comprehensive loss	135	109
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	0
Net current-period other comprehensive income (loss)	-19	-85
Balance	$15	$34

Reclassifications_out_of_accum

Reclassifications out of accumulated other comprehensive (loss) (Details 15) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reclassification adjustment out of accumulated other comprehensive income
Operating revenues	$1,163,204	$1,370,455	$1,094,046	$1,042,853	$1,184,423	$1,285,782	$1,060,595	$931,604	$4,670,558	$4,462,404	$4,075,431
Interest expense									-87,016	-83,917	-76,699
Income (loss) before income taxes									411,130	415,618	-45,467
Income taxes									-119,969	-136,736	31,146
Net income (loss)									294,338	278,570	-754
Earnings (loss) from equity method investments									-41	-132	5,383
Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income
Income (loss) before income taxes									-1,107	6,737
Income taxes									413	-2,548
Net income (loss)									-694	4,189
Amortization of postretirement liability losses included in net periodic benefit cost
Reclassification adjustment out of accumulated other comprehensive income
Income taxes									492	1,276
Net income (loss)									-796	-2,001
Net periodic benefit cost									-1,288	-3,277
Reclassification adjustment for loss on foreign currency translation adjustment included in net income
Reclassification adjustment out of accumulated other comprehensive income
Net income (loss)									0	-143
Earnings (loss) from equity method investments									0	-213
Earnings (loss) from equity method investments, tax									0	70
Reclassification adjustment for loss on available-for-sale investments included in net income [Member]
Reclassification adjustment out of accumulated other comprehensive income
Income taxes									73	59
Net income (loss)									-135	-109
Other income									-208	-168
Total reclassifications
Reclassification adjustment out of accumulated other comprehensive income
Net income (loss)									-1,625	1,936
Commodity derivative instruments [Member] | Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income
Operating revenues									-468	7,803
Interest rate derivative instruments [Member] | Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income
Interest expense									($639)	($1,066)

Acquisitions_Details

Acquisitions (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2012
Business Combinations [Abstract]
Business acquisitions	$209.20	$67.50
Percent of undivided interest acquired		50.00%

Discontinued_operations_Detail

Discontinued operations (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2011
Discontinued Operations and Disposal Groups [Abstract]
Arbitration charge related to a guarantee	$21
Arbitration charge after tax	$13

Equity_method_investments_Deta

Equity method investments (Details)	Aug. 31, 2013	Aug. 31, 2012	Nov. 30, 2011	Nov. 30, 2010
ECTE [Member]
Schedule of Equity Method Investments [Line Items]
Percentage ownership interest in equity method investment sold				59.96%
Portion of remaining interest sold	25.00%	25.00%	25.00%
ENTE [Member]
Schedule of Equity Method Investments [Line Items]
Percentage ownership interest in equity method investment sold				100.00%
ERTE [Member]
Schedule of Equity Method Investments [Line Items]
Percentage ownership interest in equity method investment sold				100.00%

Goodwill_and_other_intangible_2

Goodwill and other intangible assets (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Goodwill [Roll Forward]
Balance as of beginning of period	$636,039	[1]	$636,039	[1]
Goodwill acquired during the year/other	-835
Goodwill acquired during the year			0
Balance as of end of period	635,204	[1]	636,039	[1]
Natural gas distribution:
Goodwill [Roll Forward]
Balance as of beginning of period	345,736		345,736
Goodwill acquired during the year/other	0
Goodwill acquired during the year			0
Balance as of end of period	345,736		345,736
Pipeline and energy services:
Goodwill [Roll Forward]
Balance as of beginning of period	9,737	[1]	9,737	[1]
Goodwill acquired during the year/other	0
Goodwill acquired during the year			0
Balance as of end of period	9,737	[1]	9,737	[1]
Accumulated impairment which occurred in prior periods	12,300		12,300
Construction materials and contracting:
Goodwill [Roll Forward]
Balance as of beginning of period	176,290		176,290
Goodwill acquired during the year/other	0
Goodwill acquired during the year			0
Balance as of end of period	176,290		176,290
Construction services:
Goodwill [Roll Forward]
Balance as of beginning of period	104,276		104,276
Goodwill acquired during the year/other	-835
Goodwill acquired during the year			0
Balance as of end of period	$103,441		$104,276
[1]	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

Goodwill_and_other_intangible_3

Goodwill and other intangible assets (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Finite-lived intangible assets [Line Items]
Intangible assets, net (excluding goodwill)	$9,840,000	$13,099,000
Amortization of intangible assets	3,200,000	4,000,000	3,800,000
Estimated amortization expense for amortizable intangible assets
2015	2,500,000
2016	2,100,000
2017	1,900,000
2018	1,000,000
2019	900,000
Thereafter	1,400,000
Customer relationships [Member]
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	21,310,000	21,310,000
Accumulated amortization	-15,556,000	-13,726,000
Intangible assets, net (excluding goodwill)	5,754,000	7,584,000
Noncompete agreements [Member]
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	5,080,000	6,186,000
Accumulated amortization	-4,098,000	-4,840,000
Intangible assets, net (excluding goodwill)	982,000	1,346,000
Other [Member}
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	10,921,000	10,995,000
Accumulated amortization	-7,817,000	-6,826,000
Intangible assets, net (excluding goodwill)	$3,104,000	$4,169,000

Regulatory_assets_and_liabilit2

Regulatory assets and liabilities (Details) (USD $)	0 Months Ended
	Dec. 31, 2014		Dec. 31, 2014		Dec. 31, 2013
Regulatory assets and liabilities
Regulatory assets:	$269,586,000		$269,586,000		$179,766,000
Regulatory liabilities:	386,252,000		386,252,000		367,411,000
Net regulatory position	-116,666,000		-116,666,000		-187,645,000
Regulatory assets not earning a rate of return	229,600,000		229,600,000		163,700,000
Plant removal and decommissioning costs [Member}
Regulatory assets and liabilities
Regulatory liabilities:	338,641,000	[1]	338,641,000	[1]	308,431,000	[1]
Taxes refundable to customers [Member]
Regulatory assets and liabilities
Regulatory liabilities:	17,772,000	[1]	17,772,000	[1]	20,180,000	[1]
Natural gas costs refundable through rate adjustments [Member]
Regulatory assets and liabilities
Regulatory liabilities:	13,238,000	[2]	13,238,000	[2]	16,932,000	[2]
Other regulatory assets/liabilities [Member]
Regulatory assets and liabilities
Regulatory liabilities:	16,601,000	[1],[2]	16,601,000	[1],[2]	21,868,000	[1],[2]
Pension and postretirement benefits [Member]
Regulatory assets and liabilities
Estimated recovery period	(e)	[3]
Regulatory assets:	182,565,000	[4]	182,565,000	[4]	105,123,000	[4]
Taxes recoverable from customers [Member]
Regulatory assets and liabilities
Estimated recovery period	Over plant lives	[5]
Regulatory assets:	22,910,000	[4]	22,910,000	[4]	18,266,000	[4]
Manufactured gas plant sites remediation [Member]
Regulatory assets and liabilities
Estimated recovery period	Up to 3 years	[5]
Regulatory assets:	17,548,000	[4]	17,548,000	[4]	15,797,000	[4]
Natural gas costs recoverable through rate adjustments [Member]
Regulatory assets and liabilities
Estimated recovery period	Up to 28 months	[5]
Regulatory assets:	19,575,000	[6]	19,575,000	[6]	12,060,000	[6]
Long-term debt refinancing costs [Member]
Regulatory assets and liabilities
Estimated recovery period	Up to 23 years	[5]
Regulatory assets:	7,864,000	[4]	7,864,000	[4]	8,697,000	[4]
Costs related to identifying generation development [Member]
Regulatory assets and liabilities
Estimated recovery period	Up to 12 years	[5]
Regulatory assets:	4,165,000	[4]	4,165,000	[4]	4,512,000	[4]
Other regulatory assets/liabilities [Member]
Regulatory assets and liabilities
Estimated recovery period	Largely within 1- 4 years	[5]
Regulatory assets:	$14,959,000	[4],[6]	$14,959,000	[4],[6]	$15,311,000	[4],[6]
[1]	Included in other liabilities on the Consolidated Balance Sheets.
[2]	Included in other accrued liabilities on the Consolidated Balance Sheets.
[3]	Recovered as expense is incurred or cash contributions are made.
[4]	Included in deferred charges and other assets - other on the Consolidated Balance Sheets.
[5]	stimated recovery period for regulatory assets currently being recovered in rates charged to customers.
[6]	Included in prepayments and other current assets on the Consolidated Balance Sheets.

Derivative_Instruments_Derivat

Derivative Instruments Derivative instruments (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Derivative instruments [Line Items]
Amount of unrealized gain (loss) on hedge at de-designation date to be reclassified into AOCI			$1,800,000
Derivatives with credit-risk-related contingent feature in net liability position, aggregate fair value		7,500,000
Assets needed for immediate settlement aggregate fair value for cash flow heding instruments		7,500,000
Cash flow hedge gain (loss) to be reclassified within twelve months	($400,000)
Oil swap and or collar [Member]
Derivative instruments [Line Items]
Derivative, nonmonetary notional amount	270,000	2,900,000
Natural gas swap or and collar [Member]
Derivative instruments [Line Items]
Derivative, nonmonetary notional amount	5,000,000	18,300,000

Derivative_Instruments_Gains_a

Derivative Instruments Gains and losses on derivative instruments (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	$0	($5,594)	$8,497
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	694	-4,189	-8,754
Designated as hedging instrument [Member] | Commodity derivatives
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	0	-6,153	10,209
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	295	-4,916	-8,788
Amount of gain (loss) recognized in income statement (ineffective portion), before tax	0	-1,422	-730
Designated as hedging instrument [Member] | Interest rate derivative instruments
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	0	559	-1,712
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	399	727	34
Amount of gain (loss) recognized in income statement (ineffective portion), before tax	0	-769	0
Not designated as hedging instruments [Member] | Commodity derivatives
Derivative instruments [Line Items]
Amount of gain (loss) recognized in operating revenues, before tax	$23,400	($4,845)	$106

Fair_value_derivative_instrume

Fair value derivative instruments (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, fair value [Line Items]
Derivative asset, fair value, gross asset	$18,335	$1,950
Derivative liability, fair value, gross liability	0	7,483
Not designated as hedging instruments [Member] | Commodity derivatives | Commodity derivative instruments assets, current [Member]
Derivatives, fair value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	18,335	1,447
Not designated as hedging instruments [Member] | Commodity derivatives | Other assets noncurrent [Member]
Derivatives, fair value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	0	503
Not designated as hedging instruments [Member] | Commodity derivatives | Commodity derivative instruments liabilities [Member]
Derivatives, fair value [Line Items]
Other derivatives not designated as hedging instruments liabilities at fair value	$0	$7,483

