10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
	THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2013
	OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
	THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____________ to ______________

Commission file number 1-3480

MDU Resources Group, Inc.

(Exact name of registrant as specified in its charter)

Delaware	41-0423660
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1200 West Century Avenue

P.O. Box 5650

Bismarck, North Dakota 58506-5650

(Address of principal executive offices)

(Zip Code)

(701) 530-1000

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, par value $1.00	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Preferred Stock, par value $100

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý.

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

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

State the aggregate market value of the voting common stock held by nonaffiliates of the registrant as of June 30, 2013: $4,892,599,006.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 14, 2014: 189,370,016 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's 2014 Proxy Statement are incorporated by reference in Part III, Items 10, 11, 12, 13 and 14 of this Report.

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Contents

Part I
Forward-Looking Statements	8
Items 1 and 2 Business and Properties
General	8
Electric	9
Natural Gas Distribution	13
Pipeline and Energy Services	14
Exploration and Production	16
Construction Materials and Contracting	19
Construction Services	22
Item 1A Risk Factors	23
Item 1B Unresolved Staff Comments	29
Item 3 Legal Proceedings	29
Item 4 Mine Safety Disclosures	29
Part II
Item 5 Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6 Selected Financial Data	31
Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations	35
Item 7A Quantitative and Qualitative Disclosures About Market Risk	57
Item 8 Financial Statements and Supplementary Data	59
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	118
Item 9A Controls and Procedures	118
Item 9B Other Information	119
Part III
Item 10 Directors, Executive Officers and Corporate Governance	119
Item 11 Executive Compensation	119
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
Item 13 Certain Relationships and Related Transactions, and Director Independence	120
Item 14 Principal Accountant Fees and Services	120
Part IV
Item 15 Exhibits and Financial Statement Schedules	121
Signatures	130
Exhibits

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Definitions

The following abbreviations and acronyms used in this Form 10-K are defined below:

Abbreviation or Acronym

AFUDC	Allowance for funds used during construction
Army Corps	U.S. Army Corps of Engineers
ASC	FASB Accounting Standards Codification
BART	Best available retrofit technology
Bbl	Barrel
Bcf	Billion cubic feet
Bicent	Bicent Power LLC
Big Stone Station	475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
Black Hills Power	Black Hills Power, Inc.
BLM	Bureau of Land Management
BOE	One barrel of oil equivalent - determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas
BOPD	Barrels of oil per day
Brazilian Transmission Lines	Company's investment in the company owning ECTE, ENTE and ERTE (ownership interests in ENTE and ERTE were sold in the fourth quarter of 2010 and portions of the ownership interest in ECTE were sold in the third quarters of 2013 and 2012 and the fourth quarters of 2011 and 2010)
Btu	British thermal unit
Calumet	Calumet Specialty Products Partners, L.P.
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CCU	Cane Creek Unit
CEM	Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
Centennial	Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital	Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial Resources	Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
Clean Air Act	Federal Clean Air Act
Clean Water Act	Federal Clean Water Act
Colorado State District Court	Colorado Thirteenth Judicial District Court, Yuma County
Company	MDU Resources Group, Inc.
Coyote Creek	Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station	427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
Dakota Prairie Refinery	20,000-barrel-per-day diesel topping plant being built by Dakota Prairie Refining in southwestern North Dakota
Dakota Prairie Refining	Dakota Prairie Refining, LLC, a limited liability company jointly owned by WBI Energy and Calumet
dk	Decatherm
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
EBITDA	Earnings before interest, taxes, depreciation and amortization

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ECTE	Empresa Catarinense de Transmissão de Energia S.A. (2.5 percent ownership interest at December 31, 2013, 2.5, 2.5, 2.5 and 14.99 percent ownership interests were sold in the third quarters of 2013 and 2012 and the fourth quarters of 2011 and 2010, respectively)
EIN	Employer Identification Number
ENTE	Empresa Norte de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)
EPA	U.S. Environmental Protection Agency
ERISA	Employee Retirement Income Security Act of 1974
ERTE	Empresa Regional de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)
ESA	Endangered Species Act
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fidelity	Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings
FIP	Funding improvement plan
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
Great Plains	Great Plains Natural Gas Co., a public utility division of the Company
GVTC	Generation Verification Test Capacity
IBEW	International Brotherhood of Electrical Workers
ICWU	International Chemical Workers Union
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
IPUC	Idaho Public Utilities Commission
Item 8	Financial Statements and Supplementary Data
JTL	JTL Group, Inc., an indirect wholly owned subsidiary of Knife River
Knife River	Knife River Corporation, a direct wholly owned subsidiary of Centennial
Knife River - Northwest	Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River
K-Plan	Company's 401(k) Retirement Plan
kW	Kilowatts
kWh	Kilowatt-hour
LPP	Lea Power Partners, LLC, a former indirect wholly owned subsidiary of Centennial Resources (member interests were sold in October 2006)
LWG	Lower Willamette Group
MBbls	Thousands of barrels
MBOE	Thousands of BOE
Mcf	Thousand cubic feet
MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations
Mdk	Thousand decatherms
MDU Brasil	MDU Brasil Ltda., an indirect wholly owned subsidiary of Centennial Resources
MDU Construction Services	MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial
MDU Energy Capital	MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
MISO	Midcontinent Independent System Operator, Inc.
MMBOE	Millions of BOE
MMBtu	Million Btu

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MMcf	Million cubic feet
MMdk	Million decatherms
MNPUC	Minnesota Public Utilities Commission
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
Montana DEQ	Montana Department of Environmental Quality
Montana First Judicial District Court	Montana First Judicial District Court, Lewis and Clark County
Montana Seventeenth Judicial District Court	Montana Seventeenth Judicial District Court, Phillips County
MPPAA	Multiemployer Pension Plan Amendments Act of 1980
MTPSC	Montana Public Service Commission
MW	Megawatt
NDPSC	North Dakota Public Service Commission
NEPA	National Environmental Policy Act
New York Supreme Court	Supreme Court of the State of New York, County of New York
NGL	Natural gas liquids
NSPS	New Source Performance Standards
Oil	Includes crude oil and condensate
Omimex	Omimex Canada, Ltd.
OPUC	Oregon Public Utility Commission
Oregon DEQ	Oregon State Department of Environmental Quality
PCBs	Polychlorinated biphenyls
PDP	Proved developed producing
Prairielands	Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
Proxy Statement	Company's 2014 Proxy Statement
PRP	Potentially Responsible Party
psi	Pounds per square inch
PUD	Proved undeveloped
RCRA	Resource Conservation and Recovery Act
ROD	Record of Decision
RP	Rehabilitation plan
Ryder Scott	Ryder Scott Company, L.P.
SDPUC	South Dakota Public Utilities Commission
SEC	U.S. Securities and Exchange Commission
SEC Defined Prices	The average price of oil and natural gas during the applicable 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions
Securities Act	Securities Act of 1933, as amended
Securities Act Industry Guide 7	Description of Property by Issuers Engaged or to be Engaged in Significant Mining Operations
Sheridan System	A separate electric system owned by Montana-Dakota
SMCRA	Surface Mining Control and Reclamation Act
SourceGas	SourceGas Distribution LLC
Stock Purchase Plan	Company's Dividend Reinvestment and Direct Stock Purchase Plan
UA	United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada
VIE	Variable interest entity

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WBI Energy	WBI Energy, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Energy Midstream	WBI Energy Midstream, LLC, an indirect wholly owned subsidiary of WBI Holdings (previously Bitter Creek Pipelines, LLC, name changed effective July 1, 2012)
WBI Energy Transmission	WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings (previously Williston Basin Interstate Pipeline Company, name changed effective July 1, 2012)
WBI Holdings	WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
Westmoreland	Westmoreland Coal Company
WUTC	Washington Utilities and Transportation Commission
Wygen III	100-MW coal-fired electric generating facility near Gillette, Wyoming (25 percent ownership)
WYPSC	Wyoming Public Service Commission
ZRC	Zonal resource credit - a MW of demand equivalent assigned to generators by MISO for meeting system reliability requirements

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Part I

Forward-Looking Statements

This Form 10-K contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - MD&A - Prospective Information.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties. Nonetheless, the Company's expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

Items 1 and 2. Business and Properties

General

The Company is a diversified natural resource company, which was incorporated under the laws of the state of Delaware in 1924. Its principal executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.

Montana-Dakota, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. Cascade distributes natural gas in Oregon and Washington. Intermountain distributes natural gas in Idaho. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added services.

The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings (comprised of the pipeline and energy services and the exploration and production segments), Knife River (construction materials and contracting segment), MDU Construction Services (construction services segment), Centennial Resources and Centennial Capital (both reflected in the Other category).

The Company's investment in ECTE is reflected in the Other category. For additional information, see Item 8 - Note 4.

As of December 31, 2013, the Company had 9,133 employees with 157 employed at MDU Resources Group, Inc., 1,010 at Montana-Dakota, 34 at Great Plains, 302 at Cascade, 219 at Intermountain, 583 at WBI Holdings, 3,071 at Knife River and 3,757 at MDU Construction Services. The number of employees at certain Company operations fluctuates during the year depending upon the number and size of construction projects. The Company considers its relations with employees to be satisfactory.

The following information regarding the number of employees represented by labor contracts is as of December 31, 2013.

At Montana-Dakota and WBI Energy Transmission, 350 and 77 employees, respectively, are represented by the IBEW. Labor contracts with such employees are in effect through April 30, 2015, and March 31, 2014, for Montana-Dakota and WBI Energy Transmission, respectively.

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At Cascade, 173 employees are represented by the ICWU. The labor contract with the field operations group is effective through April 1, 2015.

At Intermountain, 116 employees are represented by the UA. Labor contracts with such employees are in effect through September 30, 2016.

Knife River operates under 43 labor contracts that represent approximately 520 of its construction materials employees. Knife River is in negotiations on 7 of its labor contracts.

MDU Construction Services has 176 labor contracts representing the majority of its employees. The majority of the labor contracts contain provisions that prohibit work stoppages or strikes and provide for binding arbitration dispute resolution in the event of an extended disagreement.

The Company's principal properties, which are of varying ages and are of different construction types, are generally in good condition, are well maintained and are generally suitable and adequate for the purposes for which they are used.

The financial results and data applicable to each of the Company's business segments, as well as their financing requirements, are set forth in Item 7 - MD&A and Item 8 - Note 15 and Supplementary Financial Information.

The operations of the Company and certain of its subsidiaries are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations and state hazard communication standards. The Company believes that it is in substantial compliance with these regulations, except as to what may be ultimately determined with regard to items discussed in Environmental matters in Item 8 - Note 19. There are no pending CERCLA actions for any of the Company's properties, other than the Portland, Oregon, Harbor Superfund Site and the Bremerton Gasworks Superfund Site.

The Company produces GHG emissions primarily from its fossil fuel electric generating facilities, as well as from natural gas pipeline and storage systems, operations of equipment and fleet vehicles, and oil and natural gas exploration and development activities. GHG emissions also result from customer use of natural gas for heating and other uses. As interest in reductions in GHG emissions has grown, the Company has developed renewable generation with lower or no GHG emissions. Governmental legislative and regulatory initiatives regarding environmental and energy policy are continuously evolving and could negatively impact the Company's operations and financial results. Until legislation and regulation are finalized, the impact of these measures cannot be accurately predicted. The Company will continue to monitor legislative and regulatory activity related to environmental and energy policy initiatives. Disclosure regarding specific environmental matters applicable to each of the Company's businesses is set forth under each business description later. In addition, for a discussion of the Company's risks related to environmental laws and regulations, see Item 1A - Risk Factors.

This annual report on Form 10-K, the Company's quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge through the Company's Web site as soon as reasonably practicable after the Company has electronically filed such reports with, or furnished such reports to, the SEC. The Company's Web site address is www.mdu.com. The information available on the Company's Web site is not part of this annual report on Form 10-K.

Electric

GeneralMontana-Dakota provides electric service at retail, serving more than 134,000 residential, commercial, industrial and municipal customers in 177 communities and adjacent rural areas as of December 31, 2013. The principal properties owned by Montana-Dakota for use in its electric operations include interests in 10 electric generating facilities and three small portable diesel generators, as further described under System Supply, System Demand and Competition, approximately 3,100 and 4,700 miles of transmission and distribution lines, respectively, and 52 transmission and 269 distribution substations. Montana-Dakota has obtained and holds, or is in the process of renewing, valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises. At December 31, 2013, Montana-Dakota's net electric plant investment was $812.9 million.

The percentage of Montana-Dakota's 2013 retail electric utility operating revenues by jurisdiction is as follows: North Dakota - 62 percent; Montana - 22 percent; Wyoming - 10 percent; and South Dakota - 6 percent. Retail electric rates, service,

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accounting and certain security issuances are subject to regulation by the NDPSC, MTPSC, SDPUC and WYPSC. The interstate transmission and wholesale electric power operations of Montana-Dakota also are subject to regulation by the FERC under provisions of the Federal Power Act, as are interconnections with other utilities and power generators, the issuance of securities, accounting and other matters.

Through MISO, Montana-Dakota has access to wholesale energy, ancillary services and capacity markets for its integrated system. MISO is a regional transmission organization responsible for operational control of the transmission systems of its members. MISO provides security center operations, tariff administration and operates day-ahead and real-time energy markets, ancillary services and capacity markets. As a member of MISO, Montana-Dakota's generation is sold into the MISO energy market and its energy needs are purchased from that market.

System Supply, System Demand and CompetitionThrough an interconnected electric system, Montana-Dakota serves markets in portions of western North Dakota, including Bismarck, Mandan, Dickinson, Williston and Watford City; eastern Montana, including Sidney, Glendive and Miles City; and northern South Dakota, including Mobridge. The maximum electric peak demand experienced to date attributable to Montana-Dakota's sales to retail customers on the interconnected system was 573,587 kW in July 2012. Montana-Dakota's latest forecast for its interconnected system indicates that its annual peak will continue to occur during the summer and the sales growth rate through 2018 will approximate 5 percent annually. The interconnected system consists of nine electric generating facilities and three small portable diesel generators, which have an aggregate nameplate rating attributable to Montana-Dakota's interest of 488,905 kW and total net ZRCs of 452.5 in 2013. ZRCs are a MW of demand equivalent measure and are allocated to individual generators to meet supply obligations within MISO. For 2013, Montana-Dakota's total ZRCs, including its firm purchase power contracts, were 583.5. Montana-Dakota's peak demand supply obligation, including firm purchase power contracts, within MISO was 508.3 ZRCs for 2013. Montana-Dakota's four principal generating stations are steam-turbine generating units using coal for fuel. The nameplate rating for Montana-Dakota's ownership interest in these four stations (including interests in the Big Stone Station and the Coyote Station) is 327,758 kW. Two combustion turbine peaking stations, two wind electric generating facilities, a heat recovery electric generating facility and three small portable diesel generators supply the balance of Montana-Dakota's interconnected system electric generating capability.

Montana-Dakota has a contract for capacity of 115 MW for the period June 1, 2013 to May 31, 2014, and 120 MW for the period June 1, 2014 to May 31, 2015. On October 25, 2013, Montana-Dakota entered into a power purchase agreement with Thunder Spirit Wind, LLC, a subsidiary of Wind Works Power Corp., for approximately 107 MW of installed capacity of wind turbine generators to be located in southwest North Dakota for a 25-year period effective on the commercial operation date of the facility. The project is expected to begin commercial operation in the fourth quarter of 2015. The generation will interconnect at Montana-Dakota's substation near Hettinger, North Dakota. Energy also will be purchased as needed, or if more economical, from the MISO market. In 2013, Montana-Dakota purchased approximately 29 percent of its net kWh needs for its interconnected system through the MISO market.

Montana-Dakota is constructing an 88-MW simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $77 million and a projected in-service date in the third quarter 2014. The capacity is necessary to meet the requirements of Montana-Dakota's integrated electric system customers and will be a partial replacement for third-party contract capacity expiring in 2015. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from the NDPSC for construction and operation of the natural gas turbine. A Certificate of Site Compatibility was issued for the turbine by the NDPSC on December 21, 2012.

Through the Sheridan System, Montana-Dakota serves Sheridan, Wyoming, and neighboring communities. The maximum peak demand experienced to date attributable to Montana-Dakota sales to retail customers on that system was approximately 61,501 kW in July 2012. Montana-Dakota has a power supply contract with Black Hills Power to purchase up to 49,000 kW of capacity annually through December 31, 2016. Wygen III serves a portion of the needs of its Sheridan-area customers.

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The following table sets forth details applicable to the Company's electric generating stations:

Generating Station	Type	Nameplate Rating (kW)	2013 ZRCs	(a)	2013 Net Generation (kWh in thousands)
Interconnected System:
North Dakota:
Coyote (b)	Steam	103,647	101.7		666,431
Heskett	Steam	86,000	85.4		444,867
Glen Ullin	Heat Recovery	7,500	4.3		38,053
Cedar Hills	Wind	19,500	4.5		54,805
Diesel Units	Oil	5,475	5.6		6
South Dakota:
Big Stone (b)	Steam	94,111	101.3		623,380
Montana:
Lewis & Clark	Steam	44,000	52.1		298,969
Glendive	Combustion Turbine	75,522	72.9		1,782
Miles City	Combustion Turbine	23,150	19.5		—
Diamond Willow	Wind	30,000	5.2		93,175
		488,905	452.5		2,221,468
Sheridan System:
Wyoming:
Wygen III (b)	Steam	28,000	N/A		208,533
		516,905	452.5		2,430,001
(a)  Interconnected system only. MISO requires generators to obtain their summer capability through the GVTC. The GVTC is then converted to ZRCs by applying each generator's forced outage factor against its GVTC. Wind generator's ZRCs are calculated based on a wind capacity study performed annually by MISO. ZRCs are used to meet supply obligations within MISO. (b)  Reflects Montana-Dakota's ownership interest.

Virtually all of the current fuel requirements of the Coyote, Heskett and Lewis & Clark stations are met with coal supplied by subsidiaries of Westmoreland under contracts that expire in May 2016, April 2016 and December 2017, respectively. The Coyote Station coal supply agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station or 30,000 tons per week, whichever may be the greater quantity at contracted pricing. The Heskett and Lewis & Clark coal supply agreements provide for the purchase of coal necessary to supply the coal requirements of these stations at contracted pricing. Montana-Dakota estimates the Heskett and Lewis & Clark coal requirement to be in the range of 450,000 to 550,000 tons and 250,000 to 350,000 tons per contract year, respectively.

Montana-Dakota has a contract with Coyote Creek for coal supply to the Coyote Station beginning May 2016 until December 2040. Montana-Dakota estimates the Coyote Station coal supply agreement to be approximately 2.5 million tons per contract year. For more information, see Item 8 - Note 19.

Montana-Dakota has coal supply agreements, which meet a portion of the Big Stone Station's fuel requirements, for the purchase of 1.0 million tons in 2014, 1.0 million tons in 2015 and 500,000 tons in 2016 from Peabody Coalsales, LLC, and 500,000 tons in 2014 from Westmoreland at contracted pricing. The remainder of the Big Stone Station fuel requirements will be secured through separate future contracts.

Montana-Dakota has a coal supply agreement with Wyodak Resources Development Corp., which provides for the purchase of coal necessary to supply the coal requirements of Wygen III at contracted pricing through June 1, 2060. Montana-Dakota estimates the maximum annual coal consumption of the facility to be 585,000 tons.

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The average cost of coal purchased, including freight, at Montana-Dakota's electric generating stations (including the Big Stone, Coyote and Wygen III stations) was as follows:

Years ended December 31,	2013		2012		2011
Average cost of coal per MMBtu	$	1.73	$	1.69	$	1.62
Average cost of coal per ton	$	25.32	$	24.77	$	23.38

Montana-Dakota expects that it has secured adequate capacity available through existing baseload generating stations, renewable generation, turbine peaking stations, demand reduction programs and firm contracts to meet the peak customer demand requirements of its customers through mid-2016. Future capacity that is needed to replace contracts and meet system growth requirements is expected to be met by constructing new generation resources, or acquiring additional capacity through power purchase contracts or the MISO capacity auction. For additional information regarding potential power generation projects, see Item 7 - MD&A - Prospective Information - Electric and natural gas distribution.

Montana-Dakota has major interconnections with its neighboring utilities and considers these interconnections adequate for coordinated planning, emergency assistance, exchange of capacity and energy and power supply reliability.

Montana-Dakota is subject to competition in varying degrees, in certain areas, from rural electric cooperatives, on-site generators, co-generators and municipally owned systems. In addition, competition in varying degrees exists between electricity and alternative forms of energy such as natural gas.

Regulatory Matters and Revenues Subject to RefundIn North Dakota, Montana-Dakota reflects monthly increases or decreases in fuel and purchased power costs (including demand charges) and is deferring those electric fuel and purchased power costs that are greater or less than amounts presently being recovered through its existing rate schedules. In Montana, a monthly Fuel and Purchased Power Tracking Adjustment mechanism allows Montana-Dakota to reflect 90 percent of the increases or decreases in fuel and purchased power costs (including demand charges) and Montana-Dakota is deferring 90 percent of costs that are greater or less than amounts presently being recovered through its existing rate schedules. A fuel adjustment clause contained in South Dakota jurisdictional electric rate schedules allows Montana-Dakota to reflect monthly increases or decreases in fuel and purchased power costs (excluding demand charges). In Wyoming, an annual Electric Power Supply Cost Adjustment mechanism allows Montana-Dakota to reflect increases or decreases in purchased power costs (including demand charges but excluding increases or decreases from base coal price) related to power supply and Montana-Dakota is deferring costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within a period ranging from 14 to 25 months from the time such costs are paid. For additional information, see Item 8 - Note 6.

