MDU Resources (MDU) 10-K 19 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 11, 2016	Jun. 30, 2015
Document and entity information [Abstract]
Entity Registrant Name	MDU RESOURCES GROUP INC
Entity Central Index Key	67,716
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 3,805,857,581
Entity Common Stock, Shares Outstanding		195,265,744
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues:
Electric, natural gas distribution and regulated pipeline and midstream	$ 1,148,272	$ 1,246,646	$ 1,156,838
Nonregulated pipeline and midstream, construction materials and contracting, construction services, refining and other	3,043,277	2,868,170	2,763,333
Total operating revenues	4,191,549	4,114,816	3,920,171
Operating expenses:
Fuel and purchased power	86,238	89,312	83,528
Purchased natural gas sold	450,114	558,463	495,471
Cost of crude oil	159,811	0	0
Operation and maintenance:
Electric, natural gas distribution and regulated pipeline and midstream	277,638	269,225	253,214
Nonregulated pipeline and midstream, construction materials and contracting, construction services, refining and other	2,593,300	2,529,020	2,426,145
Depreciation, depletion and amortization	227,730	203,980	200,398
Taxes, other than income	142,585	145,393	140,713
Total operating expenses	3,937,416	3,795,393	3,599,469
Operating income	254,133	319,423	320,702
Other income	19,232	9,873	6,086
Interest expense	93,068	86,906	83,803
Income before income taxes	180,297	242,390	242,985
Income taxes	65,603	63,227	74,294
Income from continuing operations	114,694	179,163	168,691
Income (loss) from discontinued operations, net of tax (Note 2)	(772,385)	115,175	109,879
Net income (loss)	(657,691)	294,338	278,570
Net loss attributable to noncontrolling interest	(35,256)	(3,895)	(363)
Dividends declared on preferred stocks	685	685	685
Earnings (loss) on common stock	$ (623,120)	$ 297,548	$ 278,248
Earnings (loss) per common share - basic:
Earnings before discontinued operations	$ 0.77	$ 0.95	$ 0.89
Discontinued operations, net of tax	(3.97)	0.60	0.58
Earnings (loss) per common share - basic	(3.20)	1.55	1.47
Earnings (loss) per common share - diluted:
Earnings before discontinued operations	0.77	0.95	0.89
Discontinued operations, net of tax	(3.97)	0.60	0.58
Earnings (loss) per common share - diluted	$ (3.20)	$ 1.55	$ 1.47
Weighted average common shares outstanding - basic	194,928	192,507	188,855
Weighted average common shares outstanding - diluted	194,986	192,587	189,693

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income (loss)	$ (657,691)	$ 294,338	$ 278,570
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized loss on derivative instruments arising during the period, net of tax of $0, $0 and $(3,116) in 2015, 2014 and 2013, respectively	0	0	(5,594)
Reclassification adjustment for loss on derivative instruments included in net income (loss), net of tax of $233, $240 and $339 in 2015, 2014 and 2013, respectively	404	399	727
Reclassification adjustment for (gain) loss on derivative instruments included in income (loss) from discontinued operations, net of tax of $0, $173 and $(2,887) in 2015, 2014 and 2013, respectively	0	295	(4,916)
Net unrealized gain (loss) on derivative instruments qualifying as hedges	404	694	(9,783)
Postretirement liability adjustment:
Postretirement liability gains (losses) arising during the period, net of tax of $(55), $(7,665) and $11,818 in 2015, 2014 and 2013, respectively	(88)	(12,409)	18,539
Amortization of postretirement liability losses included in net periodic benefit cost (credit), net of tax of $1,128, $492 and $1,276 in 2015, 2014 and 2013, respectively	1,794	796	2,001
Reclassification of postretirement liability adjustment to regulatory asset, net of tax of $1,416, $4,509 and $0 in 2015, 2014 and 2013, respectively	2,255	7,202	0
Postretirement liability adjustment	3,961	(4,411)	20,540
Foreign currency translation adjustment:
Foreign currency translation adjustment recognized during the period, net of tax of $(105), $(99) and $(177) in 2015, 2014 and 2013, respectively	(173)	(162)	(299)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss), net of tax of $490, $0 and $70 in 2015, 2014 and 2013, respectively	802	0	143
Foreign currency translation adjustment	629	(162)	(156)
Net unrealized loss on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(91), $(83) and $(105) in 2015, 2014 and 2013, respectively	(170)	(154)	(194)
Reclassification adjustment for loss on available-for-sale investments included in net income (loss), net of tax of $70, $73 and $59 in 2015, 2014 and 2013, respectively	131	135	109
Net unrealized loss on available-for-sale investments	(39)	(19)	(85)
Other comprehensive income (loss)	4,955	(3,898)	10,516
Comprehensive income (loss)	(652,736)	290,440	289,086
Comprehensive loss attributable to noncontrolling interest	(35,256)	(3,895)	(363)
Comprehensive income (loss) attributable to common stockholders	$ (617,480)	$ 294,335	$ 289,449

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income - Parenthetical - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net unrealized gain (loss) on derivative instruments arising during the period, tax	$ 0	$ 0	$ (3,116)
Reclassification adjustment for (gain) loss on derivative instruments included in net income, tax	233	240	339
Reclassification adjustment for (gain) loss on derivative instruments included in discontinued operations, tax	0	173	(2,887)
Postretirement liability gains (losses) arising during the period, tax	(55)	(7,665)	11,818
Amortization of postretirement liability losses included in net periodic benefit cost (credit), tax	1,128	492	1,276
Reclassification of postretirement liability adjustment to regulatory asset, tax	1,416	4,509	0
Foreign currency translation adjustment recognized during the period, tax	(105)	(99)	(177)
Reclassification adjustment for (gain) loss on foreign currency translation adjustment included in net income, tax	490	0	70
Net unrealized gains (losses) on available-for-sale investments arising during the period, tax	(91)	(83)	(105)
Reclassification adjustments for (gain) loss on available-for-sale investments included in net income, tax	$ 70	$ 73	$ 59

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 84,591	$ 81,855
Receivables, net		590,105	599,186
Inventories		253,727	289,410
Deferred income taxes		32,849	32,012
Prepayments and other current assets		35,189	83,763
Current assets held for sale		24,581	131,177
Total current assets		1,021,042	1,217,403
Investments		119,704	117,883
Property, plant and equipment (Note 1)		6,817,668	6,294,778
Less accumulated depreciation, depletion and amortization		2,506,571	2,386,113
Net property, plant and equipment		4,311,097	3,908,665
Deferred charges and other assets:
Goodwill (Note 3)	[1]	635,204	635,204
Other intangible assets, net (Note 3)		7,342	9,840
Other		366,485	322,943
Noncurrent assets held for sale		166,734	1,620,470
Total deferred charges and other assets		1,175,765	2,588,457
Total assets		6,627,608	7,832,408
Current liabilities:
Short-term borrowings (Note 7)		45,500	0
Long-term debt due within one year		243,789	268,552
Accounts payable		310,466	279,115
Taxes payable		45,775	39,955
Dividends payable		36,784	35,607
Accrued compensation		46,130	57,402
Other accrued liabilities		171,592	155,765
Current liabilities held for sale		47,603	154,728
Total current liabilities		947,639	991,124
Long-term debt (Note 7)		1,627,443	1,825,278
Deferred credits and other liabilities:
Deferred income taxes		720,319	714,022
Other liabilities		811,659	756,759
Noncurrent liabilities held for sale		0	295,441
Total deferred credits and other liabilities		1,531,978	1,766,222
Equity:
Preferred stocks (Note 9)		15,000	15,000
Common stockholders' equity:
Common stock (Note 10) Authorized - 500,000,000 shares, $1.00 par value Issued - 195,804,665 shares in 2015 and 194,754,812 shares in 2014		195,805	194,755
Other paid-in capital		1,230,119	1,207,188
Retained earnings		996,355	1,762,827
Accumulated other comprehensive loss		(37,148)	(42,103)
Treasury stock at cost - 538,921 shares		(3,626)	(3,626)
Total common stockholders' equity		2,381,505	3,119,041
Total stockholders' equity		2,396,505	3,134,041
Noncontrolling interest		124,043	115,743
Total equity		2,520,548	3,249,784
Total liabilities and equity		$ 6,627,608	$ 7,832,408
[1]	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and midstream segment, which occurred in prior periods.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Stockholders' equity:
Common stock, shares authorized	500,000,000	500,000,000
Common stock, par value	$ 1	$ 1
Common stock, shares issued	195,804,665	194,754,812
Treasury stock, shares	538,921	538,921

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Preferred stock	Common Stock	Other Paid-in Capital	Retained Earnings	Total accumulated other comprehensive loss	Treasury Stock	Noncontrolling interest
Balance (in shares) at Dec. 31, 2013		150,000
Balance (in shares) at Dec. 31, 2012			189,369,450
Treasury stock (in shares) at Dec. 31, 2012							(538,921)
Balance at Dec. 31, 2012	$ 2,648,248	$ 15,000	$ 189,369	$ 1,039,080	$ 1,457,146	$ (48,721)	$ (3,626)
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
Net tax 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 (in shares) at Dec. 31, 2012		150,000
Balance (in shares) at Dec. 31, 2013			189,868,780
Treasury stock (in shares) at Dec. 31, 2013							(538,921)
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, 2014		150,000
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 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 (in shares) at Dec. 31, 2013		150,000
Balance (in shares) at Dec. 31, 2014	194,754,812		194,754,812
Treasury stock (in shares) at Dec. 31, 2014	(538,921)						(538,921)
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, 2015		150,000
Net income (loss) attributable to parent					(622,435)
Net loss attributable to noncontrolling interest	(35,256)							(35,256)
Net income (loss)	(657,691)
Other comprehensive income (loss)	4,955					4,955
Dividends declared on preferred stocks	(685)				(685)
Dividends declared on common stock	(143,352)				(143,352)
Stock-based compensation	3,689			3,689
Net tax deficit on stock-based compensation	(1,606)			(1,606)
Issuance of common stock - shares			1,049,853
Issuance of common stock	21,898		$ 1,050	20,848
Contribution from non-controlling interest	52,000							52,000
Distribution to non-controlling interest	$ (8,444)							(8,444)
Balance (in shares) at Dec. 31, 2014		150,000
Balance (in shares) at Dec. 31, 2015	195,804,665		195,804,665
Treasury stock (in shares) at Dec. 31, 2015	(538,921)						(538,921)
Balance at Dec. 31, 2015	$ 2,520,548	$ 15,000	$ 195,805	$ 1,230,119	$ 996,355	$ (37,148)	$ (3,626)	$ 124,043

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income (loss)	$ (657,691)	$ 294,338	$ 278,570
Income (loss) from discontinued operations, net of tax	(772,385)	115,175	109,879
Income from continuing operations	114,694	179,163	168,691
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	227,730	203,980	200,398
Deferred income taxes	301	58,990	28,551
Excess tax benefit on stock-based compensation	0	(4,729)	0
Changes in current assets and liabilities, net of acquisitions:
Receivables	(313)	4,010	(25,635)
Inventories	(17,100)	(22,795)	28,292
Other current assets	50,097	(40,617)	(13,569)
Accounts payable	49,117	(42,138)	26,285
Other current liabilities	6,325	(15,988)	(26,360)
Other noncurrent changes	10,256	(21,450)	(30,786)
Net cash provided by continuing operations	441,107	298,426	355,867
Net cash provided by discontinued operations	200,037	305,241	398,441
Net cash provided by operating activities	641,144	603,667	754,308
Investing activities:
Capital expenditures	(625,375)	(608,028)	(531,332)
Acquisitions, net of cash acquired	0	(269)	0
Net proceeds from sale or disposition of property and other	54,569	29,598	40,802
Investments	1,515	(1,041)	302
Proceeds from sale of equity method investments	0	0	1,896
Net cash used in continuing operations	(569,291)	(579,740)	(488,332)
Net cash provided by (used in) discontinued operations	186,838	(324,451)	(294,329)
Net cash used in investing activities	(382,453)	(904,191)	(782,661)
Financing activities:
Issuance of short-term borrowings	45,500	0	9,500
Repayment of short-term borrowings	0	(11,500)	0
Issuance of long-term debt	345,920	606,084	507,924
Repayment of long-term debt	(569,498)	(368,249)	(423,707)
Proceeds from issuance of common stock	21,898	150,060	14,554
Dividends paid	(142,835)	(136,712)	(98,405)
Excess tax benefit on stock-based compensation	0	4,729	0
Tax withholding on stock-based compensation	0	(5,564)	0
Contribution from noncontrolling interest	52,000	86,900	27,000
Distribution to noncontrolling interest	(8,444)	0	0
Net cash provided by (used in) continuing operations	(255,459)	325,748	36,866
Net cash used in discontinued operations	(271)	(554)	0
Net cash provided by financing activities	(255,730)	325,194	36,866
Effect of exchange rate changes on cash and cash equivalents	(225)	(155)	(215)
Increase (decrease) in cash and cash equivalents	2,736	24,515	8,298
Cash and cash equivalents - beginning of year	81,855	57,340	49,042
Cash and cash equivalents - end of year	$ 84,591	$ 81,855	$ 57,340

Summary of significant accounti

Summary of significant accounting policies	12 Months Ended
	Dec. 31, 2015
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 midstream, construction materials and contracting, construction services, refining and other. The electric and natural gas distribution businesses, as well as a portion of the pipeline and midstream business, are regulated. Construction materials and contracting, construction services, refining and the other businesses, as well as a portion of the pipeline and midstream business, are nonregulated. For further descriptions of the Company's businesses, see Note 13 . 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 4 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, 2015 , up to the date of issuance of these consolidated financial statements. In the second quarter of 2015, the Company announced its plan to market Fidelity, previously referred to as the Company's exploration and production segment, and exit that line of business. In the third and fourth quarters of 2015 and the first quarter of 2016, the Company entered into purchase and sale agreements to sell the vast majority of Fidelity's assets, comprising greater than 93 percent of total production for 2014. The Company's consolidated financial statements and accompanying notes for current and prior periods have been restated to present the results of operations of Fidelity as discontinued operations, other than certain general and administrative costs and interest expense which were previously allocated to the former exploration and production segment and do not meet the criteria for income (loss) from discontinued operations. In addition, the assets and liabilities have been treated and classified as held for sale. Unless otherwise indicated, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company's continuing operations. For more information on discontinued operations, see Note 2 . 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 $27.8 million and $29.4 million at December 31, 2015 and 2014 , 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, 2015 and 2014 , was $9.8 million and $9.5 million , respectively. Inventories and natural gas in storage 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. Crude oil and refined products at Dakota Prairie Refinery are carried at lower of cost or market value using the last-in, first-out method. In 2015, Dakota Prairie Refinery recorded $12.2 million (before tax) of inventory impairments due to the lower of cost or market valuation which is reflected in cost of crude oil on the Consolidated Statements of Income. All other inventories are stated at the lower of average cost or market value. 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: 2015 2014 (In thousands) Aggregates held for resale $ 115,854 $ 108,161 Asphalt oil 36,498 42,135 Materials and supplies 16,997 54,282 Merchandise for resale 15,318 24,420 Refined products 8,498 — Natural gas in storage (current) 21,023 19,302 Crude oil 4,678 5,045 Other 34,861 36,065 Total $ 253,727 $ 289,410 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 $49.1 million and $49.3 million at December 31, 2015 and 2014 , respectively. Investments The Company's investments include the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. 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 6 and 14 . 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 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, 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: 2015 2014 2013 (In thousands) Interest capitalized $ 4,902 $ 8,586 $ 6,033 AFUDC - borrowed $ 4,907 $ 3,022 $ 2,767 AFUDC - equity $ 7,971 $ 5,803 $ 3,322 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. 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: 2015 2014 Weighted Average Depreciable Life in Years (Dollars in thousands, where applicable) Regulated: Electric: Generation $ 1,003,173 $ 627,952 39 Distribution 375,612 343,692 44 Transmission 255,842 229,997 57 Construction in progress 42,436 150,445 - Other 109,085 105,015 14 Natural gas distribution: Distribution 1,624,645 1,481,390 35 Construction in progress 20,530 59,310 - Other 431,406 364,059 22 Pipeline and midstream: Transmission 460,305 449,276 53 Gathering 37,831 39,595 20 Storage 44,011 43,994 60 Construction in progress 7,549 5,386 - Other 40,168 39,910 33 Nonregulated: Pipeline and midstream: Gathering and processing 158,949 227,598 16 Construction in progress 89 691 - Other 9,827 11,938 10 Construction materials and contracting: Land 123,723 125,372 - Buildings and improvements 69,011 70,566 19 Machinery, vehicles and equipment 937,084 921,564 12 Construction in progress 18,615 8,709 - Aggregate reserves 404,995 403,731 * Construction services: Land 6,460 5,265 - Buildings and improvements 23,824 17,936 25 Machinery, vehicles and equipment 121,940 112,973 6 Other 11,055 8,221 3 Refining: Refinery 445,198 88,232 20 Construction in progress 135 313,613 - Other: Land 2,837 2,837 - Other 46,700 48,100 23 Eliminations (15,367 ) (12,589 ) Less accumulated depreciation, depletion and amortization 2,506,571 2,386,113 Net property, plant and equipment $ 4,311,097 $ 3,908,665 * 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, oil and natural gas properties, and assets held for sale, 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 the third quarter of 2015 , the Company recognized an impairment of $14.1 million (before tax) related to the sale of certain non-strategic natural gas gathering assets that were written down to their estimated fair value that was determined using the market approach. In the second quarters of 2015 and 2013 , the Company recognized impairments of $3.0 million (before tax) and $14.5 million (before tax), respectively, related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a continued 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 their estimated fair value that was determined using the income approach. The impairments are recorded in operation and maintenance expense on the Consolidated Statements of Income. For more information on these nonrecurring fair value measurements, see Note 6 . 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 13 . 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, 2015 , 2014 and 2013 , there were no significant impairment losses recorded. At December 31, 2015 , 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 2015 . 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. 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 $102.1 million and $99.7 million at December 31, 2015 and 2014 , 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: 2015 2014 (In thousands) Costs and estimated earnings in excess of billings on uncompleted contracts $ 64,369 $ 58,243 Billings in excess of costs and estimated earnings on uncompleted contracts $ 68,048 $ 47,011 Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31 were as follows: 2015 2014 (In thousands) Short-term retainage* $ 46,207 $ 47,551 Long-term retainage** 1,605 1,053 Total retainage $ 47,812 $ 48,604 * 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 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 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 5 . 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 8 . 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 which are filed annually. Natural gas costs refundable through rate adjustments were $20.9 million and $13.2 million at December 31, 2015 and 2014 , respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $547,000 and $19.6 million at December 31, 2015 and 2014 , 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. 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 (loss) per common share were computed by dividing earnings (loss) 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 2015, 2014 and 2013, there were no shares excluded from the calculation of diluted earnings per share. 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: 2015 2014 2013 (In thousands) Weighted average common shares outstanding - basic 194,928 192,507 188,855 Effect of dilutive performance share awards 58 80 838 Weighted average common shares outstanding - diluted 194,986 192,587 189,693 Shares excluded from the calculation of diluted earnings per share — — — 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 assets held for sale, long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; 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; and the valuation of stock-based compensation. 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: 2015 2014 2013 (In thousands) Interest, net of amount capitalized and AFUDC - borrowed of $9,809, $11,608 and $8,800 in 2015, 2014 and 2013, respectively $ 90,386 $ 81,241 $ 81,575 Income taxes paid, net $ 33,409 $ 64,211 $ 52,580 Noncash investing transactions at December 31 were as follows: 2015 2014 2013 (In thousands) Property, plant and equipment additions in accounts payable $ 51,702 $ 62,453 $ 22,832 New accounting standards Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity In April 2014, the FASB issued guidance related to the definition and reporting of discontinued operations. The guidance changed the definition of discontinued operations to include only disposals of a component or group of components that represent a strategic shift and that have a major effect on an entity's operations or financial results. The guidance also expands the disclosure requirements for transactions that meet the definition of a discontinued operation, and also requires entities to disclose information about individually significant components that are disposed of or held for sale that do not meet the definition of a discontinued operation. This guidance was effective for the Company on January 1, 2015, and is to be applied prospectively. The adoption required additional disclosures for the Company's discontinued operations, however it did not impact the Company's results of operations, financial position or cash flows. 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 was to be effective for the Company on January 1, 2017. In August 2015, the FASB issued guidance deferring the effective date of the revenue guidance one year and allowing entities to early adopt. With this decision, the guidance will be effective for the Company on January 1, 2018. 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. Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued guidance on simplifying the presentation of debt issuance costs in the financial statements. This guidance requires entities to present debt issuance costs as a direct deduction to the related debt liability. The amortization of these costs will be reported as interest expense. The guidance was effective for the Company on January 1, 2016, and is to be applied retrospectively. Early adoption of this guidance was permitted, however the Company has not elected to do so. The guidance will require a reclassification of the debt issuance costs on the Consolidated Balance Sheets, but will not impact the Company's results of operations or cash flows. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent) In May 2015, the FASB issued guidance on fair value measurement and disclosure requirements removing the requirement to include investments in the fair value hierarchy for which fair value is measured using the net asset value per share practical expedient. The new guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at net asset value using the practical expedient, and rather limits those disclosures to investments for which the practical expedient has been elected. This guidance was effective for the Company on January 1, 2016, with early adoption permitted. The Company is evaluating the effects the adoption of the new guidance will have on its disclosures, however it will not impact the Company's results of operations, financial position or cash flows. Simplifying the Measurement of Inventory In July 2015, the FASB issued guidance regarding inventory that is measured using the first-in, first-out or average cost method. The guidance does not apply to inventory measured using the last-in, first-out or the retail inventory method. The guidance requires inventory within its scope to be measured at the lower of cost or net realizable value, which is the estimated selling price in the normal course of business less reasonably predictable costs of completion, disposal and transportation. These amendments more closely align GAAP with IFRS. This guidance will be effective for the Company on January 1, 2017, and should be applied prospectively with early adoption permitted as of the beginning of an interim or annual reporting period. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position and cash flows. Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. The guidance will require all deferred tax assets and liabilities to be classified as noncurrent. These amendments will align GAAP with IFRS. This guidance will be effective for the Company on January 1, 2017, with early adoption permitted. Entities will have the option to apply the guidance prospectively, for all deferred tax assets and liabilities, or retrospectively. The Company is evaluating the effects the adoption of the new guidance will have on its financial position and disclosures, however it will not impact the Company's results of operations or cash flows. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued guidance regarding the classification and measurement of financial instruments. The guidance revises the way an entity classifies and measures investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value and amends certain disclosure requirements related to the fair value of financial instruments. This guidance will be effective for the Company on January 1, 2018, with early adoption of certain amendments permitted. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures. 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

Discontinued operations

Discontinued operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued operations	Discontinued Operations In the second quarter of 2015, the Company began the marketing and sale process of Fidelity with an anticipated sale to occur within one year. In the third and fourth quarters of 2015 and the first quarter of 2016, the Company entered into purchase and sale agreements to sell the vast majority of Fidelity's assets, comprising greater than 93 percent of total production for 2014. The completion of the majority of these sales occurred in the fourth quarter of 2015 and the Company continues to market the remaining assets of Fidelity. The sale of Fidelity is part of the Company's strategic plan to grow its capital investments in the remaining business segments and to focus on creating a greater long-term value. The assets and liabilities for these operations have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. The Company's consolidated financial statements and accompanying notes for current and prior periods have been restated. At the time the assets were classified as held for sale, depreciation, depletion and amortization expense was no longer recorded. The carrying amounts of the major classes of assets and liabilities that are classified as held for sale on the Company's Consolidated Balance Sheets at December 31 were as follows: 2015 2014 (In thousands) Assets Current assets: Receivables, net $ 13,387 $ 94,132 Inventories 1,308 11,401 Commodity derivative instruments — 18,335 Prepayments and other current assets 9,886 7,309 Total current assets held for sale 24,581 131,177 Noncurrent assets: Investments 37 37 Net property, plant and equipment 793,422 1,618,099 Deferred income taxes 127,655 — Other 161 2,334 Less allowance for impairment of assets held for sale 754,541 — Total noncurrent assets held for sale 166,734 1,620,470 Total assets held for sale $ 191,315 $ 1,751,647 Liabilities Current liabilities: Long-term debt due within one year $ — $ 897 Accounts payable 25,013 103,556 Taxes payable 1,052 19,900 Deferred income taxes 3,620 8,206 Accrued compensation 13,080 5,373 Other accrued liabilities 4,838 16,796 Total current liabilities held for sale 47,603 154,728 Noncurrent liabilities: Deferred income taxes — 238,391 Other liabilities — 57,050 Total noncurrent liabilities held for sale — 295,441 Total liabilities held for sale $ 47,603 $ 450,169 At December 31, 2015, the Company’s deferred tax assets included in assets held for sale were largely comprised of $78.9 million of federal and state net operating loss carryforwards and $38.1 million of basis differences on oil and natural gas producing properties. At December 31, 2014, the Company’s deferred tax liabilities included in liabilities held for sale were largely comprised of $270.0 million of basis differences on oil and natural gas producing properties offset in part by $26.4 million of asset retirement obligations. The Company had federal income tax net operating loss carryforwards of $208.2 million at December 31, 2015, and no federal income tax net operating loss carryforwards at December 31, 2014. At December 31, 2015 and 2014, the Company had various state income tax net operating loss carryforwards of $201.4 million and $5.9 million , respectively. The federal net operating loss carryforwards expire in 2036 if not utilized. The state net operating loss carryforwards are due to expire between 2016 and 2036. It is likely a portion of the benefit from the state carryforwards will not be realized; therefore, valuation allowances of $300,000 and $253,000 have been provided in 2015 and 2014, respectively. The Company performed a fair value assessment of the assets and liabilities classified as held for sale. In the second quarter of 2015, the estimated fair value was determined using the income and the market approaches. The income approach was determined by using the present value of future estimated cash flows. The income approach considered management’s views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry including estimated reserves, estimated prices, market differentials, estimates of well operating and future development costs and timing of operations. The estimated cash flows were discounted using a rate believed to be consistent with those used by principal market participants. The market approach was provided by a third party and based on market transactions involving similar interests in oil and natural gas properties. The fair value assessment indicated an impairment based on the carrying value exceeding the estimated fair value, which resulted in the Company writing down Fidelity’s assets at June 30, 2015, and recording an impairment of $400.0 million ( $252.0 million after tax) during the second quarter of 2015. In the third quarter of 2015, the estimated fair value of Fidelity was determined by agreed upon pricing in the purchase and sale agreements for the assets subject to the agreements, the majority of which closed during the fourth quarter of 2015, including customary purchase price adjustments. The values received in the bid proposals were lower than originally anticipated due to lower commodity prices than those projected in the second quarter of 2015. For those assets for which a purchase and sale agreement has not been entered into, which the Company is continuing to market, the fair value was determined based on the market approach utilizing multiples based on similar interests in oil and natural gas properties. The fair value assessment indicated an impairment based on the current carrying value exceeding the estimated fair value, which resulted in the Company writing down Fidelity’s assets at September 30, 2015, and recording an impairment of $356.1 million ( $224.4 million after tax). In the fourth quarter of 2015, the fair value assessment was determined using the market approach based on purchase and sale agreements, one of which has been signed and one of which the Company is currently negotiating. The estimated fair value exceeded the carrying value and the Company recorded an impairment reversal of $1.6 million ( $1.0 million after tax) in the fourth quarter of 2015. The impairments were included in operating expenses from discontinued operations. The estimated fair value of Fidelity's assets have been categorized as Level 3 in the fair value hierarchy. At December 31, 2015, the Company has accrued liabilities of approximately $2.5 million for estimated transaction costs which will result in future cash expenditures. In addition to the estimated transaction costs, and due in part to the change in plans to sell the assets of Fidelity rather than sell Fidelity as a company, Fidelity incurred and expensed approximately $4.9 million of exit and disposal costs in 2015 and expects to incur an additional $6.1 million of exit and disposal costs in 2016. The exit and disposal costs are associated with severance and other related matters, excluding the office lease expenses discussed in the following paragraph. The majority of these exit and disposal activities are expected to be completed by the end of the second quarter of 2016. Fidelity is vacating its office space in Denver, Colorado. An amendment of lease has been executed with payments of $4.2 million required under the lease in 2016. A termination payment of $3.3 million was made during the fourth quarter of 2015 and existing office furniture and fixtures will be relinquished to the lessor in 2016. Unforeseen events and changes in circumstances and market conditions and material differences in the value of the assets held for sale due to changes in estimates of future cash flows could negatively affect the estimated fair value of Fidelity and result in additional impairment charges. Various factors, including oil and natural gas prices, market differentials and changes in estimates of reserve quantities could result in future impairments of the Company's assets held for sale. Historically, the Company used 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. Prior to the oil and natural gas properties being classified as held for sale, capitalized costs were 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. The Company's capitalized cost under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 2015. SEC Defined Prices, adjusted for market differentials, were used to calculate the ceiling test. Accordingly, the Company was required to write down its oil and natural gas producing properties. The Company recorded a $500.4 million ( $315.3 million after tax) noncash write-down in operating expenses from discontinued operations in the first quarter of 2015. 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 which is reflected in discontinued operations. 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. 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. The Company incurred legal expenses and had a benefit related to the resolution of this matter in the second quarter of 2014, which are reflected in discontinued operations in the consolidated financial statements and accompanying notes. The reconciliation of the major classes of income and expense constituting pretax income (loss) from discontinued operations to the after-tax net income (loss) from discontinued operations of the Company's Consolidated Statements of Income at December 31 were as follows: 2015 2014 2013 (In thousands) Operating revenues $ 184,853 $ 547,571 $ 536,023 Operating expenses 1,423,037 378,891 364,120 Operating income (loss) (1,238,184 ) 168,680 171,903 Other income 2,374 1,163 549 Interest expense 235 110 114 Income (loss) from discontinued operations before income taxes (1,236,045 ) 169,733 172,338 Income taxes (463,660 ) 54,558 62,459 Income (loss) from discontinued operations $ (772,385 ) $ 115,175 $ 109,879

Goodwill and other intangible a

Goodwill and other intangible assets	12 Months Ended
	Dec. 31, 2015
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, 2015 , were as follows: Balance at January 1, 2015 * Goodwill Acquired During the Year Balance at December 31, 2015 * (In thousands) Natural gas distribution $ 345,736 $ — $ 345,736 Pipeline and midstream 9,737 — 9,737 Construction materials and contracting 176,290 — 176,290 Construction services 103,441 — 103,441 Total $ 635,204 $ — $ 635,204 * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and midstream segment, which occurred in prior periods. The changes in the carrying amount of goodwill for the year ended December 31, 2014 , were as follows: Balance at January 1, 2014 * Goodwill Acquired During the Year/Other Balance at December 31, 2014 * (In thousands) Natural gas distribution $ 345,736 $ — $ 345,736 Pipeline and midstream 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 midstream segment, which occurred in prior periods. Other amortizable intangible assets at December 31 were as follows: 2015 2014 (In thousands) Customer relationships $ 20,975 $ 21,310 Accumulated amortization (16,845 ) (15,556 ) 4,130 5,754 Noncompete agreements 4,409 5,080 Accumulated amortization (3,655 ) (4,098 ) 754 982 Other 8,304 10,921 Accumulated amortization (5,846 ) (7,817 ) 2,458 3,104 Total $ 7,342 $ 9,840 Amortization expense for amortizable intangible assets for the years ended December 31, 2015 , 2014 and 2013 , was $2.5 million , $3.2 million and $4.0 million , respectively. Estimated amortization expense for intangible assets is $2.2 million in 2016 , $1.9 million in 2017 , $1.0 million in 2018 , $900,000 in 2019 , $300,000 in 2020 and $1.0 million thereafter.