Derivative_Instruments_Subject

Derivative Instruments Subject to master netting agreements (Details 4) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	$18,335	$1,950
Derivative liability, fair value, gross liability	0	7,483
Commodity derivative instruments assets [Member]
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	18,335	1,950
Gross amount not offset	0	-1,950
Derivative asset, fair value, net	18,335	0
Total assets [Member]
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	18,335	1,950
Gross amount not offset	0	-1,950
Derivative asset, fair value, net	18,335	0
Commodity derivatives - liabilities [Member]
Derivative instruments [Line Items]
Derivative liability, fair value, gross liability		7,483
Gross amount not offset		-1,950
Derivative liability, fair value, net		5,533
Total liabilities [Member]
Derivative instruments [Line Items]
Derivative liability, fair value, gross liability		7,483
Gross amount not offset		-1,950
Derivative liability, fair value, net		$5,533

Availableforsale_securities_De

Available-for-sale securities (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Available-for-sale securities [Line Items]
Investments used to satisfy obligations under nonqualified benefit plans	$65,800,000	$62,400,000
Net unrealized gain (loss) of investments used to satify obligations under nonqualified benefit plans	3,400,000	13,500,000	5,200,000
Available-for-sale securities:
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	10,168,000	10,057,000
Available-for-sale securities, gross unrealized gains	60,000	84,000
Available-for-sale securities, gross unrealized losses	-37,000	-31,000
Available-for-sale securities	10,191,000	10,110,000
Mortgage-backed securities
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	6,594,000	8,151,000
Available-for-sale securities, gross unrealized gains	60,000	69,000
Available-for-sale securities, gross unrealized losses	-18,000	-27,000
Available-for-sale securities	6,636,000	8,193,000
U.S. Treasury securities
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	3,574,000	1,906,000
Available-for-sale securities, gross unrealized gains	0	15,000
Available-for-sale securities, gross unrealized losses	-19,000	-4,000
Available-for-sale securities	$3,555,000	$1,917,000

Fair_value_measurements_Detail

Fair value measurements (Details 2) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Jun. 30, 2013
Concentration risks, percentage [Abstract]
Percentage investment in common stock of mid-cap companies	20.00%		29.00%
Percentage investment in common stock of small-cap companies	18.00%		28.00%
Percentage investment in common stock of large-cap companies	29.00%		28.00%
Percentage in fixed-income investments	32.00%		15.00%
Percentage investment in cash and cash equivalents	1.00%
Assets, fair value disclosure, nonrecurring					$9,700,000
Fair value, measurements, recurring [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	112,830,000		93,657,000
Liabilities:			7,483,000
Fair value, measurements, recurring [Member] | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:			7,483,000
Fair value, measurements, recurring [Member] | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	18,473,000		19,227,000
Fair value, measurements, recurring [Member] | Insurance contract [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	65,831,000	[1]	62,370,000	[2]
Fair value, measurements, recurring [Member] | Mortgage-backed securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	6,636,000		8,193,000
Fair value, measurements, recurring [Member] | U.S. Government securities [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	3,555,000		1,917,000
Fair value, measurements, recurring [Member] | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	18,335,000		1,950,000
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Liabilities:			0
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:			0
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Insurance contract [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0	[1]	0	[2]
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage-backed securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Government securities [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2)
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	112,830,000		93,657,000
Liabilities:			7,483,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:			7,483,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	18,473,000		19,227,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Insurance contract [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	65,831,000	[1]	62,370,000	[2]
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	6,636,000		8,193,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | U.S. Government securities [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	3,555,000		1,917,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	18,335,000		1,950,000
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3)
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Liabilities:			0
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:			0
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Insurance contract [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0	[1]	0	[2]
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Mortgage-backed securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | U.S. Government securities [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0		0
[1]	The insurance contract invests approximately 20 percent in common stock of mid-cap companies, 18 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies, 32 percent in fixed-income investments and 1 percent in cash equivalents.
[2]	The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

Fair_value_measurements_Detail1

Fair value measurements (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$2,094,727	$1,854,563
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$2,239,445	$1,912,590

Credit_facilities_Details

Credit facilities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		8-May-14	Dec. 31, 2013		Dec. 01, 2014
Line of credit facility and other debt [Abstract]
Letters of credit at end of period	$36.40
Long-term debt [Member] | Commercial paper revolving credit agreement [Member] | MDU Resources Group, Inc [Member]
Line of credit facility and other debt [Abstract]
Facility limit, maximum borrowing capacity	175		175
Amount outstanding, end of period	77.5	[1]		78.9	[1]
Expiration date	8-May-19
Long-term debt [Member] | Commercial paper revolving credit agreement [Member] | Centennial Energy Holdings, Inc [Member]
Line of credit facility and other debt [Abstract]
Facility limit, maximum borrowing capacity	650		650
Amount outstanding, end of period	211	[1]		75	[1]
Expiration date	8-May-19
Long-term debt [Member] | Revolving credit facility [Member] | MDU Resources Group, Inc [Member]
Line of credit facility and other debt [Abstract]
Letters of credit at end of period	0
Option to increase borrowings, maximum amount	225
Long-term debt [Member] | Revolving credit facility [Member] | Cascade Natural Gas Corporation [Member]
Line of credit facility and other debt [Abstract]
Facility limit, maximum borrowing capacity	50	[2]
Amount outstanding, end of period	0			11.5
Letters of credit at end of period	2.2	[3]
Expiration date	9-Jul-18
Option to increase borrowings, maximum amount	75
Long-term debt [Member] | Revolving credit facility [Member] | Intermountain Gas Company [Member]
Line of credit facility and other debt [Abstract]
Facility limit, maximum borrowing capacity	65	[4]
Amount outstanding, end of period	21			3
Letters of credit at end of period	0
Expiration date	13-Jul-18
Option to increase borrowings, maximum amount	90
Long-term debt [Member] | Revolving credit facility [Member] | Centennial Energy Holdings, Inc [Member]
Line of credit facility and other debt [Abstract]
Letters of credit at end of period	0
Option to increase borrowings, maximum amount	800
Short-term debt [Member] | Revolving credit facility [Member] | Dakota Prairie Refining, LLC [Member]
Line of credit facility and other debt [Abstract]
Facility limit, maximum borrowing capacity	50	[5]				50
Amount outstanding, end of period	0			0
Letters of credit at end of period	1	[3]
Expiration date	1-Dec-15
Option to increase borrowings, maximum amount	$75
[1]	Amount outstanding under commercial paper program.
[2]	Certain provisions allow for increased borrowings, up to a maximum of $75.0 million.
[3]	An outstanding letter of credit reduces the amount available under the credit agreement.
[4]	Certain provisions allow for increased borrowings, up to a maximum of $90.0 million.
[5]	Certain provisions allow for increased borrowings up to a maximum of $75.0 million.

Shortterm_borrowings_Details_2

Short-term borrowings (Details 2) (Revolving credit facility [Member], Short-term debt [Member], Dakota Prairie Refining, LLC [Member], USD $)	Dec. 31, 2014		Dec. 01, 2014
In Millions, unless otherwise specified
Revolving credit facility [Member] | Short-term debt [Member] | Dakota Prairie Refining, LLC [Member]
Short-term debt [Line Items]
Facility limit, maximum borrowing capacity	$50	[1]	$50
Ratio of total debt to total capitalization as specified in debt convenants.	65.00%
Ratio of total funded debt to total capitalization as specified in debt covenants	65.00%
[1]	Certain provisions allow for increased borrowings up to a maximum of $75.0 million.

Longterm_borrowings_Details_3

Long-term borrowings (Details 3) (USD $)	Dec. 31, 2014		8-May-14	Sep. 12, 2013	Jan. 15, 2015	Jan. 09, 2015
In Millions, unless otherwise specified
Debt instrument [Line Items]
Letters of credit	$36.40
MDU Resources Group, Inc [Member] | Commercial paper revolving credit agreement [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Facility limit, maximum borrowing capacity	175		175
Ratio of funded debt to total capitalization as specified in debt convenants	65.00%
Ratio of funded debt to capitalization - Company alone, as specified in debt convenants	65.00%
MDU Resources Group, Inc [Member] | Revolving credit facility [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Letters of credit	0
MDU Energy Capital, LLC [Member] | Master shelf agreement [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Ratio of total debt to adjusted total capitalization as specified in debt convenants	70.00%
Ratio of subsidiary debt to subsidiary capitalization as specified in debt convenants	65.00%
Ratio of total debt to total capitalization as specified in debt convenants.	65.00%
Ratio - EBIT to interest expense	150.00%
Cascade Natural Gas Corporation [Member] | Revolving credit facility [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Facility limit, maximum borrowing capacity	50	[1]
Ratio of total debt to total capitalization as specified in debt convenants.	65.00%
Letters of credit	2.2	[2]
Intermountain Gas Company [Member] | Revolving credit facility [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Facility limit, maximum borrowing capacity	65	[3]
Ratio of total debt to total capitalization as specified in debt convenants.	65.00%
Letters of credit	0
Centennial Energy Holdings, Inc [Member] | Commercial paper revolving credit agreement [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Facility limit, maximum borrowing capacity	650		650
Centennial Energy Holdings, Inc [Member] | Master shelf agreement [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Ratio of total debt to total capitalization as specified in debt convenants.	60.00%
Ratio of EBITDA to interest expense	175.00%
Centennial Energy Holdings, Inc [Member] | Revolving credit facility [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Ratio of total debt to total capitalization as specified in debt convenants.	65.00%
Letters of credit	0
WBI Energy Transmission, Inc. [Member] | Uncommitted Long Term Private Shelf Agreement [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Ratio of total debt to total capitalization as specified in debt convenants.	55.00%
Long-term private shelf agreement				175
Notes outstanding	100
Subsequent Event [Member] | Cascade Natural Gas Corporation [Member] | Senior notes [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Senior notes issued					25
Senior notes weighted average interest rate					4.20%
Subsequent Event [Member] | Centennial Energy Holdings, Inc [Member] | Letter of credit [Member] | Long-term debt [Member]
Debt instrument [Line Items]
Letters of credit						$28
[1]	Certain provisions allow for increased borrowings, up to a maximum of $75.0 million.
[2]	An outstanding letter of credit reduces the amount available under the credit agreement.
[3]	Certain provisions allow for increased borrowings, up to a maximum of $90.0 million.