Environmental MattersMontana-Dakota's electric operations are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations; and state hazard communication standards. Montana-Dakota believes it is in substantial compliance with these regulations.

Montana-Dakota's electric generating facilities have Title V Operating Permits, under the Clean Air Act, issued by the states in which they operate. Each of these permits has a five-year life. Near the expiration of these permits, renewal applications are submitted. Permits continue in force beyond the expiration date, provided the application for renewal is submitted by the required date, usually six months prior to expiration. The Title V Operating Permit renewal application for Coyote Station was submitted to the North Dakota Department of Health in March 2013 and the Title V Operating Permit renewal application for Big Stone Station was submitted to the South Dakota Department of Environment and Natural Resources in November 2013.

State water discharge permits issued under the requirements of the Clean Water Act are maintained for power production facilities on the Yellowstone and Missouri rivers. These permits also have five-year lives. Montana-Dakota renews these permits as necessary prior to expiration. Other permits held by these facilities may include an initial siting permit, which is typically a one-time, preconstruction permit issued by the state; state permits to dispose of combustion by-products; state authorizations to withdraw water for operations; and Army Corps permits to construct water intake structures. Montana-Dakota's Army Corps permits grant one-time permission to construct and do not require renewal. Other permit terms vary and the permits are renewed as necessary.

Montana-Dakota's electric operations are conditionally exempt small-quantity hazardous waste generators and subject only to minimum regulation under the RCRA. Montana-Dakota routinely handles PCBs from its electric operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required.

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Montana-Dakota incurred $32.7 million of environmental capital expenditures in 2013, largely for the installation of a BART air quality control system at the Big Stone Station. Capital expenditures are estimated to be $47 million, $46 million and $8 million in 2014, 2015 and 2016, respectively, to maintain environmental compliance as new emission controls are required, including the installation of a BART air quality control system, as discussed above. Projects for 2014 through 2016 will also include sulfur-dioxide, nitrogen oxide and mercury and non-mercury metals control equipment installation at electric generating stations. Montana-Dakota's capital and operational expenditures could also be affected in a variety of ways by future air and wastewater effluent discharge regulation, as well as potential new GHG legislation or regulation. In particular, such GHG legislation or regulation would likely increase capital expenditures and operational costs associated with GHG emissions compliance until carbon capture technology becomes economical, at which time capital expenditures may be necessary to incorporate such technology into existing or new generating facilities. Montana-Dakota expects that it will recover the operational and capital expenditures for GHG regulatory compliance in its rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations.

Natural Gas Distribution

GeneralThe Company's natural gas distribution operations consist of Montana-Dakota, Great Plains, Cascade and Intermountain, which sell natural gas at retail, serving over 876,000 residential, commercial and industrial customers in 334 communities and adjacent rural areas across eight states as of December 31, 2013, and provide natural gas transportation services to certain customers on their systems. These services are provided through distribution systems aggregating approximately 18,500 miles. The natural gas distribution operations have obtained and hold, or are in the process of renewing, valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. These operations intend to protect their service areas and seek renewal of all expiring franchises. At December 31, 2013, the natural gas distribution operations' net natural gas distribution plant investment was $1.1 billion.

The percentage of the natural gas distribution operations' 2013 natural gas utility operating sales revenues by jurisdiction is as follows: Idaho - 34 percent; Washington - 24 percent; North Dakota - 14 percent; Oregon - 8 percent; Montana - 8 percent; South Dakota - 6 percent; Minnesota - 4 percent; and Wyoming - 2 percent. The natural gas distribution operations are subject to regulation by the IPUC, MNPUC, MTPSC, NDPSC, OPUC, SDPUC, WUTC and WYPSC regarding retail rates, service, accounting and certain security issuances.

System Supply, System Demand and Competition The natural gas distribution operations serve retail natural gas markets, consisting principally of residential and firm commercial space and water heating users, in portions of Idaho, including Boise, Nampa, Twin Falls, Pocatello and Idaho Falls; western Minnesota, including Fergus Falls, Marshall and Crookston; eastern Montana, including Billings, Glendive and Miles City; North Dakota, including Bismarck, Mandan, Dickinson, Wahpeton, Williston, Watford City, Minot and Jamestown; central and eastern Oregon, including Bend, Pendleton, Ontario and Baker City; western and north-central South Dakota, including Rapid City, Pierre, Spearfish and Mobridge; western, southeastern and south-central Washington, including Bellingham, Bremerton, Longview, Aberdeen, Wenatchee/Moses Lake, Mount Vernon, Tri-Cities, Walla Walla and Yakima; and northern Wyoming, including Sheridan. These markets are highly seasonal and sales volumes depend largely on the weather, the effects of which are mitigated in certain jurisdictions by a weather normalization mechanism discussed in Regulatory Matters. In addition to the residential and commercial sales, the utilities transport natural gas for larger commercial and industrial customers who purchase their own supply of natural gas.

Competition in varying degrees exists between natural gas and other fuels and forms of energy. The natural gas distribution operations have established various natural gas transportation service rates for their distribution businesses to retain interruptible commercial and industrial loads. These services have enhanced the natural gas distribution operations' competitive posture with alternative fuels, although certain customers have bypassed the distribution systems by directly accessing transmission pipelines within close proximity. These bypasses did not have a material effect on results of operations.

The natural gas distribution operations and various distribution transportation customers obtain their system requirements directly from producers, processors and marketers. The Company's purchased natural gas is supplied by a portfolio of contracts specifying market-based pricing and is transported under transportation agreements with WBI Energy Transmission, Northwest Pipeline GP, Northern Natural Gas, Gas Transmission Northwest LLC, Northwestern Energy, Viking Gas Transmission Company and Ruby Pipeline LLC. The natural gas distribution operations have contracts for storage services to provide gas supply during the winter heating season and to meet peak day demand with various storage providers, including WBI Energy Transmission, Questar Pipeline Company, Northwest Pipeline GP and Northern Natural Gas. In addition, certain of the operations have entered into natural gas supply management agreements with various parties. Demand for natural gas, which is a widely traded commodity, has historically been sensitive to seasonal heating and industrial load requirements as well as

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changes in market price. The natural gas distribution operations believe that, based on current and projected domestic and regional supplies of natural gas and the pipeline transmission network currently available through their suppliers and pipeline service providers, supplies are adequate to meet their system natural gas requirements for the next decade.

Regulatory Matters The natural gas distribution operations' retail natural gas rate schedules contain clauses permitting adjustments in rates based upon changes in natural gas commodity, transportation and storage costs. Current tariffs allow for recovery or refunds of under- or over-recovered gas costs within a period ranging from 12 to 28 months.

Montana-Dakota's North Dakota and South Dakota natural gas tariffs contain weather normalization mechanisms applicable to firm customers that adjust the distribution delivery charge revenues to reflect weather fluctuations during the November 1 through May 1 billing periods.

On March 13, 2013, the OPUC approved an extension of Cascade's decoupling mechanism until December 31, 2015. Cascade also has an earnings sharing mechanism with respect to its Oregon jurisdictional operations as required by the OPUC.

For additional information on regulatory matters, see Item 8 - Note 18.

Environmental MattersThe natural gas distribution operations are subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. The natural gas distribution operations believe they are in substantial compliance with those regulations.

The Company's natural gas distribution operations are conditionally exempt small-quantity hazardous waste generators and subject only to minimum regulation under the RCRA. Certain locations of the natural gas distribution operations routinely handle PCBs from their natural gas operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required. Capital and operational expenditures for natural gas distribution operations could be affected in a variety of ways by potential new GHG legislation or regulation. In particular, such legislation or regulation would likely increase capital expenditures for energy efficiency and conservation programs and operational costs associated with GHG emissions compliance. Natural gas distribution operations expect to recover the operational and capital expenditures for GHG regulatory compliance in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations.

The natural gas distribution operations did not incur any material environmental expenditures in 2013. Except as to what may be ultimately determined with regard to the issues described later, the natural gas distribution operations do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2016.

Montana-Dakota has had an economic interest in four historic manufactured gas plants and Great Plains has had an economic interest in one historic manufactured gas plant within their service territories. Montana-Dakota is investigating a former manufactured gas plant in Montana. Montana-Dakota will seek recovery through the MTPSC in its natural gas rates charged to customers for any remediation costs incurred for this site. None of the remaining former manufactured gas plant sites of Montana-Dakota or Great Plains are being actively investigated. Cascade has had an economic interest in nine former manufactured gas plants within its service territory. Cascade has been involved in the investigation and remediation of three manufactured gas plants in Washington and Oregon. See Item 8 - Note 19 for a further discussion of these three manufactured gas plants. 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.

Pipeline and Energy Services

GeneralWBI Energy owns and operates both regulated and nonregulated businesses. The regulated business of this segment, WBI Energy Transmission, owns and operates approximately 3,800 miles of transmission, gathering and storage lines in Montana, North Dakota, South Dakota and Wyoming. Three underground storage fields in Montana and Wyoming provide storage services to local distribution companies, producers, natural gas marketers and others, and serve to enhance system deliverability. Its system is strategically located near five natural gas producing basins, making natural gas supplies available to its transportation and storage customers. The system has 13 interconnecting points with other pipeline facilities allowing for the receipt and/or delivery of natural gas to and from other regions of the country and from Canada. Under the Natural Gas Act, as amended, WBI Energy Transmission is subject to the jurisdiction of the FERC regarding certificate, rate, service and accounting matters, and at December 31, 2013, its net plant investment was $337.6 million.

The nonregulated business of this segment, owns and operates gathering facilities in Colorado, Montana and Wyoming. It also owns a 50 percent undivided interest in the Pronghorn assets located in western North Dakota that were acquired in 2012,

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which include a natural gas processing plant, both oil and gas gathering pipelines, an oil storage terminal and an oil pipeline. In total, facilities include approximately 1,600 miles of operated field gathering lines, some of which interconnect with WBI Energy's regulated pipeline system. The nonregulated business provides natural gas and oil gathering services, natural gas processing and a variety of other energy-related services, including cathodic protection, water hauling, contract compression operations, measurement services, and energy efficiency product sales and installation services to large end-users.

WBI Energy, in conjunction with Calumet, formed Dakota Prairie Refining, to develop, build and operate Dakota Prairie Refinery. Construction began on the facility in late March 2013 and, when complete, it will process Bakken crude oil into diesel, which will be marketed within the Bakken region. Total project costs are estimated to be approximately $350 million, with a projected in-service date in late 2014.

This segment also includes an energy services business which provides natural gas purchase and sales services to local distribution companies, producers, other marketers and a limited number of large end-users, primarily using natural gas produced by Fidelity. Certain of the services are provided based on contracts that call for a determinable quantity of natural gas. At December 31, 2013, it has commitments to deliver fixed and determinable amounts of natural gas under these contracts of 1.9 MMdk in 2014 and the commitments to deliver natural gas for years subsequent to 2014 are immaterial. The Company currently estimates that it can adequately meet the requirements of these contracts based upon the estimated natural gas production and reserves of Fidelity.

A majority of its pipeline and energy services business is transacted in the northern Great Plains and Rocky Mountain regions of the United States.

For information regarding natural gas gathering operations litigation, see Item 8 - Note 19.

System Supply, System Demand and Competition Natural gas supplies emanate from traditional and nontraditional production activities in the region and from off-system supply sources. While certain traditional regional supply sources are in various stages of decline, incremental supply from nontraditional sources have been developed which has helped support WBI Energy Transmission's supply needs. This includes new natural gas supply associated with the continued development of the Bakken area in Montana and North Dakota. The Powder River Basin also provides a nontraditional natural gas supply to the WBI Energy Transmission system. In addition, off-system supply sources are available through the Company's interconnections with other pipeline systems. WBI Energy Transmission expects to facilitate the movement of these supplies by making available its transportation and storage services. WBI Energy Transmission will continue to look for opportunities to increase transportation, gathering and storage services through system expansion and/or other pipeline interconnections or enhancements that could provide substantial future benefits.

WBI Energy Transmission's underground natural gas storage facilities have a certificated storage capacity of approximately 353 Bcf, including 193 Bcf of working gas capacity, 85 Bcf of cushion gas and 75 Bcf of native gas. These storage facilities enable customers to purchase natural gas at more uniform daily volumes throughout the year and meet winter peak requirements.

WBI Energy Transmission competes with several pipelines for its customers' transportation, storage and gathering business and at times may discount rates in an effort to retain market share. However, the strategic location of its system near five natural gas producing basins and the availability of underground storage and gathering services, along with interconnections with other pipelines, serve to enhance its competitive position.

Although certain of WBI Energy Transmission's firm customers, including its largest firm customer Montana-Dakota, serve relatively secure residential and commercial end-users, they generally all have some price-sensitive end-users that could switch to alternate fuels.

WBI Energy Transmission transports substantially all of Montana-Dakota's natural gas, primarily utilizing firm transportation agreements, which for 2013 represented 45 percent of WBI Energy Transmission's subscribed firm transportation contract demand. The majority of the firm transportation agreements with Montana-Dakota expire in June 2017. In addition, Montana-Dakota has a contract with WBI Energy Transmission to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements expiring in July 2015.

The nonregulated business competes with several midstream companies for existing customers, for the expansion of its systems and for the installation of new systems. Its strong position in the fields in which it operates, its focus on customer service and the variety of services it offers, along with its interconnection with various other pipelines, serve to enhance its competitive position.

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Regulatory Matters For additional information on regulatory matters, see Item 8 - Note 18.

Environmental MattersThe pipeline and energy services operations are generally subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. The Company believes it is in substantial compliance with those regulations.

Ongoing operations are subject to the Clean Air Act, the Clean Water Act, the NEPA and other state and federal regulations. Administration of many provisions of these laws has been delegated to the states where WBI Energy and its subsidiaries operate. Permit terms vary and all permits carry operational compliance conditions. Some permits require annual renewal, some have terms ranging from one to five years and others have no expiration date. Permits are renewed and modified, as necessary, based on defined permit expiration dates, operational demand and/or regulatory changes.

Detailed environmental assessments and/or environmental impact statements are included in the FERC's permitting processes for both the construction and abandonment of WBI Energy Transmission's natural gas transmission pipelines, compressor stations and storage facilities.

The pipeline and energy services operations did not incur any material environmental expenditures in 2013 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2016.

Exploration and Production

GeneralFidelity is involved in the acquisition, exploration, development and production of oil and natural gas resources. Fidelity continues to seek additional reserve and production growth opportunities through these activities. Future growth is dependent upon its success in these endeavors. Fidelity shares revenues and expenses from the development of specified properties in proportion to its ownership interests.

For information regarding exploration and production litigation, see Item 8 - Note 19.

Fidelity's business is focused primarily in two core regions: Rocky Mountain and Mid-Continent/Gulf States.

Rocky Mountain

Fidelity's Rocky Mountain region includes the following significant operating areas:

• Bakken areas - Oil targets in which Fidelity holds approximately 16,000 net acres in Mountrail County, North Dakota, approximately 50,000 net acres in Stark County, North Dakota, and approximately 59,000 net acres in Richland County, Montana.

• Cedar Creek Anticline - Primarily in eastern Montana, the Company has a long-held net profits interest in this oil play.

• Paradox Basin - The Company holds approximately 130,000 net acres located in Grand and San Juan Counties, Utah, targeting oil, including its recent acquisition of 35,000 net acres of leaseholds and has an option to earn another 20,000 acres.

• Big Horn Basin - These interests include approximately 21,000 net acres in Wyoming, targeting oil and NGL.

• Green River Basin - These properties were primarily natural gas targets in Wyoming and were sold at the end of 2013.

• Baker Field - Long-held natural gas properties in which Fidelity holds approximately 98,000 net acres in southeastern Montana and southwestern North Dakota.

• Bowdoin Field - Long-held natural gas properties in which Fidelity holds approximately 127,000 net acres in north-central Montana.

• Other - Includes other exploratory oil projects and various non-operated positions.

Mid-Continent/Gulf States

Fidelity's Mid-Continent/Gulf States region includes the following significant operating areas:

• South Texas - This area includes approximately 9,000 net acres in the Tabasco, Texan Gardens and Flores fields. This area has significant NGL content associated with the natural gas.

• East Texas - Fidelity holds approximately 9,000 net acres, primarily natural gas and associated NGL.

• Other - Includes various non-operated onshore interests, as well as offshore interests in the shallow waters off the coasts of Texas and Louisiana.

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Operating InformationAnnual net production by region for 2013 was as follows:

Region	Oil  (MBbls)	NGL  (MBbls)	Natural Gas  (MMcf)	Total (MBOE)	Percent of Total
Rocky Mountain	4,481	250	19,461	7,975	78	%
Mid-Continent/Gulf States	334	531	8,547	2,289	22
Total	4,815	781	28,008	10,264	100	%
Note: Bakken-Mountrail County represents 43% of total annual net oil production and is the only field that contains 15 percent or more of the Company's total proved reserves as of December 31, 2013.

Annual net production by region for 2012 was as follows:

Region	Oil  (MBbls)	NGL  (MBbls)	Natural Gas  (MMcf)	Total (MBOE)	Percent of Total
Rocky Mountain	3,295	249	23,180	7,408	74	%
Mid-Continent/Gulf States	399	579	10,034	2,650	26
Total	3,694	828	33,214	10,058	100	%
Note: Bakken-Mountrail County represents 47% of total annual net oil production and is the only field that contains 15 percent or more of the Company's total proved reserves as of December 31, 2012.

Annual net production by region for 2011 was as follows:

Region	Oil  (MBbls)	NGL  (MBbls)	Natural Gas  (MMcf)	Total (MBOE)	Percent of Total
Rocky Mountain	2,290	199	34,472	8,234	74	%
Mid-Continent/Gulf States	434	577	11,126	2,865	26
Total	2,724	776	45,598	11,099	100	%
Note: There are no fields that contain 15 percent or more of the Company's total proved reserves as of December 31, 2011.

Well and Acreage InformationGross and net productive well counts and gross and net developed and undeveloped acreage related to Fidelity's interests at December 31, 2013, were as follows:

	Gross	*	Net	**
Productive wells:
Oil	899		171
Natural gas	2,006		1,541
Total	2,905		1,712
Developed acreage (000's)	581		347
Undeveloped acreage set to expire in the years (000's):
2014	87		63
2015	130		81
2016	22		16
Thereafter	563		277
Total undeveloped acreage	802		437
* Reflects well or acreage in which an interest is owned.
** Reflects Fidelity's percentage of ownership.

In most cases, acreage set to expire can be held through drilling operations or the Company can exercise extension options.

Delivery Commitments At December 31, 2013, Fidelity has commitments to deliver fixed and determinable amounts of oil under contracts of 452,500 Bbls in 2014 and the commitments to deliver oil for years subsequent to 2014 are immaterial. Fidelity does not have any material delivery commitments to deliver fixed and determinable amounts of natural gas at December 31, 2013.

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Exploratory and Development WellsThe following table reflects activities related to Fidelity's oil and natural gas wells drilled and/or tested during 2013, 2012 and 2011:

	Net Exploratory			Net Development
	Productive	Dry Holes	Total	Productive	Dry Holes	Total	Total
2013	3	2	5	35	3	38	43
2012	24	3	27	39	1	40	67
2011	4	—	4	48	—	48	52

At December 31, 2013, there were 11 gross (5 net) wells in the process of drilling or under evaluation, all of which were development wells. These wells are not included in the previous table. Fidelity expects to complete the drilling and testing of these wells within the next 12 months.

The information in the preceding table should not be considered indicative of future performance nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.

CompetitionThe exploration and production industry is highly competitive. Fidelity competes with a substantial number of major and independent exploration and production companies in acquiring producing properties and new leases for future exploration and development, and in securing the equipment, services and expertise necessary to explore, develop and operate its properties.

Environmental MattersFidelity's operations are generally subject to federal, state and local environmental and operational laws and regulations. Fidelity believes it is in substantial compliance with these regulations.

The ongoing operations of Fidelity are subject to the Clean Air Act, the Clean Water Act, the NEPA, ESA and other state, federal and local regulations. Administration of many provisions of these laws has been delegated to the states where Fidelity operates. Permit terms vary and all permits carry operational compliance conditions. Some permits require annual renewal, some have terms ranging from one to five years and others have no expiration date. Permits are renewed and modified, as necessary, based on defined permit expiration dates, operational demand and/or regulatory changes.

Detailed environmental assessments and/or environmental impact statements under federal and state laws are required as part of the permitting process covering the conduct of drilling and production operations as well as in the abandonment and reclamation of facilities.

In connection with production operations, Fidelity has not incurred any material capital environmental expenditures in 2013 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2016.

Proved Reserve InformationEstimates of proved oil, NGL and natural gas 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. Other factors used in the proved reserve estimates are prices, market differentials, estimates of well operating and future development 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 proved 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. The technical person responsible for overseeing the preparation of the reserve estimates holds a bachelor of science degree in mathematics with a technical minor in petroleum engineering, has 26 years of experience in petroleum engineering and reserve estimation, and is a member of the Society of Petroleum Engineers. In addition, the Company engages an independent third party to audit its proved reserves. Ryder Scott reviewed the Company's proved reserve quantity estimates as of December 31, 2013. The technical person at Ryder Scott primarily responsible for overseeing the reserves audit is a Senior Vice President with over 30 years of experience in estimating and auditing reserves attributable to oil and gas properties, holds a bachelor of science degree in mechanical engineering, is a registered professional engineer, and is a member of multiple professional organizations.