Regulatory assets and liabiliti

Regulatory assets and liabilities	12 Months Ended
	Dec. 31, 2015
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 Period * 2015 2014 (In thousands) Regulatory assets: Pension and postretirement benefits (a) (e) $ 185,832 $ 182,565 Taxes recoverable from customers (a) Over plant lives 27,682 22,910 Manufactured gas plant sites remediation (a) Up to 2 years 18,617 17,548 Plant costs (a) Up to 1 year 8,000 4,551 Natural gas costs recoverable through rate adjustments (b) Up to 1 year 547 19,575 Long-term debt refinancing costs (a) Up to 22 years 7,031 7,864 Costs related to identifying generation development (a) Up to 11 years 3,808 4,165 Other (a) (b) Largely within 1- 4 years 11,741 10,408 Total regulatory assets 263,258 269,586 Regulatory liabilities: Plant removal and decommissioning costs (c) 182,981 338,641 Taxes refundable to customers (c) 17,060 17,772 Natural gas costs refundable through rate adjustments (d) 20,884 13,238 Other (c) (d) 22,193 16,601 Total regulatory liabilities 243,118 386,252 Net regulatory position $ 20,140 $ (116,666 ) * 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, 2015 and 2014 , approximately $224.7 million and $229.6 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, 2015
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. The Company had no derivative instruments at December 31, 2015, and as of December 31, 2014 , credit risk was not material. Fidelity At December 31, 2014 , Fidelity held oil swap agreements with total forward notional volumes of 270,000 Bbl and natural gas swap agreements with total forward notional volumes of 5.0 million MMBtu. At December 31, 2015, Fidelity had no outstanding derivative agreements. Fidelity historically utilized 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. The gains and losses on the commodity derivative instruments held by Fidelity were included in income (loss) from discontinued operations and the associated assets and liabilities were classified as held for sale. 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 income (loss) from discontinued operations on the Consolidated Statements of Income at the date the oil and natural gas quantities were settled. 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, 2015, 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: 2015 2014 2013 (In thousands) Commodity derivatives designated as cash flow hedges: Amount of loss recognized in accumulated other comprehensive loss (effective portion), net of tax $ — $ — $ (6,153 ) Amount of (gain) loss reclassified from accumulated other comprehensive loss into discontinued operations (effective portion), net of tax — 295 (4,916 ) Amount of loss recognized in operating revenues (ineffective portion), before tax — — (1,422 ) Interest rate derivatives designated as cash flow hedges: Amount of gain recognized in accumulated other comprehensive loss (effective portion), net of tax — — 559 Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax 404 399 727 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 discontinued operations, before tax (18,335 ) 23,400 (4,845 ) 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 gross amount 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 (In thousands) Not designated as hedges: Commodity derivatives Current assets held for sale $ 18,335 Total asset derivatives $ 18,335 All of the Company's commodity derivative instruments at December 31, 2014 , 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 (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 Consolidated Balance Sheets Gross Amounts Not Offset on the Consolidated Balance Sheets Net (In thousands) Assets: Commodity derivatives $ 18,335 $ — $ 18,335 Total assets $ 18,335 $ — $ 18,335

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2015
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 $67.5 million and $65.8 million as of December 31, 2015 and 2014 , respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gains on these investments for the years ended December 31, 2015 , 2014 and 2013 , were $1.7 million , $3.4 million and $13.5 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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value (In thousands) Mortgage-backed securities $ 9,128 $ 19 $ (49 ) $ 9,098 U.S. Treasury securities 1,315 — (6 ) 1,309 Total $ 10,443 $ 19 $ (55 ) $ 10,407 December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value (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 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 are valued at the net asset value of shares held at the end of the period, based on published market quotations on active markets, or using 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. The assets are invested in high-quality, short-term money market instruments that consist of municipal obligations. There are no unfunded commitments related to these funds. 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 RIN obligations are based on the market approach using quoted prices from an independent pricing service. RINs are assigned to biofuels produced or imported into the United States as required by the EPA, which sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the United States. As a producer of diesel fuel, Dakota Prairie Refinery is required to blend biofuels into the fuel it produces at a rate that will meet the EPA's quota. RINs are purchased in the open market to satisfy the requirement as Dakota Prairie Refinery is currently unable to blend biofuels into the diesel fuel it produces. 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, 2015 and 2014 , 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, 2015, Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2015 (In thousands) Assets: Money market funds $ — $ 1,420 $ — $ 1,420 Insurance contract* — 67,459 — 67,459 Available-for-sale securities: Mortgage-backed securities — 9,098 — 9,098 U.S. Treasury securities — 1,309 — 1,309 Total assets measured at fair value $ — $ 79,286 $ — $ 79,286 Liabilities: RIN obligations $ — $ 3,052 $ — $ 3,052 Total liabilities measured at fair value $ — $ 3,052 $ — $ 3,052 * The insurance contract invests approximately 9 percent in common stock of mid-cap companies, 7 percent in common stock of small-cap companies, 19 percent in common stock of large-cap companies, 63 percent in fixed-income investments, 1 percent in target date investments and 1 percent in cash equivalents. Fair Value Measurements at December 31, 2014, Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2014 (In thousands) Assets: Money market funds $ — $ 890 $ — $ 890 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 Total assets measured at fair value $ — $ 76,912 $ — $ 76,912 * 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. 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, whenever events or changes in circumstances indicate that such carrying amounts may not be recoverable. During the second quarters of 2015 and 2013, natural gas gathering assets at the pipeline and midstream segment 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, 2015, natural gas gathering assets were written down to the nonrecurring fair value measurement of $1.1 million . During the third quarter of 2015, the Company was negotiating the sale of certain non-strategic natural gas gathering assets at the pipeline and midstream segment and as a result these assets were found to be impaired and were written down to their estimated fair value using the market approach. The estimated fair value of natural gas gathering assets that were impaired at September 30, 2015, was largely determined by agreed upon pricing in a purchase and sale agreement that the Company was negotiating, and these assets were sold in the fourth quarter of 2015. At September 30, 2015, natural gas gathering assets were written down to the nonrecurring fair value measurement of $10.8 million . The fair value of these natural gas gathering assets have been categorized as Level 3 in the fair value hierarchy. The Company performed a fair value assessment of the assets and liabilities classified as held for sale. For more information on this Level 3 nonrecurring fair value measurement, see Note 2 . 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: 2015 2014 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) Long-term debt $ 1,871,232 $ 1,893,442 $ 2,093,830 $ 2,238,548 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, 2015
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 Limit Amount Outstanding at December 31, 2015 Amount Outstanding at December 31, 2014 Letters of Credit at December 31, 2015 Expiration Date (In millions) MDU Resources Group, Inc. Commercial paper/Revolving credit agreement (a) $ 175.0 $ 44.5 (b) $ 77.5 (b) $ — 5/8/19 Cascade Natural Gas Corporation Revolving credit agreement $ 50.0 (c) $ — $ — $ 2.2 (d) 7/9/18 Intermountain Gas Company Revolving credit agreement $ 65.0 (e) $ 47.9 $ 21.0 $ — 7/13/18 Centennial Energy Holdings, Inc. Commercial paper/Revolving credit agreement (f) $ 650.0 $ 18.0 (b) $ 211.0 (b) $ 39.4 5/8/19 Dakota Prairie Refining, LLC Revolving credit agreement $ 75.0 $ 45.5 $ — $ 18.3 (d) 6/30/16 (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) Outstanding letter(s) of credit reduce 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. 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 September 30, 2015, Dakota Prairie Refining entered into an amendment to its revolving credit agreement which increased the borrowing limit from $50.0 million under the original December 1, 2014, agreement to $75.0 million and extended the termination date from December 1, 2015 to June 30, 2016. 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. 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. 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. 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. In December 2015, the lenders under the revolving credit agreement and master shelf agreement provided a waiver and an amendment, respectively, to certain covenants under these agreements removing any potential restrictions related to the disposition of the Fidelity assets. 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. 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, 2015 , 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: 2015 2014 (In thousands) Senior Notes at a weighted average rate of 5.18%, due on dates ranging from February 1, 2016 to January 15, 2055 $ 1,616,246 $ 1,636,662 Commercial paper at a weighted average rate of .73%, supported by revolving credit agreements 62,500 288,500 Term Loan Agreements at a weighted average rate of 2.16%, due on dates ranging from April 22, 2018 to April 22, 2023 69,000 72,000 Medium-Term Notes at a weighted average rate of 6.68%, due on dates ranging from September 1, 2020 to March 16, 2029 50,000 35,000 Other notes at a weighted average rate of 5.25%, due on February 1, 2035 24,589 39,662 Credit agreements at a weighted average rate of 1.82%, due on dates ranging from July 14, 2018 to November 30, 2038 48,906 22,042 Discount (9 ) (36 ) Total long-term debt 1,871,232 2,093,830 Less current maturities 243,789 268,552 Net long-term debt $ 1,627,443 $ 1,825,278 The amounts of scheduled long-term debt maturities for the five years and thereafter following December 31, 2015 , aggregate $243.8 million in 2016 ; $51.0 million in 2017 ; $175.2 million in 2018 ; $119.7 million in 2019 ; $21.0 million in 2020 and $1,260.5 million thereafter.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset retirement obligations	Asset Retirement Obligations The Company records obligations related to retirement costs of natural gas distribution mains and lines, 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: 2015 2014 (In thousands) Balance at beginning of year $ 27,211 $ 27,327 Liabilities incurred 2,751 1,697 Liabilities settled (1,708 ) (3,231 ) Accretion expense 1,163 1,112 Revisions in estimates 211,836 (73 ) Other 971 379 Balance at end of year $ 242,224 $ 27,211 The 2015 revisions in estimates consist principally of updated natural gas distribution mains and lines asset retirement obligation costs. 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.

Preferred Stocks

Preferred Stocks	12 Months Ended
	Dec. 31, 2015
Class of Stock Disclosures [Abstract]
Preferred stocks	Preferred Stocks Preferred stocks at December 31 were as follows: 2015 2014 (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 2015 , 2014 and 2013 , 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, 2015
Class of Stock Disclosures [Abstract]
Common Stock	Common Stock For the years 2015 , 2014 and 2013 , dividends declared on common stock were $.7350 , $.7150 and $.6950 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 through August 2015, the Stock Purchase Plan and K-Plan, with respect to Company stock, were funded with shares of authorized but unissued common stock. From January 2013 through December 2013, and September 2015 through December 2015, purchases of shares of common stock on the open market were used to fund the Stock Purchase Plan and K-Plan. At December 31, 2015 , there were 13.9 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 $1.6 billion of the net assets of the Company's subsidiaries were restricted from being used to transfer funds to the Company at December 31, 2015 . 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 $322 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, 2015 . 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.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2015
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, 2015 , there are 5.6 million remaining shares available to grant under these plans. The Company generally issues new shares of common stock to satisfy employee performance share awards and purchases shares on the open market for nonemployee director stock awards. Total stock-based compensation expense (after tax) was $2.9 million , $4.4 million and $3.9 million in 2015 , 2014 and 2013 , respectively. As of December 31, 2015 , total remaining unrecognized compensation expense related to stock-based compensation was approximately $5.6 million (before income taxes) which will be amortized over a weighted average period of 1.5 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 58,181 shares with a fair value of $1.1 million , 43,088 shares with a fair value of $1.1 million and 36,713 shares with a fair value of $1.1 million issued under this plan during the years ended December 31, 2015 , 2014 and 2013 , respectively. 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, 2015 , were as follows: Grant Date Performance Period Target Grant of Shares March 2013 2013-2015 188,388 February 2014 2014-2016 142,989 February 2015 2015-2017 220,078 June 2015 2015-2017 14,441 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 2015 , 2014 and 2013 were: 2015 2014 2013 Weighted average grant-date fair value $18.98 $41.13 $29.01 Blended volatility range 22.86 % – 24.61 % 18.94 % – 20.43 % 16.10 % – 19.39 % Risk-free interest rate range .05 % – 1.07 % .03 % – .74 % .09 % – .40 % Weighted average discounted dividends per share $1.57 $2.15 $2.12 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 2015 and 2013. A summary of the status of the performance share awards for the year ended December 31, 2015 , was as follows: Number of Shares Weighted Average Grant-Date Fair Value Nonvested at beginning of period 688,455 $ 28.16 Granted 258,454 18.98 Vested — — Forfeited (381,013 ) 22.31 Nonvested at end of period 565,896 $ 27.90

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income taxes	Income Taxes The components of income before income taxes from continuing operations for each of the years ended December 31 were as follows: 2015 2014 2013 (In thousands) United States $ 181,623 $ 242,442 $ 242,569 Foreign (1,326 ) (52 ) 416 Income before income taxes from continuing operations $ 180,297 $ 242,390 $ 242,985 Income tax expense from continuing operations for the years ended December 31 was as follows: 2015 2014 2013 (In thousands) Current: Federal $ 59,483 $ 4,403 $ 41,624 State 5,789 (166 ) 4,148 Foreign 30 — (29 ) 65,302 4,237 45,743 Deferred: Income taxes: Federal 3,199 55,514 29,616 State (2,478 ) 2,467 (859 ) Investment tax credit - net (420 ) 1,009 (206 ) 301 58,990 28,551 Total income tax expense $ 65,603 $ 63,227 $ 74,294 Components of deferred tax assets and deferred tax liabilities at December 31 were as follows: 2015 2014 (In thousands) Deferred tax assets: Postretirement $ 97,666 $ 99,853 Compensation-related 33,844 35,669 Alternative minimum tax credit carryforward 28,173 23,678 Customer advances 12,623 12,245 Asset retirement obligations 8,694 7,894 Legal and environmental contingencies 6,377 7,890 Other 58,202 52,862 Total deferred tax assets 245,579 240,091 Deferred tax liabilities: Depreciation and basis differences on property, plant and equipment 791,368 773,160 Postretirement 71,835 70,642 Intangible asset amortization 23,950 22,810 Other 36,906 46,637 Total deferred tax liabilities 924,059 913,249 Valuation allowance 8,990 8,852 Net deferred income tax liability $ (687,470 ) $ (682,010 ) As of December 31, 2015 and 2014 , the Company had various state income tax net operating loss carryforwards of $116.2 million and $114.3 million , respectively, and federal and state income tax credit carryforwards, excluding alternative minimum tax credit carryforwards, of $10.9 million and $7.5 million , respectively. The federal income tax credit carryforwards expire in 2036 if not utilized and state income tax credit carryforwards are due to expire between 2016 and 2032. It is likely that a portion of the benefit from the state carryforwards will not be realized; therefore, valuation allowances have been provided. Changes in tax regulations or assumptions regarding current and future taxable income could require additional valuation allowances in the future. The alternative minimum tax credit carryforwards do not expire. For information regarding net operating loss carryforwards and valuation allowances related to discontinued operations, see Note 2 . The following table reconciles the change in the net deferred income tax liability from December 31, 2014 , to December 31, 2015 , to deferred income tax expense: 2015 (In thousands) Change in net deferred income tax liability from the preceding table $ 5,460 Deferred taxes associated with other comprehensive income (3,086 ) Other (2,073 ) Deferred income tax expense for the period $ 301 Total income tax expense differs from the amount computed by applying the statutory federal income tax rate to income before taxes. The reasons for this difference were as follows: Years ended December 31, 2015 2014 2013 Amount % Amount % Amount % (Dollars in thousands) Computed tax at federal statutory rate $ 63,104 35.0 $ 84,836 35.0 $ 85,045 35.0 Increases (reductions) resulting from: State income taxes, net of federal income tax 4,903 2.7 7,048 2.9 7,379 3.0 Noncontrolling interest 12,340 6.8 1,363 .5 — — Federal renewable energy credit (3,400 ) (1.9 ) (3,655 ) (1.5 ) (3,404 ) (1.4 ) Tax compliance and uncertain tax positions (194 ) (.1 ) (8,987 ) (3.7 ) (3,902 ) (1.6 ) Domestic production activities — — (3,993 ) (1.6 ) (666 ) (.3 ) Other (11,150 ) (6.1 ) (13,385 ) (5.5 ) (10,158 ) (4.1 ) Total income tax expense $ 65,603 36.4 $ 63,227 26.1 $ 74,294 30.6 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 $2.4 million at December 31, 2015 . The amount of deferred tax liability, net of allowable foreign tax credits, associated with the undistributed earnings at December 31, 2015 , was approximately $900,000 . 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 or non-U.S. income tax examinations by tax authorities for years ending prior to 2011. With few exceptions, as of December 31, 2015 , the Company is no longer subject to state and local income tax examinations by tax authorities for years ending prior to 2010. A reconciliation of the unrecognized tax benefits (excluding interest) for the years ended December 31 was as follows: 2015 2014 2013 (In thousands) Balance at beginning of year $ 105 $ 7,845 $ 7,845 Settlements — (7,740 ) — Lapse of statute of limitations (105 ) — — Balance at end of year $ — $ 105 $ 7,845 At December 31, 2015 and 2014, there were no 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 $119,000 , including approximately $14,000 for the payment of interest and penalties at December 31, 2014 . Included in income tax expense is interest on uncertain tax positions. For the years ended December 31, 2015 , 2014 and 2013 , the Company recognized approximately $122,000 , $387,000 and $107,000 , respectively, of interest expense in income tax expense. For the years ended December 31, 2015 , 2014 and 2013 , the Company recognized approximately $3.4 million , $1.2 million and $914,000 , respectively, in interest expense. Penalties were not material in 2015 , 2014 and 2013 . The Company recognized interest income of approximately $3.7 million , $469,000 and $655,000 for the years ended December 31, 2015 , 2014 and 2013 , respectively. At December 31, 2015 and 2014 , the Company had accrued liabilities of approximately $94,000 and interest receivable of $367,000 , respectively, for the payment or receipt of interest.

Business segment data

Business segment data	12 Months Ended
	Dec. 31, 2015
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 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 midstream 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. 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 provides utility construction services specializing in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization. This segment also provides utility excavation and inside electrical and mechanical services, and manufactures and distributes transmission line construction equipment and other supplies. The refining segment refines crude oil and produces and sells diesel fuel, naphtha, ATBs and other by-products of the production process. The refining segment includes Dakota Prairie Refinery which is jointly owned by WBI Energy and Calumet and is located in southwestern North Dakota, along with WBI Energy's other activity that supports the refinery. 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 includes certain general and administrative costs (reflected in operation and maintenance expense) and interest expense which were previously allocated to Fidelity and do not meet the criteria for income (loss) from discontinued operations. The Other category also includes Centennial Resources' former investment in the Brazilian Transmission Lines. Discontinued operations includes the results of Fidelity other than certain general and administrative costs and interest expense as described above. Fidelity engaged in oil and natural gas development and production activities in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States. In the third and fourth quarters of 2015 and the first quarter of 2016, the Company entered into purchase and sale agreements to sell the vast majority of Fidelity's assets, comprising greater than 93 percent of total production for 2014. The completion of the majority of these sales occurred in the fourth quarter of 2015 and the Company continues to market the remaining assets of Fidelity. Discontinued operations also includes legal expenses and a benefit related to the vacation of an arbitration award in 2014 related to Centennial Resources. For more information on discontinued operations, see Note 2 . 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: 2015 2014 2013 (In thousands) External operating revenues: Regulated operations: Electric $ 280,615 $ 277,874 $ 257,260 Natural gas distribution 817,419 921,986 851,945 Pipeline and midstream 50,238 46,786 47,633 1,148,272 1,246,646 1,156,838 Nonregulated operations: Pipeline and midstream 54,282 64,494 56,427 Construction materials and contracting 1,901,530 1,740,089 1,675,444 Construction services 907,767 1,062,055 1,029,909 Refining 178,262 — — Other 1,436 1,532 1,553 3,043,277 2,868,170 2,763,333 Total external operating revenues $ 4,191,549 $ 4,114,816 $ 3,920,171 Intersegment operating revenues: Electric $ — $ — $ — Natural gas distribution — — — Pipeline and midstream 51,716 46,085 40,511 Construction materials and contracting 2,752 25,241 36,693 Construction services 18,660 57,474 9,930 Refining — — — Other 7,755 7,832 8,067 Intersegment eliminations (80,883 ) (136,632 ) (95,201 ) Total intersegment operating revenues $ — $ — $ — Depreciation, depletion and amortization: Electric $ 37,583 $ 35,008 $ 32,789 Natural gas distribution 64,756 54,700 50,031 Pipeline and midstream 27,981 29,749 29,105 Construction materials and contracting 65,937 68,557 74,470 Construction services 13,420 12,874 11,939 Refining 16,463 896 14 Other 2,070 2,196 2,050 Intersegment eliminations (480 ) — — Total depreciation, depletion and amortization $ 227,730 $ 203,980 $ 200,398 Interest expense: Electric $ 17,421 $ 15,595 $ 12,590 Natural gas distribution 29,471 27,217 25,123 Pipeline and midstream 9,895 9,946 10,148 Construction materials and contracting 15,183 16,368 17,394 Construction services 3,959 4,176 4,306 Refining 3,450 119 182 Other 14,292 13,739 14,216 Intersegment eliminations (603 ) (254 ) (156 ) Total interest expense $ 93,068 $ 86,906 $ 83,803 2015 2014 2013 (In thousands) Income taxes: Electric $ 11,523 $ 12,442 $ 9,683 Natural gas distribution 11,377 11,350 16,633 Pipeline and midstream 7,505 12,232 3,466 Construction materials and contracting 41,619 18,586 24,765 Construction services 16,432 24,753 29,504 Refining (13,815 ) (2,533 ) (76 ) Other (8,107 ) (9,798 ) (6,812 ) Intersegment eliminations (931 ) (3,805 ) (2,869 ) Total income taxes $ 65,603 $ 63,227 $ 74,294 Earnings (loss) on common stock: Regulated operations: Electric $ 35,914 $ 36,731 $ 34,837 Natural gas distribution 23,607 30,484 37,656 Pipeline and midstream 20,680 15,440 15,388 80,201 82,655 87,881 Nonregulated operations: Pipeline and midstream (7,430 ) 9,226 (7,687 ) Construction materials and contracting 89,096 51,510 50,946 Construction services 23,762 54,432 52,213 Refining (22,457 ) (2,038 ) (72 ) Other (12,376 ) (7,317 ) (10,605 ) 70,595 105,813 84,795 Intersegment eliminations (1,531 ) (6,095 ) (4,307 ) Earnings on common stock before income (loss) from discontinued operations 149,265 182,373 168,369 Income (loss) from discontinued operations, net of tax (772,385 ) 115,175 109,879 Total earnings (loss) on common stock $ (623,120 ) $ 297,548 $ 278,248 Capital expenditures: Electric $ 332,876 $ 185,121 $ 168,557 Natural gas distribution 130,793 120,613 101,279 Pipeline and midstream 18,315 61,754 40,533 Construction materials and contracting 48,126 37,896 34,607 Construction services 38,269 26,942 15,102 Refining 22,052 115,655 86,559 Other 3,755 2,131 2,249 Net proceeds from sale or disposition of property and other (63,831 ) (60,177 ) (28,392 ) Total net capital expenditures $ 530,355 $ 489,935 $ 420,494 Assets: Electric* $ 1,327,258 $ 1,030,611 $ 884,283 Natural gas distribution* 2,042,925 1,931,908 1,786,068 Pipeline and midstream 593,025 655,735 620,639 Construction materials and contracting 1,279,057 1,272,231 1,305,808 Construction services 450,896 454,602 450,614 Refining 464,699 429,102 178,062 Other** 278,433 306,572 236,543 Assets held for sale 191,315 1,751,647 1,611,430 Total assets $ 6,627,608 $ 7,832,408 $ 7,073,447 2015 2014 2013 (In thousands) Property, plant and equipment: Electric* $ 1,786,148 $ 1,457,101 $ 1,315,822 Natural gas distribution* 2,076,581 1,904,759 1,776,901 Pipeline and midstream 758,729 818,388 789,569 Construction materials and contracting 1,553,428 1,529,942 1,510,355 Construction services 163,279 144,395 134,948 Refining 445,333 401,845 172,603 Other 49,537 50,937 49,997 Eliminations (15,367 ) (12,589 ) (4,473 ) Less accumulated depreciation, depletion and amortization 2,506,571 2,386,113 2,284,169 Net property, plant and equipment $ 4,311,097 $ 3,908,665 $ 3,461,553 * 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). Capital expenditures for 2015 , 2014 and 2013 include noncash capital expenditure-related accounts payable and exclude capital expenditures of the noncontrolling interest related to Dakota Prairie Refinery. The net transactions were $(40.5) million in 2015 , $(88.8) million in 2014 and $(70.0) million in 2013 .