Longterm_debt_outstanding_Deta

Long-term debt outstanding (Details 4) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Long-term debt maturities [Abstract]
2015	$269,400,000
2016	293,800,000
2017	51,000,000
2018	148,200,000
2019	345,700,000
Thereafter	986,600,000
Senior notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	5.43%
Commercial paper [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	0.37%
Term loan agreements [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	2.12%
Medium-term notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	7.32%
Other notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	5.23%
Loans payable [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	3.47%
Long-term debt [Member]
Long term debt outstanding [Abstract]
Long-term debt	2,094,727,000	1,854,563,000
Less current maturities	269,449,000	12,277,000
Long-term debt	1,825,278,000	1,842,286,000
Long-term debt [Member] | Senior notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	1,636,662,000	1,545,078,000
Long-term debt [Member] | Commercial paper [Member]
Long term debt outstanding [Abstract]
Long-term debt	288,500,000	153,924,000
Long-term debt [Member] | Term loan agreements [Member]
Long term debt outstanding [Abstract]
Long-term debt	72,000,000	75,000,000
Long-term debt [Member] | Medium-term notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	35,000,000	35,000,000
Long-term debt [Member] | Other notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	39,662,000	39,863,000
Long-term debt [Member] | Loans payable [Member]
Long term debt outstanding [Abstract]
Long-term debt	22,939,000	5,701,000
Long-term debt [Member] | Discount on commercial paper program [Member]
Long term debt outstanding [Abstract]
Long-term debt	($36,000)	($3,000)

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset retirement obligation [Roll Forward]
Balance, beginning of period	$98,529,000	$102,545,000
Liabilities incurred	5,416,000	5,610,000
Liabilities acquired	1,414,000	0
Asset retirement obligation, liabilities settled	-18,388,000	-22,257,000
Accretion expense	4,605,000	4,574,000
Revisions in estimates	884,000	7,671,000
Other	379,000	386,000
Balance, end of period	92,839,000	98,529,000
Fair value of assets legally restricted for purposes of settling asset retirement obligations	$2,300,000	$4,100,000

Preferred_Stocks_Details

Preferred Stocks (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Preferred stock redemption price upon liquidation (in dollars per share)	$100
Preferred stocks	$15,000	$15,000
Cumulative Preferred Stock, Par Value $100 Issuable in Series [Member]
Class of Stock [Line Items]
Authorized preferred cumulative shares (in shares)	500,000	500,000
Cumulative preferred shares, par value (in dollars per share)	$100	$100
Preferred stock, series 4.50% [Member]
Class of Stock [Line Items]
Preferred stock redemption price at the option of the company (in dollars per share)	$105
Preferred stocks	10,000	10,000
Preferred shares outstanding (in shares)	100,000	100,000
Preferred stock, $100 par value	4.50%	4.50%	4.50%
Preferred stock, dividends per share, declared	$4.50	$4.50	$4.50
Preferred stock, series 4.70% [Member]
Class of Stock [Line Items]
Preferred stock redemption price at the option of the company (in dollars per share)	$102
Preferred stocks	$5,000	$5,000
Preferred shares outstanding (in shares)	50,000	50,000
Preferred stock, $100 par value	4.70%	4.70%	4.70%
Preferred stock, dividends per share, declared	$4.70	$4.70	$4.70
Cumulative preferred stock A, without par value, issuable in series [Member]
Class of Stock [Line Items]
Authorized preferred cumulative shares (in shares)	1,000,000	1,000,000
Cumulative preference stock , without par value, issuable in series [Member]
Class of Stock [Line Items]
Authorized preferred cumulative shares (in shares)	500,000	500,000

Common_Stock_Details

Common Stock (Details) (USD $)	12 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Dividends declared per common share	$0.72	$0.70	$0.68
Company's subsidiaries net assets restricted from being used to transfer funds to the Company	$2,300,000,000
Credit agreement limitation on company ratio of funded debt to capitalization (excluding subsidiaries)	65.00%
Company's (excluding its subsidiaries) net assets restricted from use for dividend payments	$259,000,000
MDU Resources Group, Inc. [Member]
Shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan (in shares)	14.9
Centennial [Member]
Maximum distributions to the company as a percentage of consolidated net income after taxes, excluding noncash write-downs, for the preceding fiscal year (in hundredths)	100.00%

Stock_based_compensation_plans

Stock based compensation plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Y
Share-based Compensation [Abstract]
Share-based compensation arrangement, number of shares available for grant	5.6
Share-based compensation expense, net of tax	$4.40	$3.90	$4
Share-based compensation nonvested awards total compensation cost not yet recognized	$8
Share-based compensation, nonvested awards, total compensation cost not yet recognized, period for recognition	1.6

Stock_awards_Details_2

Stock awards (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Nonemployee director stock compensation plan [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Shares issued for stock-based compensation	43,088	36,713	53,888
Fair value of vested shares	$1,100,000	$1,100,000	$1,100,000
Long-term incentive plan [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Shares issued for stock-based compensation			43,103
Fair value of vested shares			$930,000

Performance_share_awards_Detai

Performance share awards (Details 3) (Performance shares [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based compensation arrangement by share-based payment award [Line Items]
Participant target grant of shares, percentage rate range, minimum	0.00%
Participant target grant of shares, percentage rate range, maximum	200.00%
Historical volatility rate	50.00%
Implied volatility rate	50.00%
Expected volatility rate, minimum	18.94%	16.10%	24.29%
Expected volatility rate, maximum	20.43%	19.39%	25.81%
Risk-free interest rate, minimum	0.03%	0.09%	0.10%
Risk-free interest rate, maximum	0.74%	0.40%	0.35%
Discounted dividends, per share	$2.15	$2.12	$1.19
Fair value of vested shares	$16,600,000	$0	$0
Nonvested at beginning of period	749,991
Nonvested at beginning of period	$21.99
Granted	196,840
Grant-date fair value	$41.13	$29.01	$17.18
Additional performance shares earned	236,699
Additional performance shares earned	$19.99
Vested	-491,213
Vested	$19.99
Forfeited	-3,862
Forfeited	$29.01
Nonvested at end of period	688,455	749,991
Nonvested at end of period	$28.16	$21.99
Grant date February 2012 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	251,196
Grant date March 2013 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	240,419
Grant date February 2014 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	196,840

Components_of_income_loss_befo

Components of income (loss) before income taxes from continuing operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
United States	$411,182	$415,202	($47,175)
Foreign	-52	416	1,708
Income (loss) before income taxes	$411,130	$415,618	($45,467)

Income_tax_expense_benefit_Det

Income tax expense (benefit) (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	$32,726	$45,518	($26,858)
State	5,390	4,311	858
Foreign	0	-29	-75
Current income taxes	38,116	49,800	-26,075
Deferred:
Federal	81,017	78,953	-1,224
State	4,989	8,031	-6,323
Investment tax credit - net	1,009	-206	44
Deferred income taxes	87,015	86,778	-7,503
Change in uncertain tax positions	-5,183	0	1,974
Change in accrued interest	21	158	458
Total income tax expense (benefit)	$119,969	$136,736	($31,146)

Components_of_deferred_tax_ass

Components of deferred tax assets and liabilities (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Valuation Allowance, Amount	$0	$0
Deferred tax assets:
Regulatory matters	134,567,000	125,607,000
Accrued pension costs	97,690,000	74,320,000
Alternative minimum tax credit carryforward	23,844,000	33,304,000
Compensation-related	38,654,000	31,550,000
Asset retirement obligations	34,296,000	29,578,000
Legal and environmental contingencies	10,049,000	10,710,000
Other	59,389,000	45,101,000
Total deferred tax assets	398,489,000	350,170,000
Deferred tax liabilities:
Depreciation and basis differences on property, plant and equipment	906,455,000	813,597,000
Basis differences on oil and natural gas producing properties	270,939,000	266,168,000
Regulatory matters	97,521,000	64,914,000
Intangible asset amortization	22,505,000	13,579,000
Other	29,676,000	26,170,000
Total deferred tax liabilities	1,327,096,000	1,184,428,000
Net deferred income tax liability	($928,607,000)	($834,258,000)

Deferred_tax_reconciliation_De

Deferred tax reconciliation (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Change in net deferred income tax liability from the preceding table	$94,349
Deferred taxes associated with other comprehensive loss	2,360
Other	-9,694
Deferred income taxes	$87,015	$86,778	($7,503)

Income_tax_expense_benefit_sta

Income tax expense (benefit) statutory rate versus actual rate (Details 5) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Computed tax at federal statutory rate
Computed tax at federal statutory rate	$143,895,000	$145,466,000	($15,914,000)
Federal statutory rate (in hundredths)	35.00%	35.00%	35.00%
Increases (reductions) resulting from:
State income taxes, net of federal income tax	10,483,000	10,524,000	2,469,000
State income tax rate (in hundredths)	2.50%	2.50%	-5.40%
Domestic production activities	-5,460,000	-677,000	0
Domestic production activities (in hundredths)	-1.30%	-0.20%	0.00%
Nonqualified benefit plans	-1,624,000	-5,173,000	-2,359,000
Nonqualified benefit plans (in hundredths)	-0.40%	-1.20%	5.20%
Depletion allowance	-4,010,000	-3,764,000	-3,728,000
Depletion allowance rate (in hundredths)	-1.00%	-0.90%	8.20%
Federal renewable energy credit	-3,655,000	-3,404,000	-3,401,000
Federal renewable energy credit rate (in hundreths)	-0.90%	-0.80%	7.50%
Deductible K-Plan dividends	-2,062,000	-1,593,000	-2,829,000
Deductible K-Plan dividends rate (in hundredths)	-0.50%	-0.40%	6.20%
AFUDC equity	-2,031,000	-1,074,000	-1,500,000
AFUDC equity rate (in hundredths)	-0.50%	-0.30%	3.30%
Resolution of tax matters and uncertain tax positions	-7,367,000	-859,000	2,559,000
Resolution of tax matters and uncertain tax positions rate (in hundredths)	-1.80%	-0.20%	-5.60%
Deferred tax rate changes	9,000	741,000	-3,083,000
Deferred tax rate changes rate (in hundredths)	0.00%	0.20%	6.80%
Other	-8,209,000	-3,451,000	-3,360,000
Other rate (in hundredths)	-1.90%	-0.80%	7.30%
Total income tax expense (benefit)	119,969,000	136,736,000	-31,146,000
Total income tax expense (benefit) rate (in hundredths)	29.20%	32.90%	68.50%
Temporary differences [Abstract]
Undistributed earnings from foreign operations	3,600,000
Deferred tax liabilities, undistributed foreign earnings	$1,400,000

Unrecognized_tax_benefits_Deta

Unrecognized tax benefits (Details 6) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$14,914,000	$14,914,000	$11,206,000
Additions for tax positions of prior years	0	0	3,708,000
Settlements	-14,777,000	0	0
Balance at end of year	137,000	14,914,000	14,914,000
Unrecognized tax benefits highly certain deductibility		8,400,000
Unrecognized tax benefits that would affect the effective tax rate	155,000	9,000,000
Unrecognized tax benefits, interest and penalties	18,000	2,500,000
Interest expense	1,800,000	1,200,000	740,000
Interest income	540,000	660,000	290,000
Accrued liability for payment of interest	$1,800,000	$2,800,000