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Fidelity's proved reserves by region at December 31, 2013, are as follows:

	Oil	NGL	Natural Gas	Total	Percent		PV-10 Value		*
Region	(MBbls)	(MBbls)	(MMcf)	(MBOE)	of Total		(in millions)
Rocky Mountain	38,788	2,442	128,124	62,584	78	%	$	1,159.3
Mid-Continent/Gulf States	2,231	4,160	70,321	18,111	22		175.7
Total proved reserves	41,019	6,602	198,445	80,695	100	%	1,335.0
Discounted future income taxes							321.0
Standardized measure of discounted future net cash flows relating to proved reserves							$	1,014.0
* Pre-tax PV-10 value is a non-GAAP financial measure that is derived from the most directly comparable GAAP financial measure which is the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows disclosed in Item 8 - Supplementary Financial Information, is presented after deducting discounted future income taxes, whereas the PV-10 value is presented before income taxes. Pre-tax PV-10 value is commonly used by the Company to evaluate properties that are acquired and sold and to assess the potential return on investment in the Company's oil and natural gas properties. The Company believes pre-tax PV-10 value is a useful supplemental disclosure to the standardized measure as the Company believes readers may utilize this value as a basis for comparison of the relative size and value of the Company's reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. However, pre-tax PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Neither the pre-tax PV-10 value nor the standardized measure of discounted future net cash flows purports to represent the fair value of the Company's oil and natural gas properties.

For additional information related to oil and natural gas interests, see Item 8 - Note 1 and Supplementary Financial Information.

Construction Materials and Contracting

GeneralKnife River operates construction materials and contracting businesses headquartered in Alaska, California, Hawaii, Idaho, Iowa, Minnesota, Montana, North Dakota, Oregon, Texas, Washington and Wyoming. These operations mine, process and sell construction aggregates (crushed stone, sand and gravel); produce and sell asphalt mix and supply ready-mixed concrete for use in most types of construction, including roads, freeways and bridges, as well as homes, schools, shopping centers, office buildings and industrial parks. Although not common to all locations, other products include the sale of cement, liquid asphalt for various commercial and roadway applications, various finished concrete products and other building materials and related contracting services.

For information regarding construction materials litigation, see Item 8 - Note 19.

The construction materials business had approximately $456 million in backlog at December 31, 2013, compared to $406 million at December 31, 2012. The Company anticipates that a significant amount of the current backlog will be completed during 2014.

CompetitionKnife River's construction materials products are marketed under highly competitive conditions. Price is the principal competitive force to which these products are subject, with service, quality, delivery time and proximity to the customer also being significant factors. The number and size of competitors varies in each of Knife River's principal market areas and product lines.

The demand for construction materials products is significantly influenced by the cyclical nature of the construction industry in general. In addition, construction materials activity in certain locations may be seasonal in nature due to the effects of weather. The key economic factors affecting product demand are changes in the level of local, state and federal governmental spending, general economic conditions within the market area that influence both the commercial and private sectors, and prevailing interest rates.

Knife River is not dependent on any single customer or group of customers for sales of its products and services, the loss of which would have a material adverse effect on its construction materials businesses.

Reserve Information Aggregate reserve estimates are calculated based on the best available data. This data is collected from drill holes and other subsurface investigations, as well as investigations of surface features such as mine high walls and other exposures of the aggregate reserves. Mine plans, production history and geologic data also are utilized to estimate reserve quantities. Most acquisitions are made of mature businesses with established reserves, as distinguished from exploratory-type properties.

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Estimates are based on analyses of the data described above by experienced internal mining engineers, operating personnel and geologists. Property setbacks and other regulatory restrictions and limitations are identified to determine the total area available for mining. Data described previously are used to calculate the thickness of aggregate materials to be recovered. Topography associated with alluvial sand and gravel deposits is typically flat and volumes of these materials are calculated by applying the thickness of the resource over the areas available for mining. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 1.5 tons per cubic yard in the ground is used for sand and gravel deposits.

Topography associated with the hard rock reserves is typically much more diverse. Therefore, using available data, a final topography map is created and computer software is utilized to compute the volumes between the existing and final topographies. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 2 tons per cubic yard in the ground is used for hard rock quarries.

Estimated reserves are probable reserves as defined in Securities Act Industry Guide 7. Remaining reserves are based on estimates of volumes that can be economically extracted and sold to meet current market and product applications. The reserve estimates include only salable tonnage and thus exclude waste materials that are generated in the crushing and processing phases of the operation. Approximately 1.0 billion tons of the 1.1 billion tons of aggregate reserves are permitted reserves. The remaining reserves are on properties that are expected to be permitted for mining under current regulatory requirements. The data used to calculate the remaining reserves may require revisions in the future to account for changes in customer requirements and unknown geological occurrences. The years remaining were calculated by dividing remaining reserves by the three-year average sales from 2011 through 2013. Actual useful lives of these reserves will be subject to, among other things, fluctuations in customer demand, customer specifications, geological conditions and changes in mining plans.

The following table sets forth details applicable to the Company's aggregate reserves under ownership or lease as of December 31, 2013, and sales for the years ended December 31, 2013, 2012 and 2011:

	Number of Sites (Crushed Stone)		Number of Sites (Sand & Gravel)		Tons Sold (000's)			Estimated Reserves (000's tons)	Lease Expiration	Reserve Life (years)
Production Area	owned	leased	owned	leased	2013	2012	2011
Anchorage, AK	—	—	1	—	1,074	110	137	18,880	N/A	43
Hawaii	—	6	—	—	1,672	1,678	1,527	57,333	2017-2064	35
Northern CA	—	—	9	1	1,525	1,203	1,552	45,570	2018	32
Southern CA	—	2	—	—	241	784	1,134	92,110	2035	Over 100
Portland, OR	1	3	5	3	3,343	2,698	3,106	231,734	2014-2055	76
Eugene, OR	3	4	4	1	825	847	884	168,392	2016-2046	Over 100
Central OR/WA/ID	1	2	5	4	1,045	1,131	851	123,613	2015-2077	Over 100
Southwest OR	5	4	11	5	1,465	1,613	1,604	96,768	2014-2053	62
Central MT	—	—	1	2	1,236	1,200	758	28,213	2017-2027	26
Northwest MT	—	—	7	2	1,242	1,011	1,370	65,993	2016-2020	55
Wyoming	—	—	1	1	983	428	461	11,571	2019	19
Central MN	—	1	37	24	1,578	1,714	1,520	73,429	2014-2028	46
Northern MN	2	—	16	5	349	195	355	26,782	2015-2017	89
ND/SD	—	—	3	19	1,862	1,711	1,727	30,899	2014-2031	17
Iowa	—	—	—	—	—	305	249	—	—	—
Texas	1	1	1	—	672	692	1,182	12,089	2022	14
Sales from other sources					5,601	5,965	6,319
					24,713	23,285	24,736	1,083,376

The 1.1 billion tons of estimated aggregate reserves at December 31, 2013, are comprised of 494 million tons that are owned and 589 million tons that are leased. Approximately 49 percent of the tons under lease have lease expiration dates of 20 years or more. The weighted average years remaining on all leases containing estimated probable aggregate reserves is approximately 28 years, including options for renewal that are at Knife River's discretion. Based on a three-year average of sales from 2011 through 2013 of leased reserves, the average time necessary to produce remaining aggregate reserves from such leases is approximately 68 years. Some sites have leases that expire prior to the exhaustion of the estimated reserves. The estimated reserve life assumes, based on Knife River's experience, that leases will be renewed to allow sufficient time to fully recover these reserves.

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The changes in Knife River's aggregate reserves for the years ended December 31 are as follows:

	2013		2012		2011
	(000's of tons)
Aggregate reserves:
Beginning of year	1,088,236		1,088,833		1,107,396
Acquisitions	22,682		950		1,200
Sales volumes*	(19,112	)	(17,320	)	(18,417	)
Other**	(8,430	)	15,773		(1,346	)
End of year	1,083,376		1,088,236		1,088,833
* Excludes sales from other sources.
** Includes property sales and revisions of previous estimates.

Environmental MattersKnife River's construction materials and contracting operations are subject to regulation customary for such operations, including federal, state and local environmental compliance and reclamation regulations. Except as to the issues described later, Knife River believes it is in substantial compliance with these regulations. Individual permits applicable to Knife River's various operations are managed largely by local operations, particularly as they relate to application, modification, renewal, compliance and reporting procedures.

Knife River's asphalt and ready-mixed concrete manufacturing plants and aggregate processing plants are subject to Clean Air Act and Clean Water Act requirements for controlling air emissions and water discharges. Some mining and construction activities also are subject to these laws. In most of the states where Knife River operates, these regulatory programs have been delegated to state and local regulatory authorities. Knife River's facilities also are subject to RCRA as it applies to the management of hazardous wastes and underground storage tank systems. These programs also have generally been delegated to the state and local authorities in the states where Knife River operates. Knife River's facilities must comply with requirements for managing wastes and underground storage tank systems.

Some Knife River activities are directly regulated by federal agencies. For example, certain in-water mining operations are subject to provisions of the Clean Water Act that are administered by the Army Corps. Knife River operates several such operations, including gravel bar skimming and dredging operations, and Knife River has the associated permits as required. The expiration dates of these permits vary, with five years generally being the longest term.

Knife River's operations also are occasionally subject to the ESA. For example, land use regulations often require environmental studies, including wildlife studies, before a permit may be granted for a new or expanded mining facility or an asphalt or concrete plant. If endangered species or their habitats are identified, ESA requirements for protection, mitigation or avoidance apply. Endangered species protection requirements are usually included as part of land use permit conditions. Typical conditions include avoidance, setbacks, restrictions on operations during certain times of the breeding or rearing season, and construction or purchase of mitigation habitat. Knife River's operations also are subject to state and federal cultural resources protection laws when new areas are disturbed for mining operations or processing plants. Land use permit applications generally require that areas proposed for mining or other surface disturbances be surveyed for cultural resources. If any are identified, they must be protected or managed in accordance with regulatory agency requirements.

The most comprehensive environmental permit requirements are usually associated with new mining operations, although requirements vary widely from state to state and even within states. In some areas, land use regulations and associated permitting requirements are minimal. However, some states and local jurisdictions have very demanding requirements for permitting new mines. Environmental impact reports are sometimes required before a mining permit application can even be considered for approval. These reports can take up to several years to complete. The report can include projected impacts of the proposed project on air and water quality, wildlife, noise levels, traffic, scenic vistas and other environmental factors. The reports generally include suggested actions to mitigate the projected adverse impacts.

Provisions for public hearings and public comments are usually included in land use permit application review procedures in the counties where Knife River operates. After taking into account environmental, mine plan and reclamation information provided by the permittee as well as comments from the public and other regulatory agencies, the local authority approves or denies the permit application. Denial is rare, but land use permits often include conditions that must be addressed by the permittee. Conditions may include property line setbacks, reclamation requirements, environmental monitoring and reporting, operating hour restrictions, financial guarantees for reclamation, and other requirements intended to protect the environment or address concerns submitted by the public or other regulatory agencies.

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Knife River has been successful in obtaining mining and other land use permit approvals so that sufficient permitted reserves are available to support its operations. For mining operations, this often requires considerable advanced planning to ensure sufficient time is available to complete the permitting process before the newly permitted aggregate reserve is needed to support Knife River's operations.

Knife River's Gascoyne surface coal mine last produced coal in 1995 but continues to be subject to reclamation requirements of the SMCRA, as well as the North Dakota Surface Mining Act. Portions of the Gascoyne Mine remain under reclamation bond until the 10-year revegetation liability period has expired. A portion of the original permit has been released from bond and additional areas are currently in the process of having the bond released. Knife River's intention is to request bond release as soon as it is deemed possible with all final bond release applications being filed by 2016.

Knife River did not incur any material environmental expenditures in 2013 and, except as to what may be ultimately determined with regard to the issues described later, Knife River does not expect to incur any material expenditures related to environmental compliance with current laws and regulations through 2016.

In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a commercial property site, acquired by Knife River - Northwest in 1999, and part of the Portland, Oregon, Harbor Superfund Site. For additional information, see Item 8 - Note 19.

Mine SafetyThe Dodd-Frank Act requires disclosure of certain mine safety information. For additional information, see Item 4 - Mine Safety Disclosures.

Construction Services

GeneralMDU Construction Services specializes in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment. These services are provided to utilities and large manufacturing, commercial, industrial, institutional and government customers.

Construction and maintenance crews are active year round. However, activity in certain locations may be seasonal in nature due to the effects of weather.

MDU Construction Services operates a fleet of owned and leased trucks and trailers, support vehicles and specialty construction equipment, such as backhoes, excavators, trenchers, generators, boring machines and cranes. In addition, as of December 31, 2013, MDU Construction Services owned or leased facilities in 16 states. This space is used for offices, equipment yards, warehousing, storage and vehicle shops.

MDU Construction Services' backlog is comprised of the uncompleted portion of services to be performed under job-specific contracts. The backlog at December 31, 2013, was approximately $459 million compared to $325 million at December 31, 2012. MDU Construction Services expects to complete a significant amount of this backlog during 2014. Due to the nature of its contractual arrangements, in many instances MDU Construction Services' customers are not committed to the specific volumes of services to be purchased under a contract, but rather MDU Construction Services is committed to perform these services if and to the extent requested by the customer. Therefore, there can be no assurance as to the customers' requirements during a particular period or that such estimates at any point in time are predictive of future revenues.

MDU Construction Services works with the National Electrical Contractors Association, the IBEW and other trade associations on hiring and recruiting a qualified workforce.

CompetitionMDU Construction Services operates in a highly competitive business environment. Most of MDU Construction Services' work is obtained on the basis of competitive bids or by negotiation of either cost-plus or fixed-price contracts. The workforce and equipment are highly mobile, providing greater flexibility in the size and location of MDU Construction Services' market area. Competition is based primarily on price and reputation for quality, safety and reliability. The size and location of the services provided, as well as the state of the economy, will be factors in the number of competitors that MDU Construction Services will encounter on any particular project. MDU Construction Services believes that the diversification of the services it provides, the markets it serves throughout the United States and the management of its workforce will enable it to effectively operate in this competitive environment.

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Utilities and independent contractors represent the largest customer base for this segment. Accordingly, utility and subcontract work accounts for a significant portion of the work performed by MDU Construction Services and the amount of construction contracts is dependent to a certain extent on the level and timing of maintenance and construction programs undertaken by customers. MDU Construction Services relies on repeat customers and strives to maintain successful long-term relationships with these customers.

Environmental Matters MDU Construction Services' operations are subject to regulation customary for the industry, including federal, state and local environmental compliance. MDU Construction Services believes it is in substantial compliance with these regulations.

The nature of MDU Construction Services' operations is such that few, if any, environmental permits are required. Operational convenience supports the use of petroleum storage tanks in several locations, which are permitted under state programs authorized by the EPA. MDU Construction Services has no ongoing remediation related to releases from petroleum storage tanks. MDU Construction Services' operations are conditionally exempt small-quantity waste generators, subject to minimal regulation under the RCRA. Federal permits for specific construction and maintenance jobs that may require these permits are typically obtained by the hiring entity, and not by MDU Construction Services.

MDU Construction Services did not incur any material environmental expenditures in 2013 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2016.

Item 1A. Risk Factors

The Company's business and financial results are subject to a number of risks and uncertainties, including those set forth below and in other documents that it files with the SEC. The factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

Economic Risks

The Company's exploration and production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, that are subject to various external influences that cannot be controlled.

These factors include: fluctuations in oil, NGL and natural gas production and prices; fluctuations in commodity price basis differentials; availability of economic supplies of natural gas; drilling successes in oil and natural gas operations; the timely receipt of necessary permits and approvals; the ability to contract for or to secure necessary drilling rig and service contracts and to retain employees to identify, drill for and develop reserves; the ability to acquire oil and natural gas properties; and other risks incidental to the development and operations of oil and natural gas wells, processing plants and pipeline systems. Volatility in oil, NGL and natural gas prices could negatively affect the results of operations, cash flows and asset values of the Company's exploration and production and pipeline and energy services businesses.

The regulatory approval, permitting, construction, startup and/or operation of power generation facilities and Dakota Prairie Refinery may involve unanticipated events or delays that could negatively impact the Company's business and its results of operations and cash flows.

The construction, startup and operation of power generation facilities and Dakota Prairie Refinery involve many risks, which may include: delays; breakdown or failure of equipment; inability to obtain required governmental permits and approvals; inability to complete financing; inability to negotiate acceptable equipment acquisition, construction, fuel and crude oil supply, off-take, transmission, transportation or other material agreements; changes in markets and market prices for power, crude oil and refined products; cost increases; as well as the risk of performance below expected levels of output or efficiency. Such unanticipated events could negatively impact the Company's business, its results of operations and cash flows.

Economic volatility affects the Company's operations, as well as the demand for its products and services and the value of its investments and investment returns including its pension and other postretirement benefit plans, and may have a negative impact on the Company's future revenues and cash flows.

The global demand for natural resources, interest rate changes, governmental budget constraints and the ongoing threat of terrorism can create volatility in the financial markets. Unfavorable economic conditions can negatively affect the level of public and private expenditures on projects and the timing of these projects which, in turn, can negatively affect the demand for

23

the Company's products and services, primarily at the Company's construction businesses. The level of demand for construction products and services could be adversely impacted by the economic conditions in the industries the Company serves, as well as in the economy in general. State and federal budget issues may negatively affect the funding available for infrastructure spending. This economic volatility could have a material adverse effect on the Company's results of operations, cash flows and asset values.

Changing market conditions could negatively affect the market value of assets held in the Company's pension and other postretirement benefit plans and may increase the amount and accelerate the timing of required funding contributions.

The Company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyond the Company's control. If the Company is unable to obtain economic financing in the future, the Company's ability to execute its business plans, make capital expenditures or pursue acquisitions that the Company may otherwise rely on for future growth could be impaired. As a result, the market value of the Company's common stock may be adversely affected. If the Company issues a substantial amount of common stock it could have a dilutive effect on its existing shareholders.

The Company relies on access to both short-term borrowings, including the issuance of commercial paper, and long-term capital markets as sources of liquidity for capital requirements not satisfied by its cash flow from operations. If the Company is not able to access capital at competitive rates, the ability to implement its business plans may be adversely affected. Market disruptions or a downgrade of the Company's credit ratings may increase the cost of borrowing or adversely affect its ability to access one or more financial markets. Such disruptions could include:

• A severe prolonged economic downturn

• The bankruptcy of unrelated industry leaders in the same line of business

• Deterioration in capital market conditions

• Turmoil in the financial services industry

• Volatility in commodity prices

• Terrorist attacks

• Cyber attacks

Economic turmoil, market disruptions and volatility in the securities trading markets, as well as other factors including changes in the Company's results of operations, financial position and prospects, may adversely affect the market price of the Company's common stock.

The Company currently has a shelf registration statement on file with the SEC, under which the Company may issue and sell any combination of common stock and debt securities. The issuance of a substantial amount of the Company's common stock, whether sold pursuant to the registration statement, issued in connection with an acquisition or otherwise issued, or the perception that such an issuance could occur, may adversely affect the market price of the Company's common stock.

The Company is exposed to credit risk and the risk of loss resulting from the nonpayment and/or nonperformance by the Company's customers and counterparties.

If the Company's customers or counterparties were to experience financial difficulties or file for bankruptcy, the Company could experience difficulty in collecting receivables. The nonpayment and/or nonperformance by the Company's customers and counterparties could have a negative impact on the Company's results of operations and cash flows.

The backlogs at the Company's construction materials and contracting and construction services businesses are subject to delay or cancellation and may not be realized.

Backlog consists of the uncompleted portion of services to be performed under job-specific contracts. Contracts are subject to delay, default or cancellation and the contracts in the Company's backlog are subject to changes in the scope of services to be provided as well as adjustments to the costs relating to the applicable contracts. Backlog may also be affected by project delays or cancellations resulting from weather conditions, external market factors and economic factors beyond the Company's control, including the current economic slowdown. Accordingly, there is no assurance that backlog will be realized.

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Actual quantities of recoverable oil, NGL and natural gas reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts. There is a risk that changes in estimates of proved reserve quantities or other factors including downward movements in prices, could result in additional future noncash write-downs of the Company's oil and natural gas properties.

The process of estimating oil, NGL and natural gas reserves is complex. Reserve estimates are based on assumptions relating to oil, NGL and natural gas pricing, drilling and operating expenses, capital expenditures, taxes, timing of operations, and the percentage of interest owned by the Company in the properties. The proved reserve estimates are prepared for each of the Company's properties by internal engineers assigned to an asset team by geographic area. The internal engineers analyze available geological, geophysical, engineering and economic data for each geographic area. The internal engineers make various assumptions regarding this data. The extent, quality and reliability of this data can vary. Although the Company has prepared its proved reserve estimates in accordance with guidelines established by the industry and the SEC, significant changes to the proved reserve estimates may occur based on actual results of production, drilling, costs and pricing.

The Company bases the estimated discounted future net cash flows from proved reserves on prices and current costs in accordance with SEC requirements. Actual future prices and costs may be significantly different. There is risk that lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in additional future noncash write-downs of the Company's oil and natural gas properties.

Environmental and Regulatory Risks

The Company's operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.

The Company is subject to environmental laws and regulations affecting many aspects of its present and future operations, including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, cause delays as a result of litigation and administrative proceedings, and create compliance, remediation, containment, monitoring and reporting obligations, particularly with regard to laws relating to electric generation operations and oil and natural gas development and processing. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Although the Company strives to comply with all applicable environmental laws and regulations, public and private entities, as well as private individuals, may seek injunctive relief or other remedies to enforce applicable environmental laws and regulations with which they have differing interpretations of the Company's legal or regulatory compliance. The Company cannot predict the outcome (financial or operational) of any related litigation or administrative proceedings that may arise.