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2015
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. Prior to 2013, defined pension plan benefits and accruals for all nonunion and certain union plans were frozen. On June 30, 2015, an additional union plan was frozen. At December 31, 2015, all of the Company's defined pension plans have been 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, 2015 and 2014 , and amounts recognized in the Consolidated Balance Sheets at December 31, 2015 and 2014 , were as follows: Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In thousands) Change in benefit obligation: Benefit obligation at beginning of year $ 475,337 $ 402,772 $ 99,012 $ 81,726 Service cost 86 129 1,816 1,518 Interest cost 17,141 17,682 3,607 3,521 Plan participants' contributions — — 1,408 1,399 Actuarial (gain) loss (24,875 ) 80,520 (5,873 ) 18,024 Benefits paid (24,729 ) (25,766 ) (7,236 ) (7,176 ) Benefit obligation at end of year 442,960 475,337 92,734 99,012 Change in net plan assets: Fair value of plan assets at beginning of year 354,363 334,844 87,586 84,543 Actual gain (loss) on plan assets (10,879 ) 24,500 258 7,527 Employer contribution 13,912 20,785 577 1,293 Plan participants' contributions — — 1,408 1,399 Benefits paid (24,729 ) (25,766 ) (7,236 ) (7,176 ) Fair value of net plan assets at end of year 332,667 354,363 82,593 87,586 Funded status - under $ (110,293 ) $ (120,974 ) $ (10,141 ) $ (11,426 ) Amounts recognized in the Consolidated Balance Sheets at December 31: Other assets (noncurrent) $ — $ — $ 5,095 $ 4,345 Other accrued liabilities (current) — — (421 ) (322 ) Other liabilities (noncurrent) (110,293 ) (120,974 ) (14,815 ) (15,449 ) Net amount recognized $ (110,293 ) $ (120,974 ) $ (10,141 ) $ (11,426 ) Amounts recognized in accumulated other comprehensive (income) loss consist of: Actuarial loss $ 208,671 $ 207,430 $ 22,484 $ 25,779 Prior service cost (credit) — 294 (14,374 ) (15,744 ) Total $ 208,671 $ 207,724 $ 8,110 $ 10,035 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 4 . 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 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. 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: 2015 2014 (In thousands) Projected benefit obligation $ 442,960 $ 475,337 Accumulated benefit obligation $ 442,960 $ 475,337 Fair value of plan assets $ 332,667 $ 354,363 Components of net periodic benefit cost (credit) for the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows: Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 (In thousands) Components of net periodic benefit cost (credit): Service cost $ 86 $ 129 $ 155 $ 1,816 $ 1,518 $ 1,675 Interest cost 17,141 17,682 16,249 3,607 3,521 3,215 Expected return on assets (22,254 ) (21,218 ) (19,917 ) (4,795 ) (4,617 ) (4,343 ) Amortization of prior service cost (credit) 36 71 71 (1,371 ) (1,393 ) (1,457 ) Recognized net actuarial loss 7,016 4,869 7,173 1,960 649 1,814 Curtailment loss 258 — — — — — Net periodic benefit cost (credit), including amount capitalized 2,283 1,533 3,731 1,217 (322 ) 904 Less amount capitalized 316 388 727 120 (21 ) 164 Net periodic benefit cost (credit) 1,967 1,145 3,004 1,097 (301 ) 740 Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss: Net (gain) loss 8,257 77,238 (60,173 ) (1,336 ) 15,114 (30,461 ) Amortization of actuarial loss (7,016 ) (4,869 ) (7,173 ) (1,960 ) (649 ) (1,814 ) Amortization of prior service (cost) credit (294 ) (71 ) (71 ) 1,371 1,393 1,457 Total recognized in accumulated other comprehensive (income) loss 947 72,298 (67,417 ) (1,925 ) 15,858 (30,818 ) Total recognized in net periodic benefit cost (credit) and accumulated other comprehensive (income) loss $ 2,914 $ 73,443 $ (64,413 ) $ (828 ) $ 15,557 $ (30,078 ) The estimated net loss for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2016 is $6.2 million . 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 2016 are $1.5 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 2015 2014 2015 2014 Discount rate 4.00 % 3.70 % 4.06 % 3.74 % Expected return on plan assets 6.75 % 7.00 % 5.75 % 6.00 % Rate of compensation increase N/A N/A 3.00 % 3.00 % Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows: Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 Discount rate 3.70 % 4.53 % 3.74 % 4.48 % Expected return on plan assets 7.00 % 7.00 % 6.00 % 6.00 % Rate of compensation increase N/A N/A 3.00 % 3.00 % 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, 2015, 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 30 percent to 40 percent equity securities and 60 percent to 70 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: 2015 2014 Health care trend rate assumed for next year 4.0 % – 8.0 % 4.0 % – 7.0 % Health care cost trend rate - ultimate 5.0 % – 6.0 % 5.0 % – 6.0 % Year in which ultimate trend rate achieved 2021 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, 2015 : 1 Percentage Point Increase 1 Percentage Point Decrease (In thousands) Effect on total of service and interest cost components $ 203 $ (169 ) Effect on postretirement benefit obligation $ 4,006 $ (3,407 ) 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, 2015 and 2014 , 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, 2015, Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2015 (In thousands) Assets: Cash equivalents $ — $ 8,379 $ — $ 8,379 Equity securities: U.S. companies 15,135 — — 15,135 International companies 2,332 — — 2,332 Collective and mutual funds* 154,400 63,568 — 217,968 Corporate bonds — 62,145 — 62,145 Municipal bonds — 11,680 — 11,680 U.S. Government securities 5,288 6,823 — 12,111 Total assets measured at fair value $ 177,155 $ 152,595 $ — $ 329,750 * Collective and mutual funds invest approximately 19 percent in common stock of large-cap U.S. companies, 6 percent in common stock of mid-cap U.S. companies, 16 percent in corporate bonds, 29 percent in common stock of international companies, 16 percent in cash equivalents and 14 percent in other investments. Fair Value Measurements at December 31, 2014, Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2014 (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. 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, 2015 and 2014 , 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, 2015, Using Quoted Prices Significant Significant Unobservable Balance at December 31, 2015 (In thousands) Assets: Cash equivalents $ — $ 3,261 $ — $ 3,261 Equity securities: U.S. companies 2,274 — — 2,274 International companies 9 — — 9 Insurance contract* — 77,044 — 77,044 Total assets measured at fair value $ 2,283 $ 80,305 $ — $ 82,588 * The insurance contract invests approximately 19 percent in common stock of large-cap U.S. companies, 22 percent in U.S. Government securities, 10 percent in mortgage-backed securities, 36 percent in corporate bonds and 13 percent in other investments. Fair Value Measurements at December 31, 2014, Using Quoted Prices Significant Significant Unobservable Balance at December 31, 2014 (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. The Company does not expect to contribute to its defined benefit pension plans and expects to contribute approximately $800,000 to its postretirement benefit plans in 2016 . The following benefit payments, which reflect future service, as appropriate, and expected Medicare Part D subsidies are as follows: Years Pension Benefits Other Postretirement Benefits Expected Medicare Part D Subsidy (In thousands) 2016 $ 24,223 $ 5,234 $ 197 2017 24,680 5,351 191 2018 24,980 5,420 183 2019 25,323 5,441 175 2020 25,700 5,331 168 2021 - 2025 133,029 27,261 688 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. In February 2016, the Company froze the unfunded, nonqualified defined benefit plans to new participants and eliminated upgrades. Vesting for participants not fully vested was retained. The Company's net periodic benefit cost for these plans was $7.1 million , $6.6 million and $7.3 million in 2015 , 2014 and 2013 , respectively. The total projected benefit obligation for these plans was $110.8 million and $115.6 million at December 31, 2015 and 2014 , respectively. The accumulated benefit obligation for these plans was $104.6 million and $108.2 million at December 31, 2015 and 2014 , respectively. A weighted average discount rate of 3.77 percent and 3.51 percent at December 31, 2015 and 2014 , respectively, and a rate of compensation increase of 4.00 percent and 4.00 percent at December 31, 2015 and 2014 , were used to determine benefit obligations. A discount rate of 3.51 percent and 4.32 percent for the years ended December 31, 2015 and 2014 , respectively, and a rate of compensation increase of 4.00 percent and 4.00 percent for the years ended December 31, 2015 and 2014 , respectively, were used to determine net periodic benefit cost. The amount of benefit payments for the unfunded, nonqualified benefit plans are expected to aggregate $6.5 million in 2016 ; $6.7 million in 2017 ; $7.1 million in 2018 ; $7.3 million in 2019 ; $7.8 million in 2020 and $37.7 million for the years 2021 through 2025. In 2012, the Company established a nonqualified defined contribution plan for certain key management employees. Expenses incurred under this plan for 2015 , 2014 and 2013 were $207,000 , $104,000 and $25,000 , respectively. The Company had investments of $105.2 million and $101.4 million at December 31, 2015 and 2014 , respectively, consisting of equity securities of $54.2 million and $54.9 million , respectively, life insurance carried on plan participants (payable upon the employee's death) of $34.3 million and $32.8 million , respectively, and other investments of $16.7 million and $13.7 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 $36.8 million in 2015 , $34.4 million in 2014 and $33.2 million in 2013 . 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 2015 and 2014 is for the plan's year-end at December 31, 2014 , and December 31, 2013 , 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 2015 2014 2015 2014 2013 (In thousands) Edison Pension Plan 93-6061681-001 Green as of 12/31/2015 Green as of 12/31/2014 No $ 5,517 $ 9,061 $ 6,358 No 12/31/2017 IBEW Local No. 82 Pension Plan 31-6127268-001 Red as of 6/30/2015 Red as of 6/30/2014 Implemented 2,252 1,392 1,284 No 11/29/2015* IBEW Local No. 246 Pension Plan 34-6582842-001 Yellow as of 5/31/2015 Yellow as of 5/31/2014 Implemented 433 694 1,848 No 10/31/2017 IBEW Local No. 357 Pension Plan A 88-6023284-001 Green Green No 1,896 3,575 2,348 No 5/31/2018 IBEW Local 648 Pension Plan 31-6134845-001 Red as of 2/28/2015 Red as of 2/28/2014 Implemented 745 1,110 1,489 No 9/2/2018 Idaho Plumbers and Pipefitters Pension Plan 82-6010346-001 Green as of 5/31/2015 Green as of 5/31/2014 No 1,169 1,125 1,121 No 9/30/2016 Local Union 212 IBEW Pension Trust Fund 31-6127280-001 Yellow as of 4/30/2015 Yellow as of 4/30/2014 Implemented 937 568 531 No 6/5/2016 National Automatic Sprinkler Industry Pension Fund 52-6054620-001 Red as of 12/31/2015 Red as of 12/31/2014 Implemented 677 608 583 No 3/31/2016- National Electrical Benefit Fund 53-0181657-001 Green Green No 5,271 6,476 5,883 No 6/30/2015*- Pension Trust Fund for Operating Engineers 94-6090764-001 Red as of 12/31/2015 Red as of 12/31/2014 Implemented 1,997 1,445 1,510 No 6/15/2015*– Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming** 83-6011320-001 Red as of 12/31/2015 Red as of 12/31/2014 Implemented — 68 76 No 10/31/2005* Sheet Metal Workers' Pension Plan of Southern CA, AZ and NV 95-6052257-001 Red as of 12/31/2015 Red as of 12/31/2014 Implemented 714 676 512 No 6/30/2016 Southwest Marine Pension Trust 95-6123404-001 Red Red Implemented 26 31 42 No 1/31/2014*– Other funds 17,478 15,988 15,675 Total contributions $ 39,112 $ 42,817 $ 39,260 * 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 2014 and 2013 IBEW Local No. 82 Pension Plan 2014 and 2013 Local Union No. 124 IBEW Pension Trust Fund 2014 and 2013 Local Union 212 IBEW Pension Trust Fund 2014 and 2013 IBEW Local Union No. 357 Pension Plan A 2014 and 2013 IBEW Local 573 Pension Plan 2014 IBEW Local 648 Pension Plan 2014 and 2013 Idaho Plumbers and Pipefitters Pension Plan 2014 Minnesota Teamsters Construction Division Pension Fund 2014 and 2013 Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming* 2014 and 2013 Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525 2014 and 2013 * 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. The Company estimated the withdrawal liability to be approximately $14.0 million at December 31, 2014. In the first quarter of 2015, the Company accrued an additional withdrawal liability of approximately $2.4 million . The total withdrawal liability is currently estimated at $16.4 million . 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 $31.4 million , $34.6 million and $37.1 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Amounts contributed in 2015 , 2014 and 2013 to defined contribution multiemployer plans were $19.5 million , $22.0 million and $20.6 million , respectively.

Jointly owned facilities

Jointly owned facilities	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 (In thousands) Big Stone Station: Utility plant in service $ 157,761 $ 64,283 Less accumulated depreciation 48,242 43,043 $ 109,519 $ 21,240 Coyote Station: Utility plant in service $ 140,895 $ 138,810 Less accumulated depreciation 94,755 94,443 $ 46,140 $ 44,367 Wygen III: Utility plant in service $ 65,023 $ 65,597 Less accumulated depreciation 6,788 5,928 $ 58,235 $ 59,669

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Regulatory matters	Regulatory Matters On March 31, 2015, Cascade filed an application with the OPUC for a natural gas rate increase. Cascade requested a total increase of approximately $3.6 million annually or approximately 5.1 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, as well as environmental remediation expenses. On November 2, 2015, Cascade, staff of the OPUC, the Citizens' Utility Board of Oregon and the Northwest Industrial Gas Users filed a settlement agreement that resolved all issues of the application and reflected a natural gas rate increase of approximately $600,000 annually or approximately .8 percent, to be effective February 1, 2016. The OPUC issued an order on December 28, 2015, accepting the settlement. On June 25, 2015, Montana-Dakota filed an application for an electric rate increase with the MTPSC. Montana-Dakota requested a total increase of approximately $11.8 million annually or approximately 21.1 percent above current rates. The increase is necessary to recover Montana-Dakota’s investments in modifications to generation facilities to comply with new EPA requirements, the addition and/or replacement of capacity and energy requirements and transmission facilities along with the additional depreciation, operation and maintenance expenses and taxes associated with the increases in investment. Montana-Dakota requested an interim increase of approximately $11.0 million annually. The MTPSC denied the request for interim rates on December 15, 2015. On February 8, 2016, Montana-Dakota and the interveners to the case filed a stipulation and settlement agreement reflecting an annual increase of $3.0 million effective April 1, 2016, and an additional increase of $4.4 million effective April 1, 2017. A technical hearing was held February 9, 2016. This matter is pending before the MTPSC. On June 30, 2015, Montana-Dakota filed an application with the SDPUC for an electric rate increase. Montana-Dakota requested a total increase of approximately $2.7 million annually or approximately 19.2 percent above current rates. The increase is necessary to recover Montana-Dakota’s investments in modifications to generation facilities to comply with new EPA requirements, the addition and/or replacement of capacity and energy requirements and transmission facilities along with the additional depreciation, operation and maintenance expenses and taxes associated with the increases in investment. This matter is pending before the SDPUC. An interim increase of $2.7 million , subject to refund, was implemented January 1, 2016. A hearing is scheduled for the week of April 11, 2016. On June 30, 2015, Montana-Dakota filed an application for a natural gas rate increase with the SDPUC. Montana-Dakota requested a total increase of approximately $1.5 million annually or approximately 3.1 percent above current rates. The increase is necessary to recover increased operating expenses along with increased investment in facilities, including the related depreciation expense and taxes, partially offset by an increase in customers and throughput. This matter is pending before the SDPUC. An interim increase of $1.5 million , subject to refund, was implemented January 1, 2016. A hearing is scheduled for April 4, 2016. On September 1, 2015, and as amended on October 5, 2015, Montana-Dakota submitted an update to its transmission formula rate under the MISO tariff including a revenue requirement for the Company’s multivalue project of $3.8 million , which was effective January 1, 2016. On September 30, 2015, Great Plains filed an application for a natural gas rate increase with the MNPUC. Great Plains requested a total increase of approximately $1.6 million annually or approximately 6.4 percent above current rates. The increase is necessary to recover increased operating expenses along with increased investment in facilities, including the related depreciation expense and taxes. Great Plains requested an interim increase of $1.5 million or approximately 6.4 percent, subject to refund. The interim request was approved by the MNPUC on November 30, 2015, and was effective with service rendered on and after January 1, 2016. This matter is pending before the MNPUC. A technical hearing is scheduled for April 7 and 8, 2016. On October 21, 2015, Montana-Dakota filed an application with the NDPSC for an update of an electric generation resource recovery rider and requested a renewable resource cost adjustment rider. Montana-Dakota requested a combined total of approximately $25.3 million with approximately $20.0 million incremental to current rates, to be effective January 1, 2016. This application was resubmitted as two applications on October 26, 2015. On October 26, 2015, Montana-Dakota filed an application requesting a renewable resource cost adjustment rider of $15.4 million for the recovery of the Thunder Spirit Wind project, placed in service in the fourth quarter of 2015. A settlement was reached with the NDPSC Advocacy Staff whereby Montana-Dakota agreed to a 10.5 percent return on equity on the renewable resource cost adjustment rider, as well as committed to file an electric general rate case no later than September 30, 2016. The renewable resource cost adjustment rider was approved by the NDPSC on January 5, 2016, to be effective January 7, 2016, resulting in an annual increase of $15.1 million on an interim basis pending the determination of the return on equity in the upcoming rate case. On October 26, 2015, Montana-Dakota filed an application for an update to the electric generation resource recovery rider, which currently includes recovery of Montana-Dakota's investment in the 88-MW simple-cycle natural gas turbine and associated facilities near Mandan, North Dakota. The application proposed to also include the 19 MW of new generation from natural gas-fired internal combustion engines and associated facilities, near Sidney, Montana, placed in service in the fourth quarter of 2015, for a total of $9.9 million or an incremental increase of $4.6 million to be recovered under the rider. On January 25, 2016, Montana-Dakota and the NDPSC Advocacy Staff filed a settlement agreement. If approved by the NDPSC, the settlement would result in an interim increase of $9.7 million or an incremental increase of $4.4 million , subject to refund, a 10.5 percent return on equity and Montana-Dakota would commit to filing an electric general rate case no later than September 30, 2016. A technical hearing on this matter was held on February 4, 2016. On November 25, 2015, Montana-Dakota filed an application with the NDPSC for an update of its transmission cost adjustment for recovery of MISO-related charges and two transmission projects located in North Dakota, equating to $6.8 million to be collected under the transmission cost adjustment. An update to the transmission cost adjustment was submitted on January 19, 2016, to reflect the provisions of the settlement agreement approved by the NDPSC for the renewable resource cost adjustment rider. An informal hearing with the NDPSC was held January 20, 2016, regarding this matter. The NDPSC approved the filing on February 10, 2016, with rates to be effective February 12, 2016. On December 1, 2015, Cascade filed an application with the WUTC for a natural gas rate increase. Cascade requested a total increase of approximately $10.5 million annually or approximately 4.2 percent above current rates. The requested increase includes costs associated with increased infrastructure investment and the associated operating expenses. The filing is pending before the WUTC. The natural gas rate increase is expected to be effective November 1, 2016. A hearing on this matter has been scheduled to begin August 2, 2016.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
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 $19.5 million and $27.6 million , which include liabilities held for sale, for contingencies, including litigation, production taxes, royalty claims and environmental matters at December 31, 2015 and 2014 , respectively, including amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note. 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 . 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. WBI Energy Midstream resolved this matter in December 2015 through a settlement that included dismissal of the litigation and payment of an amount that was not material. 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. 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 which JTL expects will be approved by the Montana DEQ in the first half of 2016. The Company intends to resolve the Montana First Judicial District Court litigation through settlement. Construction Services Bombard Mechanical is a third-party defendant in litigation pending in Nevada State District Court in which the plaintiff claims damages attributable to defects in the construction of a 48 story residential tower built in 2008 for which Bombard Mechanical performed plumbing and mechanical work as a subcontractor. On March 12, 2015, the plaintiff presented cost of repair estimates totaling approximately $21 million for alleged plumbing and mechanical system defects associated in whole or in part with work performed by Bombard Mechanical. Bombard Mechanical is being defended in the action under a policy of insurance subject to a reservation of rights. 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. Coos County The Oregon DEQ issued a Notice of Civil Penalty to LTM dated October 12, 2015, asserting violations of Oregon water quality statutes and rules resulting from the stockpiling and grading of earthen material during 2014 at a site in Coos County and assessing civil penalties totaling approximately $160,000 . The Notice of Civil Penalty alleges violations by causing pollution to an intermittent creek, by conducting activity described in a general National Pollutant Discharge Elimination System permit without applying for coverage under the general permit, by placing the earthen materials in a location where they were likely to escape or be carried into waters of the state, and by failing to submit a revised ESCP where there was a change in the size of the project or the location of the disturbed area. The Notice of Civil Penalty also requires LTM to submit a revised ESCP containing measures to prevent further erosion from entering the intermittent creek and to file a work plan outlining how the earthen material will be permanently stabilized or removed. LTM intends to request a contested case hearing on the Notice of Civil Penalty. 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, December 1, 2014 and December 1, 2015. 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. The 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 $12.9 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 4 . 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, 2015 , were $52.3 million in 2016 , $42.7 million in 2017 , $35.5 million in 2018 , $26.4 million in 2019 , $15.9 million in 2020 and $76.9 million thereafter. Rent expense was $65.1 million , $48.5 million and $39.7 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Purchase commitments The Company has entered into various commitments, largely construction, natural gas and coal supply, purchased power, natural gas transportation and storage, and service, shipping and construction materials supply contracts, some of which are subject to variability in volume and price. These commitments range from one to 45 years . The commitments under these contracts as of December 31, 2015 , were $443.7 million in 2016 , $228.0 million in 2017 , $138.9 million in 2018 , $112.9 million in 2019 , $90.4 million in 2020 and $853.9 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, 2015 , 2014 and 2013 , were $861.4 million , $925.2 million and $860.5 million , respectively. Guarantees In 2009, multiple sales agreements were signed to sell the Company's ownership interests in the Brazilian Transmission Lines. In connection with the sale, 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. 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, insurance deductibles and loss limits, and certain other guarantees. At December 31, 2015 , the fixed maximum amounts guaranteed under these agreements aggregated $128.6 million . The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $33.1 million in 2016 ; $35.0 million in 2017 ; $600,000 in 2018 ; $54.9 million in 2019 ; $1.0 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. There were no amounts outstanding under the above guarantees at December 31, 2015 . 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, 2015 , the fixed maximum amounts guaranteed under these letters of credit aggregated $57.3 million , all of which expire in 2016. The amount outstanding by subsidiaries of the Company under the above letters of credit was $4.1 million and was reflected on the Consolidated Balance Sheet at December 31, 2015 . In the event of default under these letter of credit obligations, the subsidiary issuing the letter of credit for that particular obligation would be required to make payments under its letter of credit. Centennial and WBI Holdings have guaranteed certain debt obligations of Dakota Prairie Refining. For more information, see Variable interest entities in this note. 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, 2015 . 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, 2015 , approximately $530.0 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 being shared equally between WBI Energy and Calumet. WBI Energy's and Calumet's cumulative capital contributions, net of distributions, as of December 31, 2015, are $230.4 million and $163.6 million , respectively. 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. The net loss attributable to noncontrolling interest on the Consolidated Statements of Income is pretax as Dakota Prairie Refining is a limited liability company. On September 30, 2015, Dakota Prairie Refining entered into an amendment to its revolving credit agreement which increased the borrowing limit from $50.0 million under the original December 1, 2014, agreement to $75.0 million and extended the termination date from December 1, 2015 to June 30, 2016. Centennial and Calumet have each 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. Dakota Prairie Refinery has commenced operations. 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: 2015 2014 (In thousands) Assets Current assets: Cash and cash equivalents $ 851 $ 21,376 Accounts receivable 7,693 2,759 Inventories 13,176 5,311 Other current assets 6,215 4,019 Total current assets 27,935 33,465 Net property, plant and equipment 425,123 398,984 Deferred charges and other assets: Other 9,626 3,400 Total deferred charges and other assets 9,626 3,400 Total assets $ 462,684 $ 435,849 Liabilities Current liabilities: Short-term borrowings $ 45,500 $ — Long-term debt due within one year 5,250 3,000 Accounts payable 24,766 55,089 Taxes payable 1,391 648 Accrued compensation 938 727 Other accrued liabilities 4,953 899 Total current liabilities 82,798 60,363 Long-term debt 63,750 69,000 Total liabilities $ 146,548 $ 129,363 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, 2015 , 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, 2015 , was $40.1 million .

Quarterly Data (Unaudited)

Quarterly Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
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 2015 and 2014 : First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except per share amounts) 2015 Operating revenues $ 862,349 $ 986,215 $ 1,280,500 $ 1,062,485 Operating expenses 818,680 940,887 1,170,757 1,007,092 Operating income 43,669 45,328 109,743 55,393 Income from continuing operations 15,160 14,057 53,400 32,077 Income (loss) from discontinued operations, net of tax (324,605 ) (251,415 ) (202,626 ) 6,261 Net income (loss) attributable to the Company (305,917 ) (229,604 ) (139,448 ) 52,534 Earnings (loss) per common share - basic: Earnings before discontinued operations .10 .11 .32 .24 Discontinued operations, net of tax (1.67 ) (1.29 ) (1.04 ) .03 Earnings (loss) per common share - basic (1.57 ) (1.18 ) (.72 ) .27 Earnings (loss) per common share - diluted: Earnings before discontinued operations .10 .11 .32 .24 Discontinued operations, net of tax (1.67 ) (1.29 ) (1.04 ) .03 Earnings (loss) per common share - diluted (1.57 ) (1.18 ) (.72 ) .27 Weighted average common shares outstanding: Basic 194,479 194,805 195,151 195,266 Diluted 194,566 194,838 195,169 195,324 2014 Operating revenues $ 900,761 $ 952,564 $ 1,213,203 $ 1,048,288 Operating expenses 837,153 890,210 1,094,310 973,720 Operating income 63,608 62,354 118,893 74,568 Income from continuing operations 31,027 29,446 63,639 55,051 Income from discontinued operations, net of tax 25,112 23,881 38,482 27,700 Net income attributable to the Company 56,662 54,106 103,209 84,256 Earnings per common share - basic: Earnings before discontinued operations .17 .16 .33 .29 Discontinued operations, net of tax .13 .12 .20 .14 Earnings per common share - basic .30 .28 .53 .43 Earnings per common share - diluted: Earnings before discontinued operations .16 .16 .33 .29 Discontinued operations, net of tax .14 .12 .20 .14 Earnings per common share - diluted .30 .28 .53 .43 Weighted average common shares outstanding: Basic 189,820 192,060 193,949 194,136 Diluted 190,432 192,659 194,300 194,219 Notes: • First quarter 2015 reflects a MEPP withdrawal liability of $2.4 million (before tax). For more information, see Note 14 . • Second quarter 2015 reflects an impairment of coalbed natural gas gathering assets of $3.0 million (before tax). For more information, see Note 1 . • Third quarter 2015 reflects an impairment of coalbed natural gas gathering assets of $14.1 million (before tax). For more information, see Note 1 . • Fourth quarter 2014 reflects a MEPP withdrawal liability of approximately $14.0 million (before tax). For more information, see Note 14 . • 2014 and first quarter 2015 have been restated to present the results of operations of Fidelity as discontinued operations, other than certain general and administrative costs and interest expense which were previously allocated to the former exploration and production segment and do not meet the criteria for income (loss) from discontinued operations. 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 Acti

Exploration and Production Activities (Unaudited) (Notes)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Exploration and production activities	Exploration and Production Activities (Unaudited) In the third and fourth quarters of 2015 and the first quarter of 2016, the Company entered into purchase and sale agreements to sell the vast majority of Fidelity's assets, comprising greater than 93 percent of total production for 2014. A majority of the sales were completed in the fourth quarter of 2015. At the time the Company committed to a plan to sell Fidelity, the Company stopped the use of the full-cost method of accounting for its oil and natural gas production activities. The assets and liabilities have been classified as held for sale and the results of operations included in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. Prior to the asset sales, Fidelity was significantly involved in the development and production of oil and natural gas resources. For more information, see Note 2 . Fidelity shares revenues and expenses from the development of specified properties 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: 2015 * 2014 2013 (In thousands) Subject to amortization $ — $ 3,205,036 $ 2,893,010 Not subject to amortization — 132,141 124,869 Total capitalized costs — 3,337,177 3,017,879 Less accumulated depreciation, depletion and amortization — 1,752,566 1,562,116 Net capitalized costs $ — $ 1,584,611 $ 1,455,763 * Excludes assets held for sale. Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities were as follows: Years ended December 31, 2015 * 2014 ** 2013 ** (In thousands) Acquisitions: Proved properties $ — $ 87,919 $ 1,817 Unproved properties — 138,683 4,608 Exploration — 16,879 26,975 Development — 331,400 355,421 Total capital expenditures $ — $ 574,881 $ 388,821 * No wells were drilled in 2015. ** 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 of $(9.0) million and $(10.7) million for the years ended December 31, 2014 and 2013 , respectively. The preceding table excludes proceeds from the sales of oil and natural gas properties of $246.6 million and $83.6 million for the years ended December 31, 2014 and 2013 , respectively. The following reflects the results of operations from the Company's oil and natural gas producing activities included in discontinued operations, excluding corporate overhead and financing costs: Years ended December 31, 2015 2014 2013 (In thousands) Income (loss) from discontinued operations $ (772,385 ) $ 111,998 $ 110,191 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, 2015, 2014 and 2013 , 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. 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 changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2015, were as follows: Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) Total (MBOE) Proved developed and undeveloped reserves: Balance at beginning of year 43,918 7,187 245,011 91,940 Production (3,286 ) (393 ) (16,747 ) (6,471 ) Extensions and discoveries 744 29 681 888 Improved recovery — — — — Purchases of proved reserves — — — — Sales of proved reserves (16,474 ) (6,864 ) (202,560 ) (57,097 ) Revisions of previous estimates (12,215 ) 252 (23,854 ) (15,939 ) Balance at end of year 12,687 211 2,531 13,321 Significant changes in proved reserves for the year ended December 31, 2015, include: • Sales of proved reserves of (57.1) MMBOE, primarily due to the Company's decision to sell Fidelity and exit the exploration and production business • Revisions of previous estimates of (15.9) MMBOE, largely the result of lower commodity prices 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 (MBbls) NGL (MBbls) Natural Gas (MMcf) Total (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 (MBbls) NGL (MBbls) Natural Gas (MMcf) Total (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: • Extensions 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 following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31: 2015 2014 2013 Proved developed reserves: Oil (MBbls) 11,380 30,130 31,394 NGL (MBbls) 144 4,217 5,322 Natural Gas (MMcf) 2,033 184,437 176,546 Total (MBOE) 11,865 65,086 66,140 PUD reserves: Oil (MBbls) 1,307 13,788 9,625 NGL (MBbls) 67 2,970 1,280 Natural Gas (MMcf) 498 60,574 21,899 Total (MBOE) 1,456 26,854 14,555 Total proved reserves: Oil (MBbls) 12,687 43,918 41,019 NGL (MBbls) 211 7,187 6,602 Natural Gas (MMcf) 2,531 245,011 198,445 Total (MBOE) 13,321 91,940 80,695 As of December 31, 2015 , the Company had 1.5 MMBOE of PUD reserves, which is a decrease of 25.4 MMBOE from December 31, 2014 . The decrease relates to the various asset sales during 2015 and certain PUD reserves becoming uneconomic due to lower commodity prices. At December 31, 2015 , the Company did not have any PUD locations that remained undeveloped for five years of more. 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 (In thousands) Future cash inflows $ 5,185,500 $ 4,507,000 Future production costs 1,856,900 1,734,800 Future development costs 570,200 403,000 Future net cash flows before income taxes 2,758,400 2,369,200 Future income tax expense 686,100 545,200 Future net cash flows 2,072,300 1,824,000 10% annual discount for estimated timing of cash flows 997,400 810,000 Discounted future net cash flows relating to proved oil, NGL and natural gas reserves $ 1,074,900 $ 1,014,000 Note: Standardized measure not applicable in 2015 as the remaining oil and natural gas properties are held for sale and subject to fair value impairment. The following are the sources of change in the standardized measure of discounted future net cash flows by year: 2014 2013 (In thousands) Beginning of year $ 1,014,000 $ 883,400 Net revenues from production (368,900 ) (398,000 ) Net change in sales prices and production costs related to future production 86,300 162,200 Extensions and discoveries, net of future production-related costs 231,900 366,500 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 ) Changes in estimated future development costs 65,100 6,700 Development costs incurred during the current year 104,600 141,500 Accretion of discount 109,400 94,600 Net change in income taxes (33,400 ) (141,400 ) Revisions of previous estimates (16,300 ) (55,800 ) Other (2,300 ) (7,900 ) Net change 60,900 130,600 End of year $ 1,074,900 $ 1,014,000 Note: Standardized measure not applicable in 2015 as the remaining oil and natural gas properties are held for sale and subject to fair value impairment. Historically, 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.