Business_segment_data_Details

Business segment data (Details) (USD $)	3 Months Ended													12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012		Sep. 30, 2012	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Business segment data [Line Items]
External operating revenues	$1,163,204,000		$1,370,455,000	$1,094,046,000	$1,042,853,000	$1,184,423,000		$1,285,782,000	$1,060,595,000	$931,604,000				$4,670,558,000		$4,462,404,000		$4,075,431,000
Intersegment operating revenues														0		0		0
Depreciation, depletion and amortization														401,368,000		386,856,000		359,205,000
Interest expense														87,016,000		83,917,000		76,699,000
Income taxes														119,969,000		136,736,000		-31,146,000
Earnings (loss) on common stock before income (loss) from discontinued operations														294,371,000		278,560,000		-15,006,000
Income (loss) from discontinued operations, net of tax	2,672,000		3,000	547,000	-45,000	-58,000		-118,000	-59,000	-77,000				3,177,000	[1]	-312,000	[1]	13,567,000	[1]
Total earnings (loss) on common stock														297,548,000		278,248,000		-1,439,000
Net proceeds from sale or disposition of property and other														-306,994,000		-112,131,000		-57,460,000
Total net capital expenditures														843,690,000		728,070,000		933,777,000
Total assets	7,809,978,000					7,061,332,000					6,682,491,000			7,809,978,000		7,061,332,000		6,682,491,000
Property, plant and equipment	9,693,171,000					8,803,866,000								9,693,171,000		8,803,866,000
Less accumulated depreciation, depletion and amortization	4,166,407,000					3,872,487,000					3,608,912,000			4,166,407,000		3,872,487,000		3,608,912,000
Net property, plant and equipment	5,526,764,000					4,931,379,000					4,498,839,000			5,526,764,000		4,931,379,000		4,498,839,000
Additional information [Abstract]
Write-downs of oil and natural gas properties											231,700,000		160,100,000	0		0		391,800,000
Noncash write-down of natural gas and oil properties, after tax											145,900,000		100,900,000					246,800,000
Asset impairment charges									9,000,000							9,000,000		1,700,000
Reversal of an arbitration charge after tax						1,500,000										1,500,000		15,000,000
Net noncash inclusion of acct pay and NCI exclusion of capital expenditures														-61,200,000		-56,800,000		33,700,000
Electric:
Business segment data [Line Items]
External operating revenues														277,874,000		257,260,000		236,895,000
Intersegment operating revenues														0		0		0
Depreciation, depletion and amortization														35,008,000		32,789,000		32,509,000
Interest expense														15,595,000		12,590,000		12,421,000
Income taxes														12,442,000		9,683,000		8,975,000
Earnings (loss) on common stock before income (loss) from discontinued operations														36,731,000		34,837,000		30,634,000
Capital expenditures														185,121,000		168,557,000		112,035,000
Total assets	1,030,611,000	[2]				884,283,000	[2]				760,324,000	[2]		1,030,611,000	[2]	884,283,000	[2]	760,324,000	[2]
Property, plant and equipment	1,457,101,000	[2]				1,315,822,000	[2]				1,150,584,000	[2]		1,457,101,000	[2]	1,315,822,000	[2]	1,150,584,000	[2]
Natural gas distribution:
Business segment data [Line Items]
External operating revenues														921,986,000		851,945,000		754,848,000
Intersegment operating revenues														0		0		0
Depreciation, depletion and amortization														54,700,000		50,031,000		45,731,000
Interest expense														27,217,000		25,123,000		28,726,000
Income taxes														11,350,000		16,633,000		12,005,000
Earnings (loss) on common stock before income (loss) from discontinued operations														30,484,000		37,656,000		29,409,000
Capital expenditures														120,613,000		101,279,000		130,178,000
Total assets	1,931,908,000	[2]				1,786,068,000	[2]				1,703,459,000	[2]		1,931,908,000	[2]	1,786,068,000	[2]	1,703,459,000	[2]
Property, plant and equipment	1,904,759,000	[2]				1,776,901,000	[2]				1,689,950,000	[2]		1,904,759,000	[2]	1,776,901,000	[2]	1,689,950,000	[2]
Pipeline and energy services:
Business segment data [Line Items]
External operating revenues														166,496,000		155,369,000		139,883,000
Intersegment operating revenues														49,372,000		46,699,000		53,274,000
Depreciation, depletion and amortization														30,645,000		29,119,000		27,684,000
Interest expense														10,048,000		10,330,000		7,742,000
Income taxes														9,699,000		3,390,000		15,291,000
Earnings (loss) on common stock before income (loss) from discontinued operations														22,628,000		7,629,000		26,588,000
Capital expenditures														177,409,000		127,092,000		133,787,000
Total assets	1,081,902,000					798,701,000					622,470,000			1,081,902,000		798,701,000		622,470,000
Property, plant and equipment	1,220,233,000					962,172,000					816,533,000			1,220,233,000		962,172,000		816,533,000
Exploration and production:
Business segment data [Line Items]
External operating revenues														500,526,000		490,924,000		412,651,000
Intersegment operating revenues														47,045,000		45,099,000		35,966,000
Depreciation, depletion and amortization														198,199,000		186,458,000		160,681,000
Interest expense														13,834,000		14,315,000		9,018,000
Income taxes														47,739,000		53,197,000		-108,264,000
Earnings (loss) on common stock before income (loss) from discontinued operations														96,733,000		94,450,000		-177,283,000
Capital expenditures														600,572,000		391,315,000		554,528,000
Total assets	1,738,064,000					1,616,131,000					1,539,017,000			1,738,064,000		1,616,131,000		1,539,017,000
Property, plant and equipment	3,402,879,000					3,060,848,000					2,764,560,000			3,402,879,000		3,060,848,000		2,764,560,000
Construction materials and contracting:
Business segment data [Line Items]
External operating revenues														1,740,089,000		1,675,444,000		1,597,257,000
Intersegment operating revenues														25,241,000		36,693,000		20,168,000
Depreciation, depletion and amortization														68,557,000		74,470,000		79,527,000
Interest expense														16,368,000		17,394,000		15,211,000
Income taxes														18,586,000		24,765,000		14,099,000
Earnings (loss) on common stock before income (loss) from discontinued operations														51,510,000		50,946,000		32,420,000
Capital expenditures														37,896,000		34,607,000		45,083,000
Total assets	1,272,231,000					1,305,808,000					1,371,252,000			1,272,231,000		1,305,808,000		1,371,252,000
Property, plant and equipment	1,529,942,000					1,510,355,000					1,504,981,000			1,529,942,000		1,510,355,000		1,504,981,000
Construction services:
Business segment data [Line Items]
External operating revenues														1,062,055,000		1,029,909,000		932,013,000
Intersegment operating revenues														57,474,000		9,930,000		6,545,000
Depreciation, depletion and amortization														12,874,000		11,939,000		11,063,000
Interest expense														4,176,000		4,306,000		4,435,000
Income taxes														24,753,000		29,504,000		24,128,000
Earnings (loss) on common stock before income (loss) from discontinued operations														54,432,000		52,213,000		38,429,000
Capital expenditures														26,942,000		15,102,000		14,835,000
Total assets	454,602,000					450,614,000					429,547,000			454,602,000		450,614,000		429,547,000
Property, plant and equipment	144,395,000					134,948,000					130,624,000			144,395,000		134,948,000		130,624,000
Other
Business segment data [Line Items]
External operating revenues														1,532,000		1,553,000		1,884,000
Intersegment operating revenues														7,832,000		8,067,000		8,486,000
Depreciation, depletion and amortization														2,196,000		2,050,000		2,010,000
Interest expense														15,000		15,000		13,000
Income taxes														-1,119,000		2,433,000		2,620,000
Earnings (loss) on common stock before income (loss) from discontinued operations														7,461,000		5,136,000		4,797,000
Capital expenditures														2,131,000		2,249,000		791,000
Total assets	300,660,000	[3]				219,727,000	[3]				256,422,000	[3]		300,660,000	[3]	219,727,000	[3]	256,422,000	[3]
Property, plant and equipment	50,937,000					49,997,000					50,519,000			50,937,000		49,997,000		50,519,000
Eliminations
Business segment data [Line Items]
Intersegment operating revenues														-186,964,000		-146,488,000		-124,439,000
Depreciation, depletion and amortization														-811,000		0		0
Interest expense														-237,000		-156,000		-867,000
Income taxes														-3,481,000		-2,869,000		0
Earnings (loss) on common stock before income (loss) from discontinued operations														-5,608,000		-4,307,000		0
Property, plant and equipment	-17,075,000					-7,177,000					0			-17,075,000		-7,177,000		0
Regulated:
Business segment data [Line Items]
External operating revenues														1,366,356,000		1,264,574,000		1,131,626,000
Nonregulated:
Business segment data [Line Items]
External operating revenues														$3,304,202,000		$3,197,830,000		$2,943,805,000
[1]	Reflected in the Other category.
[2]	Includes allocations of common utility property.
[3]	Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

Change_in_benefit_obligations_

Change in benefit obligations and plan assets (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	$402,772	$459,111
Service cost	129	155	1,078
Interest cost	17,682	16,249	17,598
Plan participants' contributions	0	0
Actuarial (gain) loss	80,520	-44,551
Benefits paid	-25,766	-28,192
Benefit obligation at end of year	475,337	402,772	459,111
Change in net plan assets:
Fair value of plan assets at beginning of year	334,844	309,184
Actual gain on plan assets	24,500	35,539
Employer contribution	20,785	18,313
Plan participants' contributions	0	0
Benefits paid	-25,766	-28,192
Fair value of net plan assets at end of year	354,363	334,844	309,184
Funded status - (under) over	-120,974	-67,928
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	0	0
Other accrued liabilities (current)	0	0
Other liabilities (noncurrent)	-120,974	-67,928
Net amount recognized	-120,974	-67,928
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	207,430	135,061
Prior service cost (credit)	294	365
Total	207,724	135,426
Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	81,726	103,358
Service cost	1,518	1,675	1,747
Interest cost	3,521	3,215	4,166
Plan participants' contributions	1,399	1,472
Actuarial (gain) loss	18,024	-20,985
Benefits paid	-7,176	-7,009
Benefit obligation at end of year	99,012	81,726	103,358
Change in net plan assets:
Fair value of plan assets at beginning of year	84,543	74,361
Actual gain on plan assets	7,527	13,819
Employer contribution	1,293	1,900
Plan participants' contributions	1,399	1,472
Benefits paid	-7,176	-7,009
Fair value of net plan assets at end of year	87,586	84,543	74,361
Funded status - (under) over	-11,426	2,817
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	4,345	9,679
Other accrued liabilities (current)	-322	-381
Other liabilities (noncurrent)	-15,449	-6,481
Net amount recognized	-11,426	2,817
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	25,779	11,314
Prior service cost (credit)	-15,744	-17,137
Total	$10,035	($5,823)

Benefit_obligations_in_excess_

Benefit obligations in excess of plan assets (Details 2) (Pension Benefits, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$475,337	$402,772
Accumulated benefit obligation	475,337	402,772
Fair value of plan assets	$354,363	$334,844