Existing environmental laws and regulations may be revised and new laws and regulations seeking to protect the environment may be adopted or become applicable to the Company. These laws and regulations could require the Company to limit the use or output of certain facilities, restrict the use of certain fuels, install pollution controls, remediate environmental contamination, remove or reduce environmental hazards, or prevent or limit the development of resources. Revised or additional laws and regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on the Company's results of operations and cash flows.

The EPA has issued draft regulations that outline several possible approaches for coal combustion residuals management under the RCRA. One approach, designating coal ash as a hazardous waste, would significantly change the manner and increase the costs of managing coal ash at five plants that supply electricity to customers of Montana-Dakota. This designation also could significantly increase costs for Knife River, which beneficially uses fly ash as a cement replacement in ready-mixed concrete and road base applications.

In December 2011, the EPA finalized the Mercury and Air Toxics Standards rules that will require reductions in mercury and other air emissions from coal- and oil-fired electric utility steam generating units. Montana-Dakota evaluated the pollution control technologies needed at its electric generation resources to comply with this final rule and determined that additional particulate matter control is required to control non-mercury metal emissions at the Lewis & Clark Station near Sidney, Montana. On October 9, 2013, Montana-Dakota received an order from the NDPSC approving Montana-Dakota's request for advance determination of prudence to install a baghouse at Lewis & Clark Station. Controls must be installed by April 16, 2015, or April 16, 2016, if a one-year extension is granted for installation.

Hydraulic fracturing is an important common practice used by Fidelity that involves injecting water; sand; guar, a water thickening agent; and trace amounts of chemicals under pressure into rock formations to stimulate oil, NGL and natural gas

25

production. Fidelity is following state regulations for well drilling and completion, including regulations related to hydraulic fracturing and disposing of recovered fluids. Fracturing fluid constituents are reported on state or national websites. The EPA is developing a study to review the potential effects of hydraulic fracturing on underground sources of drinking water; the results of that study could impact future legislation or regulation. The BLM has released draft well stimulation regulations for hydraulic fracturing operations. If implemented, the BLM regulations would only affect Fidelity's operations on BLM-administered lands. If adopted as proposed, the BLM regulations, along with other legislative initiatives and regulatory studies, proceedings or initiatives at federal or state agencies that focus on the hydraulic fracturing process, could result in additional compliance, reporting and disclosure requirements. Future legislation or regulation could increase compliance and operating costs, as well as delay or inhibit the Company's ability to develop its oil, NGL and natural gas reserves.

On August 16, 2012, the EPA published a final NSPS rule for the oil and natural gas industry. The NSPS rule phases in over two years. The first phase was effective October 15, 2012, and primarily covers natural gas wells that are hydraulically fractured. Under the new rule, gas vapors or emissions from the natural gas wells must be captured or combusted utilizing a high efficiency device. Additional reporting requirements and control devices covering oil and natural gas production equipment will be phased in for certain new oil and gas facilities with a final effective date of January 1, 2015. This new rule's impacts on Fidelity, WBI Energy Transmission and WBI Energy Midstream are not expected to be material and are likely to include implementation of recordkeeping, reporting and testing requirements and the acquisition and installation of required equipment.

Initiatives to reduce GHG emissions could adversely impact the Company's operations.

Concern that GHG emissions are contributing to global climate change has led to international, federal and state legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions. On June 25, 2013, President Obama released his Climate Action Plan for the U.S. in which he stated his goal to reduce GHG emissions "in the range of 17 percent" below 2005 levels by 2020. The president issued a memorandum to the EPA on the same day, instructing the EPA to re-propose the GHG NSPS rule for new electric generation units. The EPA released the re-proposed rule on January 8, 2014, in the Federal Register, which takes the place of the rule proposed in 2012 for new electric generation units that the EPA did not finalize. This rule applies to new fossil fuel-fired electric generation units, including coal-fired units, natural gas-fired combined-cycle units and natural gas-fired simple cycle peaking units. The EPA's 1,100 pounds of carbon dioxide per MW hour emissions standard for coal-fired units does not allow for any new coal-fired electric generation to be constructed unless carbon dioxide is captured and sequestered. The EPA has not applied this new standard to existing fossil fuel-fired units or existing units that make modifications, therefore no impacts to Montana-Dakota's existing electric generating facilities are expected. However, it is not clear that the EPA will always exempt required future pollution control project modifications from GHG NSPS. If the EPA does not clearly exempt these projects, the Company's electric generation operations could be adversely impacted.

The president also directed the EPA to develop a GHG NSPS standard for existing fossil fuel-fired electric generation units by June 1, 2014, with finalization by June 1, 2015. The president did not specify a GHG standard or the format of the standard.

The primary GHG emitted from the Company's operations is carbon dioxide from combustion of fossil fuels at Montana-Dakota's electric generating facilities, particularly its coal-fired facilities. Approximately 70 percent of Montana-Dakota's owned generating capacity and more than 90 percent of the electricity it generates is from coal-fired facilities.

Montana-Dakota's existing electric generating facilities are expected to be subject to GHG laws or regulations within the next few years through a GHG NSPS for existing and modified units. Implementation of treaties, legislation or regulations to reduce GHG emissions could affect Montana-Dakota's electric utility operations by requiring expanded energy conservation efforts or increased development of renewable energy sources, as well as other mandates that could significantly increase capital expenditures and operating costs. If Montana-Dakota does not receive timely and full recovery of GHG emission compliance costs from its customers, then such costs could have an adverse impact on the results of its operations.

In addition to Montana-Dakota's electric generation operations, the GHG emissions from the Company's other operations are monitored, analyzed and reported as required in accordance with applicable laws and regulations. The Company monitors the development of GHG regulations and the potential for GHG regulations to impact all existing and future operations.

Due to the uncertain availability of technologies to control GHG emissions and the unknown obligations that potential GHG emission legislation or regulations may create, the Company cannot determine the potential financial impact on its operations.

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The Company is subject to government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party's ability to acquire the Company.

The Company is subject to regulation or governmental actions by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return and recovery of investment and cost, financing, industry rate structures, health care legislation, tax legislation and recovery of purchased power and purchased gas costs. These governmental regulations significantly influence the Company's operating environment and may affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on the Company's results of operations and cash flows. Approval from a number of federal and state regulatory agencies would need to be obtained by any potential acquirer of the Company. The approval process could be lengthy and the outcome uncertain.

Other Risks

Weather conditions can adversely affect the Company's operations, and revenues and cash flows.

The Company's results of operations can be affected by changes in the weather. Weather conditions influence the demand for electricity and natural gas, affect the price of energy commodities, affect the ability to perform services at the construction materials and contracting and construction services businesses and affect ongoing operation and maintenance and construction and drilling activities for the pipeline and energy services and exploration and production businesses. In addition, severe weather can be destructive, causing outages, reduced oil and natural gas production, and/or property damage, which could require additional costs to be incurred. As a result, adverse weather conditions could negatively affect the Company's results of operations, financial position and cash flows.

Competition is increasing in all of the Company's businesses.

All of the Company's businesses are subject to increased competition. Construction services' competition is based primarily on price and reputation for quality, safety and reliability. Construction materials products are marketed under highly competitive conditions and are subject to such competitive forces as price, service, delivery time and proximity to the customer. The electric utility and natural gas industries also are experiencing increased competitive pressures as a result of consumer demands, technological advances, volatility in natural gas prices and other factors. The pipeline and energy services business competes with several pipelines for access to natural gas supplies and gathering, transportation and storage business. The exploration and production business is subject to competition in the acquisition and development of oil and natural gas properties. The increase in competition could negatively affect the Company's results of operations, financial position and cash flows.

The Company could be subject to limitations on its ability to pay dividends.

The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on its common stock. Regulatory, contractual and legal limitations, as well as capital requirements and the Company's financial performance or cash flows, could limit the earnings of the Company's divisions and subsidiaries which, in turn, could restrict the Company's ability to pay dividends on its common stock and adversely affect the Company's stock price.

An increase in costs related to obligations under multiemployer pension plans could have a material negative effect on the Company's results of operations and cash flows.

Various operating subsidiaries of the Company participate in approximately 80 multiemployer pension plans for employees represented by certain unions. The Company is required to make contributions to these plans in amounts established under numerous collective bargaining agreements between the operating subsidiaries and those unions.

The Company may be obligated to increase its contributions to underfunded plans that are classified as being in endangered, seriously endangered or critical status as defined by the Pension Protection Act of 2006. Plans classified as being in one of these statuses are required to adopt RPs or FIPs to improve their funded status through increased contributions, reduced benefits or a combination of the two. Based on available information, the Company believes that approximately 45 percent of the multiemployer plans to which it contributes are currently in endangered, seriously endangered or critical status.

The Company may also be required to increase its contributions to multiemployer plans where the other participating employers in such plans withdraw from the plan and are not able to contribute an amount sufficient to fund the unfunded liabilities associated with their participants in the plans. The amount and timing of any increase in the Company's required

27

contributions to multiemployer pension plans may also depend upon one or more of the following factors including the outcome of collective bargaining, actions taken by trustees who manage the plans, actions taken by the plans' other participating employers, the industry for which contributions are made, future determinations that additional plans reach endangered, seriously endangered or critical status, government regulations and the actual return on assets held in the plans, among others. The Company may experience increased operating expenses as a result of the required contributions to multiemployer pension plans, which may have a material adverse effect on the Company's results of operations, financial position or cash flows.

In addition, pursuant to ERISA, as amended by MPPAA, the Company could incur a partial or complete withdrawal liability upon withdrawing from a plan, exiting a market in which it does business with a union workforce or upon termination of a plan to the extent these plans are underfunded.

The Company's operations may be negatively impacted by cyber attacks or acts of terrorism.

The Company operates in industries that require continual operation of sophisticated information technology systems and network infrastructure. While the Company has developed procedures and processes that are designed to protect these systems, they may be vulnerable to failures or unauthorized access due to hacking, viruses, acts of terrorism or other causes. If the technology systems were to fail or be breached and these systems were not recovered in a timely manner, the Company's operational systems and infrastructure, such as the Company's electric generation, transmission and distribution facilities and its oil and natural gas production, storage and pipeline systems, may be unable to fulfill critical business functions. Any such disruption could result in a decrease in the Company's revenues and/or significant remediation costs which could have a material adverse effect on the Company's results of operations, financial position and cash flows. Additionally, because generation, transmission systems and gas pipelines are part of an interconnected system, a disruption elsewhere in the system could negatively impact the Company's business.

The Company's business requires access to sensitive customer data in the ordinary course of business. Despite the Company's implementation of security measures, a failure or breach of a security system could compromise sensitive and confidential information and data. Such an event could result in negative publicity, remediation costs and possible legal claims and fines which could adversely affect the Company's financial results. The Company's third party service providers that perform critical business functions or have access to sensitive and confidential information and data may also be vulnerable to security breaches and other risks that could have an adverse effect on the Company.

Other factors that could impact the Company's businesses.

The following are other factors that should be considered for a better understanding of the financial condition of the Company. These other factors may impact the Company's financial results in future periods.

• Acquisition, disposal and impairments of assets or facilities

• Changes in operation, performance and construction of plant facilities or other assets

• Changes in present or prospective generation

• The ability to obtain adequate and timely cost recovery for the Company's regulated operations through regulatory proceedings

• The availability of economic expansion or development opportunities

• Population growth rates and demographic patterns

• Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services

• The cyclical nature of large construction projects at certain operations

• Changes in tax rates or policies

• Unanticipated project delays or changes in project costs, including related energy costs

• Unanticipated changes in operating expenses or capital expenditures

• Labor negotiations or disputes

• Inability of the various contract counterparties to meet their contractual obligations

• Changes in accounting principles and/or the application of such principles to the Company

• Changes in technology

• Changes in legal or regulatory proceedings

• The ability to effectively integrate the operations and the internal controls of acquired companies

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• The ability to attract and retain skilled labor and key personnel

• Increases in employee and retiree benefit costs and funding requirements

Item 1B. Unresolved Staff Comments

The Company has no unresolved comments with the SEC.

Item 3. Legal Proceedings

For information regarding legal proceedings, see Item 8 - Note 19, which is incorporated herein by reference.

Item 4. Mine Safety Disclosures

For information regarding mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K, see Exhibit 95 to this Form 10-K, which is incorporated herein by reference.

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Part II

Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company's common stock is listed on the New York Stock Exchange under the symbol "MDU." The price range of the Company's common stock as reported by The Wall Street Journal composite tape during 2013 and 2012 and dividends declared thereon were as follows:

	Common Stock Price (High)		Common Stock Price (Low)		Common Stock Dividends Declared Per Share
2013
First quarter		$25.00		$21.50		$.1725
Second quarter	27.14		23.37		.1725
Third quarter	30.21		25.94		.1725
Fourth quarter	30.97		27.53		.1775
						$.6950
2012
First quarter		$22.50		$21.14		$.1675
Second quarter	23.21		20.76		.1675
Third quarter	23.11		21.42		.1675
Fourth quarter	22.23		19.59		.1725
						$.6750

As of December 31, 2013, the Company's common stock was held by approximately 13,900 stockholders of record.

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. For more information on factors that may limit the Company's ability to pay dividends, see Item 8 - Note 12.

The following table includes information with respect to the Company's purchase of equity securities:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	(a) Total Number of Shares (or Units) Purchased (1)	(b)  Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2)
October 1 through October 31, 2013	—
November 1 through November 30, 2013	33,027		$30.53
December 1 through December 31, 2013	3,686	29.83
Total	36,713
(1) Represents shares of common stock purchased on the open market in connection with annual stock grants made to the Company's non-employee directors and for those directors who elected to receive additional shares of common stock in lieu of a portion of their cash retainer. (2) Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.

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Item6. Selected Financial Data

	2013			2012			(a)	2011			2010			2009			(b)	2008			(c)
Selected Financial Data
Operating revenues (000's):
Electric	$	257,260		$	236,895			$	225,468		$	211,544		$	196,171			$	208,326
Natural gas distribution	851,945			754,848				907,400			892,708			1,072,776				1,036,109
Pipeline and energy services	202,068			193,157				278,343			329,809			307,827				532,153
Exploration and production	536,023			448,617				453,586			434,354			439,655				712,279
Construction materials and contracting	1,712,137			1,617,425				1,510,010			1,445,148			1,515,122				1,640,683
Construction services	1,039,839			938,558				854,389			789,100			819,064				1,257,319
Other	9,620			10,370				11,446			7,727			9,487				10,501
Intersegment eliminations	(146,488		)	(124,439		)		(190,150		)	(200,695		)	(183,601		)		(394,092		)
	$	4,462,404		$	4,075,431			$	4,050,492		$	3,909,695		$	4,176,501			$	5,003,278
Operating income (loss) (000's):
Electric	$	54,274		$	49,852			$	49,096		$	48,296		$	36,709			$	35,415
Natural gas distribution	78,829			67,579				82,856			75,697			76,899				76,887
Pipeline and energy services	20,046			49,139				45,365			46,310			69,388				49,560
Exploration and production	161,402			(276,642		)		133,790			143,169			(473,399		)		202,954
Construction materials and contracting	93,629			57,864				51,092			63,045			93,270				62,849
Construction services	85,246			66,531				39,144			33,352			44,255				81,485
Other	6,649			4,884				5,024			858			(219		)		2,887
Intersegment eliminations	(7,176		)	—				—			—			—				—
	$	492,899		$	19,207			$	406,367		$	410,727		$	(153,097	)		$	512,037
Earnings (loss) on common stock (000's):
Electric	$	34,837		$	30,634			$	29,258		$	28,908		$	24,099			$	18,755
Natural gas distribution	37,656			29,409				38,398			36,944			30,796				34,774
Pipeline and energy services	7,629			26,588				23,082			23,208			37,845				26,367
Exploration and production	94,450			(177,283		)		80,282			85,638			(296,730		)		122,326
Construction materials and contracting	50,946			32,420				26,430			29,609			47,085				30,172
Construction services	52,213			38,429				21,627			17,982			25,589				49,782
Other	5,136			4,797				6,190			21,046			7,357				10,812
Intersegment eliminations	(4,307		)	—				—			—			—				—
Earnings (loss) on common stock before income (loss) from discontinued operations	278,560			(15,006		)		225,267			243,335			(123,959		)		292,988
Income (loss) from discontinued operations, net of tax	(312		)	13,567				(12,926		)	(3,361		)	—				—
	$	278,248		$	(1,439	)		$	212,341		$	239,974		$	(123,959	)		$	292,988
Earnings (loss) per common share before discontinued operations - diluted	$	1.47		$	(.08	)		$	1.19		$	1.29		$	(.67	)		$	1.59
Discontinued operations, net of tax	—			.07				(.07		)	(.02		)	—				—
	$	1.47		$	(.01	)		$	1.12		$	1.27		$	(.67	)		$	1.59

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	2013			2012			(a)	2011			2010			2009			(b)	2008			(c)
Common Stock Statistics
Weighted average common shares outstanding - diluted (000's)	189,693			188,826				188,905			188,229			185,175				183,807
Dividends declared per common share	$	.6950		$	.6750			$	.6550		$	.6350		$	.6225			$	.6000
Book value per common share	$	15.01		$	13.95			$	14.62		$	14.22		$	13.61			$	14.95
Market price per common share (year end)	$	30.55		$	21.24			$	21.46		$	20.27		$	23.60			$	21.58
Market price ratios:
Dividend payout	47		%	(d)				58		%	50		%	(d)				38		%
Yield	2.3		%	3.2		%		3.1		%	3.2		%	2.7		%		2.9		%
Market value as a percent of book value	203.5		%	152.3		%		146.8		%	142.5		%	173.4		%		144.3		%

(a) Reflects $246.8 million of after-tax noncash write-downs of oil and natural gas properties.

(b) Reflects a $384.4 million after-tax noncash write-down of oil and natural gas properties.

(c) Reflects an $84.2 million after-tax noncash write-down of oil and natural gas properties.

(d) Not meaningful due to effects of the after-tax noncash write-down(s), as previously discussed.

Note: Intermountain, a natural gas distribution business, was acquired on October 1, 2008.

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	2013			2012			2011			2010			2009			2008
General
Total assets (000's)	$	7,061,332		$	6,682,491		$	6,556,125		$	6,303,549		$	5,990,952		$	6,587,845
Total long-term debt (000's)	$	1,854,563		$	1,744,975		$	1,424,678		$	1,506,752		$	1,499,306		$	1,647,302
Capitalization ratios:
Common equity	60		%	60		%	66		%	64		%	63		%	61		%
Total debt	40			40			34			36			37			39
	100		%	100		%	100		%	100		%	100		%	100		%
Electric
Retail sales (thousand kWh)	3,173,086			2,996,528			2,878,852			2,785,710			2,663,560			2,663,452
Electric system summer and firm purchase contract ZRCs (Interconnected system)	583.5			552.8			572.8			553.3			(a)			(a)
Electric system peak demand obligation, including firm purchase contracts, ZRCs (Interconnected system)	508.3			550.7			524.2			529.5			(a)			(a)
Demand peak - kW (Interconnected system)	573,587			573,587			535,761			525,643			525,643			525,643
Electricity produced (thousand kWh)	2,430,001			2,299,686			2,488,337			2,472,288			2,203,665			2,538,439
Electricity purchased (thousand kWh)	971,261			870,516			645,567			521,156			682,152			516,654
Average cost of fuel and purchased power per kWh	$	.025		$	.023		$	.021		$	.021		$	.023		$	.025
Natural Gas Distribution (b)
Sales (Mdk)	108,260			93,810			103,237			95,480			102,670			87,924
Transportation (Mdk)	149,490			132,010			124,227			135,823			132,689			103,504
Degree days (% of normal)
Montana-Dakota/Great Plains	105		%	84		%	101		%	98		%	104		%	103		%
Cascade	98		%	96		%	103		%	96		%	105		%	108		%
Intermountain	110		%	91		%	107		%	100		%	107		%	90		%
Pipeline and Energy Services
Transportation (Mdk)	178,598			137,720			113,217			140,528			163,283			138,003
Gathering (Mdk)	40,737			47,084			66,500			77,154			92,598			102,064
Customer natural gas storage balance (Mdk)	26,693			43,731			36,021			58,784			61,506			30,598
Exploration and Production
Production:
Oil (MBbls)	4,815			3,694			2,724			2,767			2,557			2,232
NGL (MBbls)	781			828			776			495			554			576
Natural gas (MMcf)	28,008			33,214			45,598			50,391			56,632			65,457
Total production (MBOE)	10,264			10,058			11,099			11,661			12,550			13,717
Average realized prices (excluding realized and unrealized gain/loss on commodity derivatives):
Oil (per Bbl)	$	89.70		$	84.84		$	91.62		$	70.61		$	53.57		$	89.41
NGL (per Bbl)	$	37.39		$	39.81		$	54.06		$	44.93		$	32.18		$	54.65
Natural gas (per Mcf)	$	2.89		$	2.08		$	3.30		$	3.57		$	2.99		$	7.29
Average realized prices (including realized gain/loss on commodity derivatives):
Oil (per Bbl)	$	89.35		$	86.54		$	86.20		$	69.59		$	50.67		$	88.66
NGL (per Bbl)	$	37.39		$	39.81		$	54.06		$	44.93		$	32.18		$	54.65
Natural gas (per Mcf)	$	2.96		$	2.91		$	3.84		$	4.36		$	5.16		$	7.38
Proved reserves:
Oil (MBbls)	41,019			33,453			27,005			25,666			25,930			25,238
NGL (MBbls)	6,602			7,153			7,342			7,201			8,286			9,110
Natural gas (MMcf)	198,445			239,278			379,827			448,397			448,425			604,282
Total proved reserves (MBOE)	80,695			80,486			97,651			107,599			108,954			135,062

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	2013	2012	2011	2010	2009	2008
Construction Materials and Contracting
Sales (000's):
Aggregates (tons)	24,713	23,285	24,736	23,349	23,995	31,107
Asphalt (tons)	6,228	5,988	6,709	6,279	6,360	5,846
Ready-mixed concrete (cubic yards)	3,223	3,157	2,864	2,764	3,042	3,729
Aggregate reserves (000's tons)	1,083,376	1,088,236	1,088,833	1,107,396	1,125,491	1,145,161
(a) Information not available for periods prior to 2010. (b) Intermountain was acquired on October 1, 2008.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Overview

The Company's strategy is to apply its expertise in energy and transportation infrastructure industries to increase market share, increase profitability and enhance shareholder value through:

• Organic growth as well as a continued disciplined approach to the acquisition of well-managed companies and properties

• The elimination of system-wide cost redundancies through increased focus on integration of operations and standardization and consolidation of various support services and functions across companies within the organization

• The development of projects that are accretive to earnings per share and return on invested capital

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities, revolving credit facilities and the issuance from time to time of debt and equity securities. For more information on the Company's net capital expenditures, see Liquidity and Capital Commitments.