Summary of significant accoun28

Summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2015
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 midstream, construction materials and contracting, construction services, refining and other. The electric and natural gas distribution businesses, as well as a portion of the pipeline and midstream business, are regulated. Construction materials and contracting, construction services, refining and the other businesses, as well as a portion of the pipeline and midstream business, are nonregulated. For further descriptions of the Company's businesses, see Note 13 . 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 4 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, 2015 , up to the date of issuance of these consolidated financial statements. In the second quarter of 2015, the Company announced its plan to market Fidelity, previously referred to as the Company's exploration and production segment, and exit that line of business. In the third and fourth quarters of 2015 and the first quarter of 2016, the Company entered into purchase and sale agreements to sell the vast majority of Fidelity's assets, comprising greater than 93 percent of total production for 2014. The Company's consolidated financial statements and accompanying notes for current and prior periods have been restated to present the results of operations of Fidelity as discontinued operations, other than certain general and administrative costs and interest expense which were previously allocated to the former exploration and production segment and do not meet the criteria for income (loss) from discontinued operations. In addition, the assets and liabilities have been treated and classified as held for sale. Unless otherwise indicated, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company's continuing operations. For more information on discontinued operations, see Note 2 .
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 $27.8 million and $29.4 million at December 31, 2015 and 2014 , 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, 2015 and 2014 , was $9.8 million and $9.5 million , respectively.
Inventories and natural gas in storage	Inventories and natural gas in storage 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. Crude oil and refined products at Dakota Prairie Refinery are carried at lower of cost or market value using the last-in, first-out method. In 2015, Dakota Prairie Refinery recorded $12.2 million (before tax) of inventory impairments due to the lower of cost or market valuation which is reflected in cost of crude oil on the Consolidated Statements of Income. All other inventories are stated at the lower of average cost or market value. 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: 2015 2014 (In thousands) Aggregates held for resale $ 115,854 $ 108,161 Asphalt oil 36,498 42,135 Materials and supplies 16,997 54,282 Merchandise for resale 15,318 24,420 Refined products 8,498 — Natural gas in storage (current) 21,023 19,302 Crude oil 4,678 5,045 Other 34,861 36,065 Total $ 253,727 $ 289,410 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 $49.1 million and $49.3 million at December 31, 2015 and 2014 , respectively.
Investments	Investments The Company's investments include the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. 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 6 and 14 .
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 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, 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: 2015 2014 2013 (In thousands) Interest capitalized $ 4,902 $ 8,586 $ 6,033 AFUDC - borrowed $ 4,907 $ 3,022 $ 2,767 AFUDC - equity $ 7,971 $ 5,803 $ 3,322 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. 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: 2015 2014 Weighted Average Depreciable Life in Years (Dollars in thousands, where applicable) Regulated: Electric: Generation $ 1,003,173 $ 627,952 39 Distribution 375,612 343,692 44 Transmission 255,842 229,997 57 Construction in progress 42,436 150,445 - Other 109,085 105,015 14 Natural gas distribution: Distribution 1,624,645 1,481,390 35 Construction in progress 20,530 59,310 - Other 431,406 364,059 22 Pipeline and midstream: Transmission 460,305 449,276 53 Gathering 37,831 39,595 20 Storage 44,011 43,994 60 Construction in progress 7,549 5,386 - Other 40,168 39,910 33 Nonregulated: Pipeline and midstream: Gathering and processing 158,949 227,598 16 Construction in progress 89 691 - Other 9,827 11,938 10 Construction materials and contracting: Land 123,723 125,372 - Buildings and improvements 69,011 70,566 19 Machinery, vehicles and equipment 937,084 921,564 12 Construction in progress 18,615 8,709 - Aggregate reserves 404,995 403,731 * Construction services: Land 6,460 5,265 - Buildings and improvements 23,824 17,936 25 Machinery, vehicles and equipment 121,940 112,973 6 Other 11,055 8,221 3 Refining: Refinery 445,198 88,232 20 Construction in progress 135 313,613 - Other: Land 2,837 2,837 - Other 46,700 48,100 23 Eliminations (15,367 ) (12,589 ) Less accumulated depreciation, depletion and amortization 2,506,571 2,386,113 Net property, plant and equipment $ 4,311,097 $ 3,908,665 * 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, oil and natural gas properties, and assets held for sale, 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 the third quarter of 2015 , the Company recognized an impairment of $14.1 million (before tax) related to the sale of certain non-strategic natural gas gathering assets that were written down to their estimated fair value that was determined using the market approach. In the second quarters of 2015 and 2013 , the Company recognized impairments of $3.0 million (before tax) and $14.5 million (before tax), respectively, related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a continued 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 their estimated fair value that was determined using the income approach. The impairments are recorded in operation and maintenance expense on the Consolidated Statements of Income. For more information on these nonrecurring fair value measurements, see Note 6 . 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 13 . 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, 2015 , 2014 and 2013 , there were no significant impairment losses recorded. At December 31, 2015 , 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 2015 . 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.
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 $102.1 million and $99.7 million at December 31, 2015 and 2014 , 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: 2015 2014 (In thousands) Costs and estimated earnings in excess of billings on uncompleted contracts $ 64,369 $ 58,243 Billings in excess of costs and estimated earnings on uncompleted contracts $ 68,048 $ 47,011 Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31 were as follows: 2015 2014 (In thousands) Short-term retainage* $ 46,207 $ 47,551 Long-term retainage** 1,605 1,053 Total retainage $ 47,812 $ 48,604 * 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 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 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 5 .
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 8 .
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 which are filed annually. Natural gas costs refundable through rate adjustments were $20.9 million and $13.2 million at December 31, 2015 and 2014 , respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $547,000 and $19.6 million at December 31, 2015 and 2014 , 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.
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 (loss) per common share were computed by dividing earnings (loss) 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 2015, 2014 and 2013, there were no shares excluded from the calculation of diluted earnings per share. 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: 2015 2014 2013 (In thousands) Weighted average common shares outstanding - basic 194,928 192,507 188,855 Effect of dilutive performance share awards 58 80 838 Weighted average common shares outstanding - diluted 194,986 192,587 189,693 Shares excluded from the calculation of diluted earnings per share — — —
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 assets held for sale, long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; 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; and the valuation of stock-based compensation. 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 Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity In April 2014, the FASB issued guidance related to the definition and reporting of discontinued operations. The guidance changed the definition of discontinued operations to include only disposals of a component or group of components that represent a strategic shift and that have a major effect on an entity's operations or financial results. The guidance also expands the disclosure requirements for transactions that meet the definition of a discontinued operation, and also requires entities to disclose information about individually significant components that are disposed of or held for sale that do not meet the definition of a discontinued operation. This guidance was effective for the Company on January 1, 2015, and is to be applied prospectively. The adoption required additional disclosures for the Company's discontinued operations, however it did not impact the Company's results of operations, financial position or cash flows. 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 was to be effective for the Company on January 1, 2017. In August 2015, the FASB issued guidance deferring the effective date of the revenue guidance one year and allowing entities to early adopt. With this decision, the guidance will be effective for the Company on January 1, 2018. 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. Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued guidance on simplifying the presentation of debt issuance costs in the financial statements. This guidance requires entities to present debt issuance costs as a direct deduction to the related debt liability. The amortization of these costs will be reported as interest expense. The guidance was effective for the Company on January 1, 2016, and is to be applied retrospectively. Early adoption of this guidance was permitted, however the Company has not elected to do so. The guidance will require a reclassification of the debt issuance costs on the Consolidated Balance Sheets, but will not impact the Company's results of operations or cash flows. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent) In May 2015, the FASB issued guidance on fair value measurement and disclosure requirements removing the requirement to include investments in the fair value hierarchy for which fair value is measured using the net asset value per share practical expedient. The new guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at net asset value using the practical expedient, and rather limits those disclosures to investments for which the practical expedient has been elected. This guidance was effective for the Company on January 1, 2016, with early adoption permitted. The Company is evaluating the effects the adoption of the new guidance will have on its disclosures, however it will not impact the Company's results of operations, financial position or cash flows. Simplifying the Measurement of Inventory In July 2015, the FASB issued guidance regarding inventory that is measured using the first-in, first-out or average cost method. The guidance does not apply to inventory measured using the last-in, first-out or the retail inventory method. The guidance requires inventory within its scope to be measured at the lower of cost or net realizable value, which is the estimated selling price in the normal course of business less reasonably predictable costs of completion, disposal and transportation. These amendments more closely align GAAP with IFRS. This guidance will be effective for the Company on January 1, 2017, and should be applied prospectively with early adoption permitted as of the beginning of an interim or annual reporting period. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position and cash flows. Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. The guidance will require all deferred tax assets and liabilities to be classified as noncurrent. These amendments will align GAAP with IFRS. This guidance will be effective for the Company on January 1, 2017, with early adoption permitted. Entities will have the option to apply the guidance prospectively, for all deferred tax assets and liabilities, or retrospectively. The Company is evaluating the effects the adoption of the new guidance will have on its financial position and disclosures, however it will not impact the Company's results of operations or cash flows. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued guidance regarding the classification and measurement of financial instruments. The guidance revises the way an entity classifies and measures investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value and amends certain disclosure requirements related to the fair value of financial instruments. This guidance will be effective for the Company on January 1, 2018, with early adoption of certain amendments permitted. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.
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 5 . The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2015 , 2014 and 2013 , were as follows: Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges Post- retirement Liability Adjustment Foreign Currency Translation Adjustment Net Unrealized Gain (Loss) on Available- for-sale Investments Total Accumulated Other Comprehensive Loss (In thousands) 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 ) Other comprehensive income (loss) before reclassifications — (88 ) (173 ) (170 ) (431 ) Amounts reclassified from accumulated other comprehensive loss 404 1,794 802 131 3,131 Amounts reclassified from accumulated other comprehensive loss to a regulatory asset — 2,255 — — 2,255 Net current-period other comprehensive income (loss) 404 3,961 629 (39 ) 4,955 Balance at December 31, 2015 $ (2,667 ) $ (34,257 ) $ (200 ) $ (24 ) $ (37,148 ) Reclassifications out of accumulated other comprehensive loss for the years ended December 31 were as follows: 2015 2014 Location on Consolidated Statements of Income (In thousands) Reclassification adjustment for loss on derivative instruments included in net income (loss): Interest rate derivative instruments $ (637 ) $ (639 ) Interest expense 233 240 Income taxes (404 ) (399 ) Commodity derivative instruments, net of tax — (295 ) Income (loss) from discontinued operations, net of tax (404 ) (694 ) Amortization of postretirement liability losses included in net periodic benefit cost (credit) (2,922 ) (1,288 ) (a) 1,128 492 Income taxes (1,794 ) (796 ) Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss) (1,292 ) — Other income 490 — Income taxes (802 ) — Reclassification adjustment for loss on available-for-sale investments included in net income (loss) (201 ) (208 ) Other income 70 73 Income taxes (131 ) (135 ) Total reclassifications $ (3,131 ) $ (1,625 ) (a) Included in net periodic benefit cost (credit). For more information, see Note 14 .

Summary of significant accoun29

Summary of significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Inventories	Inventories at December 31 consisted of: 2015 2014 (In thousands) Aggregates held for resale $ 115,854 $ 108,161 Asphalt oil 36,498 42,135 Materials and supplies 16,997 54,282 Merchandise for resale 15,318 24,420 Refined products 8,498 — Natural gas in storage (current) 21,023 19,302 Crude oil 4,678 5,045 Other 34,861 36,065 Total $ 253,727 $ 289,410
AFUDC and interest capitailized	The amount of AFUDC and interest capitalized for the years ended December 31 were as follows: 2015 2014 2013 (In thousands) Interest capitalized $ 4,902 $ 8,586 $ 6,033 AFUDC - borrowed $ 4,907 $ 3,022 $ 2,767 AFUDC - equity $ 7,971 $ 5,803 $ 3,322
Property, plant and equipment	Property, plant and equipment at December 31 was as follows: 2015 2014 Weighted Average Depreciable Life in Years (Dollars in thousands, where applicable) Regulated: Electric: Generation $ 1,003,173 $ 627,952 39 Distribution 375,612 343,692 44 Transmission 255,842 229,997 57 Construction in progress 42,436 150,445 - Other 109,085 105,015 14 Natural gas distribution: Distribution 1,624,645 1,481,390 35 Construction in progress 20,530 59,310 - Other 431,406 364,059 22 Pipeline and midstream: Transmission 460,305 449,276 53 Gathering 37,831 39,595 20 Storage 44,011 43,994 60 Construction in progress 7,549 5,386 - Other 40,168 39,910 33 Nonregulated: Pipeline and midstream: Gathering and processing 158,949 227,598 16 Construction in progress 89 691 - Other 9,827 11,938 10 Construction materials and contracting: Land 123,723 125,372 - Buildings and improvements 69,011 70,566 19 Machinery, vehicles and equipment 937,084 921,564 12 Construction in progress 18,615 8,709 - Aggregate reserves 404,995 403,731 * Construction services: Land 6,460 5,265 - Buildings and improvements 23,824 17,936 25 Machinery, vehicles and equipment 121,940 112,973 6 Other 11,055 8,221 3 Refining: Refinery 445,198 88,232 20 Construction in progress 135 313,613 - Other: Land 2,837 2,837 - Other 46,700 48,100 23 Eliminations (15,367 ) (12,589 ) Less accumulated depreciation, depletion and amortization 2,506,571 2,386,113 Net property, plant and equipment $ 4,311,097 $ 3,908,665 * Depleted on the units-of-production method.
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: 2015 2014 (In thousands) Costs and estimated earnings in excess of billings on uncompleted contracts $ 64,369 $ 58,243 Billings in excess of costs and estimated earnings on uncompleted contracts $ 68,048 $ 47,011 Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31 were as follows: 2015 2014 (In thousands) Short-term retainage* $ 46,207 $ 47,551 Long-term retainage** 1,605 1,053 Total retainage $ 47,812 $ 48,604 * 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: 2015 2014 2013 (In thousands) Weighted average common shares outstanding - basic 194,928 192,507 188,855 Effect of dilutive performance share awards 58 80 838 Weighted average common shares outstanding - diluted 194,986 192,587 189,693 Shares excluded from the calculation of diluted earnings per share — — —
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: 2015 2014 2013 (In thousands) Interest, net of amount capitalized and AFUDC - borrowed of $9,809, $11,608 and $8,800 in 2015, 2014 and 2013, respectively $ 90,386 $ 81,241 $ 81,575 Income taxes paid, net $ 33,409 $ 64,211 $ 52,580 Noncash investing transactions at December 31 were as follows: 2015 2014 2013 (In thousands) Property, plant and equipment additions in accounts payable $ 51,702 $ 62,453 $ 22,832
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, 2015 , 2014 and 2013 , were as follows: Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges Post- retirement Liability Adjustment Foreign Currency Translation Adjustment Net Unrealized Gain (Loss) on Available- for-sale Investments Total Accumulated Other Comprehensive Loss (In thousands) 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 ) Other comprehensive income (loss) before reclassifications — (88 ) (173 ) (170 ) (431 ) Amounts reclassified from accumulated other comprehensive loss 404 1,794 802 131 3,131 Amounts reclassified from accumulated other comprehensive loss to a regulatory asset — 2,255 — — 2,255 Net current-period other comprehensive income (loss) 404 3,961 629 (39 ) 4,955 Balance at December 31, 2015 $ (2,667 ) $ (34,257 ) $ (200 ) $ (24 ) $ (37,148 )
Reclassification out of accumulated other comprehensive income (loss)	Reclassifications out of accumulated other comprehensive loss for the years ended December 31 were as follows: 2015 2014 Location on Consolidated Statements of Income (In thousands) Reclassification adjustment for loss on derivative instruments included in net income (loss): Interest rate derivative instruments $ (637 ) $ (639 ) Interest expense 233 240 Income taxes (404 ) (399 ) Commodity derivative instruments, net of tax — (295 ) Income (loss) from discontinued operations, net of tax (404 ) (694 ) Amortization of postretirement liability losses included in net periodic benefit cost (credit) (2,922 ) (1,288 ) (a) 1,128 492 Income taxes (1,794 ) (796 ) Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss) (1,292 ) — Other income 490 — Income taxes (802 ) — Reclassification adjustment for loss on available-for-sale investments included in net income (loss) (201 ) (208 ) Other income 70 73 Income taxes (131 ) (135 ) Total reclassifications $ (3,131 ) $ (1,625 ) (a) Included in net periodic benefit cost (credit). For more information, see Note 14 .

Discontinued operations (Tables

Discontinued operations (Tables)	12 Months Ended
	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Groups, Including Discontinued Operations [Table Text Block]	The carrying amounts of the major classes of assets and liabilities that are classified as held for sale on the Company's Consolidated Balance Sheets at December 31 were as follows: 2015 2014 (In thousands) Assets Current assets: Receivables, net $ 13,387 $ 94,132 Inventories 1,308 11,401 Commodity derivative instruments — 18,335 Prepayments and other current assets 9,886 7,309 Total current assets held for sale 24,581 131,177 Noncurrent assets: Investments 37 37 Net property, plant and equipment 793,422 1,618,099 Deferred income taxes 127,655 — Other 161 2,334 Less allowance for impairment of assets held for sale 754,541 — Total noncurrent assets held for sale 166,734 1,620,470 Total assets held for sale $ 191,315 $ 1,751,647 Liabilities Current liabilities: Long-term debt due within one year $ — $ 897 Accounts payable 25,013 103,556 Taxes payable 1,052 19,900 Deferred income taxes 3,620 8,206 Accrued compensation 13,080 5,373 Other accrued liabilities 4,838 16,796 Total current liabilities held for sale 47,603 154,728 Noncurrent liabilities: Deferred income taxes — 238,391 Other liabilities — 57,050 Total noncurrent liabilities held for sale — 295,441 Total liabilities held for sale $ 47,603 $ 450,169
Reconciliation of Major Classes of Income And Expense [Table Text Block]	The reconciliation of the major classes of income and expense constituting pretax income (loss) from discontinued operations to the after-tax net income (loss) from discontinued operations of the Company's Consolidated Statements of Income at December 31 were as follows: 2015 2014 2013 (In thousands) Operating revenues $ 184,853 $ 547,571 $ 536,023 Operating expenses 1,423,037 378,891 364,120 Operating income (loss) (1,238,184 ) 168,680 171,903 Other income 2,374 1,163 549 Interest expense 235 110 114 Income (loss) from discontinued operations before income taxes (1,236,045 ) 169,733 172,338 Income taxes (463,660 ) 54,558 62,459 Income (loss) from discontinued operations $ (772,385 ) $ 115,175 $ 109,879

Goodwill and other intangible31

Goodwill and other intangible assets (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Changes in the carrying amount of goodwill	The changes in the carrying amount of goodwill for the year ended December 31, 2015 , were as follows: Balance at January 1, 2015 * Goodwill Acquired During the Year Balance at December 31, 2015 * (In thousands) Natural gas distribution $ 345,736 $ — $ 345,736 Pipeline and midstream 9,737 — 9,737 Construction materials and contracting 176,290 — 176,290 Construction services 103,441 — 103,441 Total $ 635,204 $ — $ 635,204 * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and midstream segment, which occurred in prior periods. The changes in the carrying amount of goodwill for the year ended December 31, 2014 , were as follows: Balance at January 1, 2014 * Goodwill Acquired During the Year/Other Balance at December 31, 2014 * (In thousands) Natural gas distribution $ 345,736 $ — $ 345,736 Pipeline and midstream 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 midstream segment, which occurred in prior periods.
Other amortizable intangible assets	Other amortizable intangible assets at December 31 were as follows: 2015 2014 (In thousands) Customer relationships $ 20,975 $ 21,310 Accumulated amortization (16,845 ) (15,556 ) 4,130 5,754 Noncompete agreements 4,409 5,080 Accumulated amortization (3,655 ) (4,098 ) 754 982 Other 8,304 10,921 Accumulated amortization (5,846 ) (7,817 ) 2,458 3,104 Total $ 7,342 $ 9,840

Regulatory assets and liabili32

Regulatory assets and liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
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 Period * 2015 2014 (In thousands) Regulatory assets: Pension and postretirement benefits (a) (e) $ 185,832 $ 182,565 Taxes recoverable from customers (a) Over plant lives 27,682 22,910 Manufactured gas plant sites remediation (a) Up to 2 years 18,617 17,548 Plant costs (a) Up to 1 year 8,000 4,551 Natural gas costs recoverable through rate adjustments (b) Up to 1 year 547 19,575 Long-term debt refinancing costs (a) Up to 22 years 7,031 7,864 Costs related to identifying generation development (a) Up to 11 years 3,808 4,165 Other (a) (b) Largely within 1- 4 years 11,741 10,408 Total regulatory assets 263,258 269,586 Regulatory liabilities: Plant removal and decommissioning costs (c) 182,981 338,641 Taxes refundable to customers (c) 17,060 17,772 Natural gas costs refundable through rate adjustments (d) 20,884 13,238 Other (c) (d) 22,193 16,601 Total regulatory liabilities 243,118 386,252 Net regulatory position $ 20,140 $ (116,666 ) * 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 Period * 2015 2014 (In thousands) Regulatory assets: Pension and postretirement benefits (a) (e) $ 185,832 $ 182,565 Taxes recoverable from customers (a) Over plant lives 27,682 22,910 Manufactured gas plant sites remediation (a) Up to 2 years 18,617 17,548 Plant costs (a) Up to 1 year 8,000 4,551 Natural gas costs recoverable through rate adjustments (b) Up to 1 year 547 19,575 Long-term debt refinancing costs (a) Up to 22 years 7,031 7,864 Costs related to identifying generation development (a) Up to 11 years 3,808 4,165 Other (a) (b) Largely within 1- 4 years 11,741 10,408 Total regulatory assets 263,258 269,586 Regulatory liabilities: Plant removal and decommissioning costs (c) 182,981 338,641 Taxes refundable to customers (c) 17,060 17,772 Natural gas costs refundable through rate adjustments (d) 20,884 13,238 Other (c) (d) 22,193 16,601 Total regulatory liabilities 243,118 386,252 Net regulatory position $ 20,140 $ (116,666 ) * 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, 2015
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: 2015 2014 2013 (In thousands) Commodity derivatives designated as cash flow hedges: Amount of loss recognized in accumulated other comprehensive loss (effective portion), net of tax $ — $ — $ (6,153 ) Amount of (gain) loss reclassified from accumulated other comprehensive loss into discontinued operations (effective portion), net of tax — 295 (4,916 ) Amount of loss recognized in operating revenues (ineffective portion), before tax — — (1,422 ) Interest rate derivatives designated as cash flow hedges: Amount of gain recognized in accumulated other comprehensive loss (effective portion), net of tax — — 559 Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax 404 399 727 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 discontinued operations, before tax (18,335 ) 23,400 (4,845 )
Derivative instruments	The location and fair value of the gross amount 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 (In thousands) Not designated as hedges: Commodity derivatives Current assets held for sale $ 18,335 Total asset derivatives $ 18,335
Offsetting assets and liabilities master netting	The gross derivative assets (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 Consolidated Balance Sheets Gross Amounts Not Offset on the Consolidated Balance Sheets Net (In thousands) Assets: Commodity derivatives $ 18,335 $ — $ 18,335 Total assets $ 18,335 $ — $ 18,335

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Available-for-sale securities	Details of available-for-sale securities were as follows: December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value (In thousands) Mortgage-backed securities $ 9,128 $ 19 $ (49 ) $ 9,098 U.S. Treasury securities 1,315 — (6 ) 1,309 Total $ 10,443 $ 19 $ (55 ) $ 10,407 December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value (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
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, 2015, Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2015 (In thousands) Assets: Money market funds $ — $ 1,420 $ — $ 1,420 Insurance contract* — 67,459 — 67,459 Available-for-sale securities: Mortgage-backed securities — 9,098 — 9,098 U.S. Treasury securities — 1,309 — 1,309 Total assets measured at fair value $ — $ 79,286 $ — $ 79,286 Liabilities: RIN obligations $ — $ 3,052 $ — $ 3,052 Total liabilities measured at fair value $ — $ 3,052 $ — $ 3,052 * The insurance contract invests approximately 9 percent in common stock of mid-cap companies, 7 percent in common stock of small-cap companies, 19 percent in common stock of large-cap companies, 63 percent in fixed-income investments, 1 percent in target date investments and 1 percent in cash equivalents. Fair Value Measurements at December 31, 2014, Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2014 (In thousands) Assets: Money market funds $ — $ 890 $ — $ 890 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 Total assets measured at fair value $ — $ 76,912 $ — $ 76,912 * 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 of long-term debt outstanding	The estimated fair value of the Company's Level 2 long-term debt at December 31 was as follows: 2015 2014 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) Long-term debt $ 1,871,232 $ 1,893,442 $ 2,093,830 $ 2,238,548

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Outstanding credit facilities	The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries: Company Facility Facility Limit Amount Outstanding at December 31, 2015 Amount Outstanding at December 31, 2014 Letters of Credit at December 31, 2015 Expiration Date (In millions) MDU Resources Group, Inc. Commercial paper/Revolving credit agreement (a) $ 175.0 $ 44.5 (b) $ 77.5 (b) $ — 5/8/19 Cascade Natural Gas Corporation Revolving credit agreement $ 50.0 (c) $ — $ — $ 2.2 (d) 7/9/18 Intermountain Gas Company Revolving credit agreement $ 65.0 (e) $ 47.9 $ 21.0 $ — 7/13/18 Centennial Energy Holdings, Inc. Commercial paper/Revolving credit agreement (f) $ 650.0 $ 18.0 (b) $ 211.0 (b) $ 39.4 5/8/19 Dakota Prairie Refining, LLC Revolving credit agreement $ 75.0 $ 45.5 $ — $ 18.3 (d) 6/30/16 (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) Outstanding letter(s) of credit reduce 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.
Long term debt outstanding	Long-term debt outstanding at December 31 was as follows: 2015 2014 (In thousands) Senior Notes at a weighted average rate of 5.18%, due on dates ranging from February 1, 2016 to January 15, 2055 $ 1,616,246 $ 1,636,662 Commercial paper at a weighted average rate of .73%, supported by revolving credit agreements 62,500 288,500 Term Loan Agreements at a weighted average rate of 2.16%, due on dates ranging from April 22, 2018 to April 22, 2023 69,000 72,000 Medium-Term Notes at a weighted average rate of 6.68%, due on dates ranging from September 1, 2020 to March 16, 2029 50,000 35,000 Other notes at a weighted average rate of 5.25%, due on February 1, 2035 24,589 39,662 Credit agreements at a weighted average rate of 1.82%, due on dates ranging from July 14, 2018 to November 30, 2038 48,906 22,042 Discount (9 ) (36 ) Total long-term debt 1,871,232 2,093,830 Less current maturities 243,789 268,552 Net long-term debt $ 1,627,443 $ 1,825,278

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 (In thousands) Balance at beginning of year $ 27,211 $ 27,327 Liabilities incurred 2,751 1,697 Liabilities settled (1,708 ) (3,231 ) Accretion expense 1,163 1,112 Revisions in estimates 211,836 (73 ) Other 971 379 Balance at end of year $ 242,224 $ 27,211

Preferred Stocks (Tables)

Preferred Stocks (Tables)	12 Months Ended
	Dec. 31, 2015
Class of Stock Disclosures [Abstract]
Preferred stock	Preferred stocks at December 31 were as follows: 2015 2014 (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