Components_of_net_periodic_ben

Components of net periodic benefit cost (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Components of net periodic benefit cost (credit):
Service cost	$129	$155	$1,078
Interest cost	17,682	16,249	17,598
Expected return on assets	-21,218	-19,917	-23,536
Amortization of prior service cost (credit)	71	71	-46
Recognized net actuarial loss	4,869	7,173	7,070
Curtailment gain	0	0	-1,023
Amortization of net transition obligation	0	0	0
Net periodic benefit cost (credit), including amount capitalized	1,533	3,731	1,141
Less amount capitalized	388	727	937
Net periodic benefit cost (credit)	1,145	3,004	204
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	77,238	-60,173	19,982
Prior service cost (credit)	0	0	0
Amortization of actuarial loss	-4,869	-7,173	-7,070
Amortization of prior service (cost) credit	-71	-71	1,069
Amortization of net transition obligation	0	0	0
Total recognized in accumulated other comprehensive (income) loss	72,298	-67,417	13,981
Total recognized in net periodic benefit cost (credit) and accumulated other comprehensive (income) loss	73,443	-64,413	14,185
Other Postretirement Benefits
Components of net periodic benefit cost (credit):
Service cost	1,518	1,675	1,747
Interest cost	3,521	3,215	4,166
Expected return on assets	-4,617	-4,343	-4,890
Amortization of prior service cost (credit)	-1,393	-1,457	-1,438
Recognized net actuarial loss	649	1,814	2,134
Curtailment gain	0	0	0
Amortization of net transition obligation	0	0	2,128
Net periodic benefit cost (credit), including amount capitalized	-322	904	3,847
Less amount capitalized	-21	164	910
Net periodic benefit cost (credit)	-301	740	2,937
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	15,114	-30,461	1,863
Prior service cost (credit)	0	0	-11,418
Amortization of actuarial loss	-649	-1,814	-2,134
Amortization of prior service (cost) credit	1,393	1,457	1,438
Amortization of net transition obligation	0	0	-2,128
Total recognized in accumulated other comprehensive (income) loss	15,858	-30,818	-12,379
Total recognized in net periodic benefit cost (credit) and accumulated other comprehensive (income) loss	$15,557	($30,078)	($9,442)

Estimated_net_loss_and_prior_s

Estimated net loss and prior service credit (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, amortization of net gains (losses)	($7,100,000)
Defined benefit plan, amortization of net prior service cost (credit)	71,000
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, amortization of net gains (losses)	-1,800,000
Defined benefit plan, amortization of net prior service cost (credit)	($1,400,000)

Weighted_average_assumptions_D

Weighted average assumptions (Details 5)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Used to determine benefit obligation
Discount rate	3.70%	4.53%
Expected return on plan assets	7.00%	7.00%
Used to determine benefit cost
Discount rate	4.53%	3.65%
Expected return on plan assets	7.00%	7.00%
Other Postretirement Benefits
Used to determine benefit obligation
Discount rate	3.74%	4.48%
Expected return on plan assets	6.00%	6.00%
Rate of compensation increase	3.00%	3.00%
Used to determine benefit cost
Discount rate	4.48%	3.67%
Expected return on plan assets	6.00%	6.00%
Rate of compensation increase	3.00%	4.00%

Expected_rate_of_return_Detail

Expected rate of return (Details 6)	12 Months Ended
	Dec. 31, 2014
Equity securities [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target plan asset allocations range maximum	50.00%
Defined benefit plan, target plan asset allocations range minimum	40.00%
Equity securities [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target plan asset allocations range maximum	75.00%
Defined benefit plan, target plan asset allocations range minimum	65.00%
Fixed Income Securities [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target plan asset allocations range maximum	60.00%
Defined benefit plan, target plan asset allocations range minimum	50.00%
Fixed Income Securities [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target plan asset allocations range maximum	35.00%
Defined benefit plan, target plan asset allocations range minimum	25.00%

Health_care_rate_assumptions_a

Health care rate assumptions and cost trend rate (Details 7) (Other Postretirement Benefits, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate assumed for next year (minimum)	4.00%	6.00%
Health care trend rate assumed for next year (maximum)	7.00%	7.00%
Health care cost trend rate - ultimate (minimum)	5.00%	5.00%
Health care cost trend rate - ultimate (maximum)	6.00%	6.00%
Year In which ultimate trend rate achieved, (maximum)	2017	2017
Percentage excess over the health care cost trend rate that retiree contributions will generally increase each year	6.00%
Effect on total of service and interest cost components, one percentage point increase	$247
Effect on total of service and interest cost components, one percentage point decrease	-207
Effect on postretirement benefit obligations, one percentage point increase	4,489
Effect on postretirement benefit obligations, one percentage point decrease	($3,832)

Fair_value_Details_8

Fair value (Details 8)	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Number of investment managers of plan assets	15
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Number of investment managers of plan assets	1

Fair_value_pension_and_postret

Fair value - pension and postretirement (Details 9) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	$354,363,000		$334,844,000		$309,184,000
Percentage investment in common stock of large-cap U.S. companies	13.00%		19.00%
Percentage investment in US Government securities	13.00%		12.00%
Percentage investment in corporate bonds	23.00%		27.00%
Percentage investment in common stock of international companies	33.00%		13.00%
Percentage investment in other investments	18.00%		18.00%
Percentage investment in common stock of mid-cap U.S. companies			11.00%
Estimated future employer contributions in next fiscal year	3,900,000
Pension Benefits | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	5,631,000		9,406,000
Pension Benefits | Equity securities of U.S. companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	39,077,000		62,599,000
Pension Benefits | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	5,189,000		39,437,000
Pension Benefits | Collective and Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	209,852,000	[1]	158,748,000	[2]
Pension Benefits | Corporate debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	59,471,000		42,721,000
Pension Benefits | Municipal bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	10,462,000		7,561,000
Pension Benefits | U.S. Government securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	21,850,000		11,822,000
Pension Benefits | Total assets measured at fair value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	351,532,000		332,294,000
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities of U.S. companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	39,077,000		62,599,000
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	5,189,000		39,437,000
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Collective and Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	132,403,000	[1]	116,265,000	[2]
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Government securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	15,001,000		7,487,000
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Total assets measured at fair value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	191,670,000		225,788,000
Pension Benefits | Significant Other Observable Inputs (Level 2) | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	5,631,000		9,406,000
Pension Benefits | Significant Other Observable Inputs (Level 2) | Equity securities of U.S. companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Significant Other Observable Inputs (Level 2) | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Significant Other Observable Inputs (Level 2) | Collective and Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	77,449,000	[1]	42,483,000	[2]
Pension Benefits | Significant Other Observable Inputs (Level 2) | Corporate debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	59,471,000		42,721,000
Pension Benefits | Significant Other Observable Inputs (Level 2) | Municipal bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	10,462,000		7,561,000
Pension Benefits | Significant Other Observable Inputs (Level 2) | U.S. Government securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	6,849,000		4,335,000
Pension Benefits | Significant Other Observable Inputs (Level 2) | Total assets measured at fair value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	159,862,000		106,506,000
Pension Benefits | Significant Unobservable Inputs (Level 3) | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Significant Unobservable Inputs (Level 3) | Equity securities of U.S. companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Significant Unobservable Inputs (Level 3) | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Significant Unobservable Inputs (Level 3) | Collective and Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0	[1]	0	[2]
Pension Benefits | Significant Unobservable Inputs (Level 3) | Corporate debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Significant Unobservable Inputs (Level 3) | Municipal bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Significant Unobservable Inputs (Level 3) | U.S. Government securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Pension Benefits | Significant Unobservable Inputs (Level 3) | Total assets measured at fair value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	87,586,000		84,543,000		74,361,000
Percentage investment in common stock of large-cap U.S. companies	54.00%		55.00%
Percentage investment in US Government securities	11.00%		12.00%
Percentage investment in corporate bonds	10.00%		9.00%
Percentage investment in other investments	15.00%		8.00%
Percentage investment in mortgage backed securities	10.00%		8.00%
Percentage investment in common stock of mid-cap U.S. companies			8.00%
Estimated future employer contributions in next fiscal year	400,000
Other Postretirement Benefits | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,097,000		2,142,000
Other Postretirement Benefits | Equity securities of U.S. companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,614,000		2,802,000
Other Postretirement Benefits | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	25,000		221,000
Other Postretirement Benefits | Insurance investment contract
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	82,846,000	[3]	79,374,000	[4]
Other Postretirement Benefits | Total assets measured at fair value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	87,582,000		84,539,000
Other Postretirement Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,639,000		3,023,000
Other Postretirement Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Other Postretirement Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities of U.S. companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,614,000		2,802,000
Other Postretirement Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	25,000		221,000
Other Postretirement Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Insurance investment contract
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0	[3]	0	[4]
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	84,943,000		81,516,000
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,097,000		2,142,000
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) | Equity securities of U.S. companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) | Insurance investment contract
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	82,846,000	[3]	79,374,000	[4]
Other Postretirement Benefits | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Other Postretirement Benefits | Significant Unobservable Inputs (Level 3) | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Other Postretirement Benefits | Significant Unobservable Inputs (Level 3) | Equity securities of U.S. companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Other Postretirement Benefits | Significant Unobservable Inputs (Level 3) | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		0
Other Postretirement Benefits | Significant Unobservable Inputs (Level 3) | Insurance investment contract
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	$0	[3]	$0	[4]
[1]	Collective and mutual funds invest approximately 13 percent in common stock of large-cap U.S. companies, 13 percent in U.S. Government securities, 23 percent in corporate bonds, 33 percent in common stock of international companies and 18 percent in other investments.
[2]	Collective and mutual funds invest approximately 11 percent in common stock of mid-cap U.S. companies, 19 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Government securities, 27 percent in corporate bonds, 13 percent in common stock of international companies and 18 percent in other investments.
[3]	The insurance contract invests approximately 54 percent in common stock of large-cap U.S. companies, 11 percent in U.S. Government securities, 10 percent in mortgage-backed securities, 10 percent in corporate bonds and 15 percent in other investments.
[4]	The insurance contract invests approximately 55 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Government securities, 8 percent in mortgage-backed securities, 8 percent in common stock of mid-cap U.S. companies, 9 percent in corporate bonds and 8 percent in other investments.