The key strategies for each of the Company's business segments and certain related business challenges are summarized below. For a summary of the Company's business segments, see Item 8 - Note 15.

Key Strategies and Challenges

Electric and Natural Gas Distribution

Strategy Provide safe and reliable competitively priced energy and related services to customers. The electric and natural gas distribution segments continually seek opportunities to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation and transmission and natural gas systems, and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity for the Company to earn a competitive return on investment.

Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and permitted returns on investment as well as subject to certain operational, system integrity and environmental regulations. These regulations can require substantial investment to upgrade facilities. The ability of these segments to grow through acquisitions is subject to significant competition. In addition, the ability of both segments to grow service territory and customer base is affected by the economic environment of the markets served and competition from other energy providers and fuels. The construction of any new electric generating facilities, transmission lines and other service facilities are subject to increasing cost and lead time, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which will necessitate increases in electric energy prices. Legislative and regulatory initiatives to increase renewable energy resources and reduce GHG emissions could impact the price and demand for electricity and natural gas.

Pipeline and Energy Services

Strategy Utilize the segment's existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, investments in and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new energy sources for storage, gathering and transportation services; expansion of existing gathering, transmission and storage facilities; incremental expansion of pipeline capacity; expansion of midstream business to include liquid pipelines and processing/refining activities; and expansion of related energy services.

ChallengesChallenges for this segment include: energy price volatility; natural gas basis differentials; environmental and regulatory requirements; recruitment and retention of a skilled workforce; and competition from other pipeline and energy services companies.

Exploration and Production

Strategy Apply technology and utilize existing exploration and production expertise, with a focus on operated properties, to increase production and reserves from existing leaseholds, and to seek additional reserves and production opportunities both in new and existing areas to further expand the segment's asset base. By optimizing existing operations and taking advantage of new and incremental growth opportunities, this segment is focused on balancing the oil and natural gas commodity mix to maximize profitability with its goal to add value by increasing both reserves and production over the long term so as to generate competitive returns on investment.

35

Challenges Volatility in natural gas and oil prices; timely receipt of necessary permits and approvals; environmental and regulatory requirements; recruitment and retention of a skilled workforce; availability of drilling rigs, materials, auxiliary equipment and industry-related field services; inflationary pressure on development and operating costs; and competition from other exploration and production companies are ongoing challenges for this segment.

Construction Materials and Contracting

Strategy Focus on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthen long-term, strategic aggregate reserve position through purchase and/or lease opportunities; enhance profitability through cost containment, margin discipline and vertical integration of the segment's operations; develop and recruit talented employees; and continue growth through organic and acquisition opportunities. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted aggregate reserves being significant. A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials business (rock, sand, gravel, liquid asphalt, asphalt concrete, ready-mixed concrete and related products), complementing and expanding on the Company's expertise.

Challenges Recruitment and retention of key personnel and volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and steel, continue to be a concern. This business unit expects to continue cost containment efforts, positioning its operations for the resurgence in the private market, while continuing the emphasis on industrial, energy and public works projects.

Construction Services

Strategy Provide a superior return on investment by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; and focusing our efforts on projects that will permit higher margins while properly managing risk.

Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel, managing through downturns in the economy and effective management of working capital are ongoing challenges.

For more information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company's financial condition, see Item 1A - Risk Factors. For more information on each segment's key growth strategies, projections and certain assumptions, see Prospective Information.

For information pertinent to various commitments and contingencies, see Item 8 - Notes to Consolidated Financial Statements.

36

Earnings Overview

The following table summarizes the contribution to consolidated earnings (loss) by each of the Company's businesses.

Years ended December 31,	2013			2012			2011
	(Dollars in millions, where applicable)
Electric	$	34.8		$	30.6		$	29.2
Natural gas distribution	37.7			29.4			38.4
Pipeline and energy services	7.6			26.6			23.1
Exploration and production	94.5			(177.2		)	80.3
Construction materials and contracting	50.9			32.4			26.4
Construction services	52.2			38.4			21.6
Other	5.1			4.8			6.2
Intersegment eliminations	(4.3		)	—			—
Earnings (loss) before discontinued operations	278.5			(15.0		)	225.2
Income (loss) from discontinued operations, net of tax	(.3		)	13.6			(12.9		)
Earnings (loss) on common stock	$	278.2		$	(1.4	)	$	212.3
Earnings (loss) per common share - basic:
Earnings (loss) before discontinued operations	$	1.47		$	(.08	)	$	1.19
Discontinued operations, net of tax	—			.07			(.07		)
Earnings (loss) per common share - basic	$	1.47		$	(.01	)	$	1.12
Earnings (loss) per common share - diluted:
Earnings (loss) before discontinued operations	$	1.47		$	(.08	)	$	1.19
Discontinued operations, net of tax	—			.07			(.07		)
Earnings (loss) per common share - diluted	$	1.47		$	(.01	)	$	1.12

2013 compared to 2012 Consolidated earnings for 2013increased$279.6 million from the prior year. This increase was due to:

• Absence of the write-downs of oil and natural gas properties of $246.8 million (after tax), as discussed in Item 8 - Note 1, increased oil production and higher average realized natural gas and oil prices, partially offset by a lower realized gain on commodity derivatives of $21.1 million (after tax), higher depreciation, depletion and amortization expense, decreased natural gas production, higher production taxes, as well as higher general and administrative expense at the exploration and production business

• Higher asphalt and aggregate margins and volumes at the construction materials and contracting business

• Higher workloads and margins in the Western and Central regions, as well as higher equipment sales and rental revenue and margins at the construction services business

• Increased retail sales volumes and a gain on the sale of a nonregulated appliance service and repair business, partially offset by higher operation and maintenance expense, as well as higher depreciation, depletion and amortization expense at the natural gas distribution business

Partially offsetting these increases were:

• A net benefit in 2013 of $1.5 million (after tax) compared to $15.0 million (after tax) in 2012, related to the natural gas gathering operations litigation, as discussed in Item 8 - Note 19, as well as an impairment of coalbed natural gas gathering assets of $9.0 million (after tax) in 2013 compared to an impairment of $1.7 million (after tax) in 2012, as discussed in Item 8 - Note 1, at the pipeline and energy services business

• Loss from discontinued operations of $300,000 (after tax) in 2013, compared to income from discontinued operations of $13.6 million (after tax) in 2012, primarily due to the absence in 2013 of a net benefit in 2012 related to the reversal of an arbitration charge resulting from a favorable court ruling, as discussed in Item 8 - Note 3

2012 compared to 2011 Consolidated earnings for 2012decreased$213.7 million from the prior year. This decrease was due to:

• Noncash write-downs of oil and natural gas properties of $246.8 million (after tax), lower average realized natural gas prices, decreased natural gas production, as well as higher depreciation, depletion and amortization expense, partially offset by increased oil production at the exploration and production business

• Decreased retail sales volumes at the natural gas distribution business, largely resulting from warmer weather than last year

37

Partially offsetting these decreases were:

• Income from discontinued operations of $13.6 million (after tax), largely related to a benefit from an arbitration charge reversal resulting from a favorable court ruling, as discussed in Item 8 - Note 3

• Higher workloads and margins in the Central and Western regions, higher equipment sales and rental margins, as well as higher margins in the Mountain region, partially offset by higher general and administrative expense at the construction services business

• Higher ready-mixed concrete and other product line margins and volumes, increased construction margins, as well as higher liquid asphalt oil margins and volumes, partially offset by lower gains from the sale of property, plant and equipment and lower aggregate and asphalt margins and volumes at the construction materials and contracting business

• Lower operation and maintenance expense from existing operations largely related to a $15.0 million (after tax) net benefit related to the natural gas gathering operations litigation, as discussed in Item 8 - Note 19, partially offset by lower natural gas gathering volumes from existing operations at the pipeline and energy services business

Financial and Operating Data

Below are key financial and operating data for each of the Company's businesses.

Electric

Years ended December 31,	2013		2012		2011
	(Dollars in millions, where applicable)
Operating revenues	$	257.3	$	236.9	$	225.5
Operating expenses:
Fuel and purchased power	83.5		72.4		64.5
Operation and maintenance	76.5		71.8		70.3
Depreciation, depletion and amortization	32.8		32.5		32.2
Taxes, other than income	10.2		10.3		9.4
	203.0		187.0		176.4
Operating income	54.3		49.9		49.1
Earnings	$	34.8	$	30.6	$	29.2
Retail sales (million kWh)	3,173.1		2,996.5		2,878.9
Average cost of fuel and purchased power per kWh	$	.025	$	.023	$	.021

2013 compared to 2012 Electric earnings increased$4.2 million (14 percent) compared to the prior year due to:

• Higher electric retail sales margins, including the result of 6 percent higher volumes, primarily to residential, commercial and industrial customers due to increased residential customer growth and weather variances from last year

• Higher other income, largely higher allowance for funds used during construction of $800,000 (after tax)

These increases were partially offset by higher operation and maintenance expense, which includes $2.3 million (after tax) largely related to higher payroll-related costs and increased contract services, offset in part by lower benefit-related costs.

2012 compared to 2011Electric earnings increased$1.4 million (5 percent) compared to the prior year due to:

• Higher retail sales volumes of 4 percent, primarily to small commercial and industrial and residential customers, reflecting increased demand due to warmer summer weather than last year, as well as increased customer growth, offset in part by decreased volumes to large commercial and industrial customers

• Higher other income, largely higher allowance for funds used during construction of $900,000 (after tax)

• Lower net interest expense, which includes $900,000 (after tax) due in part to higher capitalized interest

Partially offsetting these increases were:

• Higher income taxes, including $1.4 million which is partially related to the absence of an income tax benefit related to favorable resolutions of certain income tax matters in 2011

• Increased taxes other than income of $600,000 (after tax), primarily related to higher property taxes

38

• Higher operation and maintenance expense, which includes $500,000 (after tax) largely related to increased contract services at certain of the Company's electric generation stations, as well as higher payroll-related costs, partially offset by lower benefit-related costs

Natural Gas Distribution

Years ended December 31,	2013			2012			2011
	(Dollars in millions, where applicable)
Operating revenues	$	851.9		$	754.8		$	907.4
Operating expenses:
Purchased natural gas sold	534.8			457.4			594.6
Operation and maintenance	142.3			139.4			137.3
Depreciation, depletion and amortization	50.0			45.7			44.6
Taxes, other than income	46.0			44.7			48.0
	773.1			687.2			824.5
Operating income	78.8			67.6			82.9
Earnings	$	37.7		$	29.4		$	38.4
Volumes (MMdk):
Sales	108.3			93.8			103.3
Transportation	149.5			132.0			124.2
Total throughput	257.8			225.8			227.5
Degree days (% of normal)*
Montana-Dakota/Great Plains	105		%	84		%	101		%
Cascade	98		%	96		%	103		%
Intermountain	110		%	91		%	107		%
Average cost of natural gas, including transportation, per dk	$	4.94		$	4.88		$	5.76
* Degree days are a measure of the daily temperature-related demand for energy for heating.

2013 compared to 2012 The natural gas distribution business experienced an increase in earnings of $8.3 million (28 percent) compared to the prior year due to:

• Increased retail sales volumes of 15 percent, largely resulting from increased customer growth and colder weather than last year, partially offset by weather normalization adjustments in certain jurisdictions

• A $2.8 million (after tax) gain on the sale of Montana-Dakota's nonregulated appliance service and repair business

• Lower net interest expense, which includes $2.3 million (after tax) largely related to lower average interest rates

These increases were partially offset by:

• Higher operation and maintenance expense, which includes $3.4 million (after tax) largely related to higher payroll-related costs, offset in part by lower benefit-related costs

• Increased depreciation, depletion and amortization expense of $2.7 million (after tax), primarily resulting from higher property, plant and equipment balances

• Lower other income, which includes $2.0 million (after tax) largely related to lower allowance for funds used during construction

2012 compared to 2011 The natural gas distribution business experienced a decrease in earnings of $9.0 million (23 percent) compared to the prior year due to:

• Lower earnings of $7.6 million (after tax) related to decreased retail sales volumes, largely resulting from warmer weather than last year, partially offset by weather normalization in certain jurisdictions

• Taxes other than income includes $1.3 million (after tax) primarily related to higher property taxes. Taxes other than income also reflects the effect of lower natural gas revenues.

• Absence in 2012 of a reduction of deferred income taxes, which includes $1.2 million primarily associated with benefits in 2011

• Increased operation and maintenance expense, which includes $700,000 (after tax) partially related to increased contract services

39

These decreases were partially offset by higher other income, which includes $1.1 million (after tax) primarily related to allowance for funds used during construction.

Pipeline and Energy Services

Years ended December 31,	2013			2012		2011
	(Dollars in millions)
Operating revenues	$	202.1		$	193.1	$	278.3
Operating expenses:
Purchased natural gas sold	57.5			50.5		125.3
Operation and maintenance*	81.8			52.2		68.9
Depreciation, depletion and amortization	29.1			27.7		25.5
Taxes, other than income	13.6			13.6		13.2
	182.0			144.0		232.9
Operating income	20.1			49.1		45.4
Earnings*	$	7.6		$	26.6	$	23.1
Transportation volumes (MMdk)	178.6			137.7		113.2
Natural gas gathering volumes (MMdk)	40.7			47.1		66.5
Customer natural gas storage balance (MMdk):
Beginning of period	43.7			36.0		58.8
Net injection (withdrawal)	(17.0		)	7.7		(22.8		)
End of period	26.7			43.7		36.0
* Reflects an impairment of coalbed natural gas gathering assets of $14.5 million ($9.0 million after tax) in second quarter 2013 and $2.7 million ($1.7 million after tax) in second quarter 2012, as well as a net benefit of $2.5 million ($1.5 million after tax) in fourth quarter 2013 and $24.1 million ($15.0 million after tax) in second quarter 2012 related to the natural gas gathering operations litigation, largely reflected in operation and maintenance expense, as discussed in Item 8 - Note 19.

2013 compared to 2012 Pipeline and energy services earnings decreased$19.0 million (71 percent) largely due to:

• A net benefit in 2013 of $1.5 million (after tax) compared to $15.0 million (after tax) in 2012, related to the natural gas gathering operations litigation, as discussed in Item 8 - Note 19

• An impairment of coalbed natural gas gathering assets of $9.0 million (after tax) in 2013, compared to an impairment of $1.7 million (after tax) in 2012, largely resulting from lower natural gas prices, as discussed in Item 8 - Note 1

• Lower storage services revenue of $3.1 million (after tax), primarily due to lower average rates and lower storage balances

• Lower earnings of $3.1 million (after tax) resulting from lower natural gas gathering volumes from existing operations, largely resulting from customers experiencing production curtailments, normal declines and deferral of natural gas development activity

Partially offsetting the earnings decrease were:

• Higher earnings from the Company's interest in the Pronghorn oil and natural gas gathering and processing assets, which were acquired in May 2012, primarily due to higher volumes

• Lower operation and maintenance expense (excluding the asset impairments, net benefits related to the natural gas gathering operations litigation and Pronghorn-related expense), which includes $2.0 million (after tax), largely related to lower payroll-related costs, legal and contract services

• Lower depreciation, depletion and amortization expense (excluding depreciation on Pronghorn oil and natural gas gathering and processing assets), which includes $1.6 million (after tax), primarily related to the coalbed areas

2012 compared to 2011 Pipeline and energy services earnings increased$3.5 million (15 percent) largely due to:

• Lower operation and maintenance expense from existing operations largely related to a $15.0 million (after tax) net benefit related to the natural gas gathering operations litigation, as discussed in Item 8 - Note 19, which was partially offset by an impairment of certain natural gas gathering assets of $1.7 million (after tax) due largely to low natural gas prices

• Higher oil and natural gas gathering and processing volumes from the acquisition of the Company's interest in the Pronghorn oil and natural gas gathering and processing assets, as discussed in Item 8 - Note 2

40

Partially offsetting the earnings increase were:

• Lower earnings of $10.4 million (after tax) due to lower natural gas gathering volumes from existing operations, largely resulting from customers experiencing normal declines, production curtailments, deferral of certain natural gas development activity and the Company's divestments

• Lower storage services revenue of $600,000 (after tax), largely lower average storage balances, as well as lower withdrawal volumes

Results also reflect lower operating revenues and lower purchased natural gas sold, both related to lower natural gas prices and lower natural gas volumes.

Exploration and Production

Years ended December 31,	2013			2012			2011
	(Dollars in millions, where applicable)
Operating revenues:
Oil	$	431.9		$	313.4		$	249.6
NGL	29.2			33.0			41.9
Natural gas	81.0			69.2			150.7
Realized gain on commodity derivatives	.2			33.6			9.6
Unrealized gain (loss) on commodity derivatives	(6.3		)	(.6		)	1.8
	536.0			448.6			453.6
Operating expenses:
Operation and maintenance:
Lease operating costs	82.2			77.7			75.6
Gathering and transportation	15.4			17.4			24.3
Other	42.9			37.0			36.5
Depreciation, depletion and amortization	186.4			160.7			142.6
Taxes, other than income:
Production and property taxes	46.6			39.7			40.8
Other	1.1			1.0			—
Write-downs of oil and natural gas properties	—			391.8			—
	374.6			725.3			319.8
Operating income (loss)	161.4			(276.7		)	133.8
Earnings (loss)	$	94.5		$	(177.2	)	$	80.3
Production:
Oil (MBbls)	4,815			3,694			2,724
NGL (MBbls)	781			828			776
Natural gas (MMcf)	28,008			33,214			45,598
Total production (MBOE)	10,264			10,058			11,099
Average realized prices (excluding realized and unrealized gain/loss on commodity derivatives):
Oil (per Bbl)	$	89.70		$	84.84		$	91.62
NGL (per Bbl)	$	37.39		$	39.81		$	54.06
Natural gas (per Mcf)	$	2.89		$	2.08		$	3.30
Average realized prices (including realized gain/loss on commodity derivatives):
Oil (per Bbl)	$	89.35		$	86.54		$	86.20
NGL (per Bbl)	$	37.39		$	39.81		$	54.06
Natural gas (per Mcf)	$	2.96		$	2.91		$	3.84
Average depreciation, depletion and amortization rate, per BOE	$	17.41		$	15.28		$	12.25
Production costs, including taxes, per BOE:
Lease operating costs	$	8.01		$	7.73		$	6.81
Gathering and transportation	1.50			1.73			2.19
Production and property taxes	4.54			3.94			3.67
	$	14.05		$	13.40		$	12.67

41

2013 compared to 2012 Earnings at the exploration and production business increased$271.7 million due to:

• Absence of the write-downs of oil and natural gas properties of $246.8 million (after tax), as discussed in Item 8 - Note 1

• Increased oil production of 30 percent, primarily related to drilling activity in the Bakken and Paradox Basin areas

• Higher average realized natural gas prices of 39 percent, excluding gain/loss on commodity derivatives

• Higher average realized oil prices of 6 percent, excluding gain/loss on commodity derivatives

Partially offsetting these increases were:

• Lower realized gain on commodity derivatives of $21.1 million (after tax), due to higher commodity prices relative to hedge prices

• Higher depreciation, depletion and amortization expense of $16.2 million (after tax), largely due to higher depletion rates

• Decreased natural gas production of 16 percent, largely related to production curtailments, normal declines and deferral of certain natural gas development activity

• Higher production taxes of $4.3 million (after tax), primarily resulting from higher revenues

• Unrealized loss on commodity derivatives of $3.9 million (after tax) in 2013, compared to $400,000 (after tax) in 2012

• Higher general and administrative expense of $3.8 million (after tax), including higher payroll-related costs

• Higher net interest expense of $3.3 million (after tax), largely due to lower capitalized interest

• Increased lease operating expenses of $2.8 million (after tax), largely related to higher costs in the Bakken area resulting from increased production volumes and higher workover costs, as well as higher costs in the Paradox Basin resulting from increased production volumes, partially offset by lower costs at certain natural gas properties where curtailments of production have occurred

2012 compared to 2011Earnings at the exploration and production business decreased$257.5 million due to:

• Noncash write-downs of oil and natural gas properties of $246.8 million (after tax), as discussed in Item 8 - Note 1

• Lower average realized natural gas prices of 25 percent

• Decreased natural gas production of 27 percent, largely related to normal declines, production curtailments, deferral of certain natural gas development activity and divestment of existing properties

• Higher depreciation, depletion and amortization expense of $11.4 million (after tax), due to higher depletion rates, partially offset by lower volumes

• Lower average realized NGL prices of 26 percent

Partially offsetting these decreases were:

• Increased oil production of 36 percent, primarily related to drilling activity in the Bakken area, as well as the Paradox Basin

• Lower gathering and transportation expense of $4.3 million (after tax), largely due to lower gathering costs resulting from lower volumes and lower gathering rates in the coalbed area

Construction Materials and Contracting

Years ended December 31,	2013		2012		2011
	(Dollars in millions)
Operating revenues	$	1,712.1	$	1,617.4	$	1,510.0
Operating expenses:
Operation and maintenance	1,505.2		1,442.5		1,337.4
Depreciation, depletion and amortization	74.5		79.5		85.5
Taxes, other than income	38.8		37.5		36.0
	1,618.5		1,559.5		1,458.9
Operating income	93.6		57.9		51.1
Earnings	$	50.9	$	32.4	$	26.4
Sales (000's):
Aggregates (tons)	24,713		23,285		24,736
Asphalt (tons)	6,228		5,988		6,709
Ready-mixed concrete (cubic yards)	3,223		3,157		2,864

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2013 compared to 2012 Earnings at the construction materials and contracting business increased$18.5 million (57 percent) due to:

• Higher earnings of $6.6 million (after tax) resulting from higher asphalt margins and volumes

• Higher earnings of $5.6 million (after tax) resulting from higher aggregate margins and volumes

• Lower selling, general and administrative costs of $2.4 million (after tax), largely lower insurance costs

• Higher earnings of $1.4 million (after tax) resulting from higher ready-mixed concrete margins and volumes

• Increased construction workloads and margins of $1.4 million (after tax)

• Higher earnings resulting from higher other product line volumes and margins

Partially offsetting these increases was higher interest expense of $1.3 million (after tax), resulting from higher average interest rates.