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation [Abstract]
Target grants performance share	Target grants of performance shares outstanding at December 31, 2015 , were as follows: Grant Date Performance Period Target Grant of Shares March 2013 2013-2015 188,388 February 2014 2014-2016 142,989 February 2015 2015-2017 220,078 June 2015 2015-2017 14,441
Schedule of share-based payment award, performance shares, valuation assumptions	Assumptions used for grants of performance shares issued in 2015 , 2014 and 2013 were: 2015 2014 2013 Weighted average grant-date fair value $18.98 $41.13 $29.01 Blended volatility range 22.86 % – 24.61 % 18.94 % – 20.43 % 16.10 % – 19.39 % Risk-free interest rate range .05 % – 1.07 % .03 % – .74 % .09 % – .40 % Weighted average discounted dividends per share $1.57 $2.15 $2.12
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, 2015 , was as follows: Number of Shares Weighted Average Grant-Date Fair Value Nonvested at beginning of period 688,455 $ 28.16 Granted 258,454 18.98 Vested — — Forfeited (381,013 ) 22.31 Nonvested at end of period 565,896 $ 27.90

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of income (loss) before income taxes	The components of income before income taxes from continuing operations for each of the years ended December 31 were as follows: 2015 2014 2013 (In thousands) United States $ 181,623 $ 242,442 $ 242,569 Foreign (1,326 ) (52 ) 416 Income before income taxes from continuing operations $ 180,297 $ 242,390 $ 242,985
Income tax expense (benefit)	Income tax expense from continuing operations for the years ended December 31 was as follows: 2015 2014 2013 (In thousands) Current: Federal $ 59,483 $ 4,403 $ 41,624 State 5,789 (166 ) 4,148 Foreign 30 — (29 ) 65,302 4,237 45,743 Deferred: Income taxes: Federal 3,199 55,514 29,616 State (2,478 ) 2,467 (859 ) Investment tax credit - net (420 ) 1,009 (206 ) 301 58,990 28,551 Total income tax expense $ 65,603 $ 63,227 $ 74,294
Deferred tax assets and deferred tax liabilities	Components of deferred tax assets and deferred tax liabilities at December 31 were as follows: 2015 2014 (In thousands) Deferred tax assets: Postretirement $ 97,666 $ 99,853 Compensation-related 33,844 35,669 Alternative minimum tax credit carryforward 28,173 23,678 Customer advances 12,623 12,245 Asset retirement obligations 8,694 7,894 Legal and environmental contingencies 6,377 7,890 Other 58,202 52,862 Total deferred tax assets 245,579 240,091 Deferred tax liabilities: Depreciation and basis differences on property, plant and equipment 791,368 773,160 Postretirement 71,835 70,642 Intangible asset amortization 23,950 22,810 Other 36,906 46,637 Total deferred tax liabilities 924,059 913,249 Valuation allowance 8,990 8,852 Net deferred income tax liability $ (687,470 ) $ (682,010 )
Schedule of change in net deferred income tax liability reconciliation	The following table reconciles the change in the net deferred income tax liability from December 31, 2014 , to December 31, 2015 , to deferred income tax expense: 2015 (In thousands) Change in net deferred income tax liability from the preceding table $ 5,460 Deferred taxes associated with other comprehensive income (3,086 ) Other (2,073 ) Deferred income tax expense for the period $ 301
Reconciliation of income tax expense (benefit) at statutory federal rate versus actual rate	Total income tax expense differs from the amount computed by applying the statutory federal income tax rate to income before taxes. The reasons for this difference were as follows: Years ended December 31, 2015 2014 2013 Amount % Amount % Amount % (Dollars in thousands) Computed tax at federal statutory rate $ 63,104 35.0 $ 84,836 35.0 $ 85,045 35.0 Increases (reductions) resulting from: State income taxes, net of federal income tax 4,903 2.7 7,048 2.9 7,379 3.0 Noncontrolling interest 12,340 6.8 1,363 .5 — — Federal renewable energy credit (3,400 ) (1.9 ) (3,655 ) (1.5 ) (3,404 ) (1.4 ) Tax compliance and uncertain tax positions (194 ) (.1 ) (8,987 ) (3.7 ) (3,902 ) (1.6 ) Domestic production activities — — (3,993 ) (1.6 ) (666 ) (.3 ) Other (11,150 ) (6.1 ) (13,385 ) (5.5 ) (10,158 ) (4.1 ) Total income tax expense $ 65,603 36.4 $ 63,227 26.1 $ 74,294 30.6
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: 2015 2014 2013 (In thousands) Balance at beginning of year $ 105 $ 7,845 $ 7,845 Settlements — (7,740 ) — Lapse of statute of limitations (105 ) — — Balance at end of year $ — $ 105 $ 7,845

Business segment data (Tables)

Business segment data (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 2013 (In thousands) External operating revenues: Regulated operations: Electric $ 280,615 $ 277,874 $ 257,260 Natural gas distribution 817,419 921,986 851,945 Pipeline and midstream 50,238 46,786 47,633 1,148,272 1,246,646 1,156,838 Nonregulated operations: Pipeline and midstream 54,282 64,494 56,427 Construction materials and contracting 1,901,530 1,740,089 1,675,444 Construction services 907,767 1,062,055 1,029,909 Refining 178,262 — — Other 1,436 1,532 1,553 3,043,277 2,868,170 2,763,333 Total external operating revenues $ 4,191,549 $ 4,114,816 $ 3,920,171 Intersegment operating revenues: Electric $ — $ — $ — Natural gas distribution — — — Pipeline and midstream 51,716 46,085 40,511 Construction materials and contracting 2,752 25,241 36,693 Construction services 18,660 57,474 9,930 Refining — — — Other 7,755 7,832 8,067 Intersegment eliminations (80,883 ) (136,632 ) (95,201 ) Total intersegment operating revenues $ — $ — $ — Depreciation, depletion and amortization: Electric $ 37,583 $ 35,008 $ 32,789 Natural gas distribution 64,756 54,700 50,031 Pipeline and midstream 27,981 29,749 29,105 Construction materials and contracting 65,937 68,557 74,470 Construction services 13,420 12,874 11,939 Refining 16,463 896 14 Other 2,070 2,196 2,050 Intersegment eliminations (480 ) — — Total depreciation, depletion and amortization $ 227,730 $ 203,980 $ 200,398 Interest expense: Electric $ 17,421 $ 15,595 $ 12,590 Natural gas distribution 29,471 27,217 25,123 Pipeline and midstream 9,895 9,946 10,148 Construction materials and contracting 15,183 16,368 17,394 Construction services 3,959 4,176 4,306 Refining 3,450 119 182 Other 14,292 13,739 14,216 Intersegment eliminations (603 ) (254 ) (156 ) Total interest expense $ 93,068 $ 86,906 $ 83,803 2015 2014 2013 (In thousands) Income taxes: Electric $ 11,523 $ 12,442 $ 9,683 Natural gas distribution 11,377 11,350 16,633 Pipeline and midstream 7,505 12,232 3,466 Construction materials and contracting 41,619 18,586 24,765 Construction services 16,432 24,753 29,504 Refining (13,815 ) (2,533 ) (76 ) Other (8,107 ) (9,798 ) (6,812 ) Intersegment eliminations (931 ) (3,805 ) (2,869 ) Total income taxes $ 65,603 $ 63,227 $ 74,294 Earnings (loss) on common stock: Regulated operations: Electric $ 35,914 $ 36,731 $ 34,837 Natural gas distribution 23,607 30,484 37,656 Pipeline and midstream 20,680 15,440 15,388 80,201 82,655 87,881 Nonregulated operations: Pipeline and midstream (7,430 ) 9,226 (7,687 ) Construction materials and contracting 89,096 51,510 50,946 Construction services 23,762 54,432 52,213 Refining (22,457 ) (2,038 ) (72 ) Other (12,376 ) (7,317 ) (10,605 ) 70,595 105,813 84,795 Intersegment eliminations (1,531 ) (6,095 ) (4,307 ) Earnings on common stock before income (loss) from discontinued operations 149,265 182,373 168,369 Income (loss) from discontinued operations, net of tax (772,385 ) 115,175 109,879 Total earnings (loss) on common stock $ (623,120 ) $ 297,548 $ 278,248 Capital expenditures: Electric $ 332,876 $ 185,121 $ 168,557 Natural gas distribution 130,793 120,613 101,279 Pipeline and midstream 18,315 61,754 40,533 Construction materials and contracting 48,126 37,896 34,607 Construction services 38,269 26,942 15,102 Refining 22,052 115,655 86,559 Other 3,755 2,131 2,249 Net proceeds from sale or disposition of property and other (63,831 ) (60,177 ) (28,392 ) Total net capital expenditures $ 530,355 $ 489,935 $ 420,494 Assets: Electric* $ 1,327,258 $ 1,030,611 $ 884,283 Natural gas distribution* 2,042,925 1,931,908 1,786,068 Pipeline and midstream 593,025 655,735 620,639 Construction materials and contracting 1,279,057 1,272,231 1,305,808 Construction services 450,896 454,602 450,614 Refining 464,699 429,102 178,062 Other** 278,433 306,572 236,543 Assets held for sale 191,315 1,751,647 1,611,430 Total assets $ 6,627,608 $ 7,832,408 $ 7,073,447 2015 2014 2013 (In thousands) Property, plant and equipment: Electric* $ 1,786,148 $ 1,457,101 $ 1,315,822 Natural gas distribution* 2,076,581 1,904,759 1,776,901 Pipeline and midstream 758,729 818,388 789,569 Construction materials and contracting 1,553,428 1,529,942 1,510,355 Construction services 163,279 144,395 134,948 Refining 445,333 401,845 172,603 Other 49,537 50,937 49,997 Eliminations (15,367 ) (12,589 ) (4,473 ) Less accumulated depreciation, depletion and amortization 2,506,571 2,386,113 2,284,169 Net property, plant and equipment $ 4,311,097 $ 3,908,665 $ 3,461,553 * 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).

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 , and amounts recognized in the Consolidated Balance Sheets at December 31, 2015 and 2014 , were as follows: Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In thousands) Change in benefit obligation: Benefit obligation at beginning of year $ 475,337 $ 402,772 $ 99,012 $ 81,726 Service cost 86 129 1,816 1,518 Interest cost 17,141 17,682 3,607 3,521 Plan participants' contributions — — 1,408 1,399 Actuarial (gain) loss (24,875 ) 80,520 (5,873 ) 18,024 Benefits paid (24,729 ) (25,766 ) (7,236 ) (7,176 ) Benefit obligation at end of year 442,960 475,337 92,734 99,012 Change in net plan assets: Fair value of plan assets at beginning of year 354,363 334,844 87,586 84,543 Actual gain (loss) on plan assets (10,879 ) 24,500 258 7,527 Employer contribution 13,912 20,785 577 1,293 Plan participants' contributions — — 1,408 1,399 Benefits paid (24,729 ) (25,766 ) (7,236 ) (7,176 ) Fair value of net plan assets at end of year 332,667 354,363 82,593 87,586 Funded status - under $ (110,293 ) $ (120,974 ) $ (10,141 ) $ (11,426 ) Amounts recognized in the Consolidated Balance Sheets at December 31: Other assets (noncurrent) $ — $ — $ 5,095 $ 4,345 Other accrued liabilities (current) — — (421 ) (322 ) Other liabilities (noncurrent) (110,293 ) (120,974 ) (14,815 ) (15,449 ) Net amount recognized $ (110,293 ) $ (120,974 ) $ (10,141 ) $ (11,426 ) Amounts recognized in accumulated other comprehensive (income) loss consist of: Actuarial loss $ 208,671 $ 207,430 $ 22,484 $ 25,779 Prior service cost (credit) — 294 (14,374 ) (15,744 ) Total $ 208,671 $ 207,724 $ 8,110 $ 10,035
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: 2015 2014 (In thousands) Projected benefit obligation $ 442,960 $ 475,337 Accumulated benefit obligation $ 442,960 $ 475,337 Fair value of plan assets $ 332,667 $ 354,363
Components of net periodic benefit cost	Components of net periodic benefit cost (credit) for the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows: Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 (In thousands) Components of net periodic benefit cost (credit): Service cost $ 86 $ 129 $ 155 $ 1,816 $ 1,518 $ 1,675 Interest cost 17,141 17,682 16,249 3,607 3,521 3,215 Expected return on assets (22,254 ) (21,218 ) (19,917 ) (4,795 ) (4,617 ) (4,343 ) Amortization of prior service cost (credit) 36 71 71 (1,371 ) (1,393 ) (1,457 ) Recognized net actuarial loss 7,016 4,869 7,173 1,960 649 1,814 Curtailment loss 258 — — — — — Net periodic benefit cost (credit), including amount capitalized 2,283 1,533 3,731 1,217 (322 ) 904 Less amount capitalized 316 388 727 120 (21 ) 164 Net periodic benefit cost (credit) 1,967 1,145 3,004 1,097 (301 ) 740 Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss: Net (gain) loss 8,257 77,238 (60,173 ) (1,336 ) 15,114 (30,461 ) Amortization of actuarial loss (7,016 ) (4,869 ) (7,173 ) (1,960 ) (649 ) (1,814 ) Amortization of prior service (cost) credit (294 ) (71 ) (71 ) 1,371 1,393 1,457 Total recognized in accumulated other comprehensive (income) loss 947 72,298 (67,417 ) (1,925 ) 15,858 (30,818 ) Total recognized in net periodic benefit cost (credit) and accumulated other comprehensive (income) loss $ 2,914 $ 73,443 $ (64,413 ) $ (828 ) $ 15,557 $ (30,078 )
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 2015 2014 2015 2014 Discount rate 4.00 % 3.70 % 4.06 % 3.74 % Expected return on plan assets 6.75 % 7.00 % 5.75 % 6.00 % Rate of compensation increase N/A N/A 3.00 % 3.00 % Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows: Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 Discount rate 3.70 % 4.53 % 3.74 % 4.48 % Expected return on plan assets 7.00 % 7.00 % 6.00 % 6.00 % Rate of compensation increase N/A N/A 3.00 % 3.00 %
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: 2015 2014 Health care trend rate assumed for next year 4.0 % – 8.0 % 4.0 % – 7.0 % Health care cost trend rate - ultimate 5.0 % – 6.0 % 5.0 % – 6.0 % Year in which ultimate trend rate achieved 2021 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, 2015 : 1 Percentage Point Increase 1 Percentage Point Decrease (In thousands) Effect on total of service and interest cost components $ 203 $ (169 ) Effect on postretirement benefit obligation $ 4,006 $ (3,407 )
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, 2015, Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2015 (In thousands) Assets: Cash equivalents $ — $ 8,379 $ — $ 8,379 Equity securities: U.S. companies 15,135 — — 15,135 International companies 2,332 — — 2,332 Collective and mutual funds* 154,400 63,568 — 217,968 Corporate bonds — 62,145 — 62,145 Municipal bonds — 11,680 — 11,680 U.S. Government securities 5,288 6,823 — 12,111 Total assets measured at fair value $ 177,155 $ 152,595 $ — $ 329,750 * Collective and mutual funds invest approximately 19 percent in common stock of large-cap U.S. companies, 6 percent in common stock of mid-cap U.S. companies, 16 percent in corporate bonds, 29 percent in common stock of international companies, 16 percent in cash equivalents and 14 percent in other investments. Fair Value Measurements at December 31, 2014, Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2014 (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. 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, 2015 and 2014 , 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, 2015, Using Quoted Prices Significant Significant Unobservable Balance at December 31, 2015 (In thousands) Assets: Cash equivalents $ — $ 3,261 $ — $ 3,261 Equity securities: U.S. companies 2,274 — — 2,274 International companies 9 — — 9 Insurance contract* — 77,044 — 77,044 Total assets measured at fair value $ 2,283 $ 80,305 $ — $ 82,588 * The insurance contract invests approximately 19 percent in common stock of large-cap U.S. companies, 22 percent in U.S. Government securities, 10 percent in mortgage-backed securities, 36 percent in corporate bonds and 13 percent in other investments. Fair Value Measurements at December 31, 2014, Using Quoted Prices Significant Significant Unobservable Balance at December 31, 2014 (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.
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 Benefits Other Postretirement Benefits Expected Medicare Part D Subsidy (In thousands) 2016 $ 24,223 $ 5,234 $ 197 2017 24,680 5,351 191 2018 24,980 5,420 183 2019 25,323 5,441 175 2020 25,700 5,331 168 2021 - 2025 133,029 27,261 688
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 2015 2014 2015 2014 2013 (In thousands) Edison Pension Plan 93-6061681-001 Green as of 12/31/2015 Green as of 12/31/2014 No $ 5,517 $ 9,061 $ 6,358 No 12/31/2017 IBEW Local No. 82 Pension Plan 31-6127268-001 Red as of 6/30/2015 Red as of 6/30/2014 Implemented 2,252 1,392 1,284 No 11/29/2015* IBEW Local No. 246 Pension Plan 34-6582842-001 Yellow as of 5/31/2015 Yellow as of 5/31/2014 Implemented 433 694 1,848 No 10/31/2017 IBEW Local No. 357 Pension Plan A 88-6023284-001 Green Green No 1,896 3,575 2,348 No 5/31/2018 IBEW Local 648 Pension Plan 31-6134845-001 Red as of 2/28/2015 Red as of 2/28/2014 Implemented 745 1,110 1,489 No 9/2/2018 Idaho Plumbers and Pipefitters Pension Plan 82-6010346-001 Green as of 5/31/2015 Green as of 5/31/2014 No 1,169 1,125 1,121 No 9/30/2016 Local Union 212 IBEW Pension Trust Fund 31-6127280-001 Yellow as of 4/30/2015 Yellow as of 4/30/2014 Implemented 937 568 531 No 6/5/2016 National Automatic Sprinkler Industry Pension Fund 52-6054620-001 Red as of 12/31/2015 Red as of 12/31/2014 Implemented 677 608 583 No 3/31/2016- National Electrical Benefit Fund 53-0181657-001 Green Green No 5,271 6,476 5,883 No 6/30/2015*- Pension Trust Fund for Operating Engineers 94-6090764-001 Red as of 12/31/2015 Red as of 12/31/2014 Implemented 1,997 1,445 1,510 No 6/15/2015*– Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming** 83-6011320-001 Red as of 12/31/2015 Red as of 12/31/2014 Implemented — 68 76 No 10/31/2005* Sheet Metal Workers' Pension Plan of Southern CA, AZ and NV 95-6052257-001 Red as of 12/31/2015 Red as of 12/31/2014 Implemented 714 676 512 No 6/30/2016 Southwest Marine Pension Trust 95-6123404-001 Red Red Implemented 26 31 42 No 1/31/2014*– Other funds 17,478 15,988 15,675 Total contributions $ 39,112 $ 42,817 $ 39,260 * 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 2014 and 2013 IBEW Local No. 82 Pension Plan 2014 and 2013 Local Union No. 124 IBEW Pension Trust Fund 2014 and 2013 Local Union 212 IBEW Pension Trust Fund 2014 and 2013 IBEW Local Union No. 357 Pension Plan A 2014 and 2013 IBEW Local 573 Pension Plan 2014 IBEW Local 648 Pension Plan 2014 and 2013 Idaho Plumbers and Pipefitters Pension Plan 2014 Minnesota Teamsters Construction Division Pension Fund 2014 and 2013 Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming* 2014 and 2013 Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525 2014 and 2013 * 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, 2015
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: 2015 2014 (In thousands) Big Stone Station: Utility plant in service $ 157,761 $ 64,283 Less accumulated depreciation 48,242 43,043 $ 109,519 $ 21,240 Coyote Station: Utility plant in service $ 140,895 $ 138,810 Less accumulated depreciation 94,755 94,443 $ 46,140 $ 44,367 Wygen III: Utility plant in service $ 65,023 $ 65,597 Less accumulated depreciation 6,788 5,928 $ 58,235 $ 59,669

Commitment and Contingencies Di

Commitment and Contingencies Disclosure (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 (In thousands) Assets Current assets: Cash and cash equivalents $ 851 $ 21,376 Accounts receivable 7,693 2,759 Inventories 13,176 5,311 Other current assets 6,215 4,019 Total current assets 27,935 33,465 Net property, plant and equipment 425,123 398,984 Deferred charges and other assets: Other 9,626 3,400 Total deferred charges and other assets 9,626 3,400 Total assets $ 462,684 $ 435,849 Liabilities Current liabilities: Short-term borrowings $ 45,500 $ — Long-term debt due within one year 5,250 3,000 Accounts payable 24,766 55,089 Taxes payable 1,391 648 Accrued compensation 938 727 Other accrued liabilities 4,953 899 Total current liabilities 82,798 60,363 Long-term debt 63,750 69,000 Total liabilities $ 146,548 $ 129,363

Quarterly Financial Information

Quarterly Financial Information Disclosure (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly financial data	The following unaudited information shows selected items by quarter for the years 2015 and 2014 : First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except per share amounts) 2015 Operating revenues $ 862,349 $ 986,215 $ 1,280,500 $ 1,062,485 Operating expenses 818,680 940,887 1,170,757 1,007,092 Operating income 43,669 45,328 109,743 55,393 Income from continuing operations 15,160 14,057 53,400 32,077 Income (loss) from discontinued operations, net of tax (324,605 ) (251,415 ) (202,626 ) 6,261 Net income (loss) attributable to the Company (305,917 ) (229,604 ) (139,448 ) 52,534 Earnings (loss) per common share - basic: Earnings before discontinued operations .10 .11 .32 .24 Discontinued operations, net of tax (1.67 ) (1.29 ) (1.04 ) .03 Earnings (loss) per common share - basic (1.57 ) (1.18 ) (.72 ) .27 Earnings (loss) per common share - diluted: Earnings before discontinued operations .10 .11 .32 .24 Discontinued operations, net of tax (1.67 ) (1.29 ) (1.04 ) .03 Earnings (loss) per common share - diluted (1.57 ) (1.18 ) (.72 ) .27 Weighted average common shares outstanding: Basic 194,479 194,805 195,151 195,266 Diluted 194,566 194,838 195,169 195,324 2014 Operating revenues $ 900,761 $ 952,564 $ 1,213,203 $ 1,048,288 Operating expenses 837,153 890,210 1,094,310 973,720 Operating income 63,608 62,354 118,893 74,568 Income from continuing operations 31,027 29,446 63,639 55,051 Income from discontinued operations, net of tax 25,112 23,881 38,482 27,700 Net income attributable to the Company 56,662 54,106 103,209 84,256 Earnings per common share - basic: Earnings before discontinued operations .17 .16 .33 .29 Discontinued operations, net of tax .13 .12 .20 .14 Earnings per common share - basic .30 .28 .53 .43 Earnings per common share - diluted: Earnings before discontinued operations .16 .16 .33 .29 Discontinued operations, net of tax .14 .12 .20 .14 Earnings per common share - diluted .30 .28 .53 .43 Weighted average common shares outstanding: Basic 189,820 192,060 193,949 194,136 Diluted 190,432 192,659 194,300 194,219 Notes: • First quarter 2015 reflects a MEPP withdrawal liability of $2.4 million (before tax). For more information, see Note 14 . • Second quarter 2015 reflects an impairment of coalbed natural gas gathering assets of $3.0 million (before tax). For more information, see Note 1 . • Third quarter 2015 reflects an impairment of coalbed natural gas gathering assets of $14.1 million (before tax). For more information, see Note 1 . • Fourth quarter 2014 reflects a MEPP withdrawal liability of approximately $14.0 million (before tax). For more information, see Note 14 . • 2014 and first quarter 2015 have been restated to present the results of operations of Fidelity as discontinued operations, other than certain general and administrative costs and interest expense which were previously allocated to the former exploration and production segment and do not meet the criteria for income (loss) from discontinued operations.

Exploration and Production Ac45

Exploration and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 * 2014 2013 (In thousands) Subject to amortization $ — $ 3,205,036 $ 2,893,010 Not subject to amortization — 132,141 124,869 Total capitalized costs — 3,337,177 3,017,879 Less accumulated depreciation, depletion and amortization — 1,752,566 1,562,116 Net capitalized costs $ — $ 1,584,611 $ 1,455,763 * Excludes assets held for sale.
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, 2015 * 2014 ** 2013 ** (In thousands) Acquisitions: Proved properties $ — $ 87,919 $ 1,817 Unproved properties — 138,683 4,608 Exploration — 16,879 26,975 Development — 331,400 355,421 Total capital expenditures $ — $ 574,881 $ 388,821 * No wells were drilled in 2015. ** 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 of $(9.0) million and $(10.7) million for the years ended December 31, 2014 and 2013 , respectively.
Results of operations for oil and gas producing activities disclosure	The following reflects the results of operations from the Company's oil and natural gas producing activities included in discontinued operations, excluding corporate overhead and financing costs: Years ended December 31, 2015 2014 2013 (In thousands) Income (loss) from discontinued operations $ (772,385 ) $ 111,998 $ 110,191
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, 2015, were as follows: Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) Total (MBOE) Proved developed and undeveloped reserves: Balance at beginning of year 43,918 7,187 245,011 91,940 Production (3,286 ) (393 ) (16,747 ) (6,471 ) Extensions and discoveries 744 29 681 888 Improved recovery — — — — Purchases of proved reserves — — — — Sales of proved reserves (16,474 ) (6,864 ) (202,560 ) (57,097 ) Revisions of previous estimates (12,215 ) 252 (23,854 ) (15,939 ) Balance at end of year 12,687 211 2,531 13,321 Significant changes in proved reserves for the year ended December 31, 2015, include: • Sales of proved reserves of (57.1) MMBOE, primarily due to the Company's decision to sell Fidelity and exit the exploration and production business • Revisions of previous estimates of (15.9) MMBOE, largely the result of lower commodity prices 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 (MBbls) NGL (MBbls) Natural Gas (MMcf) Total (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 (MBbls) NGL (MBbls) Natural Gas (MMcf) Total (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: • Extensions 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 following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31: 2015 2014 2013 Proved developed reserves: Oil (MBbls) 11,380 30,130 31,394 NGL (MBbls) 144 4,217 5,322 Natural Gas (MMcf) 2,033 184,437 176,546 Total (MBOE) 11,865 65,086 66,140 PUD reserves: Oil (MBbls) 1,307 13,788 9,625 NGL (MBbls) 67 2,970 1,280 Natural Gas (MMcf) 498 60,574 21,899 Total (MBOE) 1,456 26,854 14,555 Total proved reserves: Oil (MBbls) 12,687 43,918 41,019 NGL (MBbls) 211 7,187 6,602 Natural Gas (MMcf) 2,531 245,011 198,445 Total (MBOE) 13,321 91,940 80,695
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 (In thousands) Future cash inflows $ 5,185,500 $ 4,507,000 Future production costs 1,856,900 1,734,800 Future development costs 570,200 403,000 Future net cash flows before income taxes 2,758,400 2,369,200 Future income tax expense 686,100 545,200 Future net cash flows 2,072,300 1,824,000 10% annual discount for estimated timing of cash flows 997,400 810,000 Discounted future net cash flows relating to proved oil, NGL and natural gas reserves $ 1,074,900 $ 1,014,000 Note: Standardized measure not applicable in 2015 as the remaining oil and natural gas properties are held for sale and subject to fair value impairment. The following are the sources of change in the standardized measure of discounted future net cash flows by year: 2014 2013 (In thousands) Beginning of year $ 1,014,000 $ 883,400 Net revenues from production (368,900 ) (398,000 ) Net change in sales prices and production costs related to future production 86,300 162,200 Extensions and discoveries, net of future production-related costs 231,900 366,500 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 ) Changes in estimated future development costs 65,100 6,700 Development costs incurred during the current year 104,600 141,500 Accretion of discount 109,400 94,600 Net change in income taxes (33,400 ) (141,400 ) Revisions of previous estimates (16,300 ) (55,800 ) Other (2,300 ) (7,900 ) Net change 60,900 130,600 End of year $ 1,074,900 $ 1,014,000 Note: Standardized measure not applicable in 2015 as the remaining oil and natural gas properties are held for sale and subject to fair value impairment.