Estimated_future_benefit_payme

Estimated future benefit payments and subsidies (Details 10) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments, next twelve months	$5,162
Prescription drug subsidy receipts, next twelve months	218
Expected future benefit payments, year two	5,186
Prescription drug subsidy receipts, year two	213
Expected future benefit payments, year three	5,262
Prescription drug subsidy receipts, year three	207
Expected future benefit payments, year four	5,329
Prescription drug subsidy receipts, Year Four	200
Expected future benefit payments, year five	5,344
Prescription drug subsidy receipts, year five	193
Expected future benefit payments, five fiscal years thereafter	26,714
Prescription drug subsidy receipts, after year five	836
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments, next twelve months	23,769
Expected future benefit payments, year two	24,025
Expected future benefit payments, year three	24,621
Expected future benefit payments, year four	25,064
Expected future benefit payments, year five	25,498
Expected future benefit payments, five fiscal years thereafter	$133,935

Nonqualified_defined_benefit_p

Nonqualified defined benefit plan (Details 11) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Investments in nonqualified benefit plans	$101,400,000	$98,100,000
Supplemental employee retirement plan, defined benefit [Member]
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Net periodic benefit cost	6,600,000	7,300,000	8,100,000
Projected benefit obligation	115,600,000	106,900,000
Accumulated benefit obligation	108,200,000	99,700,000
Discount rate to determine benefit obligation	3.51%	4.32%
Rate of compensation increase to determine benefit obligation	4.00%	4.00%
Discount rate to determine net periodic benefit cost	4.32%	3.44%
Rate of compensation increase to determine net periodic benefit cost	4.00%	3.00%
Expected future benefit payments, next twelve months	6,600,000
Expected future benefit payments, year two	6,500,000
Expected future benefit payments, year three	6,700,000
Expected future benefit payments, year four	7,100,000
Expected future benefit payments, year five	7,300,000
Expected future benefit payments, five fiscal years thereafter	$37,900,000

Defined_contribution_plans_Det

Defined contribution plans (Details 12) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Nonqualified Defined Contribution Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, cost recognized	$104,000	$25,000
Defined Contribution Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, cost recognized	$34,400,000	$33,200,000	$29,300,000

Employee_Benefit_Plans_Investm

Employee Benefit Plans Investments in nonqualified plans (Details 13) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Nonqualified Defined Benefit and Contribution Plan Investments [Line Items]
Investments in nonqualified benefit plans	$101.40	$98.10
Life insurance carried on plan participants [Member]
Nonqualified Defined Benefit and Contribution Plan Investments [Line Items]
Investments in nonqualified benefit plans	32.8	31.4
Equity securities [Member]
Nonqualified Defined Benefit and Contribution Plan Investments [Line Items]
Investments in nonqualified benefit plans	54.9	53.5
Other investments [Member]
Nonqualified Defined Benefit and Contribution Plan Investments [Line Items]
Investments in nonqualified benefit plans	$13.70	$13.20

Multiemployer_plans_Details_14

Multiemployer plans (Details 14) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Multiemployer Plans [Line Items]
Multiemployer plan red zone status funded percentage, maximum	65.00%
Multiemployer plan yellow zone status funded percentage, minimum	65.00%
Mulitiemployer plan yellow status funded percentage, maximum	80.00%
Multiemployer plan green zone status funded percentage, minimum	80.00%
MEPP withdrawal liability, after tax	$8,400,000
Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, withdrawal obligation	14,000,000
MEPP withdrawal liability, after tax	8,400,000
Multiemployer plan, period contributions	42,817,000		39,260,000		34,779,000
Edison Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	936061681
Multiemployer plan number	1
Multiemployer plans, certified zone status	Green		Green
Multiemployer plans, certified zone status, date	31-Dec-14		31-Dec-13
Multiemployer plans, funding improvement plan and rehabilitation plan	No
Multiemployer plan, period contributions	9,061,000		6,358,000		5,171,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	31-Dec-14	[1]
IBEW Local 38 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	346574238
Multiemployer plan number	1
Multiemployer plans, certified zone status	Yellow		Yellow
Multiemployer plans, certified zone status, date	30-Apr-14		30-Apr-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	777,000		1,041,000		2,771,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	23-Apr-17
IBEW Local No. 82 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	316127268
Multiemployer plan number	1
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	30-Jun-14		30-Jun-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	1,392,000		1,284,000		1,093,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	29-Nov-15
IBEW Local No. 246 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	346582842
Multiemployer plan number	1
Multiemployer plans, certified zone status	Yellow		Yellow
Multiemployer plans, certified zone status, date	31-May-14		31-May-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	694,000		1,848,000		1,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	31-Oct-17
IBEW Local 648 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	316134845
Multiemployer plan number	1
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	28-Feb-14		28-Feb-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	1,110,000		1,489,000		564,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	31-Aug-15
Laborers Pension Trust Fund for Northern California [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	946277608
Multiemployer plan number	1
Multiemployer plans, certified zone status	Yellow		Yellow
Multiemployer plans, certified zone status, date	31-May-14		31-May-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	663,000		921,000		567,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	30-Jun-16
National Electrical Benefit Fund [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	530181657
Multiemployer plan number	1
Multiemployer plans, certified zone status	Green		Green
Multiemployer plans, funding improvement plan and rehabilitation plan	No
Multiemployer plan, period contributions	6,476,000		5,883,000		5,603,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	30-Nov-19
OE Pension Trust Fund [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	946090764
Multiemployer plan number	1
Multiemployer plans, certified zone status	Red		Yellow
Multiemployer plans, certified zone status, date	31-Dec-14
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	1,445,000		1,510,000		1,156,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date, first	15-Jun-15
Multiemployer plans, collective-bargaining arrangement, expiration date, last	30-Jun-16
Operating Engineers Local 800 and WY Contractors Association Pension Plan for WY [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	836011320	[2]
Multiemployer plan number	1
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	31-Dec-14		31-Dec-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	68,000		76,000		91,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date			31-Oct-05	[1]
Operating Engineers Pension Trust [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	956032478
Multiemployer plan number	1
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	30-Jun-14		30-Jun-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	612,000		493,000		761,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	1-Jul-16
Sheet Metal Workers Pension Plan of Southern CA, AZ, and NV [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	956052257
Multiemployer plan number	1
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	31-Dec-14		31-Dec-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	676,000		512,000		467,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	30-Jun-15
Southwest Marine Pension Trust [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	956123404
Multiemployer plan number	1
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	31-Dec-14		31-Dec-13
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	31,000		42,000		76,000
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date, first	31-Jan-14	[1]
Multiemployer plans, collective-bargaining arrangement, expiration date, last	31-Jan-19
Other funds [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions	$19,812,000		$17,803,000		$16,458,000
[1]	Plan includes collective bargaining agreements which have expired. The agreements contain provisions that automatically renew the existing contracts in lieu of a new negotiated collective bargaining agreement.
[2]	The Company withdrew from the plan as of October 26, 2014, as discussed below.

Multiemployer_other_postretire

Multiemployer other postretirement and defined contribution plans (Details 15) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Multiemployer Plans, Defined Contribution [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions	$22,000	$20,600	$18,700
Multiemployer Plans, Postretirement Benefit [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions	$34,600	$37,100	$31,400

Jointly_owned_facilities_Detai

Jointly owned facilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Big Stone Station:
Jointly owned facilities [Line Items]
Utility plant in service	$64,283	$63,890
Less accumulated depreciation	43,043	41,323
Utility plant in services net	21,240	22,567
Coyote Station:
Jointly owned facilities [Line Items]
Utility plant in service	138,810	138,261
Less accumulated depreciation	94,443	89,528
Utility plant in services net	44,367	48,733
Wygen III:
Jointly owned facilities [Line Items]
Utility plant in service	65,597	64,332
Less accumulated depreciation	5,928	4,639
Utility plant in services net	$59,669	$59,693

Recovered_Sheet1

Regulatory matters and revenues subject to refund (Details) (USD $)	0 Months Ended
	Aug. 11, 2014	Oct. 03, 2014	Feb. 03, 2015	Jan. 07, 2015	Feb. 06, 2015
MTPSC [Member]
Regulatory matters and revenues subject to refund [Line Items]
Total gas rate increase requested	$3,000,000
Percent above current rates requested	3.60%
WYPSC [Member]
Regulatory matters and revenues subject to refund [Line Items]
Total gas rate increase requested		788,000
Percent above current rates requested		4.10%
Subsequent Event [Member] | MTPSC [Member]
Regulatory matters and revenues subject to refund [Line Items]
Interim rate increase (decrease), amount			2,000,000
Interim rate increase (decrease), percent			2.30%
Subsequent Event [Member] | NDPSC-Generation [Member]
Regulatory matters and revenues subject to refund [Line Items]
Approved rate adjustment increase (decrease), amount				5,300,000
Subsequent Event [Member] | NDPSC [Member]
Regulatory matters and revenues subject to refund [Line Items]
Total gas rate increase requested					4,300,000
Percent above current rates requested					3.40%
Amount of requested interim increase in annual gas rates					$4,300,000
Requested percentage of interim gas rate increase					3.40%

Commitments_contingencies_and_

Commitments, contingencies and litigation (Details) (USD $)	0 Months Ended	3 Months Ended
	Aug. 06, 2012	Jun. 30, 2012	Sep. 30, 2010	Dec. 31, 2014	Dec. 31, 2013	Aug. 31, 2011	Oct. 31, 2010
Loss Contingencies [Line Items]
Potential liabilities related to litigation and environmental matters				$27,600,000	$29,500,000
Litigation related to construction materials [Member]
Loss Contingencies [Line Items]
Loss contingency, estimate of possible loss						3,700,000
Additional amount per day of potential penalties						5,000
Former employee litigation [Member]
Loss Contingencies [Line Items]
Plaintiffs request compensatory damages	23,800,000
Natural gas gathering operations [Member]
Loss Contingencies [Line Items]
Arbitration award							26,600,000
Amount of expense (benefit) recorded in operation and maintenance expense related to natural gas gathering contract dispute, before tax		-24,100,000	26,600,000
Amount of expense (benefit) recorded in operation and maintenance expense related to natural gas gathering contract dispute, after tax		($15,000,000)	$16,500,000

Enviromental_matters_Details_2

Enviromental matters (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014
Portland Harbor site [Member]
Site Contingency [Line Items]
Environmental matters investigative costs	$70,000,000
Eugene, OR manufactured gas plant site [Member]
Site Contingency [Line Items]
Site contingency, low estimate, loss exposure	500,000
Site contingency, high estimate, loss exposure	11,000,000
Estimated proportional share of cleanup liability	50.00%
Accrual for environmental loss contingencies	1,700,000
Bremerton, WA manufactured gas plant site [Member]
Site Contingency [Line Items]
Site contingency, low estimate, loss exposure	340,000
Site contingency, high estimate, loss exposure	6,400,000
Accrual for environmental loss contingencies	12,500,000
Bellingham, WA manufactured gas plant site [Member]
Site Contingency [Line Items]
Site contingency, loss exposure not accrued, best estimate	$8,000,000

Operating_leases_Details_3

Operating leases (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Leases, Annual minimum lease payments due [Abstract]
2015	$48.10
2016	43.5
2017	34.3
2018	28.1
2019	19.7
Thereafter	78.7
Rent expense
Rent expense	$53.70	$48.10	$42.90

Purchase_commitments_Details_4

Purchase commitments (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Term of unrecorded unconditional purchase obligation	one to 46 years
Purchase commitments due
2015	$694.70
2016	304.6
2017	161
2018	91
2019	86.4
Thereafter	910.6
Amounts purchased under various commitments	$925.20	$861.80	$718.40

Guarantees_Details_5

Guarantees (Details 5) (USD $)	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Amount of hedging obligations guaranteed reflected on balance sheet	$0
Guarantor obligations, maximum exposure, undiscounted	86,700,000
Fixed maximum amounts guaranteed by year 2015	66,900,000
Fixed maximum amounts guaranteed by year 2016	700,000
Fixed maximum amounts guaranteed by year 2017	600,000
Fixed maximum amounts guaranteed by year 2018	500,000
Fixed maximum amounts guaranteed by year 2019	500,000
Expires on a specified number of days after the receipt of written notice	13,500,000
Fixed maximum amounts guaranteed by year no maturity date	4,000,000
Amount outstanding under guarantees that are reflected on balance sheet	200,000
Letters of credit	36,400,000
Outstanding letters of credit	0
Natural gas transportation and storage agreement fixed maximum amount of performance guarantee of a related party	4,000,000
The amount outstanding by a related party under the guarantee	1,100,000
Amount of surety bonds outstanding	$423,500,000