2012 compared to 2011 Earnings at the construction materials and contracting business increased$6.0 million (23 percent) due to:

• Higher earnings of $6.4 million (after tax) resulting from higher ready-mixed concrete margins and volumes, primarily in the North Central and Northwest regions, as well as higher other product line volumes and margins

• Increased construction margins of $3.6 million (after tax), largely related to increased construction margins in the South and Intermountain regions

• Higher earnings of $3.6 million (after tax) resulting from higher liquid asphalt oil margins and volumes

• Lower selling, general and administrative costs of $2.8 million (after tax), largely due to lower benefit and payroll-related costs

Partially offsetting the increases were:

• Lower gains of $4.0 million (after tax) from the sale of property, plant and equipment

• Lower earnings of $3.6 million (after tax) resulting from lower aggregate margins primarily due to higher costs, as well as lower volumes

• Lower earnings of $2.9 million (after tax) resulting from lower asphalt margins primarily due to higher costs, as well as lower volumes

Construction Services

Years ended December 31,	2013		2012		2011
	(In millions)
Operating revenues	$	1,039.8	$	938.6	$	854.4
Operating expenses:
Operation and maintenance	910.7		831.9		778.5
Depreciation, depletion and amortization	11.9		11.1		11.4
Taxes, other than income	32.0		29.1		25.4
	954.6		872.1		815.3
Operating income	85.2		66.5		39.1
Earnings	$	52.2	$	38.4	$	21.6

2013 compared to 2012Construction services earnings increased$13.8 million (36 percent) compared to the prior year primarily due to higher workloads and margins in the Western and Central regions, as well as higher equipment sales and rental revenue and margins. This increase was partially offset by higher general and administrative expense of $3.3 million (after tax), including higher payroll-related costs.

2012 compared to 2011 Construction services earnings increased$16.8 million (78 percent) compared to the prior year due to higher earnings of $21.3 million resulting from higher workloads and margins in the Central and Western regions, higher equipment sales and rental margins, as well as higher margins in the Mountain region. These increases were partially offset by higher general and administrative expense of $4.6 million (after tax), including higher payroll-related costs.

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Other

Years ended December 31,	2013			2012		2011
	(In millions)
Operating revenues	$	9.6		$	10.4	$	11.4
Operating expenses:
Operation and maintenance	.8			3.3		4.7
Depreciation, depletion and amortization	2.1			2.0		1.6
Taxes, other than income	.1			.2		.1
	3.0			5.5		6.4
Operating income	6.6			4.9		5.0
Income from continuing operations	5.1			4.8		6.2
Income (loss) from discontinued operations, net of tax	(.3		)	13.6		(12.9		)
Earnings (loss)	$	4.8		$	18.4	$	(6.7	)

2013 compared to 2012Other earnings decreased$13.6 million compared to the prior year primarily due to a loss from discontinued operations of $300,000 (after tax) in 2013, compared to income from discontinued operations of $13.6 million (after tax) in 2012, primarily due to the absence in 2013 of a net benefit in 2012 related to the reversal of an arbitration charge for a guarantee of a construction contract at the domestic power production business, which was sold in 2007, as discussed in Item 8 - Note 3.

2012 compared to 2011Other earnings increased$25.1 million compared to the prior year primarily due to income from discontinued operations of $13.6 million (after tax) in 2012, largely the net benefit related to the reversal of an arbitration charge, as previously discussed, compared to a loss from discontinued operations of $12.9 million (after tax) in 2011, largely related to the arbitration charge for a guarantee of a construction contract at the domestic power production business, which was sold in 2007, as discussed in Item 8 - Note 3.

Intersegment Transactions

Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's elimination of intersegment transactions. The amounts relating to these items are as follows:

Years ended December 31,	2013		2012		2011
	(In millions)
Intersegment transactions:
Operating revenues	$	146.4	$	124.4	$	190.1
Purchased natural gas sold	87.2		82.7		147.7
Operation and maintenance	52.1		41.7		42.4
Income taxes	2.8		—		—
Earnings on common stock	4.3		—		—

For more information on intersegment eliminations, see Item 8 - Note 15.

Prospective Information

The following information highlights the key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters for certain of the Company's businesses. Many of these highlighted points are "forward-looking statements." There is no assurance that the Company's projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer to assumptions contained in this section, as well as the various important factors listed in Item 1A - Risk Factors. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections.

MDU Resources Group, Inc.

• Adjusted earnings per common share for 2014 are projected in the range of $1.45 to $1.60. GAAP earnings guidance for 2014 is in the same range. Unrealized commodity derivatives fair values can fluctuate causing actual GAAP earnings to vary accordingly.

• The Company's long-term compound annual growth goals on earnings per common share from operations are in the range of 7 to 10 percent.

44

• The Company continually seeks opportunities to expand through organic growth opportunities and strategic acquisitions.

• The Company focuses on creating value through vertical integration between its business units. For example, the pipeline and energy services business' Dakota Prairie Refinery has the construction materials and services business involved in constructing the facility, the exploration and production business supplying production, either directly or in kind, to the plant, the pipeline transporting natural gas to the plant and the utility supplying electricity.

Electric and natural gas distribution

• Rate base growth is projected to be approximately 9 percent compounded annually over the next five years, including plans for an approximate $1.3 billion capital investment program.

• Regulatory actions

◦ The Company filed an application September 18, 2013, with the NDPSC for a natural gas rate increase, as discussed in Item 8 - Note 18.

◦ The Company filed an application June 14, 2013, for an advance determination of prudence with the NDPSC to add pollution control equipment at the Lewis & Clark generating station projected to be completed in 2016 to comply with the Mercury and Air Toxics Standards rules. On October 9, 2013, the commission issued an order approving the advance determination of prudence.

◦ The Company filed an application February 11, 2013, with the NDPSC for approval of an environmental cost recovery rider related to ongoing construction costs at the Big Stone Station for the installation of the BART air-quality control system, as discussed in Item 8 - Note 18.

◦ The Company filed an application December 21, 2012, with the SDPUC for a natural gas rate increase requesting a total of $1.5 million annually or approximately 3.3 percent above current rates. The case includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and new customer billing system. The Company implemented the full request July 22, 2013, subject to refund. On November 5, 2013, the commission approved a settlement stipulation for an increase of $900,000 annually, or 2.0 percent, effective with service rendered December 1, 2013.

◦ The Company filed an application September 26, 2012, with the MTPSC for a natural gas rate increase, as discussed in Item 8 - Note 18.

◦ Effective November 1, 2013, the WUTC approved recovery of $1.0 million over a one-year period for qualifying pipeline replacement projects. The WUTC issued a policy statement dated December 31, 2012, related to the accelerated replacement of natural gas pipeline facilities.

• The Company is constructing an 88-MW simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $77 million and a projected in-service date in third quarter 2014. It is located on owned property adjacent to the Company's Heskett Generating Station near Mandan, North Dakota. The capacity is necessary to meet the requirements of the Company's integrated electric system customers and will be a partial replacement for third-party contract capacity expiring in 2015. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from the NDPSC.

• Investments are being made in 2014 totaling approximately $70 million to serve the growing electric and natural gas customer base associated with the Bakken oil development where customer growth is substantially higher than the national average.

• The Company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors, with company- and customer-owned pipeline facilities designed to serve existing facilities served by fuel oil or propane, and to serve new customers. The Company is engaged in a 30-mile, approximately $60 million natural gas line project into the Hanford Nuclear Site in Washington.

45

• The Company, along with a partner, expects to build a 345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota, about 160 miles, at a total cost of approximately $360 million. The Company's share would be one-half. The project is a MISO multi-value project. A route application was filed in August 2013, with the state of South Dakota, and in October 2013, with the state of North Dakota. The project is expected to be complete in 2019.

• The Company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest and Idaho.

Pipeline and energy services

• In January 2014, the Company launched an open season to obtain capacity commitments on a proposed 375-mile natural gas pipeline from western North Dakota to northwestern Minnesota to transport natural gas to markets in eastern North Dakota, Minnesota, Wisconsin, Michigan and other Midwest markets. The pipeline is expected to provide access to additional markets via interconnections with pipelines owned by Great Lakes Gas Transmission, Viking Gas Transmission and potentially TransCanada, in northwestern Minnesota. An interconnection with the Alliance Pipeline system in eastern North Dakota also is possible. Initially the pipeline would transport approximately 400 MMcf per day of natural gas and could be expanded to more than 500 MMcf per day. The project investment is estimated to be approximately $650 million. Following the open season, receipt of adequate capacity commitments and necessary permits and regulatory approvals, construction on the new pipeline could begin in 2016 with completion expected in 2017.

• The Company, in conjunction with Calumet, formed Dakota Prairie Refining, to develop, build and operate Dakota Prairie Refinery. Construction began on the facility in late March 2013 and, when complete, it will process Bakken crude into diesel, which will be marketed within the Bakken region. Other by-products, naphtha and atmospheric tower bottoms, will be railed to other areas. The total project cost estimate has been revised to approximately $350 million, with a projected in-service date in late 2014. EBITDA for the first year of operation is projected to be in the range of $70 million to $90 million, to be shared equally with Calumet.

• On October 31, 2013, WBI Energy Transmission filed a Section 4 rate case with the FERC, as discussed in Item 8 - Note 18.

• The Company is engaged in various natural gas pipeline projects to be constructed in 2014, including connections for the planned Garden Creek II natural gas processing plant in the Bakken, an expansion of its transmission system to increase capacity to the Black Hills and a 24-mile pipeline and related processing facilities to transport Fidelity's Paradox Basin natural gas production. The total cost for these projects is approximately $50 million.

• The Company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region is expanding, most notably in the Bakken area, where the Company owns an extensive natural gas pipeline system. Ongoing energy development is expected to continue to provide growth opportunities for this business.

Exploration and production

• The Company expects to spend approximately $440 million in capital expenditures in 2014.

• For 2014, the Company expects a 10 to 20 percent increase in oil production and a 5 to 10 percent increase in NGL production. Natural gas production is expected to decline 20 to 30 percent compared to a year ago, primarily the result of the divestment of certain non-strategic natural gas-based properties in 2013. The vast majority of the capital program is focused on growing oil production considering current relative commodity prices. The Company expects to return to some natural gas development when the commodity prices make it more profitable to do so.

• The Company has a total of four drilling rigs deployed on its acreage in the Bakken and Paradox Basin areas, with two rigs operating in each area.

• Bakken areas

◦ The Company owns a total of approximately 125,000 net acres of leaseholds in Mountrail and Stark counties, North Dakota and Richland County, Montana. The Middle Bakken and Three Forks formations are targeted in North Dakota and the Red River formation is targeted in Montana.

◦ Capital expenditures are expected to total approximately $130 million in 2014.

46

◦ Net oil production for the fourth quarter 2013 was approximately 7,900 BOPD which is down 5 percent from third quarter 2013. This quarter-on-quarter drop in oil production was primarily driven by weather-related downtime in December 2013, as well as delay of a three-well pad completion.

◦ Alternative completion techniques, including increased stage count and cemented liners in the Middle Bakken (Mountrail County) and Three Forks (Mountrail and Stark counties) are being tested, with completion design changes to be finalized later in 2014.

• Paradox Basin, Utah

◦ The Company owns approximately 130,000 net acres of leaseholds including its recent acquisition of 35,000 net acres of leaseholds and has an option to earn another 20,000 acres. The Company expects to further expand its acreage in the basin.

◦ Capital expenditures are expected to total approximately $170 million in 2014.

◦ Well costs have increased and now range from $10 million to $11 million per well driven by increased lateral lengths. With longer lateral lengths, estimated ultimate recoveries are expected to increase with the upper range now at 1.5 MMBbls of oil per well.

◦ Following nine months of flowing at a constant 1,500 BOPD gross, the CCU 12-1 well came off its plateau rate and for the past seven months has still been flowing at approximately 1,000 BOPD. Cumulative production is 600 MBbls of oil.

◦ Net oil production for fourth quarter 2013 was approximately 2,850 BOPD, up 89 percent from fourth quarter 2012 and 24 percent higher than third quarter 2013. Current production is approximately 3,000 BOPD.

◦ The CCU 7-1 well has just been completed and is in the initial flowback and production ramp up period. Flowing on a 5/64 choke, the well was producing 350 BOPD at more than 3,000 psi flowing pressure. The well will be brought to full production capability over the next month. The CCU 36-1 has been flowing consistently at an average rate of 930 BOPD gross since October 11, 2013, with an average flowing pressure of approximately 3,400 psi.

◦ The Company's understanding of this play and the quality of the play continues to improve. It is anticipated that this field will play a key role in the Company's oil growth strategy.

• Other opportunities

◦ The Company has continued its focus on adding a third oil play and on February 10, 2014, entered into an agreement to purchase working interests and leasehold positions in oil and natural gas production assets in the southern Powder River Basin of Wyoming. Current net production is more than 1,100 BOE per day, 80 percent of which is oil, with additional production expected to be on line before closing. For more information, see Item 8 - Note 20.

• Earnings guidance reflects estimated average NYMEX index prices for February through December 2014 in the range of $90 to $95 per Bbl of crude oil and $3.75 to $4.25 per Mcf of natural gas. Estimated prices for NGL are in the range of $35 to $45 per Bbl.

• Derivatives

◦ The Company has derivative instruments for 11,000 BOPD for the first six months of 2014, 10,000 BOPD for July through September 2014 and 5,000 BOPD for October through December 2014, utilizing swaps with a weighted average price of $94.90. Covering full-year 2014, the Company has derivative instruments for 40,000 MMBtu of natural gas per day utilizing swaps at a weighted average price of $4.10.

◦ For 2015, the Company has a derivative instrument for 10,000 MMBtu of natural gas per day utilizing a swap at $4.28.

47

◦ The commodity derivative instruments that are in place as of February 18, 2014, are summarized in the following chart:

Commodity	Type	Index	Period Outstanding	Forward Notional Volume (Bbl/MMBtu)	Price (Per Bbl/MMBtu)
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$95.15
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$95.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$90.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$91.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$92.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$93.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$98.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$99.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$100.07
Crude Oil	Swap	NYMEX	1/14 - 12/14	365,000	$94.05
Crude Oil	Swap	NYMEX	1/14 - 12/14	365,000	$95.00
Crude Oil	Swap	NYMEX	7/14 - 9/14	184,000	$95.75
Crude Oil	Swap	NYMEX	7/14 - 9/14	184,000	$96.00
Crude Oil	Swap	NYMEX	7/14 - 9/14	92,000	$96.25
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$94.25
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$95.00
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$95.25
Natural Gas	Swap	NYMEX	1/14 - 12/14	7,300,000	$4.13
Natural Gas	Swap	NYMEX	1/14 - 12/14	3,650,000	$4.05
Natural Gas	Swap	NYMEX	1/14 - 12/14	3,650,000	$4.10
Natural Gas	Swap	NYMEX	1/15 - 12/15	3,650,000	$4.28

Construction materials and contracting

• Approximate work backlog as of December 31, 2013, was $456 million, compared to $406 million a year ago. Private work represents 11 percent of construction backlog and public work represents 89 percent of backlog. The backlog includes a variety of projects such as highway grading, paving and underground projects, airports, bridge work, reclamation and harbor expansions.

• The Company's approximate backlog in North Dakota as of December 31, 2013, was $97 million. North Dakota backlog was $46 million a year ago.

• Projected revenues included in the Company's 2014 earnings guidance are in the range of $1.6 billion to $1.8 billion.

• The Company anticipates margins in 2014 to be in line with 2013 margins.

• The Company continues to pursue opportunities for expansion in energy projects such as refineries, transmission, wind towers and geothermal. Initiatives are aimed at capturing additional market share and expanding into new markets.

• As the country's sixth-largest sand and gravel producer, the Company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.

Construction services

• Approximate work backlog as of December 31, 2013, was $459 million, compared to $325 million a year ago. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.

48

• Projected revenues included in the Company's 2014 earnings guidance are in the range of $1.0 billion to $1.1 billion.

• The Company anticipates lower margins in 2014 compared to 2013.

• The Company continues to pursue opportunities for expansion in energy projects such as refineries, transmission, substations, utility services, as well as solar. Initiatives are aimed at capturing additional market share and expanding into new markets.

New Accounting Standards

For information regarding new accounting standards, see Item 8 - Note 1, which is incorporated herein by reference.

Critical Accounting Policies Involving Significant Estimates

The Company has prepared its financial statements in conformity with GAAP. The preparation of these financial statements requires management 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. The Company's significant accounting policies are discussed in Item 8 - Note 1.

Estimates are used for items such as impairment testing of long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; oil, NGL and natural gas reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. The Company's critical accounting policies are subject to judgments and uncertainties that affect the application of such policies. As discussed below, the Company's financial position or results of operations may be materially different when reported under different conditions or when using different assumptions in the application of such policies.

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. The following critical accounting policies involve significant judgments and estimates.

Oil and natural gas properties

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 extent, quality and reliability of this data can vary. Other factors used in the reserve estimates are prices, market differentials, estimates of well operating and future development costs, taxes, timing of operations, and the interests owned by the Company in the properties. These estimates are refined as new information becomes available.

As these estimates change, calculated proved reserves may change. Changes in proved reserve quantities impact the Company's depreciation, depletion and amortization expense since the Company uses the units-of-production method to amortize its oil and natural gas properties. The proved reserves are also used as the basis for the disclosures in Item 8 - Supplementary Financial Information and are the underlying basis of the "ceiling test" for the Company's oil and natural gas properties.

The Company uses the full-cost method of accounting for its exploration and production activities. Under this method, capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash flows associated with asset retirement obligations that have been accrued on the balance sheet. Judgments and assumptions are made when estimating and valuing proved reserves. There is risk that lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in additional future noncash write-downs of the Company's oil and natural gas properties.

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Impairment of long-lived assets and intangibles

The Company reviews the carrying values of its long-lived assets and intangibles, excluding oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable and at least annually for goodwill.

Goodwill The Company performs its goodwill impairment testing annually in the fourth quarter. In addition, the test is performed on an interim basis whenever events or circumstances indicate that the carrying amount of goodwill may not be recoverable. Examples of such events or circumstances may include a significant adverse change in business climate, weakness in an industry in which the Company's reporting units operate or recent significant cash or operating losses with expectations that those losses will continue.

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 Item 8 - Note 15. The first step of the impairment test involves comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the years ended December 31, 2013, 2012, and 2011, there were no impairment losses recorded. At December 31, 2013, 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 10 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 2013. 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.

Long-Lived Assets Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows could negatively affect the fair value of the Company's assets and result in an impairment charge. If an impairment indicator exists for tangible and intangible assets, excluding goodwill, the asset group held and used is tested for recoverability by comparing 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.

There is risk involved when determining the fair value of assets, tangible and intangible, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the asset could be different using different estimates and assumptions in the valuation techniques used.

The Company believes its estimates used in calculating the fair value of long-lived assets, including goodwill and identifiable intangibles, are reasonable based on the information that is known when the estimates are made.

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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 recognition of revenue requires the Company to make estimates and assumptions that affect the reported amounts of revenue. Critical estimates related to the recognition of revenue include costs on construction contracts under the 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. This method depends largely on the ability to make reasonably dependable estimates related to the extent of progress toward completion of the contract, contract revenues and contract costs. Inasmuch as contract prices are generally set before the work is performed, the estimates pertaining to every project could contain significant unknown risks such as volatile labor, material and fuel costs, weather delays, adverse project site conditions, unforeseen actions by regulatory agencies, performance by subcontractors, job management and relations with project owners. Changes in estimates could have a material effect on the Company's results of operations, financial position and cash flows.

Several factors are evaluated in determining the bid price for contract work. These include, but are not limited to, the complexities of the job, past history performing similar types of work, seasonal weather patterns, competition and market conditions, job site conditions, work force safety, reputation of the project owner, availability of labor, materials and fuel, project location and project completion dates. As a project commences, estimates are continually monitored and revised as information becomes available and actual costs and conditions surrounding the job become known. If a loss is anticipated on a contract, the loss is immediately recognized.