Summary of significant accoun46

Summary of significant accounting policies Percentage of assets sold (Details)	12 Months Ended
	Dec. 31, 2014
Discontinued operations, disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percent of oil and natural gas production sold	93.00%

Accounts receivable and allowan

Accounts receivable and allowance for doubtful accounts (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Receivables past due 90 days or more	$ 27.8	$ 29.4
Allowance for doubtful accounts	$ 9.8	$ 9.5

Inventories and natural gas in

Inventories and natural gas in storage (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, plant and equipment [Line Items]
Aggregates held for resale	$ 115,854	$ 108,161
Asphalt oil	36,498	42,135
Materials and supplies	16,997	54,282
Merchandise for resale	15,318	24,420
Refined products	8,498	0
Natural gas in storage (current)	21,023	19,302
Crude oil	4,678	5,045
Other	34,861	36,065
Total	253,727	289,410
Inventory impairment	12,200
Natural gas in storage noncurrent	$ 49,100	$ 49,300

Property, plant and equipment (

Property, plant and equipment (Details 4) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, plant and equipment [Line Items]
Interest capitalized		$ 4,902	$ 8,586	$ 6,033
AFUDC - borrowed		4,907	3,022	2,767
AFUDC - equity		7,971	5,803	3,322
Property, plant and equipment		6,817,668	6,294,778
Less accumulated depreciation, depletion and amortization		2,506,571	2,386,113	2,284,169
Net property, plant and equipment		4,311,097	3,908,665	3,461,553
Electric:
Property, plant and equipment [Line Items]
Property, plant and equipment	[1]	1,786,148	1,457,101	1,315,822
Natural gas distribution:
Property, plant and equipment [Line Items]
Property, plant and equipment	[1]	2,076,581	1,904,759	1,776,901
Pipeline and midstream:
Property, plant and equipment [Line Items]
Property, plant and equipment		758,729	818,388	789,569
Construction materials and contracting:
Property, plant and equipment [Line Items]
Property, plant and equipment		1,553,428	1,529,942	1,510,355
Construction services:
Property, plant and equipment [Line Items]
Property, plant and equipment		163,279	144,395	134,948
Refining
Property, plant and equipment [Line Items]
Property, plant and equipment		445,333	401,845	172,603
Other:
Property, plant and equipment [Line Items]
Property, plant and equipment		49,537	50,937	$ 49,997
Regulated: | Electric: | Generation
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 1,003,173	627,952
Weighted average depreciable life in years		39 years
Regulated: | Electric: | Distribution
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 375,612	343,692
Weighted average depreciable life in years		44 years
Regulated: | Electric: | Transmission
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 255,842	229,997
Weighted average depreciable life in years		57 years
Regulated: | Electric: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 42,436	150,445
Regulated: | Electric: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 109,085	105,015
Weighted average depreciable life in years		14 years
Regulated: | Natural gas distribution: | Distribution
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 1,624,645	1,481,390
Weighted average depreciable life in years		35 years
Regulated: | Natural gas distribution: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 20,530	59,310
Regulated: | Natural gas distribution: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 431,406	364,059
Weighted average depreciable life in years		22 years
Regulated: | Pipeline and midstream: | Transmission
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 460,305	449,276
Weighted average depreciable life in years		53 years
Regulated: | Pipeline and midstream: | Gathering
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 37,831	39,595
Weighted average depreciable life in years		20 years
Regulated: | Pipeline and midstream: | Storage
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 44,011	43,994
Weighted average depreciable life in years		60 years
Regulated: | Pipeline and midstream: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 7,549	5,386
Regulated: | Pipeline and midstream: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 40,168	39,910
Weighted average depreciable life in years		33 years
Nonregulated: | Eliminations
Property, plant and equipment [Line Items]
Property, plant and equipment		$ (15,367)	(12,589)
Nonregulated: | Pipeline and midstream: | Gathering and processing
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 158,949	227,598
Weighted average depreciable life in years		16 years
Nonregulated: | Pipeline and midstream: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 89	691
Nonregulated: | Pipeline and midstream: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 9,827	11,938
Weighted average depreciable life in years		10 years
Nonregulated: | Construction materials and contracting: | Land
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 123,723	125,372
Nonregulated: | Construction materials and contracting: | Buildings and improvements
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 69,011	70,566
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		$ 937,084	921,564
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		$ 18,615	8,709
Nonregulated: | Construction materials and contracting: | Aggregate reserves
Property, plant and equipment [Line Items]
Property, plant and equipment	[2]	404,995	403,731
Nonregulated: | Construction services: | Land
Property, plant and equipment [Line Items]
Property, plant and equipment		6,460	5,265
Nonregulated: | Construction services: | Buildings and improvements
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 23,824	17,936
Weighted average depreciable life in years		25 years
Nonregulated: | Construction services: | Machinery, vehicles and equipment
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 121,940	112,973
Weighted average depreciable life in years		6 years
Nonregulated: | Construction services: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 11,055	8,221
Weighted average depreciable life in years		3 years
Nonregulated: | Refining | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 135	313,613
Nonregulated: | Refining | Refinery
Property, plant and equipment [Line Items]
Property, plant and equipment		$ 445,198	88,232
Weighted average depreciable life in years		20 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		$ 46,700	$ 48,100
Weighted average depreciable life in years		23 years
[1]	Includes allocations of common utility property
[2]	Depleted on the units-of-production method.

Impairment of long-lived assets

Impairment of long-lived assets (Details 5) - USD ($) $ in Millions	3 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Jun. 30, 2013
Accounting Policies [Abstract]
Asset impairment charges	$ 14.1	$ 3	$ 14.5

Goodwill (Details 6)

Goodwill (Details 6)	3 Months Ended
	Dec. 31, 2015
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%

Revenue recognition (Details 7)

Revenue recognition (Details 7) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain	$ 102.1	$ 99.7

Percentage-of-completion method

Percentage-of-completion method (Details 8) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Costs and estimated earnings in excess of billings on uncompleted contracts		$ 64,369	$ 58,243
Billings in excess of costs and estimated earnings on uncompleted contracts		68,048	47,011
Short-term retainage	[1]	46,207	47,551
Long-term retainage	[2]	1,605	1,053
Total retainage		$ 47,812	$ 48,604
[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, 2015
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 in cash flow hedge purchase	3 years
Maximum period for settlement of all interest rate derivative transactions	90 days

Natural gas costs recoverable o

Natural gas costs recoverable or refundable through rate adjustments (Details 10) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Natural gas costs refundable	$ 20,900,000	$ 13,200,000
Natural gas costs recoverable	$ 547,000	$ 19,600,000

Income taxes (Details 11)

Income taxes (Details 11)	12 Months Ended
	Dec. 31, 2015
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) - shares shares in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Weighted average common shares outstanding - basic	195,266	195,151	194,805	194,479	194,136	193,949	192,060	189,820	194,928	192,507	188,855
Effect of dilutive performance share awards									58	80	838
Weighted average common shares outstanding - diluted	195,324	195,169	194,838	194,566	194,219	194,300	192,659	190,432	194,986	192,587	189,693
Shares excluded from the calculation of diluted earnings per share									0	0	0

Cash flow information (Details

Cash flow information (Details 13) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Interest, net of amount capitalized and AFUDC - borrowed of $9,809, $11,608 and $8,800 in 2015, 2014 and 2013, respectively	$ 90,386	$ 81,241	$ 81,575
Income taxes paid, net	33,409	64,211	52,580
Capital expenditures incurred but not yet paid	51,702	62,453	22,832
Capitalized interest and AFUDC borrowed	$ 9,809	$ 11,608	$ 8,800

Comprehensive income (loss) (De

Comprehensive income (loss) (Details 14) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	$ 3,249,784	$ 2,855,902	$ 2,648,248
Amounts reclassified from accumulated other comprehensive loss	(3,131)	(1,625)
Net current-period other comprehensive income (loss)	4,955	(3,898)	10,516
Balance	2,520,548	3,249,784	2,855,902
Net unrealized gain (loss) on derivative instruments qualifying as hedges
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(3,071)	(3,765)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive loss	404	694
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	0	0
Net current-period other comprehensive income (loss)	404	694
Balance	(2,667)	(3,071)	(3,765)
Postretirement liability adjustment
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(38,218)	(33,807)
Other comprehensive income (loss) before reclassifications	(88)	(12,409)
Amounts reclassified from accumulated other comprehensive loss	1,794	796
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	2,255	7,202
Net current-period other comprehensive income (loss)	3,961	(4,411)
Balance	(34,257)	(38,218)	(33,807)
Foreign currency translation adjustment
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(829)	(667)
Other comprehensive income (loss) before reclassifications	(173)	(162)
Amounts reclassified from accumulated other comprehensive loss	802	0
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	0	0
Net current-period other comprehensive income (loss)	629	(162)
Balance	(200)	(829)	(667)
Net unrealizaed gasin (loss) on available-for-sale investments
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	15	34
Other comprehensive income (loss) before reclassifications	(170)	(154)
Amounts reclassified from accumulated other comprehensive loss	131	135
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	0	0
Net current-period other comprehensive income (loss)	(39)	(19)
Balance	(24)	15	34
Accumulated other comprehensive loss
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(42,103)	(38,205)	(48,721)
Other comprehensive income (loss) before reclassifications	(431)	(12,725)
Amounts reclassified from accumulated other comprehensive loss	3,131	1,625
Amounts reclassified from accumulated other comprehensive loss to a regulatory asset	2,255	7,202
Net current-period other comprehensive income (loss)	4,955	(3,898)	10,516
Balance	$ (37,148)	$ (42,103)	$ (38,205)

Reclassifications out of accumu

Reclassifications out of accumulated other comprehensive (loss) (Details 15) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense									$ (93,068)	$ (86,906)	$ (83,803)
Income taxes									(65,603)	(63,227)	(74,294)
Other income									19,232	9,873	6,086
Income from continuing operations									114,694	179,163	168,691
Income (loss) from discontinued operations, net of tax	$ 6,261	$ (202,626)	$ (251,415)	$ (324,605)	$ 27,700	$ 38,482	$ 23,881	$ 25,112	(772,385)	115,175	109,879
Net income (loss)									(657,691)	294,338	$ 278,570
Reclassification from accumulated other comprehensive income, current period, net of tax									(3,131)	(1,625)
Reclassification adjustment for loss on derivative instruments included in net income (loss):
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from accumulated other comprehensive income, current period, net of tax									404	694
Reclassification adjustment for loss on derivative instruments included in net income (loss): | Reclassification out of accumulated other comprehensive income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income (loss)									(404)	(694)
Reclassification adjustment for loss on derivative instruments included in net income (loss): | Reclassification out of accumulated other comprehensive income [Member] | Interest rate contract [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense									(637)	(639)
Income taxes									233	240
Income from continuing operations									(404)	(399)
Reclassification adjustment for loss on derivative instruments included in net income (loss): | Reclassification out of accumulated other comprehensive income [Member] | Commodity derivatives {Member}
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (loss) from discontinued operations, net of tax									0	(295)
Amortization of postretirement liability losses included in net periodic benefit cost (credit)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from accumulated other comprehensive income, current period, net of tax									1,794	796
Amortization of postretirement liability losses included in net periodic benefit cost (credit) | Reclassification out of accumulated other comprehensive income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income taxes									1,128	492
Net periodic benefit cost									(2,922)	(1,288)
Net income (loss)									(1,794)	(796)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from accumulated other comprehensive income, current period, net of tax									802	0
Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss) | Reclassification out of accumulated other comprehensive income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income taxes									490	0
Other income									(1,292)	0
Net income (loss)									(802)	0
Reclassification adjustment for loss on available-for-sale investments included in net income (loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from accumulated other comprehensive income, current period, net of tax									131	135
Reclassification adjustment for loss on available-for-sale investments included in net income (loss) | Reclassification out of accumulated other comprehensive income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income taxes									70	73
Other income									(201)	(208)
Net income (loss)									$ (131)	$ (135)

Percentage of assets sold (Deta

Percentage of assets sold (Details)	12 Months Ended
	Dec. 31, 2014
Discontinued operations, disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percent of oil and natural gas production sold	93.00%

Major classes of assets and lia

Major classes of assets and liabilities (Details 2) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Total current assets held for sale	$ 24,581	$ 131,177
Noncurrent assets:
Total noncurrent assets held for sale	166,734	1,620,470
Current liabilities:
Total current liabilities held for sale	47,603	154,728
Noncurrent liabilities:
Total noncurrent liabilities held for sale	0	295,441
Discontinued operations, held-for-sale or disposed by sale [Member]
Current assets:
Receivables, net	13,387	94,132
Inventories	1,308	11,401
Commodity derivative instruments	0	18,335
Prepayments and other current assets	9,886	7,309
Total current assets held for sale	24,581	131,177
Noncurrent assets:
Investments	37	37
Net property, plant and equipment	793,422	1,618,099
Deferred income taxes	127,655	0
Other	161	2,334
Less allowance for impairment of assets held for sale	754,541	0
Total noncurrent assets held for sale	166,734	1,620,470
Total assets held for sale	191,315	1,751,647
Current liabilities:
Long-term debt due within one year	0	897
Accounts payable	25,013	103,556
Taxes payable	1,052	19,900
Deferred income taxes	3,620	8,206
Accrued compensation	13,080	5,373
Other accrued liabilities	4,838	16,796
Total current liabilities held for sale	47,603	154,728
Noncurrent liabilities:
Deferred income taxes	0	238,391
Other liabilities	0	57,050
Total noncurrent liabilities held for sale	0	295,441
Total liabilities held for sale	$ 47,603	$ 450,169

Taxes and operating loss carryf

Taxes and operating loss carryforwards (Details 3) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred tax liabilities, property, plant and equipment	$ 791,368,000	$ 773,160,000
Deferred tax assets, asset retirement obligation	8,694,000	7,894,000
Valuation allowance	8,990,000	8,852,000
Discontinued operations, held-for-sale or disposed by sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred tax assets, operating loss carryforwards	78,900,000
Deferred tax assets, property, plant and equipment	38,100,000
Deferred tax liabilities, property, plant and equipment		270,000,000
Deferred tax assets, asset retirement obligation		26,400,000
Domestic Tax Authority [Member] | Discontinued operations, held-for-sale or disposed by sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating loss carryforwards	208,200,000	0
State and Local Jurisdiction [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating loss carryforwards	116,200,000	114,300,000
State and Local Jurisdiction [Member] | Discontinued operations, held-for-sale or disposed by sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating loss carryforwards	201,400,000	5,900,000
Valuation allowance	$ 300,000	$ 253,000

Impairment fair value, ceiling

Impairment fair value, ceiling test and transactions costs (Details 4) - Discontinued operations, held-for-sale or disposed by sale [Member] - USD ($) $ in Millions	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Fair value impairment	$ (1.6)	$ 356.1	$ 400
Fair value impairment after tax	(1)	$ 224.4	$ 252
Accrued liability of estimated transaction costs	2.5				$ 2.5
Expensed exit and disposal costs					4.9
Estimated future exit and disposal costs	6.1				6.1
Future lease payments	4.2				$ 4.2
Lease termination payment	$ 3.3
Impairment of oil and gas properties				$ 500.4
Impairment of oil and gas properties, after tax				$ 315.3
Acquisition costs						$ 209.2

Reconciliation of income and ex

Reconciliation of income and expenses (Details 5) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations, net of tax	$ 6,261	$ (202,626)	$ (251,415)	$ (324,605)	$ 27,700	$ 38,482	$ 23,881	$ 25,112	$ (772,385)	$ 115,175	$ 109,879
Discontinued operations, held-for-sale or disposed by sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues									184,853	547,571	536,023
Operating expenses									1,423,037	378,891	364,120
Operating income (loss)									(1,238,184)	168,680	171,903
Other income									2,374	1,163	549
Interest expense									235	110	114
Income (loss) from discontinued operations before income taxes									(1,236,045)	169,733	172,338
Income taxes									(463,660)	54,558	62,459
Income (loss) from discontinued operations, net of tax									$ (772,385)	$ 115,175	$ 109,879

Goodwill and other intangible66

Goodwill and other intangible assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Goodwill [Roll Forward]
Balance as of beginning of period	[1]	$ 635,204	$ 636,039
Goodwill acquired during the year		0
Goodwill acquired during the year/other			(835)
Balance as of end of period	[1]	635,204	635,204
Natural gas distribution:
Goodwill [Roll Forward]
Balance as of beginning of period		345,736	345,736
Goodwill acquired during the year		0
Goodwill acquired during the year/other			0
Balance as of end of period		345,736	345,736
Pipeline and midstream:
Goodwill [Roll Forward]
Balance as of beginning of period	[1]	9,737	9,737
Goodwill acquired during the year		0
Goodwill acquired during the year/other			0
Balance as of end of period	[1]	9,737	9,737
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		0
Goodwill acquired during the year/other			0
Balance as of end of period		176,290	176,290
Construction services:
Goodwill [Roll Forward]
Balance as of beginning of period		103,441	104,276
Goodwill acquired during the year		0
Goodwill acquired during the year/other			(835)
Balance as of end of period		$ 103,441	$ 103,441
[1]	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and midstream segment, which occurred in prior periods.

Goodwill and other intangible67

Goodwill and other intangible assets (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finite-lived intangible assets [Line Items]
Intangible assets, net (excluding goodwill)	$ 7,342,000	$ 9,840,000
Amortization of intangible assets	2,500,000	3,200,000	$ 4,000,000
Estimated amortization expense for amortizable intangible assets
2,016	2,200,000
2,017	1,900,000
2,018	1,000,000
2,019	900,000
2,020	300,000
Thereafter	1,000,000
Customer relationships [Member]
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	20,975,000	21,310,000
Accumulated amortization	(16,845,000)	(15,556,000)
Intangible assets, net (excluding goodwill)	4,130,000	5,754,000
Noncompete agreements [Member]
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	4,409,000	5,080,000
Accumulated amortization	(3,655,000)	(4,098,000)
Intangible assets, net (excluding goodwill)	754,000	982,000
Other [Member}
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	8,304,000	10,921,000
Accumulated amortization	(5,846,000)	(7,817,000)
Intangible assets, net (excluding goodwill)	$ 2,458,000	$ 3,104,000

Regulatory assets and liabili68

Regulatory assets and liabilities (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Regulatory assets and liabilities
Regulatory assets:		$ 263,258	$ 269,586
Regulatory liabilities:		243,118	386,252
Net regulatory position		20,140	(116,666)
Regulatory assets not earning a rate of return		224,700	229,600
Plant removal and decommissioning costs [Member}
Regulatory assets and liabilities
Regulatory liabilities:	[1]	182,981	338,641
Taxes refundable to customers [Member]
Regulatory assets and liabilities
Regulatory liabilities:	[1]	17,060	17,772
Natural gas costs refundable through rate adjustments [Member]
Regulatory assets and liabilities
Regulatory liabilities:	[2]	20,884	13,238
Other regulatory assets/liabilities [Member]
Regulatory assets and liabilities
Regulatory liabilities:	[1],[2]	$ 22,193	16,601
Pension and postretirement benefits [Member]
Regulatory assets and liabilities
Estimated recovery period	[3]	(e)
Regulatory assets:	[4]	$ 185,832	182,565
Taxes recoverable from customers [Member]
Regulatory assets and liabilities
Estimated recovery period	[5]	Over plant lives
Regulatory assets:	[4]	$ 27,682	22,910
Manufactured gas plant sites remediation [Member]
Regulatory assets and liabilities
Estimated recovery period	[5]	Up to 2 years
Regulatory assets:	[4]	$ 18,617	17,548
Plant costs [Member]
Regulatory assets and liabilities
Estimated recovery period	[5]	Up to 1 year
Regulatory assets:	[4]	$ 8,000	4,551
Natural gas costs recoverable through rate adjustments [Member]
Regulatory assets and liabilities
Estimated recovery period	[5]	Up to 1 year
Regulatory assets:	[6]	$ 547	19,575
Long-term debt refinancing costs [Member]
Regulatory assets and liabilities
Estimated recovery period	[5]	Up to 22 years
Regulatory assets:	[4]	$ 7,031	7,864
Costs related to identifying generation development [Member]
Regulatory assets and liabilities
Estimated recovery period	[5]	Up to 11 years
Regulatory assets:	[4]	$ 3,808	4,165
Other regulatory assets/liabilities [Member]
Regulatory assets and liabilities
Estimated recovery period	[5]	Largely within 1- 4 years
Regulatory assets:	[4],[6]	$ 11,741	$ 10,408
[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]	Estimated 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 Derivati

Derivative Instruments Derivative instruments (Details)	12 Months Ended
	Dec. 31, 2015USD ($)bblMMBTU	Dec. 31, 2014bblMMBTU	Mar. 31, 2013USD ($)
Derivative instruments [Line Items]
Amount of unrealized gain (loss) on hedge at de-designation date to be reclassified into AOCI			$ 1,800,000
Cash flow hedge gain (loss) to be reclassified within twelve months from AOCI into earnings	$ (400,000)
Oil swap and or collar [Member]
Derivative instruments [Line Items]
Derivative, nonmonetary notional amount | bbl	0	270,000
Natural gas swap or and collar [Member]
Derivative instruments [Line Items]
Derivative, nonmonetary notional amount | MMBTU	0	5,000,000

Derivative Instruments Gains an

Derivative Instruments Gains and losses on derivative instruments (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	$ 0	$ 0	$ (5,594)
Amount of (gain) loss reclassified from accumulated other comprehensive loss into discontinued operations (effective portion), net of tax	0	295	(4,916)
Amount of loss reclassified from accumulated other comprehensive loss into income statement (effective portion), net of tax	404	399	727
Designated as hedging instrument [Member] | Commodity derivatives designated as cash flow hedges [Member]
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	0	0	(6,153)
Amount of (gain) loss reclassified from accumulated other comprehensive loss into discontinued operations (effective portion), net of tax	0	295	(4,916)
Amount of loss recognized in income statement (ineffective portion), before tax	0	0	(1,422)
Designated as hedging instrument [Member] | Interest rate derivatives designated as cash flow hedges [Member]
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	0	0	559
Amount of loss reclassified from accumulated other comprehensive loss into income statement (effective portion), net of tax	404	399	727
Amount of loss recognized in income statement (ineffective portion), before tax	0	0	(769)
Not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivative instruments [Line Items]
Amount of gain (loss) recognized in discontinued operations, before tax	$ (18,335)	$ 23,400	$ (4,845)

Fair value derivative instrumen

Fair value derivative instruments (Details 3) - Discontinued operations, held-for-sale or disposed by sale [Member] $ in Thousands	Dec. 31, 2014USD ($)
Derivatives, fair value [Line Items]
Derivative asset, fair value, gross asset	$ 18,335
Not designated as hedging instruments [Member] | Commodity derivatives {Member} | Disposal Group Current Assets, Held For Sale [Member]
Derivatives, fair value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	$ 18,335

Derivative Instruments Subject

Derivative Instruments Subject to master netting agreements (Details 4) - Discontinued operations, held-for-sale or disposed by sale [Member] $ in Thousands	Dec. 31, 2014USD ($)
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	$ 18,335
Commodity derivative instruments assets [Member]
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	18,335
Gross amount not offset	0
Derivative asset, fair value, net	18,335
Total assets [Member]
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	18,335
Gross amount not offset	0
Derivative asset, fair value, net	$ 18,335

Available-for-sale securities (

Available-for-sale securities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Available-for-sale securities [Line Items]
Investments used to satisfy obligations under nonqualified benefit plans	$ 67,500	$ 65,800
Net unrealized gain (loss) of investments used to satisfy obligations under nonqualified benefit plans	1,700	3,400	$ 13,500
Available-for-sale securities:
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	10,443	10,168
Available-for-sale securities, gross unrealized gains	19	60
Available-for-sale securities, gross unrealized losses	(55)	(37)
Available-for-sale securities	10,407	10,191
Mortgage-backed securities
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	9,128	6,594
Available-for-sale securities, gross unrealized gains	19	60
Available-for-sale securities, gross unrealized losses	(49)	(18)
Available-for-sale securities	9,098	6,636
U.S. Treasury securities
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	1,315	3,574
Available-for-sale securities, gross unrealized gains	0	0
Available-for-sale securities, gross unrealized losses	(6)	(19)
Available-for-sale securities	$ 1,309	$ 3,555

Fair value measurements (Detail

Fair value measurements (Details 2) - USD ($) $ in Thousands	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2014
Concentration risks, percentage [Abstract]
Percentage investment in common stock of mid-cap companies	9.00%				20.00%
Percentage investment in common stock of small-cap companies	7.00%				18.00%
Percentage investment in common stock of large-cap companies	19.00%				29.00%
Percentage in fixed-income investments	63.00%				32.00%
Percentage Investment in Target Date Investments	1.00%
Percentage investment in cash and cash equivalents	1.00%				1.00%
Assets, fair value disclosure, nonrecurring			$ 10,800	$ 1,100
Fair value, measurements, recurring [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	$ 79,286				$ 76,912
Liabilities:	3,052
Fair value, measurements, recurring [Member] | Renewable Identification Number Obligations [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:	3,052
Fair value, measurements, recurring [Member] | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	1,420				890
Fair value, measurements, recurring [Member] | Insurance contract [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	67,459	[1]			65,831	[2]
Fair value, measurements, recurring [Member] | Mortgage-backed securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	9,098				6,636
Fair value, measurements, recurring [Member] | U.S. Treasury securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	1,309				3,555
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) | Renewable Identification Number Obligations [Member]
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. Treasury securities
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:	79,286				76,912
Liabilities:	3,052
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Renewable Identification Number Obligations [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:	3,052
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:	1,420				890
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:	67,459	[1]			65,831	[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:	9,098				6,636
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | U.S. Treasury securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	1,309				3,555
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) | Renewable Identification Number Obligations [Member]
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. Treasury securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	$ 0				$ 0
[1]	The insurance contract invests approximately 9 percent in common stock of mid-cap companies, 7 percent in common stock of small-cap companies, 19 percent in common stock of large-cap companies, 63 percent in fixed-income investments, 1 percent in target date investments and 1 percent in cash equivalents.
[2]	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 (Deta75

Fair value measurements (Details 3) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,871,232	$ 2,093,830
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 1,893,442	$ 2,238,548

Credit facilities (Details)

Credit facilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 01, 2014
Line of credit facility and other debt [Abstract]
Letters of credit at end of period		$ 57.3
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
Amount outstanding, end of period	[1]	$ 44.5		$ 77.5
Expiration date		May 8, 2019
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
Amount outstanding, end of period	[1]	$ 18		211
Expiration date		May 8, 2019
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	[2]	50
Amount outstanding, end of period		0		0
Letters of credit at end of period	[3]	$ 2.2
Expiration date		Jul. 9, 2018
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	[4]	65
Amount outstanding, end of period		47.9		21
Letters of credit at end of period		$ 0
Expiration date		Jul. 13, 2018
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		39.4
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		75	$ 75		$ 50
Amount outstanding, end of period		45.5		$ 0
Letters of credit at end of period	[3]	$ 18.3
Expiration date		Jun. 30, 2016
[1]	Amount outstanding under commercial paper program.
[2]	Certain provisions allow for increased borrowings, up to a maximum of $75.0 million.
[3]	Outstanding letter(s) of credit reduce the amount available under the credit agreement.
[4]	Certain provisions allow for increased borrowings, up to a maximum of $90.0 million.

Short-term borrowings (Details

Short-term borrowings (Details 2) - Revolving credit facility [Member] - Short-term debt [Member] - Dakota Prairie Refining, LLC [Member] - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Dec. 01, 2014
Short-term debt [Line Items]
Facility limit, maximum borrowing capacity	$ 75	$ 75	$ 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%

Long-term borrowings (Details 3

Long-term borrowings (Details 3) $ in Millions	Dec. 31, 2015USD ($)
Debt instrument [Line Items]
Letters of credit	$ 57.3
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
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
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	$ 39.4
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
[1]	Certain provisions allow for increased borrowings, up to a maximum of $75.0 million.
[2]	Outstanding letter(s) of credit reduce the amount available under the credit agreement.
[3]	Certain provisions allow for increased borrowings, up to a maximum of $90.0 million.