Variable_interest_entities_Det

Variable interest entities (Details 6) (USD $)	Dec. 31, 2014	Dec. 01, 2014	Dec. 31, 2013
Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Percent of ownership	50.00%
Total project costs	$300,000,000
Portion of capital commitment	150,000,000
Partner portion of capital commitment	75,000,000
Excess capital commitments	300,000,000
Estimated project cost	400,000,000
Term loan for project debt financing	75,000,000
Facility limit, maximum borrowing capacity		50,000,000
Fuel contract [Member]
Variable Interest Entities [Line Items]
Variable interest entity, reporting entity involvement, maximum loss exposure, amount	15,800,000
WBI Holdings [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Percent of credit agreement guaranteed		50.00%
Noncontrolling interest | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Percent of credit agreement guaranteed		50.00%
Cash and cash equivalents [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	21,376,000		4,774,000
Accounts receivable [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	2,759,000		0
Inventories [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	5,311,000		0
Other current assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	4,019,000		26,000
Total current assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	33,465,000		4,800,000
Net property, plant and equipment [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	398,984,000		172,073,000
Other [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	3,400,000		0
Total deferred charges and other assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	3,400,000		0
Total assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	435,849,000		176,873,000
Long-term debt due within one year [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	3,000,000		3,000,000
Accounts payable [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	55,089,000		8,904,000
Taxes payable [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	648,000		5,000
Accrued compensation [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	727,000		26,000
Other accrued liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	899,000		461,000
Total current liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	60,363,000		12,396,000
Long-term debt [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	69,000,000		72,000,000
Total liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	$129,363,000		$84,396,000

Quarterly_Financial_Informatio1

Quarterly Financial Information (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$1,163,204,000	$1,370,455,000	$1,094,046,000	$1,042,853,000	$1,184,423,000	$1,285,782,000	$1,060,595,000	$931,604,000	$4,670,558,000		$4,462,404,000		$4,075,431,000
Total operating expenses	1,053,582,000	1,193,690,000	995,112,000	939,949,000	1,037,306,000	1,135,909,000	969,217,000	827,073,000	4,182,333,000		3,969,505,000		4,056,224,000
Operating income	109,622,000	176,765,000	98,934,000	102,904,000	147,117,000	149,873,000	91,378,000	104,531,000	488,225,000		492,899,000		19,207,000
Income from continuing operations	80,079,000	102,118,000	52,780,000	56,184,000	91,348,000	84,550,000	46,392,000	56,592,000	291,161,000		278,882,000		-14,321,000
Income (loss) from discontinued operations, net of tax	2,672,000	3,000	547,000	-45,000	-58,000	-118,000	-59,000	-77,000	3,177,000	[1]	-312,000	[1]	13,567,000	[1]
Net income (loss) attributable to parent	84,256,000	103,209,000	54,106,000	56,662,000	91,450,000	84,456,000	46,512,000	56,515,000
Earnings (loss) per common share - basic [Abstract]
Earnings before discontinued operations	$0.42	$0.53	$0.28	$0.30	$0.48	$0.45	$0.25	$0.30	$1.53		$1.47		($0.08)
Discontinued operations, net of tax	$0.01	$0	$0	$0	$0	$0	$0	$0	$0.02		$0		$0.07
Earnings (loss) per common share - basic	$0.43	$0.53	$0.28	$0.30	$0.48	$0.45	$0.25	$0.30	$1.55		$1.47		($0.01)
Earnings per common share - diluted [Abstract]
Earnings before discontinued operations	$0.42	$0.53	$0.28	$0.30	$0.48	$0.44	$0.24	$0.30	$1.53		$1.47		($0.08)
Discontinued operations, net of tax	$0.01	$0	$0	$0	$0	$0	$0	$0	$0.02		$0		$0.07
Earnings (loss) per common share - diluted	$0.43	$0.53	$0.28	$0.30	$0.48	$0.44	$0.24	$0.30	$1.55		$1.47		($0.01)
Weighted average common shares outstanding - basic	194,136	193,949	192,060	189,820	188,929	188,831	188,831	188,831	192,507		188,855		188,826
Weighted average common shares outstanding - diluted	194,219	194,300	192,659	190,432	189,766	189,638	189,463	189,222	192,587		189,693		188,826
Unrealized gain (loss) on commodity derivatives	4,100,000	18,100,000	-3,300,000	-4,300,000	-500,000	-7,900,000	8,200,000	-3,700,000
MEPP withdrawal liability, after tax	8,400,000								8,400,000
Asset impairment charges							9,000,000				9,000,000		1,700,000
Reversal of an arbitration charge after tax					$1,500,000						$1,500,000		$15,000,000
[1]	Reflected in the Other category.

Capitalized_costs_and_ADD_rela

Capitalized costs and AD&D related to oil and natural gas producing activities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Subject to amortization	$3,205,036	$2,893,010	$2,531,562
Not subject to amortization	132,141	124,869	191,794
Total capitalized costs	3,337,177	3,017,879	2,723,356
Less accumulated depreciation, depletion and amortization	1,752,566	1,562,116	1,383,386
Net capitalized costs	$1,584,611	$1,455,763	$1,339,970

Capital_expenditures_related_t

Capital expenditures related to oil and natural gas producing activities (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Acquisitions:
Proved properties	$87,919,000	[1]	$1,817,000	[1]	$839,000	[1]
Unproved properties	138,683,000	[1]	4,608,000	[1]	31,109,000	[1]
Exploration	16,879,000	[1]	26,975,000	[1]	235,906,000	[1]
Development	331,400,000	[1]	355,421,000	[1]	275,959,000	[1]
Total capital expenditures	574,881,000	[1]	388,821,000	[1]	543,813,000	[1]
Net change in property, plant and equipment related to future liabilities for asset retirement obligations that are excluded	-9,000,000		-10,700,000		-200,000
Proceeds from sale of oil and gas property and equipment	$246,600,000		$83,600,000		$6,000,000
[1]	Excludes net additions/(reductions) to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of oil and natural gas wells, as discussed in Note 10, of $(9.0) million, $(10.7) million and $(200,000) for the years ended December 31, 2014, 2013 and 2012, respectively.

Income_resulting_from_oil_and_

Income resulting from oil and natural gas producing activites (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues:
Sales to affiliates	$47,045,000		$45,099,000		$35,966,000
Sales to external customers	468,668,000		497,018,000		379,647,000
Realized gain on commodity derivatives	8,458,000		173,000		33,628,000
Unrealized (gain) loss on commodity derivatives	23,400,000		-6,267,000		-624,000
Production costs	146,793,000		144,136,000		134,795,000
Depreciation, depletion and amortization	193,944,000	[1]	182,352,000	[1]	157,078,000	[1]
Write-downs of oil and natural gas properties	0		0		391,800,000
Pretax income (loss)	206,834,000		209,535,000		-235,056,000
Income tax expense (benefit)	75,483,000		75,836,000		-88,612,000
Results of operations for producing activities	131,351,000		133,699,000		-146,444,000
Accretion of discount for asset retirement obligations oil and gas	$3,500,000		$3,600,000		$3,300,000
[1]	Includes accretion of discount for asset retirement obligations of $3.5 million, $3.6 million and $3.3 million for the years ended December 31, 2014, 2013 and 2012, respectively, as discussed in Note 10.

Estimated_quantities_of_proved

Estimated quantities of proved reserves (Details 4)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBoe	MBoe	MBoe
Proved developed and undeveloped reserves:
Balance at beginning of year, BOE	80,695	80,486	97,651
Production, BOE	-8,998	-10,264	-10,058
Extensions and discoveries, BOE	24,025	19,050	14,756
Improved recovery, BOE	0	0	0
Purchases of proved reserves, BOE	6,748	0	0
Sales revisions, BOE	-14,796	-7,987	-423
Revisions of previous estimate, BOE	4,266	-590	-21,440
Balance at end of year, BOE	91,940	80,695	80,486
Oil (MBbls)
Proved developed and undeveloped reserves:
Balance at beginning of year	41,019	33,453	27,005
Production	-4,919	-4,815	-3,694
Extensions and discoveries	9,654	13,313	9,874
Improved recovery	0	0	0
Purchases of proved reserves	5,463	0	0
Sales of proved reserves	-4,945	-1,286	-39
Revisions of previous estimates	-2,354	354	307
Balance at end of year	43,918	41,019	33,453
NGL (MBbls)
Proved developed and undeveloped reserves:
Balance at beginning of year	6,602	7,153	7,342
Production	-609	-781	-828
Extensions and discoveries	3,634	1,333	1,817
Improved recovery	0	0	0
Purchases of proved reserves	0	0	0
Sales of proved reserves	-3,109	-25	0
Revisions of previous estimates	669	-1,078	-1,178
Balance at end of year	7,187	6,602	7,153
Natural Gas (MMcf)
Proved developed and undeveloped reserves:
Balance at beginning of year	198,445	239,278	379,827
Production	-20,822	-28,008	-33,214
Extensions and discoveries	64,420	26,428	18,386
Improved recovery	0	0	0
Purchases of proved reserves	7,711	0	0
Sales of proved reserves	-40,451	-40,055	-2,307
Revisions of previous estimates	35,708	802	-123,414
Balance at end of year	245,011	198,445	239,278

Proved_reserves_Details_5

Proved reserves (Details 5) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified	MBoe	MBoe	MBoe	MBoe
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, energy	65,086	66,140	69,131
Proved undeveloped reserves, energy	26,854	14,555	11,355
Balance at end of year, energy	91,940	80,695	80,486	97,651
Changes in proved and undeveloped reserves [Abstract]
Change in PUD reserve	12,300
New PUD reserves	21,200
Acquired PUD Reserves	3,900
Converting PUD reserves	3,700
Divested PUD Reserves	6,400
Revision to PUD reserves	-2,700
Drilling, completion and future development costs [Abstract]
Drilling and completion capital	$98.30
Future development costs estimated to be spent to develop PUD reserves year one	141.8
Future development costs estimated to be spent to develop PUD reserves year two	157.4
Future development costs estimated to be spent to develop PUD reserves year three	$120.90
Oil (MBbls)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume	30,130	31,394	27,412
Proved undeveloped reserves, volume	13,788	9,625	6,041
Balance at end of year, volume	43,918	41,019	33,453	27,005
NGL (MBbls)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume	4,217	5,322	5,342
Proved undeveloped reserves, volume	2,970	1,280	1,811
Balance at end of year, volume	7,187	6,602	7,153	7,342
Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume	184,437	176,546	218,259
Proved undeveloped reserves, volume	60,574	21,899	21,019
Balance at end of year, volume	245,011	198,445	239,278	379,827