The Company believes its estimates surrounding percentage-of-completion accounting are reasonable based on the information that is known when the estimates are made. The Company has contract administration, accounting and management control systems in place that allow its estimates to be updated and monitored on a regular basis. Because of the many factors that are evaluated in determining bid prices, it is inherent that the Company's estimates have changed in the past and will continually change in the future as new information becomes available for each job. There were no material changes in contract estimates at the individual contract level in 2013.

Pension and other postretirement benefits

The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to these plans. Costs of providing pension and other postretirement benefits bear the risk of change, as they are dependent upon numerous factors based on assumptions of future conditions.

The Company makes various assumptions when determining plan costs, including the current discount rates and the expected long-term return on plan assets, the rate of compensation increases and healthcare cost trend rates. In selecting the expected long-term return on plan assets, which is considered to be one of the key variables in determining benefit expense or income, the Company considers historical returns, current market conditions and expected future market trends, including changes in interest rates and equity and bond market performance. Another key variable in determining benefit expense or income is the discount rate. In selecting the discount rate, the Company matches forecasted future cash flows of the pension and postretirement plans to a yield curve which consists of a hypothetical portfolio of high-quality corporate bonds with varying maturity dates, as well as other factors, as a basis. The Company's pension and other postretirement benefit plan assets are primarily made up of equity and fixed-income investments. Fluctuations in actual equity and bond market returns as well as changes in general interest rates may result in increased or decreased pension and other postretirement benefit costs in the future. Management estimates the rate of compensation increase based on long-term assumed wage increases and the healthcare cost trend rates are determined by historical and future trends. The Company estimates that a 50 basis point decrease in the discount rate or in the expected return on plan assets would each increase expense by less than $1.5 million (after tax) for the year ended December 31, 2013.

The Company believes the estimates made for its pension and other postretirement benefits are reasonable based on the information that is known when the estimates are made. These estimates and assumptions are subject to a number of variables and are expected to change in the future. Estimates and assumptions will be affected by changes in the discount rate, the expected long-term return on plan assets, the rate of compensation increase and healthcare cost trend rates. The Company plans to continue to use its current methodologies to determine plan costs. For additional information on the assumptions used in determining plan costs, see Item 8 - Note 16.

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Income taxes

Income taxes require significant judgments and estimates including the determination of income tax expense, deferred tax assets and liabilities and, if necessary, any valuation allowances that may be required for deferred tax assets and accruals for uncertain tax positions. The effective income tax rate is subject to variability from period to period as a result of changes in federal and state income tax rates and/or changes in tax laws. In addition, the effective tax rate may be affected by other changes including the allocation of property, payroll and revenues between states. The Company estimates that a one percent change in the effective tax rate would affect the income tax expense by less than $5.0 million for the year ended December 31, 2013.

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.

The Company believes its estimates surrounding income taxes are reasonable based on the information that is known when the estimates are made.

Liquidity and Capital Commitments

At December 31, 2013, the Company had cash and cash equivalents of $45.2 million and available capacity of $569.4 million under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing within one year from various sources, including internally generated funds; the Company's credit facilities, as described later; and through the issuance of long-term debt and the Company's equity securities.

Cash flows

Operating activities The changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital.

Cash flows provided by operating activities in 2013 increased$157.5 million from 2012. The increase was primarily due to lower working capital requirements of $132.9 million, primarily at the exploration and production and construction materials and contracting businesses and higher income from continuing operations, largely at the exploration and production business.

Cash flows provided by operating activities in 2012 decreased $41.9 million from 2011, largely due to higher working capital requirements of $82.6 million, primarily at the exploration and production business and the electric and natural gas distribution businesses. Excluding working capital requirements, the Company experienced increased cash flows from operating activities primarily at the construction services business. In addition, excluding the effect of the write-downs of oil and natural gas properties, the decrease was partially offset by higher deferred income taxes of $18.5 million, largely due to increased capital expenditures at the exploration and production business.

Investing activities Cash flows used in investing activities in 2013 decreased $105.3 million from 2012 primarily due to higher proceeds from the sale of properties, largely at the exploration and production business, as well as lower acquisition-related capital expenditures, primarily at the pipeline and energy services business. Partially offsetting the decrease in cash flows used in investing activities was higher ongoing capital expenditures of $36.5 million, largely related to Dakota Prairie Refinery at the pipeline and energy services business and electric generation projects at the electric business, partially offset by lower capital expenditures at the exploration and production business.

Cash flows used in investing activities in 2012 increased $423.4 million from 2011 primarily due to higher ongoing capital expenditures of $375.9 million, largely at the exploration and production and electric and natural gas distribution businesses, as

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well as increased acquisition-related capital expenditures at the pipeline and energy services business. Lower investments partially offset the increase in cash flows used in investing activities.

Financing activitiesCash flows provided by financing activities in 2013 decreased$152.8 million from 2012, primarily due to higher repayment of long-term debt of $284.9 million. Partially offsetting the decrease in cash flows provided by financing activities were lower dividends paid of $61.4 million resulting from the Company accelerating the payment date for the quarterly common stock dividend from January 1, 2013 to December 31, 2012; higher issuance of long-term debt of $40.0 million; as well as a cash contribution of $27.0 million related to the noncontrolling interest.

Cash flows provided by financing activities in 2012 increased $410.8 million from 2011, primarily due to higher issuance of long-term debt and short-term borrowings of $467.7 million and $20.1 million, respectively, as well as lower repayment of short-term borrowings of $20.0 million. Partially offsetting the increase in cash flows provided by financing activities was higher repayment of long-term debt of $53.6 million, as well as higher dividends paid of $36.4 million resulting from the Company accelerating the payment date for the quarterly common stock dividend to December 31, 2012 from January 1, 2013.

Defined benefit pension plans

The Company has qualified noncontributory defined benefit pension plans for certain employees. Plan assets consist of investments in equity and fixed-income securities. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to the pension plans. Actuarial assumptions include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as determined by the Company within certain guidelines. At December 31, 2013, the pension plans' accumulated benefit obligations exceeded these plans' assets by approximately $67.9 million. Pretax pension expense reflected in the years ended December 31, 2013, 2012 and 2011, was $3.0 million, $204,000 and $3.7 million, respectively. The Company's pension expense is currently projected to be approximately $2.5 million to $3.5 million in 2014. Funding for the pension plans is actuarially determined. The minimum required contributions for 2013, 2012 and 2011 were approximately $13.2 million, $16.1 million and $9.3 million, respectively. For more information on the Company's pension plans, see Item 8 - Note 16.

Capital expenditures

The Company's capital expenditures for 2011 through 2013 and as anticipated for 2014 through 2016 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term debt.

	Actual									Estimated*
	2011			2012			2013			2014			2015			2016
	(In millions)
Capital expenditures:
Electric	$	52		$	112		$	169		$	161		$	140		$	88
Natural gas distribution	71			130			101			141			166			139
Pipeline and energy services**	45			134			127			162			44			67
Exploration and production	273			554			391			441			501			518
Construction materials and contracting	52			45			35			38			69			58
Construction services	10			15			15			22			14			15
Other	19			1			2			1			3			3
Net proceeds from sale or disposition of property and other	(41		)	(57		)	(112		)	(7		)	(5		)	(7		)
Net capital expenditures	481			934			728			959			932			881
Retirement of long-term debt	85			139			424			12			269			294
	$	566		$	1,073		$	1,152		$	971		$	1,201		$	1,175
* The Company continues to evaluate potential future acquisitions and other growth opportunities which are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the above estimates.
** 2012 includes a 50 percent undivided interest in the Pronghorn oil and natural gas gathering and processing assets, as discussed in Item 8 - Note 2. 2013 - 2016 include the Company's share of capital expenditures related to Dakota Prairie Refinery and excludes expenditures related to the proposed 375-mile natural gas pipeline at the pipeline and energy services business, as discussed in Prospective Information and Item 8 - Note 19.

Capital expenditures for 2013, 2012 and 2011 in the preceding table include noncash capital expenditure-related accounts payable and exclude capital expenditures of the noncontrolling interest related to Dakota Prairie Refinery. These net transactions were $(56.8) million in 2013, $33.7 million in 2012 and $24.0 million in 2011.

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The 2013 capital expenditures, including those for the retirement of long-term debt, were met from internal sources and the issuance of long-term debt and the Company's equity securities. Estimated capital expenditures for the years 2014 through 2016 include those for:

• System upgrades

• Routine replacements

• Service extensions

• Routine equipment maintenance and replacements

• Buildings, land and building improvements

• Pipeline, gathering and other midstream projects

• Further development of existing properties, acquisition of additional leasehold acreage and exploratory drilling at the exploration and production segment

• Power generation and transmission opportunities, including certain costs for additional electric generating capacity

• Environmental upgrades

• The Company's proportionate share of Dakota Prairie Refinery at the pipeline and energy services segment

• Other growth opportunities

The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimates in the preceding table. It is anticipated that all of the funds required for capital expenditures and retirement of long-term debt for the years 2014 through 2016 will be met from various sources, including internally generated funds; the Company's credit facilities, as described later; and through the issuance of long-term debt and the Company's equity securities.

Capital resources

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, all of which the Company and its subsidiaries, as applicable, were in compliance with at December 31, 2013. 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. For additional information on the covenants, certain other conditions and cross-default provisions, see Item 8 - Note 9.

The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries at December 31, 2013:

Company	Facility		Facility Limit			Amount Outstanding			Letters of Credit			Expiration Date
			(In millions)
MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement	(a)	$	125.0		$	78.9	(b)	$	—		10/4/17
Cascade Natural Gas Corporation	Revolving credit agreement		$	50.0	(c)	$	11.5		$	2.2	(d)	7/9/18
Intermountain Gas Company	Revolving credit agreement		$	65.0	(e)	$	3.0		$	—		7/13/18
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	75.0	(b)	$	—		6/8/17
(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 $150 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 million. (d) The outstanding letter of credit, as discussed in Item 8 - Note 19, reduces the amount available under the credit       agreement. (e) Certain provisions allow for increased borrowings, up to a maximum of $90 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 $650 million). There were no amounts outstanding under the credit agreement.

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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 commercial paper borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the seasonality of the construction businesses.

The following includes information related to the preceding table.

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 Company's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in the Company's credit ratings have not limited, nor are currently expected to limit, the Company's ability to access the capital markets. If the Company were to experience a downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.

Prior to the maturity of the credit agreement, the Company expects that it will negotiate the extension or replacement of this agreement. If the Company is unable to successfully negotiate an extension of, or replacement for, the credit agreement, or if the fees on this facility become too expensive, which the Company does not currently anticipate, the Company would seek alternative funding.

The Company's coverage of fixed charges including preferred stock dividends was 4.8 times for the 12 months ended December 31, 2013. Due to the $246.8 million after-tax noncash write-downs of oil and natural gas properties in 2012, earnings were insufficient by $51.2 million to cover fixed charges for the 12 months ended December 31, 2012. If the $246.8 million after-tax noncash write-downs were excluded, the coverage of fixed charges including preferred stock dividends would have been 4.4 times for the 12 months ended December 31, 2012.

The coverage of fixed charges including preferred stock dividends, that excludes the effect of the after-tax noncash write-downs of oil and natural gas properties is a non-GAAP financial measure. The Company believes that this non-GAAP financial measure is useful because the write-downs excluded are not indicative of the Company's cash flows available to meets its fixed charges obligations. The presentation of this additional information is not meant to be considered a substitute for the financial measure prepared in accordance with GAAP.

Total equity as a percent of total capitalization was 60 percent at both December 31, 2013 and 2012. This ratio is calculated as the Company's total equity, divided by the Company's total capital. Total capital is the Company's total debt, including short-term borrowings and long-term debt due within one year, plus total equity. This ratio indicates how a company is financing its operations, as well as its financial strength.

On May 20, 2013, the Company entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 7.5 million shares of the Company's common stock. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement. Sales of such common stock may not be made after February 28, 2016. Proceeds from the shares of common stock under the agreement are expected to be used for corporate development purposes and other general corporate purposes. The Company issued 499,330 shares of stock during the fourth quarter of 2013 under the Equity Distribution Agreement, receiving net proceeds of $14.6 million.

The Company currently has a shelf registration statement on file with the SEC, under which the Company may issue and sell any combination of common stock and debt securities. The Company may sell all or a portion of such securities if warranted by market conditions and the Company's capital requirements. Any public offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder. The Company's board of directors currently has authorized the issuance and sale of up to an aggregate of $1.0 billion worth of such securities. The Company's board of directors reviews this authorization on a periodic basis and the aggregate amount of securities authorized may be increased in the future.

Cascade Natural Gas Corporation On July 9, 2013, Cascade entered into a revolving credit agreement which replaced the previous revolving credit agreement and extended the termination date to July 9, 2018.

Intermountain Gas Company On July 15, 2013, Intermountain entered into a revolving credit agreement which replaced the previous revolving credit agreement and extended the termination date to July 13, 2018.

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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 objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in Centennial's credit ratings have not limited, nor are currently expected to limit, Centennial's ability to access the capital markets. If Centennial were to experience a downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.

Prior to the maturity of the Centennial credit agreement, Centennial expects that it will negotiate the extension or replacement of this agreement, which provides credit support to access the capital markets. In the event Centennial is unable to successfully negotiate this agreement, or in the event the fees on this facility become too expensive, which Centennial does not currently anticipate, it would seek alternative funding.

WBI Energy Transmission, Inc. On September 12, 2013, WBI Energy Transmission entered into a $175 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, 2013, which reduced capacity under this uncommitted private shelf agreement.

Off balance sheet arrangements

In connection with the sale of the Brazilian Transmission Lines, 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. For more information, see Item 8 - Note 4.

Centennial continues to guarantee CEM's obligations under a construction contract for an electric generating facility near Hobbs, New Mexico. For more information, see Item 8 - Note 19.

Contractual obligations and commercial commitments

For more information on the Company's contractual obligations on derivative instruments, long-term debt, operating leases and purchase commitments, see Item 8 - Notes 7, 9 and 19. At December 31, 2013, the Company's commitments under these obligations were as follows:

	2014		2015		2016		2017		2018		Thereafter		Total
	(In millions)
Long-term debt	$	12.3	$	269.4	$	293.8	$	204.9	$	130.2	$	944.0	$	1,854.6
Estimated interest payments*	92.2		88.2		66.2		56.7		53.8		466.1		823.2
Operating leases	32.8		26.6		22.2		17.8		13.5		45.7		158.6
Purchase commitments	635.8		281.6		170.7		100.3		73.4		910.8		2,172.6
Commodity derivatives	7.5		—		—		—		—		—		7.5
	$	780.6	$	665.8	$	552.9	$	379.7	$	270.9	$	2,366.6	$	5,016.5
* Estimated interest payments are calculated based on the applicable rates and payment dates.

At December 31, 2013, the Company had total liabilities of $98.5 million related to asset retirement obligations that are excluded from the table above. Of the total asset retirement obligations, the current portion was approximately $18.0 million at December 31, 2013, and was included in other accrued liabilities on the Consolidated Balance Sheet. The remainder, which constitutes the long-term portion of asset retirement obligations, was included in other liabilities on the Consolidated Balance Sheet. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. For more information, see Item 8 - Note 10.

Not reflected in the previous table are $14.9 million in uncertain tax positions. For more information, see Item 8 - Note 14.

The Company's minimum funding requirements for its defined benefit pension plans for 2014, which are not reflected in the previous table, are $10.9 million. For information on potential contributions above the minimum funding requirements, see Item 8 - Note 16.

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The Company's multiemployer plan contributions are based on union employee payroll, which cannot be determined in advance for future periods. The Company may also be required to make additional contributions to its multiemployer plans as a result of their funded status. For more information, see Item 1A - Risk Factors and Item 8 - Note 16.

Effects of Inflation

Inflation did not have a significant effect on the Company's operations in 2013, 2012 or 2011.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to the impact of market fluctuations associated with commodity prices, interest rates and foreign currency. The Company has policies and procedures to assist in controlling these market risks and utilizes derivatives to manage a portion of its risk.

For more information on derivatives and the Company's derivative policies and procedures, see Item 8 - Consolidated Statements of Comprehensive Income and Notes 1 and 7.

Commodity price risk

Fidelity utilizes derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on forecasted sales of oil and natural gas production.

The following table summarizes derivative agreements entered into by Fidelity as of December 31, 2013. These agreements call for Fidelity to receive fixed prices and pay variable prices.

(Forward notional volume and fair value in thousands)
	Weighted Average Fixed Price (Per Bbl/MMBtu)		Forward Notional Volume (Bbl/MMBtu)	Fair Value
Oil swap agreements maturing in 2014	$	94.74	2,911	$	(4,771	)
Natural gas swap agreements maturing in 2014	$	4.10	14,600	$	(1,265	)
Natural gas swap agreement maturing in 2015	$	4.28	3,650	$	503

The following table summarizes derivative agreements entered into by Fidelity as of December 31, 2012. These agreements call for Fidelity to receive fixed prices and pay variable prices.

(Forward notional volume and fair value in thousands)
	Weighted Average Fixed Price (Per Bbl/MMBtu)		Forward Notional Volume (Bbl/MMBtu)	Fair Value
Oil swap agreements maturing in 2013	$	99.83	1,825	$	12,038
Natural gas swap agreements maturing in 2013	$	3.89	10,950	$	3,753
	Weighted Average Floor/Ceiling Price (Per Bbl)		Forward Notional Volume (Bbl)	Fair Value
Oil collar agreements maturing in 2013	$92.50/$107.03		730	$	2,513

Interest rate risk

The Company uses fixed and variable rate long-term debt to partially finance capital expenditures and mandatory debt retirements. These debt agreements expose the Company to market risk related to changes in interest rates. The Company manages this risk by taking advantage of market conditions when timing the placement of long-term financing. The Company

57

from time to time uses interest rate swap agreements to manage a portion of the Company's interest rate risk and may take advantage of such agreements in the future to minimize such risk.

Centennial entered into interest rate swap agreements to manage a portion of its interest rate exposure on the forecasted issuance on long-term debt. The agreements called for Centennial to receive payments from or make payments to counterparties based on the difference between fixed and variable rates as specified by the interest rate swap agreements.

At December 31, 2013, the Company had no outstanding interest rate hedges.

The following table summarizes derivative instruments entered into by Centennial as of December 31, 2012. The agreements call for Centennial to receive variable rates and pay fixed rates.

(Notional amount and fair value in thousands)
	Weighted Average Fixed Interest Rate		Notional Amount		Fair Value
Interest rate swap agreements with mandatory termination dates in 2013	3.22	%	$	50,000	$	(6,255	)

The following table shows the amount of debt, including current portion, and related weighted average interest rates, both by expected maturity dates, as of December 31, 2013.

	2014			2015			2016			2017			2018			Thereafter			Total			Fair Value
	(Dollars in millions)
Long-term debt:
Fixed rate	$	9.3		$	266.4		$	288.5		$	43.5		$	108.4		$	906.5		$	1,622.6		$	1,683.0
Weighted average interest rate	6.9		%	5.7		%	6.4		%	6.3		%	6.1		%	5.1		%	5.6		%	—
Variable rate	$	3.0		$	3.0		$	5.3		$	161.4		$	21.8		$	37.5		$	232.0		$	229.6
Weighted average interest rate	1.2		%	1.2		%	1.8		%	.5		%	2.0		%	2.4		%	1.0		%	—

Foreign currency risk

The Company's investment in ECTE is exposed to market risks from changes in foreign currency exchange rates between the U.S. dollar and the Brazilian Real. For more information, see Item 8 - Note 4. At December 31, 2013 and 2012, the Company had no outstanding foreign currency hedges.

58

Item 8. Financial Statements and Supplementary Data

Management's Report on Internal Control Over Financial Reporting

The management of MDU Resources Group, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company's internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (1992).

Based on our evaluation under the framework in Internal Control-Integrated Framework (1992), management concluded that the Company's internal control over financial reporting was effective as of December 31, 2013.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2013, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report.

/s/ David L. Goodin	/s/ Doran N. Schwartz
David L. Goodin	Doran N. Schwartz
President and Chief Executive Officer	Vice President and Chief Financial Officer

59

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of MDU Resources Group, Inc.

We have audited the accompanying consolidated balance sheets of MDU Resources Group, Inc. and subsidiaries (the "Company") as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MDU Resources Group, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2014 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Minneapolis, Minnesota

February 21, 2014

60

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of MDU Resources Group, Inc.

We have audited the internal control over financial reporting of MDU Resources Group, Inc. and subsidiaries (the "Company") as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control-Integrated Framework(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2013 of the Company and our report dated February 21, 2014 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.

/s/ Deloitte & Touche LLP

Minneapolis, Minnesota

February 21, 2014

61

MDU RESOURCES GROUP, INC.