Long-term debt outstanding (Det

Long-term debt outstanding (Details 4) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-term debt maturities [Abstract]
2,016	$ 243,800
2,017	51,000
2,018	175,200
2,019	119,700
2,020	21,000
Thereafter	$ 1,260,500
Senior notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	5.18%
Commercial paper [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	0.73%
Term loan agreements [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	2.16%
Medium-term notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	6.68%
Other notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	5.25%
Loans payable [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	1.82%
Long-term debt [Member]
Long term debt outstanding [Abstract]
Long-term debt	$ 1,871,232	$ 2,093,830
Less current maturities	243,789	268,552
Long-term debt	1,627,443	1,825,278
Long-term debt [Member] | Senior notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	1,616,246	1,636,662
Long-term debt [Member] | Commercial paper [Member]
Long term debt outstanding [Abstract]
Long-term debt	62,500	288,500
Long-term debt [Member] | Term loan agreements [Member]
Long term debt outstanding [Abstract]
Long-term debt	69,000	72,000
Long-term debt [Member] | Medium-term notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	50,000	35,000
Long-term debt [Member] | Other notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	24,589	39,662
Long-term debt [Member] | Loans payable [Member]
Long term debt outstanding [Abstract]
Long-term debt	48,906	22,042
Long-term debt [Member] | Discount on commercial paper program [Member]
Long term debt outstanding [Abstract]
Long-term debt	$ (9)	$ (36)

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset retirement obligation [Roll Forward]
Balance, beginning of period	$ 27,211	$ 27,327
Liabilities incurred	2,751	1,697
Liabilities settled	(1,708)	(3,231)
Accretion expense	1,163	1,112
Revisions in estimates	211,836	(73)
Other	971	379
Balance, end of period	$ 242,224	$ 27,211

Preferred Stocks (Details)

Preferred Stocks (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Preferred stocks	$ 15,000	$ 15,000
Preferred stock redemption price upon liquidation (in dollars per share)	$ 100
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 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, redemption per share amount	$ 105
Preferred stock, series 4.70% [Member]
Class of Stock [Line Items]
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
Preferred stock, redemption per share amount	$ 102
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 ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Dividends declared per common share	$ 0.7350	$ 0.7150	$ 0.6950
Company's subsidiaries net assets restricted from being used to transfer funds to the Company	$ 1,600
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	$ 322
MDU Resources Group, Inc. [Member]
Shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan (in shares)	13.9
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) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)yrshares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Share-based Compensation [Abstract]
Share-based compensation arrangement, number of shares available for grant | shares	5.6
Share-based compensation expense, net of tax	$ 2.9	$ 4.4	$ 3.9
Share-based compensation nonvested awards total compensation cost not yet recognized	$ 5.6
Share-based compensation, nonvested awards, total compensation cost not yet recognized, period for recognition | yr	1.5

Stock awards (Details 2)

Stock awards (Details 2) - Nonemployee director stock compensation plan [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based compensation arrangement by share-based payment award [Line Items]
Shares issued for stock-based compensation	58,181	43,088	36,713
Fair value of vested shares	$ 1.1	$ 1.1	$ 1.1

Performance share awards (Detai

Performance share awards (Details 3) - Performance shares [Member] - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	22.86%	18.94%	16.10%
Expected volatility rate, maximum	24.61%	20.43%	19.39%
Risk-free interest rate, minimum	0.05%	0.03%	0.09%
Risk-free interest rate, maximum	1.07%	0.74%	0.40%
Weighted average discounted dividends per share	$ 1.57	$ 2.15	$ 2.12
Fair value of vested shares	$ 0	$ 16,600,000	$ 0
Share-based compensation arrangement by share-based payment award, options, outstanding [Roll Forward]
Nonvested at beginning of period	688,455
Nonvested at beginning of period	$ 28.16
Granted	258,454
Granted	$ 18.98	$ 41.13	$ 29.01
Vested	0
Vested	$ 0
Forfeited	(381,013)
Forfeited	$ 22.31
Nonvested at end of period	565,896	688,455
Nonvested at end of period	$ 27.90	$ 28.16
Grant date March 2013 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	188,388
Grant date February 2014 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	142,989
Grant date February 2015 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	220,078
Grant date June 2015 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	14,441

Components of income (loss) bef

Components of income (loss) before income taxes from continuing operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
United States	$ 181,623	$ 242,442	$ 242,569
Foreign	(1,326)	(52)	416
Income before income taxes	$ 180,297	$ 242,390	$ 242,985

Income tax expense (benefit) (D

Income tax expense (benefit) (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal	$ 59,483	$ 4,403	$ 41,624
State	5,789	(166)	4,148
Foreign	30	0	(29)
Current income taxes	65,302	4,237	45,743
Deferred:
Federal	3,199	55,514	29,616
State	(2,478)	2,467	(859)
Investment tax credit - net	(420)	1,009	(206)
Deferred income taxes	301	58,990	28,551
Total income tax expense	$ 65,603	$ 63,227	$ 74,294

Components of deferred tax asse

Components of deferred tax assets and liabilities (Details 3) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Postretirement	$ 97,666	$ 99,853
Compensation-related	33,844	35,669
Alternative minimum tax credit carryforward	28,173	23,678
Customer advances	12,623	12,245
Asset retirement obligations	8,694	7,894
Legal and environmental contingencies	6,377	7,890
Other	58,202	52,862
Total deferred tax assets	245,579	240,091
Deferred tax liabilities:
Depreciation and basis differences on property, plant and equipment	791,368	773,160
Postretirement	71,835	70,642
Intangible asset amortization	23,950	22,810
Other	36,906	46,637
Total deferred tax liabilities	924,059	913,249
Valuation allowance	8,990	8,852
Deferred Tax Liabilities, Net	$ (687,470)	$ (682,010)

Carryforwards (Details 4)

Carryforwards (Details 4) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
State and Local Jurisdiction [Member]
Carryforwards [Line Items]
Operating loss carryforwards	$ 116.2	$ 114.3
Federal and State Taxing Authority [Member]
Carryforwards [Line Items]
Tax credit carryforward, amount	$ 10.9	$ 7.5

Deferred tax reconciliation (De

Deferred tax reconciliation (Details 5) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Change in net deferred income tax liability from the preceding table	$ 5,460
Deferred taxes associated with other comprehensive income	(3,086)
Other	(2,073)
Deferred income taxes	$ 301	$ 58,990	$ 28,551

Income tax expense (benefit) st

Income tax expense (benefit) statutory rate versus actual rate (Details 6) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Computed tax at federal statutory rate
Computed tax at federal statutory rate	$ 63,104,000	$ 84,836,000	$ 85,045,000
Federal statutory rate (in hundredths)	35.00%	35.00%	35.00%
Increases (reductions) resulting from:
State income taxes, net of federal income tax	$ 4,903,000	$ 7,048,000	$ 7,379,000
State income tax rate (in hundredths)	2.70%	2.90%	3.00%
Noncontrolling interest	$ 12,340,000	$ 1,363,000	$ 0
Non-controlling interest (in hundredths)	6.80%	0.50%	(0.00%)
Federal renewable energy credit	$ (3,400,000)	$ (3,655,000)	$ (3,404,000)
Federal renewable energy credit rate (in hundreths)	(1.90%)	(1.50%)	(1.40%)
Tax compliance and uncertain tax positions	$ (194,000)	$ (8,987,000)	$ (3,902,000)
Tax compliance and uncertain tax positions (in hundredths)	(0.10%)	(3.70%)	(1.60%)
Domestic production activities	$ 0	$ (3,993,000)	$ (666,000)
Domestic production activities (in hundredths)	(0.00%)	(1.60%)	(0.30%)
Other	$ (11,150,000)	$ (13,385,000)	$ (10,158,000)
Other rate (in hundredths)	(6.10%)	(5.50%)	(4.10%)
Total income tax expense	$ 65,603,000	$ 63,227,000	$ 74,294,000
Total income tax expense (benefit) rate (in hundredths)	36.40%	26.10%	30.60%
Temporary differences [Abstract]
Undistributed earnings from foreign operations	$ 2,400,000
Deferred tax liabilities, undistributed foreign earnings	$ 900,000

Unrecognized tax benefits (Deta

Unrecognized tax benefits (Details 7) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 105,000	$ 7,845,000	$ 7,845,000
Settlements	0	(7,740,000)	0
Lapse of statute of limitations	(105,000)	0	0
Balance at end of year	0	105,000	7,845,000
Unrecognized tax benefits highly certain deductibility	0	0
Unrecognized tax benefits that would affect the effective tax rate		119,000
Unrecognized tax benefits, interest and penalties		14,000
Interest expense recognized in income tax expense	122,000	387,000	107,000
Interest expense	3,400,000	1,200,000	914,000
Interest income	3,700,000	469,000	$ 655,000
Accrued liability for payment of interest	$ 94,000
Amount of interest income accrued for an over payment of income taxes		$ 367,000

Business segment data (Details)

Business segment data (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business segment data [Line Items]
External operating revenues		$ 1,062,485	$ 1,280,500	$ 986,215	$ 862,349	$ 1,048,288	$ 1,213,203	$ 952,564	$ 900,761	$ 4,191,549	$ 4,114,816	$ 3,920,171
Intersegment operating revenues										0	0	0
Depreciation, depletion and amortization										227,730	203,980	200,398
Interest expense										93,068	86,906	83,803
Income taxes										65,603	63,227	74,294
Earnings (loss) on common stock before income (loss) from discontinued operations										149,265	182,373	168,369
Income (loss) from discontinued operations, net of tax		6,261	$ (202,626)	$ (251,415)	$ (324,605)	27,700	$ 38,482	$ 23,881	$ 25,112	(772,385)	115,175	109,879
Total earnings (loss) on common stock										(623,120)	297,548	278,248
Net proceeds from sale or disposition of property and other										(63,831)	(60,177)	(28,392)
Total net capital expenditures										530,355	489,935	420,494
Total assets		6,627,608				7,832,408				6,627,608	7,832,408	7,073,447
Property, plant and equipment		6,817,668				6,294,778				6,817,668	6,294,778
Less accumulated depreciation, depletion and amortization		2,506,571				2,386,113				2,506,571	2,386,113	2,284,169
Net property, plant and equipment		4,311,097				3,908,665				4,311,097	3,908,665	3,461,553
Additional information [Abstract]
Net noncash inclusion of acct pay and NCI exclusion of capital expenditures										(40,500)	$ (88,800)	(70,000)
Discontinued operations, disposed of by sale
Business segment data [Line Items]
Percent of oil and natural gas production sold											93.00%
Electric:
Business segment data [Line Items]
Intersegment operating revenues										0	$ 0	0
Depreciation, depletion and amortization										37,583	35,008	32,789
Interest expense										17,421	15,595	12,590
Income taxes										11,523	12,442	9,683
Capital expenditures										332,876	185,121	168,557
Total assets	[1]	1,327,258				1,030,611				1,327,258	1,030,611	884,283
Property, plant and equipment	[1]	1,786,148				1,457,101				1,786,148	1,457,101	1,315,822
Natural gas distribution:
Business segment data [Line Items]
Intersegment operating revenues										0	0	0
Depreciation, depletion and amortization										64,756	54,700	50,031
Interest expense										29,471	27,217	25,123
Income taxes										11,377	11,350	16,633
Capital expenditures										130,793	120,613	101,279
Total assets	[1]	2,042,925				1,931,908				2,042,925	1,931,908	1,786,068
Property, plant and equipment	[1]	2,076,581				1,904,759				2,076,581	1,904,759	1,776,901
Pipeline and midstream:
Business segment data [Line Items]
Intersegment operating revenues										51,716	46,085	40,511
Depreciation, depletion and amortization										27,981	29,749	29,105
Interest expense										9,895	9,946	10,148
Income taxes										7,505	12,232	3,466
Capital expenditures										18,315	61,754	40,533
Total assets		593,025				655,735				593,025	655,735	620,639
Property, plant and equipment		758,729				818,388				758,729	818,388	789,569
Construction materials and contracting:
Business segment data [Line Items]
Intersegment operating revenues										2,752	25,241	36,693
Depreciation, depletion and amortization										65,937	68,557	74,470
Interest expense										15,183	16,368	17,394
Income taxes										41,619	18,586	24,765
Capital expenditures										48,126	37,896	34,607
Total assets		1,279,057				1,272,231				1,279,057	1,272,231	1,305,808
Property, plant and equipment		1,553,428				1,529,942				1,553,428	1,529,942	1,510,355
Construction services:
Business segment data [Line Items]
Intersegment operating revenues										18,660	57,474	9,930
Depreciation, depletion and amortization										13,420	12,874	11,939
Interest expense										3,959	4,176	4,306
Income taxes										16,432	24,753	29,504
Capital expenditures										38,269	26,942	15,102
Total assets		450,896				454,602				450,896	454,602	450,614
Property, plant and equipment		163,279				144,395				163,279	144,395	134,948
Refining
Business segment data [Line Items]
Intersegment operating revenues										0	0	0
Depreciation, depletion and amortization										16,463	896	14
Interest expense										3,450	119	182
Income taxes										(13,815)	(2,533)	(76)
Capital expenditures										22,052	115,655	86,559
Total assets		464,699				429,102				464,699	429,102	178,062
Property, plant and equipment		445,333				401,845				445,333	401,845	172,603
Other
Business segment data [Line Items]
Intersegment operating revenues										7,755	7,832	8,067
Depreciation, depletion and amortization										2,070	2,196	2,050
Interest expense										14,292	13,739	14,216
Income taxes										(8,107)	(9,798)	(6,812)
Capital expenditures										3,755	2,131	2,249
Total assets	[2]	278,433				306,572				278,433	306,572	236,543
Property, plant and equipment		49,537				50,937				49,537	50,937	49,997
Discontinued operations, held-for-sale [Member]
Business segment data [Line Items]
Total assets		191,315				1,751,647				191,315	1,751,647	1,611,430
Eliminations
Business segment data [Line Items]
Intersegment operating revenues										(80,883)	(136,632)	(95,201)
Depreciation, depletion and amortization										(480)	0	0
Interest expense										(603)	(254)	(156)
Income taxes										(931)	(3,805)	(2,869)
Earnings (loss) on common stock before income (loss) from discontinued operations										(1,531)	(6,095)	(4,307)
Property, plant and equipment		$ (15,367)				$ (12,589)				(15,367)	(12,589)	(4,473)
Regulated:
Business segment data [Line Items]
External operating revenues										1,148,272	1,246,646	1,156,838
Earnings (loss) on common stock before income (loss) from discontinued operations										80,201	82,655	87,881
Regulated: | Electric:
Business segment data [Line Items]
External operating revenues										280,615	277,874	257,260
Earnings (loss) on common stock before income (loss) from discontinued operations										35,914	36,731	34,837
Regulated: | Natural gas distribution:
Business segment data [Line Items]
External operating revenues										817,419	921,986	851,945
Earnings (loss) on common stock before income (loss) from discontinued operations										23,607	30,484	37,656
Regulated: | Pipeline and midstream:
Business segment data [Line Items]
External operating revenues										50,238	46,786	47,633
Earnings (loss) on common stock before income (loss) from discontinued operations										20,680	15,440	15,388
Nonregulated:
Business segment data [Line Items]
External operating revenues										3,043,277	2,868,170	2,763,333
Earnings (loss) on common stock before income (loss) from discontinued operations										70,595	105,813	84,795
Nonregulated: | Pipeline and midstream:
Business segment data [Line Items]
External operating revenues										54,282	64,494	56,427
Earnings (loss) on common stock before income (loss) from discontinued operations										(7,430)	9,226	(7,687)
Nonregulated: | Construction materials and contracting:
Business segment data [Line Items]
External operating revenues										1,901,530	1,740,089	1,675,444
Earnings (loss) on common stock before income (loss) from discontinued operations										89,096	51,510	50,946
Nonregulated: | Construction services:
Business segment data [Line Items]
External operating revenues										907,767	1,062,055	1,029,909
Earnings (loss) on common stock before income (loss) from discontinued operations										23,762	54,432	52,213
Nonregulated: | Refining
Business segment data [Line Items]
External operating revenues										178,262	0	0
Earnings (loss) on common stock before income (loss) from discontinued operations										(22,457)	(2,038)	(72)
Nonregulated: | Other
Business segment data [Line Items]
External operating revenues										1,436	1,532	1,553
Earnings (loss) on common stock before income (loss) from discontinued operations										$ (12,376)	$ (7,317)	$ (10,605)
[1]	Includes allocations of common utility property
[2]	ncludes 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 a

Change in benefit obligations and plan assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	$ 475,337	$ 402,772
Service cost	86	129	$ 155
Interest cost	17,141	17,682	16,249
Plan participants' contributions	0	0
Actuarial (gain) loss	(24,875)	80,520
Benefits paid	(24,729)	(25,766)
Benefit obligation at end of year	442,960	475,337	402,772
Change in net plan assets:
Fair value of plan assets at beginning of year	354,363	334,844
Actual gain (loss) on plan assets	(10,879)	24,500
Employer contribution	13,912	20,785
Plan participants' contributions	0	0
Benefits paid	(24,729)	(25,766)
Fair value of net plan assets at end of year	332,667	354,363	334,844
Funded status - under	(110,293)	(120,974)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	0	0
Other accrued liabilities (current)	0	0
Other liabilities (noncurrent)	(110,293)	(120,974)
Net amount recognized	(110,293)	(120,974)
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	208,671	207,430
Prior service cost (credit)	0	294
Total	208,671	207,724
Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	99,012	81,726
Service cost	1,816	1,518	1,675
Interest cost	3,607	3,521	3,215
Plan participants' contributions	1,408	1,399
Actuarial (gain) loss	(5,873)	18,024
Benefits paid	(7,236)	(7,176)
Benefit obligation at end of year	92,734	99,012	81,726
Change in net plan assets:
Fair value of plan assets at beginning of year	87,586	84,543
Actual gain (loss) on plan assets	258	7,527
Employer contribution	577	1,293
Plan participants' contributions	1,408	1,399
Benefits paid	(7,236)	(7,176)
Fair value of net plan assets at end of year	82,593	87,586	$ 84,543
Funded status - under	(10,141)	(11,426)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	5,095	4,345
Other accrued liabilities (current)	(421)	(322)
Other liabilities (noncurrent)	(14,815)	(15,449)
Net amount recognized	(10,141)	(11,426)
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	22,484	25,779
Prior service cost (credit)	(14,374)	(15,744)
Total	$ 8,110	$ 10,035

Benefit obligations in excess o

Benefit obligations in excess of plan assets (Details 2) - Pension Benefits - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 442,960	$ 475,337
Accumulated benefit obligation	442,960	475,337
Fair value of plan assets	$ 332,667	$ 354,363

Components of net periodic bene

Components of net periodic benefit cost (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Components of net periodic benefit cost (credit):
Service cost	$ 86	$ 129	$ 155
Interest cost	17,141	17,682	16,249
Expected return on assets	(22,254)	(21,218)	(19,917)
Amortization of prior service cost (credit)	36	71	71
Recognized net actuarial loss	7,016	4,869	7,173
Curtailment loss	258	0	0
Net periodic benefit cost (credit), including amount capitalized	2,283	1,533	3,731
Less amount capitalized	316	388	727
Net periodic benefit cost (credit)	1,967	1,145	3,004
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	8,257	77,238	(60,173)
Amortization of actuarial loss	(7,016)	(4,869)	(7,173)
Amortization of prior service (cost) credit	(294)	(71)	(71)
Total recognized in accumulated other comprehensive (income) loss	947	72,298	(67,417)
Total recognized in net periodic benefit cost (credit) and accumulated other comprehensive (income) loss	2,914	73,443	(64,413)
Other Postretirement Benefits
Components of net periodic benefit cost (credit):
Service cost	1,816	1,518	1,675
Interest cost	3,607	3,521	3,215
Expected return on assets	(4,795)	(4,617)	(4,343)
Amortization of prior service cost (credit)	(1,371)	(1,393)	(1,457)
Recognized net actuarial loss	1,960	649	1,814
Curtailment loss	0	0	0
Net periodic benefit cost (credit), including amount capitalized	1,217	(322)	904
Less amount capitalized	120	(21)	164
Net periodic benefit cost (credit)	1,097	(301)	740
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	(1,336)	15,114	(30,461)
Amortization of actuarial loss	(1,960)	(649)	(1,814)
Amortization of prior service (cost) credit	1,371	1,393	1,457
Total recognized in accumulated other comprehensive (income) loss	(1,925)	15,858	(30,818)
Total recognized in net periodic benefit cost (credit) and accumulated other comprehensive (income) loss	$ (828)	$ 15,557	$ (30,078)

Estimated net loss and prior se

Estimated net loss and prior service credit (Details 4) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, amortization of net gains (losses)	$ (6.2)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, amortization of net gains (losses)	(1.5)
Defined benefit plan, amortization of net prior service cost (credit)	$ (1.4)

Weighted average assumptions (D

Weighted average assumptions (Details 5)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Used to determine benefit obligation
Discount rate	4.00%	3.70%
Expected return on plan assets	6.75%	7.00%
Used to determine benefit cost
Discount rate	3.70%	4.53%
Expected return on plan assets	7.00%	7.00%
Other Postretirement Benefits
Used to determine benefit obligation
Discount rate	4.06%	3.74%
Expected return on plan assets	5.75%	6.00%
Rate of compensation increase	3.00%	3.00%
Used to determine benefit cost
Discount rate	3.74%	4.48%
Expected return on plan assets	6.00%	6.00%
Rate of compensation increase	3.00%	3.00%

Expected rate of return (Detail

Expected rate of return (Details 6)	12 Months Ended
	Dec. 31, 2015
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	40.00%
Defined benefit plan, target plan asset allocations range minimum	30.00%
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	70.00%
Defined benefit plan, target plan asset allocations range minimum	60.00%

Health care rate assumptions an

Health care rate assumptions and cost trend rate (Details 7) - Other Postretirement Benefits - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate assumed for next year (minimum)	4.00%	4.00%
Health care trend rate assumed for next year (maximum)	8.00%	7.00%
Health care cost trend rate - ultimate (minimum)	5.00%	5.00%
Health care cost trend rate - ultimate (maximum)	6.00%	6.00%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2,021	2,017
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	$ 203
Effect on total of service and interest cost components, one percentage point decrease	(169)
Effect on postretirement benefit obligations, one percentage point increase	4,006
Effect on postretirement benefit obligations, one percentage point decrease	$ (3,407)

Fair value (Details 8)

Fair value (Details 8)	Dec. 31, 2015
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 postre

Fair value - pension and postretirement (Details 9) - USD ($)	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	$ 332,667,000		$ 354,363,000		$ 334,844,000
Percentage investment in common stock of large-cap U.S. companies	19.00%		13.00%
Percentage investment in common stock of mid-cap U.S. companies	6.00%
Percentage investment in US Government securities			13.00%
Percentage investment in corporate bonds	16.00%		23.00%
Percentage investment in common stock of international companies	29.00%		33.00%
Percentage investment in cash equivalents	16.00%
Percentage investment in other investments	14.00%		18.00%
Estimated future employer contributions in next fiscal year	$ 0
Pension Benefits | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	8,379,000		$ 5,631,000
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	15,135,000		39,077,000
Pension Benefits | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,332,000		5,189,000
Pension Benefits | Collective and Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	217,968,000	[1]	209,852,000	[2]
Pension Benefits | Corporate debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	62,145,000		59,471,000
Pension Benefits | Municipal bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	11,680,000		10,462,000
Pension Benefits | U.S. Government securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	12,111,000		21,850,000
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	329,750,000		351,532,000
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	15,135,000		39,077,000
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	2,332,000		5,189,000
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	154,400,000	[1]	132,403,000	[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	5,288,000		15,001,000
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	177,155,000		191,670,000
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	8,379,000		5,631,000
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	63,568,000	[1]	77,449,000	[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	62,145,000		59,471,000
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	11,680,000		10,462,000
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	6,823,000		6,849,000
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	152,595,000		159,862,000
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	$ 82,593,000		$ 87,586,000		$ 84,543,000
Percentage investment in common stock of large-cap U.S. companies	19.00%		54.00%
Percentage investment in US Government securities	22.00%		11.00%
Percentage investment in corporate bonds	36.00%		10.00%
Percentage investment in other investments	13.00%		15.00%
Percentage investment in mortgage backed securities	10.00%		10.00%
Estimated future employer contributions in next fiscal year	$ 800,000
Other Postretirement Benefits | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	3,261,000		$ 2,097,000
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	2,274,000		2,614,000
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	9,000		25,000
Other Postretirement Benefits | Insurance investment contract
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	77,044,000	[3]	82,846,000	[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	82,588,000		87,582,000
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	2,283,000		2,639,000
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	2,274,000		2,614,000
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	9,000		25,000
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	80,305,000		84,943,000
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	3,261,000		2,097,000
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	77,044,000	[3]	82,846,000	[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 19 percent in common stock of large-cap U.S. companies, 6 percent in common stock of mid-cap U.S. companies, 16 percent in corporate bonds, 29 percent in common stock of international companies, 16 percent in cash equivalents and 14 percent in other investments.
[2]	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.
[3]	The insurance contract invests approximately 19 percent in common stock of large-cap U.S. companies, 22 percent in U.S. Government securities, 10 percent in mortgage-backed securities, 36 percent in corporate bonds and 13 percent in other investments.
[4]	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.

Estimated future benefit paymen

Estimated future benefit payments and subsidies (Details 10) $ in Thousands	Dec. 31, 2015USD ($)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments, next twelve months	$ 5,234
Prescription drug subsidy receipts, next twelve months	197
Expected future benefit payments, year two	5,351
Prescription drug subsidy receipts, year two	191
Expected future benefit payments, year three	5,420
Prescription drug subsidy receipts, year three	183
Expected future benefit payments, year four	5,441
Prescription drug subsidy receipts, Year Four	175
Expected future benefit payments, year five	5,331
Prescription drug subsidy receipts, year five	168
Expected future benefit payments, five fiscal years thereafter	27,261
Prescription drug subsidy receipts, after year five	688
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments, next twelve months	24,223
Expected future benefit payments, year two	24,680
Expected future benefit payments, year three	24,980
Expected future benefit payments, year four	25,323
Expected future benefit payments, year five	25,700
Expected future benefit payments, five fiscal years thereafter	$ 133,029

Nonqualified defined benefit pl

Nonqualified defined benefit plan (Details 11) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Investments in nonqualified benefit plans	$ 105.2	$ 101.4
Supplemental employee retirement plan, defined benefit [Member]
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Net periodic benefit cost	7.1	6.6	$ 7.3
Projected benefit obligation	110.8	115.6
Accumulated benefit obligation	$ 104.6	$ 108.2
Discount rate to determine benefit obligation	3.77%	3.51%
Rate of compensation increase to determine benefit obligation	4.00%	4.00%
Discount rate to determine net periodic benefit cost	3.51%	4.32%
Rate of compensation increase to determine net periodic benefit cost	4.00%	4.00%
Expected future benefit payments, next twelve months	$ 6.5
Expected future benefit payments, year two	6.7
Expected future benefit payments, year three	7.1
Expected future benefit payments, year four	7.3
Expected future benefit payments, year five	7.8
Expected future benefit payments, five fiscal years thereafter	$ 37.7

Defined contribution plans (Det

Defined contribution plans (Details 12) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Nonqualified Defined Contribution Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, cost recognized	$ 207,000	$ 104,000	$ 25,000
Defined Contribution Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, cost recognized	$ 36,800,000	$ 34,400,000	$ 33,200,000

Employee Benefit Plans Investme

Employee Benefit Plans Investments in nonqualified plans (Details 13) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Nonqualified Defined Benefit and Contribution Plan Investments [Line Items]
Investments in nonqualified benefit plans	$ 105.2	$ 101.4
Equity securities [Member]
Nonqualified Defined Benefit and Contribution Plan Investments [Line Items]
Investments in nonqualified benefit plans	54.2	54.9
Life insurance carried on plan participants [Member]
Nonqualified Defined Benefit and Contribution Plan Investments [Line Items]
Investments in nonqualified benefit plans	34.3	32.8
Other investments [Member]
Nonqualified Defined Benefit and Contribution Plan Investments [Line Items]
Investments in nonqualified benefit plans	$ 16.7	$ 13.7

Multiemployer plans (Details 14

Multiemployer plans (Details 14) - USD ($) $ in Thousands		3 Months Ended		12 Months Ended
		Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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%
Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions				$ 39,112	$ 42,817	$ 39,260
Edison Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				936,061,681
Multiemployer plan number				1
Multiemployer plans, certified zone status				Green	Green
Multiemployer plans, certified zone status, date				Dec. 31, 2015	Dec. 31, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				No
Multiemployer plan, period contributions				$ 5,517	$ 9,061	6,358
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date				Dec. 31, 2017
IBEW Local No. 82 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				316,127,268
Multiemployer plan number				1
Multiemployer plans, certified zone status				Red	Red
Multiemployer plans, certified zone status, date				Jun. 30, 2015	Jun. 30, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 2,252	$ 1,392	1,284
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date	[1]			Nov. 29, 2015
IBEW Local No. 246 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				346,582,842
Multiemployer plan number				1
Multiemployer plans, certified zone status				Yellow	Yellow
Multiemployer plans, certified zone status, date				May 31, 2015	May 31, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 433	$ 694	1,848
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date				Oct. 31, 2017
IBEW Local No. 357 Pension Plan A [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				886,023,284
Multiemployer plan number				1
Multiemployer plans, certified zone status				Green	Green
Multiemployer plans, funding improvement plan and rehabilitation plan				No
Multiemployer plan, period contributions				$ 1,896	$ 3,575	2,348
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date				May 31, 2018
IBEW Local 648 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				316,134,845
Multiemployer plan number				1
Multiemployer plans, certified zone status				Red	Red
Multiemployer plans, certified zone status, date				Feb. 28, 2015	Feb. 28, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 745	$ 1,110	1,489
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date				Sep. 2, 2018
Idaho Plumbers and Pipefitters Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				826,010,346
Multiemployer plan number				1
Multiemployer plans, certified zone status				Green	Green
Multiemployer plans, certified zone status, date				May 31, 2015	May 31, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				No
Multiemployer plan, period contributions				$ 1,169	$ 1,125	1,121
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date				Sep. 30, 2016
Local Union 212 IBEW Pension Trust Fund [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				316,127,280
Multiemployer plan number				1
Multiemployer plans, certified zone status				Yellow	Yellow
Multiemployer plans, certified zone status, date				Apr. 30, 2015	Apr. 30, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 937	$ 568	531
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date				Jun. 5, 2016
National Automatic Sprinkler Industry Pension Fund [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				526,054,620
Multiemployer plan number				1
Multiemployer plans, certified zone status				Red	Red
Multiemployer plans, certified zone status, date				Dec. 31, 2015	Dec. 31, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 677	$ 608	583
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date, first				Mar. 31, 2016
Multiemployer Plans, Collective-Bargaining Arrangement, Expiration Date, Last				Jul. 31, 2018
National Electrical Benefit Fund [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				530,181,657
Multiemployer plan number				1
Multiemployer plans, certified zone status				Green	Green
Multiemployer plans, funding improvement plan and rehabilitation plan				No
Multiemployer plan, period contributions				$ 5,271	$ 6,476	5,883
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date, first	[1]			Jun. 30, 2015
Multiemployer Plans, Collective-Bargaining Arrangement, Expiration Date, Last				Nov. 30, 2019
Pension Trust Fund for Operating Engineers [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				946,090,764
Multiemployer plan number				1
Multiemployer plans, certified zone status				Red	Red
Multiemployer plans, certified zone status, date				Dec. 31, 2015	Dec. 31, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 1,997	$ 1,445	1,510
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date, first	[1]			Jun. 15, 2015
Multiemployer Plans, Collective-Bargaining Arrangement, Expiration Date, Last				Jun. 30, 2016
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	[2]			836,011,320
Multiemployer plan number				1
Multiemployer plans, certified zone status				Red	Red
Multiemployer plans, certified zone status, date				Dec. 31, 2015	Dec. 31, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 0	$ 68	76
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date	[1]			Oct. 31, 2005
Multiemployer plan, withdrawal obligation			$ 14,000	$ 16,400	$ 14,000
Operating Engineers Local 800 and WY Contractors Association Pension Plan for WY [Member] | Withdrawal from Multiemployer Defined Benefit Plan [Member]
Multiemployer Plans [Line Items]
Loss contingency, loss in period		$ 2,400	$ 14,000
Sheet Metal Workers Pension Plan of Southern CA, AZ, and NV [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				956,052,257
Multiemployer plan number				1
Multiemployer plans, certified zone status				Red	Red
Multiemployer plans, certified zone status, date				Dec. 31, 2015	Dec. 31, 2014
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 714	$ 676	512
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date				Jun. 30, 2016
Southwest Marine Pension Trust [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number				956,123,404
Multiemployer plan number				1
Multiemployer plans, certified zone status				Red	Red
Multiemployer plans, funding improvement plan and rehabilitation plan				Implemented
Multiemployer plan, period contributions				$ 26	$ 31	42
Multiemployer plans, surcharge				No
Multiemployer plans, collective-bargaining arrangement, expiration date, first	[1]			Jan. 31, 2014
Multiemployer Plans, Collective-Bargaining Arrangement, Expiration Date, Last				Jan. 31, 2019
Multiemployer Plan, Individually Insignificant Multiemployer Plans [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions				$ 17,478	$ 15,988	$ 15,675
[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 postretirem