Estimated_discounted_future_ca

Estimated discounted future cash flows of total proved reserves (Details 6) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$5,185,500	$4,507,000	$3,696,200
Future production costs	1,856,900	1,734,800	1,536,500
Future development costs	570,200	403,000	301,600
Future net cash flows before income taxes	2,758,400	2,369,200	1,858,100
Future income tax expense	686,100	545,200	304,900
Future net cash flows	2,072,300	1,824,000	1,553,200
10% annual discount for estimated timing of cash flows	997,400	810,000	669,800
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$1,074,900	$1,014,000	$883,400	$978,800

Change_in_discounted_future_ne

Change in discounted future net cash flows (Details 7) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Change in the standardized measure of discounted future net cash flows [Roll Forward]
Beginning of year	$1,014,000	$883,400	$978,800
Net revenues from production	-368,900	-398,000	-280,800
Net change in sales prices and production costs related to future production	86,300	162,200	-406,300
Extensions and discoveries, net of future production-related costs	231,900	366,500	355,300
Improved recovery, net of future production-related costs	0	0	0
Purchases of proved reserves, net of future production-related costs	103,800	0	0
Sales of proved reserves	-219,300	-37,800	-2,600
Changes in estimated future development costs	65,100	6,700	37,600
Development costs incurred during the current year	104,600	141,500	77,700
Accretion of discount	109,400	94,600	121,400
Net change in income taxes	-33,400	-141,400	110,000
Revisions of previous estimates	-16,300	-55,800	-100,700
Other	-2,300	-7,900	-7,000
Net change	60,900	130,600	-95,400
End of year	$1,074,900	$1,014,000	$883,400

Condensed_Statements_of_Income

Condensed Statements of Income and Comprehensive Income (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Operating revenues	$1,163,204	$1,370,455	$1,094,046	$1,042,853	$1,184,423	$1,285,782	$1,060,595	$931,604	$4,670,558	$4,462,404	$4,075,431
Operating expenses	1,053,582	1,193,690	995,112	939,949	1,037,306	1,135,909	969,217	827,073	4,182,333	3,969,505	4,056,224
Operating income	109,622	176,765	98,934	102,904	147,117	149,873	91,378	104,531	488,225	492,899	19,207
Other income									9,962	6,768	6,642
Interest expense									87,016	83,917	76,699
Income (loss) before income taxes									411,130	415,618	-45,467
Income taxes									119,969	136,736	-31,146
Net income (loss) attributable to parent	84,256	103,209	54,106	56,662	91,450	84,456	46,512	56,515
Earnings (loss) on common stock									297,548	278,248	-1,439
Comprehensive income (loss)									294,335	289,449	-2,474
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Operating revenues									628,578	549,239	472,302
Operating expenses									547,820	473,917	405,095
Operating income									80,758	75,322	67,207
Other income									5,271	3,709	3,925
Interest expense									21,055	17,386	17,297
Income (loss) before income taxes									64,974	61,645	53,835
Income taxes									16,819	13,520	11,798
Equity in earnings of subsidiaries									250,078	230,808	-42,791
Net income (loss) attributable to parent									298,233	278,933	-754
Dividends declared on preferred stocks									685	685	685
Earnings (loss) on common stock									297,548	278,248	-1,439
Comprehensive income (loss)									$294,335	$289,449	($2,474)

Condensed_Balance_Sheets_Detai

Condensed Balance Sheets (Details 2) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Thousands, except Share data, unless otherwise specified
Current assets:
Cash and cash equivalents	$81,855		$45,225		$49,042		$162,772
Receivables, net	693,318		713,067
Inventories	300,811		282,391
Deferred income taxes	23,806		25,048
Prepayments and other current assets	76,848		49,510
Total current assets	1,194,973		1,116,688
Investments	117,920		112,939
Property, plant and equipment	9,693,171		8,803,866
Less accumulated depreciation, depletion and amortization	4,166,407		3,872,487		3,608,912
Net property, plant and equipment	5,526,764		4,931,379		4,498,839
Deferred charges and other assets:
Goodwill	635,204	[1]	636,039	[1]	636,039	[1]
Other	325,277		251,188
Total deferred charges and other assets	970,321		900,326
Total assets	7,809,978		7,061,332		6,682,491
Current liabilities:
Long-term debt due within one year	269,449		12,277
Accounts payable	382,671		404,961
Taxes payable	45,631		74,175
Dividends payable	35,607		33,737
Accrued compensation	62,775		69,661
Other accrued liabilities	172,561		171,106
Total current liabilities	968,694		784,900
Long-term debt	1,825,278		1,842,286
Deferred credits and other liabilities:
Deferred income taxes	952,413		859,306
Other liabilities	813,809		718,938
Total deferred credits and other liabilities	1,766,222		1,578,244
Equity:
Preferred stocks	15,000		15,000
Authorized - 500,000,000 shares, $1.00 par value
Issued - 194,754,812 shares in 2014 and 189,868,780 shares in 2013	194,755		189,869
Other paid-in capital	1,207,188		1,056,996
Retained earnings	1,762,827		1,603,130
Accumulated other comprehensive loss	-42,103		-38,205		-48,721
Treasury stock at cost - 538,921 shares	-3,626		-3,626
Total common stockholders' equity	3,119,041		2,808,164
Total stockholders' equity	3,134,041		2,823,164
Total liabilities and equity	7,809,978		7,061,332
Condensed Balance Sheet (Parenthetical)
Common stock, shares authorized	500,000,000		500,000,000
Common stock, par value	$1		$1
Common stock, shares issued	194,754,812		189,868,780
Treasury stock, shares	538,921		538,921
MDU Resources Group, Inc. [Member]
Current assets:
Cash and cash equivalents	6,120		5,051		3,596		6,900
Receivables, net	91,493		88,529
Accounts receivable from subsidiaries	32,691		31,372
Inventories	33,584		29,312
Deferred income taxes	547		3,196
Prepayments and other current assets	70,852		14,231
Total current assets	235,287		171,691
Investments	64,446		60,687
Investment in subsidiaries	2,590,283		2,380,829
Property, plant and equipment	1,984,956		1,785,861
Less accumulated depreciation, depletion and amortization	660,026		660,693
Net property, plant and equipment	1,324,930		1,125,168
Deferred charges and other assets:
Goodwill	4,812		4,812
Other	163,408		121,253
Total deferred charges and other assets	168,220		126,065
Total assets	4,383,166		3,864,440
Current liabilities:
Long-term debt due within one year	109		109
Accounts payable	48,088		45,282
Accounts payable to subsidiaries	30,863		4,839
Taxes payable	10,583		12,337
Dividends payable	35,607		33,737
Accrued compensation	11,227		16,076
Other accrued liabilities	36,488		28,042
Total current liabilities	172,965		140,422
Long-term debt	508,164		434,598
Deferred credits and other liabilities:
Deferred income taxes	251,067		205,639
Other liabilities	316,929		260,617
Total deferred credits and other liabilities	567,996		466,256
Equity:
Preferred stocks	15,000		15,000
Authorized - 500,000,000 shares, $1.00 par value
Issued - 194,754,812 shares in 2014 and 189,868,780 shares in 2013	194,755		189,869
Other paid-in capital	1,207,188		1,056,996
Retained earnings	1,762,827		1,603,130
Accumulated other comprehensive loss	-42,103		-38,205
Treasury stock at cost - 538,921 shares	-3,626		-3,626
Total common stockholders' equity	3,119,041		2,808,164
Total stockholders' equity	3,134,041		2,823,164
Total liabilities and equity	$4,383,166		$3,864,440
Condensed Balance Sheet (Parenthetical)
Common stock, shares authorized	500,000,000		500,000,000
Common stock, par value	$1		$1
Common stock, shares issued	194,754,812		189,868,780
Treasury stock, shares	538,921		538,921
[1]	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

Condensed_Statements_of_Cash_F

Condensed Statements of Cash Flows (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$615,782	$742,193	$584,740
Capital expenditures	-972,102	-909,400	-872,920
Net proceeds from sale or disposition of property and other	276,415	124,541	40,110
Investments	709	302	9,725
Net cash used in investing activities	-904,191	-782,661	-887,952
Issuance of long-term debt	606,084	507,924	467,957
Repayment of long-term debt	-368,803	-423,707	-138,775
Proceeds from issuance of common stock	150,060	14,554	88
Dividends paid	-136,712	-98,405	-159,768
Excess tax benefit on stock-based compensation	4,729	0	26
Tax withholding on stock-based compensation	-5,564	0	0
Net cash provided by financing activities	325,194	36,866	189,628
Increase (decrease) in cash and cash equivalents	36,630	-3,817	-113,730
Cash and cash equivalents - beginning of year	45,225	49,042	162,772
Cash and cash equivalents - end of year	81,855	45,225	49,042
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	208,208	188,259	225,968
Capital expenditures	-223,251	-211,013	-150,337
Net proceeds from sale or disposition of property and other	1,552	20,624	1,120
Investments in and advances to subsidiaries	-134,451	-1,016	-1,387
Advances from subsidiaries	64,500	10,000	5,000
Investments	-794	613	12
Net cash used in investing activities	-292,444	-180,792	-145,592
Issuance of long-term debt	148,959	77,924	76,000
Repayment of long-term debt	-76,432	-85	-21
Proceeds from issuance of common stock	150,060	14,554	88
Dividends paid	-136,712	-98,405	-159,768
Excess tax benefit on stock-based compensation	3,326	0	21
Tax withholding on stock-based compensation	-3,896	0	0
Net cash provided by financing activities	85,305	-6,012	-83,680
Increase (decrease) in cash and cash equivalents	1,069	1,455	-3,304
Cash and cash equivalents - beginning of year	5,051	3,596	6,900
Cash and cash equivalents - end of year	$6,120	$5,051	$3,596

Notes_to_Condensed_Financial_S

Notes to Condensed Financial Statements (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
2015	$269,400,000
2016	293,800,000
2017	51,000,000
2018	148,200,000
2019	345,700,000
Thereafter	986,600,000
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Long-term debt	508,300,000
2015	100,000
2016	50,100,000
2017	100,000
2018	100,000,000
2019	77,500,000
Thereafter	280,500,000
Cash dividends paid to parent company by consolidated subsidiaries	$105,600,000	$77,600,000	$125,800,000

Schedule_II_Valuation_and_Qual1

Schedule II Valuation and Qualifying Accounts (Details) (Allowance for Doubtful Accounts [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for Doubtful Accounts [Member]
Allowance for doubtful accounts:
Balance, beginning of period	$10,085		$10,818		$12,407
Charged to Costs and Expenses	8,548		5,725		7,064
Other	1,335	[1]	1,395	[1]	1,754	[1]
Deductions	10,457	[2]	7,853	[2]	10,407	[2]
Balance, end of period	$9,511		$10,085		$10,818
[1]	Recoveries.
[2]	Uncollectible accounts written off.