Multiemployer other postretirement and defined contribution plans (Details 15) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Multiemployer Plans, Defined Contribution [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions	$ 19.5	$ 22	$ 20.6
Multiemployer Plans, Postretirement Benefit [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions	$ 31.4	$ 34.6	$ 37.1

Jointly owned facilities (Detai

Jointly owned facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Big Stone Station:
Jointly owned facilities [Line Items]
Utility plant in service	$ 157,761	$ 64,283
Less accumulated depreciation	48,242	43,043
Utility plant in services net	109,519	21,240
Coyote Station:
Jointly owned facilities [Line Items]
Utility plant in service	140,895	138,810
Less accumulated depreciation	94,755	94,443
Utility plant in services net	46,140	44,367
Wygen III:
Jointly owned facilities [Line Items]
Utility plant in service	65,023	65,597
Less accumulated depreciation	6,788	5,928
Utility plant in services net	$ 58,235	$ 59,669

Regulatory matters (Details)

Regulatory matters (Details) - USD ($)

Feb. 08, 2016

Jan. 25, 2016

Jan. 05, 2016

Jan. 01, 2016

Dec. 01, 2015

Nov. 30, 2015

Nov. 25, 2015

Nov. 02, 2015

Oct. 26, 2015

Oct. 21, 2015

Oct. 05, 2015

Sep. 30, 2015

Jun. 30, 2015

Jun. 25, 2015

Mar. 31, 2015

OPUC [Member]

Regulatory matters [Line Items]

Rate increase requested

$ 3,600,000

Percent above current rates requested

5.10%

Settlement agreement

$ 600,000

Settlement agreement, percentage

0.80%

MTPSC [Member]

Regulatory matters [Line Items]

Rate increase requested

$ 11,800,000

Percent above current rates requested

21.10%

Amount of requested interim increase in annual rates

$ 11,000,000

SDPUC-Electric [Member]

Regulatory matters [Line Items]

Rate increase requested

$ 2,700,000

Percent above current rates requested

19.20%

SDPUC-Natural Gas [Member]

Regulatory matters [Line Items]

Rate increase requested

$ 1,500,000

Percent above current rates requested

3.10%

MISO [Member]

Regulatory matters [Line Items]

Revenue requirement

$ 3,800,000

MNPUC [Member]

Regulatory matters [Line Items]

Rate increase requested

$ 1,600,000

Percent above current rates requested

6.40%

Interim rate increase (decrease), amount

$ 1,500,000

Interim rate increase (decrease), percentage

6.40%

NDPSC [Member]

Regulatory matters [Line Items]

Rate increase requested

$ 25,300,000

Incremental increase to current rates

$ 20,000,000

NDPSC-Renewable Rider [Member]

Regulatory matters [Line Items]

Rate increase requested

$ 15,400,000

NDPSC-Electric Rider [Member]

Regulatory matters [Line Items]

Rate increase requested

9,900,000

Incremental increase to current rates

$ 4,600,000

NDPSC-Transmission Adjustment [Member]

Regulatory matters [Line Items]

Cost adjustment

$ 6,800,000

WUTC [Member]

Regulatory matters [Line Items]

Rate increase requested

$ 10,500,000

Percent above current rates requested

4.20%

Subsequent Event [Member] | MTPSC [Member]

Regulatory matters [Line Items]

Settlement agreement

$ 3,000,000

Settlement agreement increase subsequent year

$ 4,400,000

Subsequent Event [Member] | SDPUC-Electric [Member]

Regulatory matters [Line Items]

Interim rate increase (decrease), amount

$ 2,700,000

Subsequent Event [Member] | SDPUC-Natural Gas [Member]

Regulatory matters [Line Items]

Interim rate increase (decrease), amount

$ 1,500,000

Subsequent Event [Member] | NDPSC-Renewable Rider [Member]

Regulatory matters [Line Items]

Interim rate increase (decrease), amount

$ 15,100,000

Return on equity, percentage

10.50%

Subsequent Event [Member] | NDPSC-Electric Rider [Member]

Regulatory matters [Line Items]

Settlement agreement

$ 9,700,000

Incremental increase to current rates

$ 4,400,000

Return on equity, percentage

10.50%

Llitigation (Details)

Llitigation (Details) - USD ($)	Dec. 31, 2015	Mar. 12, 2015	Dec. 31, 2014	Aug. 31, 2011	Oct. 31, 2010
Loss Contingencies [Line Items]
Potential liabilities related to litigation and environmental matters	$ 19,500,000		$ 27,600,000
Natural gas gathering operations [Member]
Loss Contingencies [Line Items]
Arbitration award					$ 26,600,000
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
Litigation Related To Construction Services [Member]
Loss Contingencies [Line Items]
Damage Repair Estimate		$ 21,000,000

Enviromental matters (Details 2

Enviromental matters (Details 2) - USD ($)	Oct. 12, 2015	Dec. 31, 2015
Portland Harbor site [Member]
Site Contingency [Line Items]
Environmental matters investigative costs		$ 70,000,000
Coos County Oregon [Member]
Site Contingency [Line Items]
Site contingency, loss exposure not accrued, best estimate	$ 160,000
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		12,900,000
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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Leases, Annual minimum lease payments due [Abstract]
2,016	$ 52.3
2,017	42.7
2,018	35.5
2,019	26.4
2,020	15.9
Thereafter	76.9
Rent expense
Rent expense	$ 65.1	$ 48.5	$ 39.7

Purchase commitments (Details 4

Purchase commitments (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Term of unrecorded unconditional purchase obligation	one to 45 years
Purchase commitments due
2,016	$ 443.7
2,017	228
2,018	138.9
2,019	112.9
2,020	90.4
Thereafter	853.9
Amounts purchased under various commitments	$ 861.4	$ 925.2	$ 860.5

Guarantees (Details 5)

Guarantees (Details 5)	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
Guarantor obligations, maximum exposure, undiscounted	$ 128,600,000
Fixed maximum amounts guaranteed by year 2016	33,100,000
Fixed maximum amounts guaranteed by year 2017	35,000,000
Fixed maximum amounts guaranteed by year 2018	600,000
Fixed maximum amounts guaranteed by year 2019	54,900,000
Expires on a specified number of days after the receipt of written notice	1,000,000
Fixed maximum amounts guaranteed by year no maturity date	4,000,000
Amount outstanding under guarantees	0
Letters of credit	57,300,000
Outstanding letters of credit	4,100,000
Amount of surety bonds outstanding	$ 530,000,000

Variable interest entities (Det

Variable interest entities (Details 6) - USD ($)	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 01, 2014
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
Term loan for project debt financing	75,000,000
Facility limit, maximum borrowing capacity		$ 75,000,000		$ 50,000,000
Fuel contract [Member]
Variable Interest Entities [Line Items]
Variable interest entity, reporting entity involvement, maximum loss exposure, amount	40,100,000
Centennial Energy Holdings, Inc [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Percent of credit agreement guaranteed		50.00%
WBI Holdings [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Cumulative capital contributions, net of distributions	230,400,000
Noncontrolling interest | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Cumulative capital contributions, net of distributions	163,600,000
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	851,000		$ 21,376,000
Accounts receivable [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	7,693,000		2,759,000
Inventories [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	13,176,000		5,311,000
Other current assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	6,215,000		4,019,000
Total current assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	27,935,000		33,465,000
Net property, plant and equipment [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	425,123,000		398,984,000
Other [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	9,626,000		3,400,000
Total deferred charges and other assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	9,626,000		3,400,000
Total assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, assets	462,684,000		435,849,000
Short-term borrowings [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	45,500,000		0
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	5,250,000		3,000,000
Accounts payable [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	24,766,000		55,089,000
Taxes payable [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	1,391,000		648,000
Accrued compensation [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	938,000		727,000
Other accrued liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	4,953,000		899,000
Total current liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	82,798,000		60,363,000
Long-term debt [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	63,750,000		69,000,000
Total liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable interest entity, consolidated, carrying amount, liabilities	$ 146,548,000		$ 129,363,000

Quarterly Financial Informat117

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues	$ 1,062,485	$ 1,280,500	$ 986,215	$ 862,349	$ 1,048,288	$ 1,213,203	$ 952,564	$ 900,761		$ 4,191,549	$ 4,114,816	$ 3,920,171
Operating expenses	1,007,092	1,170,757	940,887	818,680	973,720	1,094,310	890,210	837,153		3,937,416	3,795,393	3,599,469
Operating income	55,393	109,743	45,328	43,669	74,568	118,893	62,354	63,608		254,133	319,423	320,702
Income from continuing operations	32,077	53,400	14,057	15,160	55,051	63,639	29,446	31,027		114,694	179,163	168,691
Income (loss) from discontinued operations, net of tax	6,261	(202,626)	(251,415)	(324,605)	27,700	38,482	23,881	25,112		$ (772,385)	$ 115,175	$ 109,879
Net income (loss) attributable to parent	$ 52,534	$ (139,448)	$ (229,604)	$ (305,917)	$ 84,256	$ 103,209	$ 54,106	$ 56,662
Earnings (loss) per common share - basic [Abstract]
Earnings before discontinued operations	$ 0.24	$ 0.32	$ 0.11	$ 0.10	$ 0.29	$ 0.33	$ 0.16	$ 0.17		$ 0.77	$ 0.95	$ 0.89
Discontinued operations, net of tax	0.03	(1.04)	(1.29)	(1.67)	0.14	0.20	0.12	0.13		(3.97)	0.60	0.58
Earnings (loss) per common share - basic	$ 0.27	$ (0.72)	$ (1.18)	$ (1.57)	$ 0.43	$ 0.53	$ 0.28	$ 0.30		$ (3.20)	$ 1.55	$ 1.47
Weighted average common shares outstanding - basic	195,266	195,151	194,805	194,479	194,136	193,949	192,060	189,820		194,928	192,507	188,855
Earnings per common share - diluted [Abstract]
Earnings before discontinued operations	$ 0.24	$ 0.32	$ 0.11	$ 0.10	$ 0.29	$ 0.33	$ 0.16	$ 0.16		$ 0.77	$ 0.95	$ 0.89
Discontinued operations, net of tax	0.03	(1.04)	(1.29)	(1.67)	0.14	0.20	0.12	0.14		(3.97)	0.60	0.58
Earnings (loss) per common share - diluted	$ 0.27	$ (0.72)	$ (1.18)	$ (1.57)	$ 0.43	$ 0.53	$ 0.28	$ 0.30		$ (3.20)	$ 1.55	$ 1.47
Weighted average common shares outstanding - diluted	195,324	195,169	194,838	194,566	194,219	194,300	192,659	190,432		194,986	192,587	189,693
Additional Information [Abstract]
Asset impairment charges		$ 14,100	$ 3,000						$ 14,500
Withdrawal from multiemployer defined benefit plan [Member] | Operating Engineers Local 800 and WY Contractors Association Pension Plan for WY [Member]
Additional Information [Abstract]
Multiemployer plan withdrawal obligation				$ 2,400	$ 14,000

Exploration and Production A118

Exploration and Production Activities (Unaudited) Purchase and sale agreements (Details)	12 Months Ended
	Dec. 31, 2014
Discontinued operations, disposed of by sale
Entity Sector Industry Classifications [Line Items]
Percent of oil and natural gas production sold	93.00%

Capitalized costs and AD&D rela

Capitalized costs and AD&D related to oil and natural gas producing activities (Details 2) - USD ($) $ in Thousands	Dec. 31, 2015	[1]	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Subject to amortization	$ 0		$ 3,205,036	$ 2,893,010
Not subject to amortization	0		132,141	124,869
Total capitalized costs	0		3,337,177	3,017,879
Less accumulated depreciation, depletion and amortization	0		1,752,566	1,562,116
Net capitalized costs	$ 0		$ 1,584,611	$ 1,455,763
[1]	Excludes assets held for sale.

Capital expenditures related to

Capital expenditures related to oil and natural gas producing activities (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	[1]	Dec. 31, 2014		Dec. 31, 2013
Acquisitions:
Proved properties	$ 0		$ 87,919	[2]	$ 1,817	[2]
Unproved properties	0		138,683	[2]	4,608	[2]
Exploration	0		16,879	[2]	26,975	[2]
Development	0		331,400	[2]	355,421	[2]
Total capital expenditures	$ 0		574,881	[2]	388,821	[2]
Net change in property, plant and equipment related to future liabilities for asset retirement obligations that are excluded			(9,000)		(10,700)
Proceeds from sale of oil and gas property and equipment			$ 246,600		$ 83,600
[1]	No wells were drilled in 2015.
[2]	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 of $(9.0) million and $(10.7) million for the years ended December 31, 2014 and 2013, respectively.

Exploration and Production A121

Exploration and Production Activities (Unaudited) Results of operations (Details 4) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations, net of tax	$ 6,261	$ (202,626)	$ (251,415)	$ (324,605)	$ 27,700	$ 38,482	$ 23,881	$ 25,112	$ (772,385)	$ 115,175	$ 109,879
Discontinued operations, disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations, net of tax									$ (772,385)	$ 111,998	$ 110,191

Estimated quantities of proved

Estimated quantities of proved reserves (Details 5)	12 Months Ended
	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls	Dec. 31, 2013MBoeMMcfMBbls
Proved developed and undeveloped reserves:
Balance at beginning of year, BOE | MBoe	91,940	80,695	80,486
Production, BOE | MBoe	(6,471)	(8,998)	(10,264)
Extensions and discoveries, BOE | MBoe	888	24,025	19,050
Improved recovery, BOE | MBoe	0	0	0
Purchases of proved reserves, BOE | MBoe	0	6,748	0
Sales revisions, BOE | MBoe	(57,097)	(14,796)	(7,987)
Revisions of previous estimate, BOE | MBoe	(15,939)	4,266	(590)
Balance at end of year, BOE | MBoe	13,321	91,940	80,695
Oil (MBbls)
Proved developed and undeveloped reserves:
Balance at beginning of year	43,918	41,019	33,453
Production	(3,286)	(4,919)	(4,815)
Extensions and discoveries	744	9,654	13,313
Improved recovery	0	0	0
Purchases of proved reserves	0	5,463	0
Sales of proved reserves	(16,474)	(4,945)	(1,286)
Revisions of previous estimates	(12,215)	(2,354)	354
Balance at end of year	12,687	43,918	41,019
NGL (MBbls)
Proved developed and undeveloped reserves:
Balance at beginning of year	7,187	6,602	7,153
Production	(393)	(609)	(781)
Extensions and discoveries	29	3,634	1,333
Improved recovery	0	0	0
Purchases of proved reserves	0	0	0
Sales of proved reserves	(6,864)	(3,109)	(25)
Revisions of previous estimates	252	669	(1,078)
Balance at end of year	211	7,187	6,602
Natural Gas (MMcf)
Proved developed and undeveloped reserves:
Balance at beginning of year | MMcf	245,011	198,445	239,278
Production | MMcf	(16,747)	(20,822)	(28,008)
Extensions and discoveries | MMcf	681	64,420	26,428
Improved recovery | MMcf	0	0	0
Purchases of proved reserves | MMcf	0	7,711	0
Sales of proved reserves | MMcf	(202,560)	(40,451)	(40,055)
Revisions of previous estimates | MMcf	(23,854)	35,708	802
Balance at end of year | MMcf	2,531	245,011	198,445

Proved reserves (Details 6)

Proved reserves (Details 6)	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls	Dec. 31, 2013MBoeMMcfMBbls	Dec. 31, 2012MBoeMMcfMBbls
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, energy | MBoe	11,865	65,086	66,140
Proved undeveloped reserves, energy | MBoe	1,456	26,854	14,555
Balance at end of year, energy | MBoe	13,321	91,940	80,695	80,486
Changes in proved and undeveloped reserves [Abstract]
Change in PUD reserve | MBoe	(25,400)
Oil (MBbls)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume	11,380	30,130	31,394
Proved undeveloped reserves, volume	1,307	13,788	9,625
Balance at end of year, volume	12,687	43,918	41,019	33,453
NGL (MBbls)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume	144	4,217	5,322
Proved undeveloped reserves, volume	67	2,970	1,280
Balance at end of year, volume	211	7,187	6,602	7,153
Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume | MMcf	2,033	184,437	176,546
Proved undeveloped reserves, volume | MMcf	498	60,574	21,899
Balance at end of year, volume | MMcf	2,531	245,011	198,445	239,278

Estimated discounted future cas

Estimated discounted future cash flows of total proved reserves (Details 7) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 5,185,500	$ 4,507,000
Future production costs	1,856,900	1,734,800
Future development costs	570,200	403,000
Future net cash flows before income taxes	2,758,400	2,369,200
Future income tax expense	686,100	545,200
Future net cash flows	2,072,300	1,824,000
10% annual discount for estimated timing of cash flows	997,400	810,000
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$ 1,074,900	$ 1,014,000	$ 883,400

Change in discounted future net

Change in discounted future net cash flows (Details 8) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Change in the standardized measure of discounted future net cash flows [Roll Forward]
Beginning of year	$ 1,014,000	$ 883,400
Net revenues from production	(368,900)	(398,000)
Net change in sales prices and production costs related to future production	86,300	162,200
Extensions and discoveries, net of future production-related costs	231,900	366,500
Improved recovery, net of future production-related costs	0	0
Purchases of proved reserves, net of future production-related costs	103,800	0
Sales of proved reserves	(219,300)	(37,800)
Changes in estimated future development costs	65,100	6,700
Development costs incurred during the current year	104,600	141,500
Accretion of discount	109,400	94,600
Net change in income taxes	(33,400)	(141,400)
Revisions of previous estimates	(16,300)	(55,800)
Other	(2,300)	(7,900)
Net change	60,900	130,600
End of year	$ 1,074,900	$ 1,014,000

Schedule I-Condensed Financial

Schedule I-Condensed Financial Information of Registrant (Details)	12 Months Ended
	Dec. 31, 2015
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. 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 $625.3 million at December 31, 2015 , with annual maturities of $100,000 in 2016 , $100,000 in 2017 , $100.1 million in 2018 , $44.6 million in 2019 and $480.4 million scheduled to mature in years after 2020 . For more information on debt, see Note 7 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 $110.6 million , $105.6 million and $77.6 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.

Condensed Statements of Income

Condensed Statements of Income and Comprehensive Income (Details 2) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Operating revenues	$ 1,062,485	$ 1,280,500	$ 986,215	$ 862,349	$ 1,048,288	$ 1,213,203	$ 952,564	$ 900,761	$ 4,191,549	$ 4,114,816	$ 3,920,171
Operating expenses	1,007,092	1,170,757	940,887	818,680	973,720	1,094,310	890,210	837,153	3,937,416	3,795,393	3,599,469
Operating income	$ 55,393	$ 109,743	$ 45,328	$ 43,669	$ 74,568	$ 118,893	$ 62,354	$ 63,608	254,133	319,423	320,702
Other income									19,232	9,873	6,086
Interest expense									93,068	86,906	83,803
Income before income taxes									180,297	242,390	242,985
Income taxes									65,603	63,227	74,294
Earnings (loss) on common stock									(623,120)	297,548	278,248
Comprehensive income (loss)									(617,480)	294,335	289,449
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Operating revenues									556,112	628,578	549,239
Operating expenses									478,198	547,820	473,917
Operating income									77,914	80,758	75,322
Other income									8,318	5,271	3,709
Interest expense									23,562	21,055	17,386
Income before income taxes									62,670	64,974	61,645
Income taxes									15,882	16,819	13,520
Equity in earnings of subsidiaries from continuing operations									103,162	134,903	120,929
Net income attributable to the Company from continuing operations									149,950	183,058	169,054
Equity in earnings (loss) of subsidiaries from discontinued operations									(772,385)	115,175	109,879
Dividends declared on preferred stocks									685	685	685
Earnings (loss) on common stock									(623,120)	297,548	278,248
Comprehensive income (loss)									$ (617,480)	$ 294,335	$ 289,449

Condensed Balance Sheets (Detai

Condensed Balance Sheets (Details 3) - USD ($) $ / shares in Units, $ in Thousands		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents		$ 84,591	$ 81,855	$ 57,340	$ 49,042
Receivables, net		590,105	599,186
Inventories		253,727	289,410
Deferred income taxes		32,849	32,012
Prepayments and other current assets		35,189	83,763
Total current assets		1,021,042	1,217,403
Investments		119,704	117,883
Property, plant and equipment		6,817,668	6,294,778
Less accumulated depreciation, depletion and amortization		2,506,571	2,386,113	2,284,169
Net property, plant and equipment		4,311,097	3,908,665	3,461,553
Deferred charges and other assets:
Goodwill	[1]	635,204	635,204	636,039
Other		366,485	322,943
Total deferred charges and other assets		1,175,765	2,588,457
Total assets		6,627,608	7,832,408	7,073,447
Current liabilities:
Long-term debt due within one year		243,789	268,552
Accounts payable		310,466	279,115
Taxes payable		45,775	39,955
Dividends payable		36,784	35,607
Accrued compensation		46,130	57,402
Other accrued liabilities		171,592	155,765
Total current liabilities		947,639	991,124
Long-term debt		1,627,443	1,825,278
Deferred credits and other liabilities:
Deferred income taxes		720,319	714,022
Other liabilities		811,659	756,759
Total deferred credits and other liabilities		1,531,978	1,766,222
Equity:
Preferred stocks		15,000	15,000
Authorized - 500,000,000 shares, $1.00 par value
Issued - 195,804,665 shares in 2015 and 194,754,812 shares in 2014		195,805	194,755
Other paid-in capital		1,230,119	1,207,188
Retained earnings		996,355	1,762,827
Accumulated other comprehensive loss		(37,148)	(42,103)
Treasury stock at cost - 538,921 shares		(3,626)	(3,626)
Total common stockholders' equity		2,381,505	3,119,041
Total stockholders' equity		2,396,505	3,134,041
Total liabilities and equity		$ 6,627,608	$ 7,832,408
Condensed Balance Sheet (Parenthetical)
Common stock, shares authorized		500,000,000	500,000,000
Common stock, par value		$ 1	$ 1
Common stock, shares issued		195,804,665	194,754,812
Treasury stock, shares		538,921	538,921
MDU Resources Group, Inc. [Member]
Current assets:
Cash and cash equivalents		$ 2,921	$ 6,120	$ 5,051	$ 3,596
Receivables, net		70,511	91,493
Accounts receivable from subsidiaries		33,129	32,691
Inventories		16,883	33,584
Deferred income taxes		2,846	547
Prepayments and other current assets		7,876	70,852
Total current assets		134,166	235,287
Investments		66,784	64,446
Investment in subsidiaries		1,722,351	2,590,283
Property, plant and equipment		2,378,994	1,984,956
Less accumulated depreciation, depletion and amortization		711,209	660,026
Net property, plant and equipment		1,667,785	1,324,930
Deferred charges and other assets:
Goodwill		4,812	4,812
Other		186,187	163,408
Total deferred charges and other assets		190,999	168,220
Total assets		3,782,085	4,383,166
Current liabilities:
Long-term debt due within one year		109	109
Accounts payable		54,275	48,088
Accounts payable to subsidiaries		6,622	30,863
Taxes payable		10,995	10,583
Dividends payable		36,784	35,607
Accrued compensation		7,539	11,227
Other accrued liabilities		40,931	36,488
Total current liabilities		157,255	172,965
Long-term debt		625,155	508,164
Deferred credits and other liabilities:
Deferred income taxes		257,915	251,067
Other liabilities		345,255	316,929
Total deferred credits and other liabilities		603,170	567,996
Equity:
Preferred stocks		15,000	15,000
Authorized - 500,000,000 shares, $1.00 par value
Issued - 195,804,665 shares in 2015 and 194,754,812 shares in 2014		195,805	194,755
Other paid-in capital		1,230,119	1,207,188
Retained earnings		996,355	1,762,827
Accumulated other comprehensive loss		(37,148)	(42,103)
Treasury stock at cost - 538,921 shares		(3,626)	(3,626)
Total common stockholders' equity		2,381,505	3,119,041
Total stockholders' equity		2,396,505	3,134,041
Total liabilities and equity		$ 3,782,085	$ 4,383,166
Condensed Balance Sheet (Parenthetical)
Common stock, shares authorized		500,000,000	500,000,000
Common stock, par value		$ 1	$ 1
Common stock, shares issued		195,804,655	194,754,812
Treasury stock, shares		538,921	538,921
[1]	Balance is presented net of accumulated impairment of $12.3 million at the pipeline and midstream segment, which occurred in prior periods.

Condensed Statements of Cash Fl

Condensed Statements of Cash Flows (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 641,144	$ 603,667	$ 754,308
Capital expenditures	(625,375)	(608,028)	(531,332)
Net proceeds from sale or disposition of property and other	54,569	29,598	40,802
Investments	1,515	(1,041)	302
Net cash used in investing activities	(382,453)	(904,191)	(782,661)
Issuance of long-term debt	345,920	606,084	507,924
Repayment of long-term debt	(569,498)	(368,249)	(423,707)
Proceeds from issuance of common stock	21,898	150,060	14,554
Dividends paid	(142,835)	(136,712)	(98,405)
Excess tax benefit on stock-based compensation	0	4,729	0
Tax withholding on stock-based compensation	0	(5,564)	0
Net cash provided by financing activities	(255,730)	325,194	36,866
Increase (decrease) in cash and cash equivalents	2,736	24,515	8,298
Cash and cash equivalents - beginning of year	81,855	57,340	49,042
Cash and cash equivalents - end of year	84,591	81,855	57,340
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	255,273	208,208	188,259
Capital expenditures	(349,985)	(223,251)	(211,013)
Net proceeds from sale or disposition of property and other	3,268	1,552	20,624
Investments in and advances to subsidiaries	(7,000)	(134,451)	(1,016)
Advances from subsidiaries	100,000	64,500	10,000
Investments	5	(794)	613
Net cash used in investing activities	(253,712)	(292,444)	(180,792)
Issuance of long-term debt	224,185	148,959	77,924
Repayment of long-term debt	(108,008)	(76,432)	(85)
Proceeds from issuance of common stock	21,898	150,060	14,554
Dividends paid	(142,835)	(136,712)	(98,405)
Excess tax benefit on stock-based compensation	0	3,326	0
Tax withholding on stock-based compensation	0	(3,896)	0
Net cash provided by financing activities	(4,760)	85,305	(6,012)
Increase (decrease) in cash and cash equivalents	(3,199)	1,069	1,455
Cash and cash equivalents - beginning of year	6,120	5,051	3,596
Cash and cash equivalents - end of year	$ 2,921	$ 6,120	$ 5,051

Notes to Condensed Financial St

Notes to Condensed Financial Statements (Details 5) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
2,016	$ 243,800,000
2,017	51,000,000
2,018	175,200,000
2,019	119,700,000
Mature in years after 2020	1,260,500,000
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Long-term debt	625,300,000
2,016	100,000
2,017	100,000
2,018	100,100,000
2,019	44,600,000
Mature in years after 2020	480,400,000
Cash dividends paid to parent company by consolidated subsidiaries	$ 110,600,000	$ 105,600,000	$ 77,600,000

Schedule II - Consolidated Valu

Schedule II - Consolidated Valuation and Qualifying Accounts (Details)	12 Months Ended
	Dec. 31, 2015
Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts	Consolidated Valuation and Qualifying Accounts For the years ended December 31, 2015 , 2014 and 2013 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: 2015 $ 9,511 $ 11,343 $ 1,012 $ 12,031 $ 9,835 2014 10,085 8,548 1,335 10,457 9,511 2013 10,818 5,725 1,395 7,853 10,085 * 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.

Schedule II - Consolidated V132

Schedule II - Consolidated Valuation and Qualifying Accounts (Details 2) - Allowance for Doubtful Accounts [Member] - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allowance for doubtful accounts:
Balance, beginning of period		$ 9,511	$ 10,085	$ 10,818
Charged to Costs and Expenses		11,343	8,548	5,725
Other	[1]	1,012	1,335	1,395
Deductions	[2]	12,031	10,457	7,853
Balance, end of period		$ 9,835	$ 9,511	$ 10,085
[1]	Recoveries.
[2]	Uncollectible accounts written off.