Consolidated Statements of Income

Years ended December 31,	2013			2012			2011
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	1,264,574		$	1,131,626		$	1,343,714
Exploration and production, construction materials and contracting, construction services and other	3,197,830			2,943,805			2,706,778
Total operating revenues	4,462,404			4,075,431			4,050,492
Operating expenses:
Fuel and purchased power	83,528			72,380			64,485
Purchased natural gas sold	505,065			425,220			572,187
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services	269,825			254,194			275,866
Exploration and production, construction materials and contracting, construction services and other	2,535,872			2,377,285			2,215,269
Depreciation, depletion and amortization	386,856			359,205			343,395
Taxes, other than income	188,359			176,140			172,923
Write-downs of oil and natural gas properties (Note 1)	—			391,800			—
Total operating expenses	3,969,505			4,056,224			3,644,125
Operating income	492,899			19,207			406,367
Earnings (loss) from equity method investments	(132		)	5,383			4,693
Other income	6,768			6,642			6,520
Interest expense	83,917			76,699			81,354
Income (loss) before income taxes	415,618			(45,467		)	336,226
Income taxes	136,736			(31,146		)	110,274
Income (loss) from continuing operations	278,882			(14,321		)	225,952
Income (loss) from discontinued operations, net of tax (Note 3)	(312		)	13,567			(12,926		)
Net income (loss)	278,570			(754		)	213,026
Net loss attributable to noncontrolling interest	(363		)	—			—
Dividends declared on preferred stocks	685			685			685
Earnings (loss) on common stock	$	278,248		$	(1,439	)	$	212,341
Earnings (loss) per common share - basic:
Earnings (loss) before discontinued operations	$	1.47		$	(.08	)	$	1.19
Discontinued operations, net of tax	—			.07			(.07		)
Earnings (loss) per common share - basic	$	1.47		$	(.01	)	$	1.12
Earnings (loss) per common share - diluted:
Earnings (loss) before discontinued operations	$	1.47		$	(.08	)	$	1.19
Discontinued operations, net of tax	—			.07			(.07		)
Earnings (loss) per common share - diluted	$	1.47		$	(.01	)	$	1.12
Weighted average common shares outstanding - basic	188,855			188,826			188,763
Weighted average common shares outstanding - diluted	189,693			188,826			188,905

The accompanying notes are an integral part of these consolidated financial statements.

62

MDU RESOURCES GROUP, INC.

Consolidated Statements of Comprehensive Income

Years ended December 31,	2013			2012			2011
	(In thousands)
Net income (loss)	$	278,570		$	(754	)	$	213,026
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $(3,116), $4,829 and $4,683 in 2013, 2012 and 2011, respectively	(5,594		)	8,497			7,900
Reclassification adjustment for (gain) loss on derivative instruments included in net income, net of tax of $(2,548), $(5,141) and $0 in 2013, 2012 and 2011, respectively	(4,189		)	(8,754		)	—
Net unrealized gain (loss) on derivative instruments qualifying as hedges	(9,783		)	(257		)	7,900
Postretirement liability adjustment:
Postretirement liability gains (losses) arising during the period, net of tax of $11,818, $(2,060) and $(14,205) in 2013, 2012 and 2011, respectively	18,539			(3,106		)	(23,473		)
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $1,276, $1,379 and $632 in 2013, 2012 and 2011, respectively	2,001			2,079			1,046
Postretirement liability adjustment	20,540			(1,027		)	(22,427		)
Foreign currency translation adjustment:
Foreign currency translation adjustment recognized during the period, net of tax of $(177), $(296) and $(767) in 2013, 2012 and 2011, respectively	(299		)	(476		)	(1,189		)
Reclassification adjustment for (gain) loss on foreign currency translation adjustment included in net income, net of tax of $70, $2 and $(65) in 2013, 2012 and 2011, respectively	143			3			(106		)
Foreign currency translation adjustment	(156		)	(473		)	(1,295		)
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(105), $(52) and $(20) in 2013, 2012 and 2011, respectively	(194		)	(97		)	(36		)
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $59, $72 and $64 in 2013, 2012 and 2011, respectively	109			134			118
Net unrealized gain (loss) on available-for-sale investments	(85		)	37			82
Other comprehensive income (loss)	10,516			(1,720		)	(15,740		)
Comprehensive income (loss)	289,086			(2,474		)	197,286
Comprehensive loss attributable to noncontrolling interest	(363		)	—			—
Comprehensive income (loss) attributable to common stockholders	$	289,449		$	(2,474	)	$	197,286

The accompanying notes are an integral part of these consolidated financial statements.

63

MDU RESOURCES GROUP, INC.

Consolidated Balance Sheets

December 31,	2013			2012
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents	$	45,225		$	49,042
Receivables, net	713,067			678,123
Inventories	282,391			317,415
Deferred income taxes	25,048			22,846
Commodity derivative instruments	1,447			18,304
Prepayments and other current assets	49,510			42,351
Total current assets	1,116,688			1,128,081
Investments	112,939			103,243
Property, plant and equipment (Note 1)	8,803,866			8,107,751
Less accumulated depreciation, depletion and amortization	3,872,487			3,608,912
Net property, plant and equipment	4,931,379			4,498,839
Deferred charges and other assets:
Goodwill (Note 5)	636,039			636,039
Other intangible assets, net (Note 5)	13,099			17,129
Other	251,188			299,160
Total deferred charges and other assets	900,326			952,328
Total assets	$	7,061,332		$	6,682,491
Liabilities and Equity
Current liabilities:
Short-term borrowings (Note 9)	$	11,500		$	28,200
Long-term debt due within one year	12,277			134,108
Accounts payable	404,961			388,015
Taxes payable	74,175			46,475
Dividends payable	33,737			171
Accrued compensation	69,661			48,448
Commodity derivative instruments	7,483			—
Other accrued liabilities	171,106			204,698
Total current liabilities	784,900			850,115
Long-term debt (Note 9)	1,842,286			1,610,867
Deferred credits and other liabilities:
Deferred income taxes	859,306			755,102
Other liabilities	718,938			818,159
Total deferred credits and other liabilities	1,578,244			1,573,261
Commitments and contingencies (Notes 16, 18 and 19)
Equity:
Preferred stocks (Note 11)	15,000			15,000
Common stockholders' equity:
Common stock (Note 12) Authorized - 500,000,000 shares, $1.00 par value Issued - 189,868,780 shares in 2013 and 189,369,450 shares in 2012	189,869			189,369
Other paid-in capital	1,056,996			1,039,080
Retained earnings	1,603,130			1,457,146
Accumulated other comprehensive loss	(38,205		)	(48,721		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)
Total common stockholders' equity	2,808,164			2,633,248
Total stockholders' equity	2,823,164			2,648,248
Noncontrolling interest	32,738			—
Total equity	2,855,902			2,648,248
Total liabilities and equity	$	7,061,332		$	6,682,491

The accompanying notes are an integral part of these consolidated financial statements.

64

MDU RESOURCES GROUP, INC.

Consolidated Statements of Equity

Years ended December 31, 2013, 2012 and 2011
							Other Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Loss								Non-
	Preferred Stock			Common Stock												Treasury Stock					controlling
	Shares	Amount		Shares	Amount											Shares		Amount			Interest			Total
	(In thousands, except shares)
Balance at December 31, 2010	150,000	$	15,000	188,901,379	$	188,901	$	1,026,349		$	1,497,439		$	(31,261	)	(538,921	)	$	(3,626	)	$	—		$	2,692,802
Net income	—	—		—	—		—			213,026			—			—		—			—			213,026
Other comprehensive loss	—	—		—	—		—			—			(15,740		)	—		—			—			(15,740		)
Dividends declared on preferred stocks	—	—		—	—		—			(685		)	—			—		—			—			(685		)
Dividends declared on common stock	—	—		—	—		—			(123,657		)	—			—		—			—			(123,657		)
Stock-based compensation	—	—		423,591	424		10,164			—			—			—		—			—			10,588
Net tax deficit on stock-based compensation	—	—		—	—		(909		)	—			—			—		—			—			(909		)
Issuance of common stock	—	—		7,515	7		135			—			—			—		—			—			142
Balance at December 31, 2011	150,000	15,000		189,332,485	189,332		1,035,739			1,586,123			(47,001		)	(538,921	)	(3,626		)	—			2,775,567
Net loss	—	—		—	—		—			(754		)	—			—		—			—			(754		)
Other comprehensive loss	—	—		—	—		—			—			(1,720		)	—		—			—			(1,720		)
Dividends declared on preferred stocks	—	—		—	—		—			(685		)	—			—		—			—			(685		)
Dividends declared on common stock	—	—		—	—		—			(127,538		)	—			—		—			—			(127,538		)
Stock-based compensation	—	—		25,743	26		5,094			—			—			—		—			—			5,120
Net tax deficit on stock-based compensation	—	—		—	—		(1,958		)	—			—			—		—			—			(1,958		)
Issuance of common stock	—	—		11,222	11		205			—			—			—		—			—			216
Balance at December 31, 2012	150,000	15,000		189,369,450	189,369		1,039,080			1,457,146			(48,721		)	(538,921	)	(3,626		)	—			2,648,248
Net income (loss)	—	—		—	—		—			278,933			—			—		—			(363		)	278,570
Other comprehensive income	—	—		—	—		—			—			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	—	—		499,330	500		14,054			—			—			—		—			—			14,554
Contribution from non-controlling interest	—	—		—	—		—			—			—			—		—			33,101			33,101
Balance at December 31, 2013	150,000	$	15,000	189,868,780	$	189,869	$	1,056,996		$	1,603,130		$	(38,205	)	(538,921	)	$	(3,626	)	$	32,738		$	2,855,902

The accompanying notes are an integral part of these consolidated financial statements.

65

MDU RESOURCES GROUP, INC.

Consolidated Statements of Cash Flows

Years ended December 31,	2013			2012			2011
	(In thousands)
Operating activities:
Net income (loss)	$	278,570		$	(754	)	$	213,026
Income (loss) from discontinued operations, net of tax	(312		)	13,567			(12,926		)
Income (loss) from continuing operations	278,882			(14,321		)	225,952
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	386,856			359,205			343,395
Earnings (loss), net of distributions, from equity method investments	2,281			(618		)	(2,111		)
Deferred income taxes	86,778			(7,503		)	118,925
Unrealized (gain) loss on commodity derivatives	6,267			624			(1,827		)
Write-downs of oil and natural gas properties (Note 1)	—			391,800			—
Changes in current assets and liabilities, net of acquisitions:
Receivables	(40,669		)	(13,416		)	(30,452		)
Inventories	30,452			(42,334		)	(24,226		)
Other current assets	(9,474		)	297			7,729
Accounts payable	15,084			6,352			(12,263		)
Other current liabilities	29,392			(59,001		)	33,738
Other noncurrent changes	(43,937		)	(33,665		)	(31,538		)
Net cash provided by continuing operations	741,912			587,420			627,322
Net cash provided by (used in) discontinued operations	281			(2,680		)	(674		)
Net cash provided by operating activities	742,193			584,740			626,648
Investing activities:
Capital expenditures	(909,400		)	(872,920		)	(497,000		)
Acquisitions, net of cash acquired	—			(67,261		)	(157		)
Net proceeds from sale or disposition of property and other	124,541			40,110			40,107
Investments	302			9,725			(10,302		)
Proceeds from sale of equity method investments	1,896			2,394			2,807
Net cash used in continuing operations	(782,661		)	(887,952		)	(464,545		)
Net cash provided by discontinued operations	—			—			—
Net cash used in investing activities	(782,661		)	(887,952		)	(464,545		)
Financing activities:
Issuance of short-term borrowings	9,500			20,100			—
Repayment of short-term borrowings	—			—			(20,000		)
Issuance of long-term debt	507,924			467,957			300
Repayment of long-term debt	(423,707		)	(138,775		)	(85,151		)
Proceeds from issuance of common stock	14,554			88			5,744
Dividends paid	(98,405		)	(159,768		)	(123,323		)
Excess tax benefit on stock-based compensation	—			26			1,239
Contribution from noncontrolling interest	27,000			—			—
Net cash provided by (used in) continuing operations	36,866			189,628			(221,191		)
Net cash provided by discontinued operations	—			—			—
Net cash provided by (used in) financing activities	36,866			189,628			(221,191		)
Effect of exchange rate changes on cash and cash equivalents	(215		)	(146		)	(214		)
Decrease in cash and cash equivalents	(3,817		)	(113,730		)	(59,302		)
Cash and cash equivalents - beginning of year	49,042			162,772			222,074
Cash and cash equivalents - end of year	$	45,225		$	49,042		$	162,772

The accompanying notes are an integral part of these consolidated financial statements.

66

Notes to Consolidated Financial Statements

Note 1 - Summary of Significant Accounting Policies

Basis of presentation

The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline and energy services, exploration and production, construction materials and contracting, construction services and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Exploration and production, construction materials and contracting, construction services and other are nonregulated. For further descriptions of the Company's businesses, see Note 15. Intercompany balances and transactions have been eliminated in consolidation, except for certain transactions related to the Company's regulated operations in accordance with GAAP. The statements also include the ownership interests in the assets, liabilities and expenses of jointly owned electric generating facilities.

The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by the Company's nonregulated businesses.

The Company's regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals.

Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.

Management has also evaluated the impact of events occurring after December 31, 2013, up to the date of issuance of these consolidated financial statements.

Cash and cash equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts receivable and allowance for doubtful accounts

Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. For more information, see Percentage-of-completion method in this note. The total balance of receivables past due 90 days or more was $36.4 million and $34.3 million as of December 31, 2013 and 2012, 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 as of December 31, 2013 and 2012, was $10.1 million and $10.8 million, respectively.

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Inventories and natural gas in storage

Inventories, other than natural gas in storage for the Company's regulated operations, were stated at the lower of average cost or market value. Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories. Inventories at December 31 consisted of:

	2013		2012
	(In thousands)
Aggregates held for resale	$	101,568	$	87,715
Materials and supplies	69,808		69,390
Asphalt oil	38,099		67,480
Merchandise for resale	21,720		31,172
Natural gas in storage (current)	16,417		29,030
Other	34,779		32,628
Total	$	282,391	$	317,415

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 $48.3 million and $49.7 million at December 31, 2013 and 2012, respectively.

Investments

The Company's investments include its equity method and cost method investments as discussed in Note 4, the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company measures its investment in the insurance contract at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated other comprehensive income (loss). For more information, see Notes 8 and 16.

Property, plant and equipment

Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for exploration and production properties as described in Oil and natural gas properties in this note, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, at the exploration and production segment only on costs that have been excluded from the full cost amortization pool and on certain construction projects associated with its other operations. The amount of AFUDC and interest capitalized for the years ended December 31 were as follows:

	2013		2012		2011
	(In thousands)
Interest capitalized	$	6,033	$	8,659	$	10,821
AFUDC - borrowed	$	2,767	$	2,483	$	1,666
AFUDC - equity	$	3,322	$	4,530	$	2,587

Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable aggregate reserves, which are depleted based on the units-of-production method, and exploration and production properties, which are amortized on the units-of-production method based on total proved reserves. The Company collects removal costs for plant assets in regulated utility rates. These amounts are recorded as regulatory liabilities, which are included in other liabilities.

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Property, plant and equipment at December 31 was as follows:

	2013			2012		Weighted Average Depreciable Life in  Years
	(Dollars in thousands, where applicable)
Regulated:
Electric:
Generation	$	570,394		$	546,011	42
Distribution	308,202			276,446		39
Transmission	196,824			180,543		48
Construction in progress	141,365			62,123		-
Other	99,037			85,461		14
Natural gas distribution:
Distribution	1,384,587			1,308,314		40
Construction in progress	46,763			71,679		-
Other	345,551			309,957		25
Pipeline and energy services:
Transmission	418,594			403,126		52
Gathering	39,597			42,420		19
Storage	42,939			42,058		51
Construction in progress	6,937			13,667		-
Other	39,504			38,386		29
Nonregulated:
Pipeline and energy services:
Midstream	213,063			233,840		17
Construction in progress	188,641			29,657		-
Other	12,897			13,379		11
Exploration and production:
Oil and natural gas properties	3,017,879			2,723,356		*
Other	42,969			41,204		8
Construction materials and contracting:
Land	125,551			126,788		-
Buildings and improvements	70,000			73,884		19
Machinery, vehicles and equipment	906,774			899,592		12
Construction in progress	13,315			11,165		-
Aggregate reserves	394,715			393,552		**
Construction services:
Land	4,821			4,723		-
Buildings and improvements	16,628			16,563		20
Machinery, vehicles and equipment	105,991			100,445		6
Other	7,508			8,893		4
Other:
Land	2,837			2,837		-
Other	47,160			47,682		23
Eliminations	(7,177		)	—
Less accumulated depreciation, depletion and amortization	3,872,487			3,608,912
Net property, plant and equipment	$	4,931,379		$	4,498,839

  *  Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $17.41, $15.28 and $12.25 for the years ended December 31, 2013, 2012 and 2011, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $124.9 million and $191.8 million were excluded from amortization at December 31, 2013 and 2012, respectively.

** Depleted on the units-of-production method.

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Impairment of long-lived assets

The Company reviews the carrying values of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. In 2013 and 2012, the Company recognized impairments of $9.0 million (after tax) and $1.7 million (after tax), respectively, which are recorded in operation and maintenance expense on the Consolidated Statements of Income. The impairments are related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a significant decline in natural gas development and production activity largely due to low natural gas prices. The coalbed natural gas gathering assets were written down to fair value that was determined using the income approach. For more information on this nonrecurring fair value measurement, see Note 8.

No significant impairment losses were recorded in 2011. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired.

The goodwill impairment test is a two-step process performed at the reporting unit level. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. For more information on the Company's operating segments, see Note 15. The first step of the impairment test involves comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the years ended December 31, 2013, 2012 and 2011, there were no impairment losses recorded. At December 31, 2013, 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 10 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 2013. Under the market approach, the Company estimates fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants. The Company believes that the estimates and assumptions used in its impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.

Oil and natural gas properties

The Company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized.

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Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash outflows associated with asset retirement obligations that have been accrued on the balance sheet. If capitalized costs, less accumulated amortization and related deferred income taxes, exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.

At December 31, 2013, the Company's full-cost ceiling exceeded the Company's capitalized cost. However, there is risk that lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in additional future noncash write-downs of the Company's oil and natural gas properties.

The Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at September 30, 2012 and December 31, 2012. SEC Defined Prices, adjusted for market differentials, are used to calculate the ceiling test. SEC Defined Prices as of September 30, 2012 and December 31, 2012, were $94.97 per Bbl for NYMEX oil and $2.83 per MMBtu for Henry Hub natural gas and $94.71 per Bbl for NYMEX oil and $2.76 per MMBtu for Henry Hub natural gas, respectively. Accordingly, the Company was required to write down its oil and natural gas producing properties. The noncash write-downs amounted to $160.1 million and $231.7 million ($100.9 million and $145.9 million after tax) for the three months ended September 30, 2012 and December 31, 2012, respectively.

The Company hedged a portion of its oil and natural gas production and the effects of the cash flow hedges were used in determining the full-cost ceiling at September 30, 2012 and December 31, 2012. The Company would have recognized additional write-downs of its oil and natural gas properties of $19.5 million ($12.3 million after tax) at September 30, 2012, and $20.8 million ($13.1 million after tax) at December 31, 2012, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 7.

The following table summarizes the Company's oil and natural gas properties not subject to amortization at December 31, 2013, in total and by the year in which such costs were incurred:

			Year Costs Incurred
	Total		2013		2012		2011		2010 and prior
	(In thousands)
Acquisition	$	93,758	$	1,514	$	23,588	$	28,543	$	40,113
Development	14,824		12,622		1,633		271		298
Exploration	14,547		9,952		4,346		198		51
Capitalized interest	1,740		340		418		410		572
Total costs not subject to amortization	$	124,869	$	24,428	$	29,985	$	29,422	$	41,034

Costs not subject to amortization as of December 31, 2013, consisted primarily of unevaluated leaseholds and development costs in the Bakken area, Texas properties and the Paradox Basin. The Company expects that the majority of these costs will be evaluated within the next five years and included in the amortization base as the properties are evaluated and/or developed.

Revenue recognition

Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is reasonably assured. The Company recognizes utility revenue each month based on the services provided to all utility customers during the month. Accrued unbilled revenue which is included in receivables, net, represents revenues recognized in excess of amounts billed. Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain was $107.4 million and $85.9 million at December 31, 2013 and 2012, 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.

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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:

	2013		2012
	(In thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	60,828	$	64,996
Billings in excess of costs and estimated earnings on uncompleted contracts	$	84,189	$	83,167

Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31, were as follows:

	2013		2012
	(In thousands)
Short-term retainage *	$	55,906	$	54,256
Long-term retainage **	4,229		2,038
Total retainage	$	60,135	$	56,294

  * 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, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions, and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties.

The Company's policy generally allows the hedging of monthly forecasted sales of oil and natural gas production at Fidelity for a period up to 42 months from the time the Company enters into the hedge. The Company's policy requires that interest rate derivative instruments not exceed a period of 24 months and foreign currency derivative instruments not exceed a 12-month period. The Company's policy allows the hedging of monthly forecasted purchases of natural gas at Cascade and Intermountain for a period up to three years.

The Company's policy requires that each month as physical oil and natural gas production at Fidelity occurs and the commodity is sold, the related portion of the derivative agreement for that month's production must settle with its counterparties. Settlements represent the exchange of cash between the Company and its counterparties based on the notional quantities and prices for each month's physical delivery as specified within the agreements. The fair value of the remaining notional amounts on the derivative agreements is recorded on the balance sheet as an asset or liability measured at fair value. The Company's policy also requires settlement of natural gas derivative instruments at Cascade and Intermountain monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days, and any foreign currency derivative transaction settlement periods may not exceed a 12-month period. The Company has policies and procedures that management believes minimize credit-risk exposure. Accordingly, the Company does not anticipate any material effect on its financial position or results of operations as a result of nonperformance by counterparties. For more information on derivative instruments, see Note 7.

The Company's derivative instruments are reflected at fair value. For more information, see Note 8.

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

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life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its nonregulated operations or incurs a regulatory asset or liability at its regulated operations. For more information on asset retirement obligations, see Note 10.

Legal costs

The Company expenses external legal fees as they are incurred.

Natural gas costs recoverable or refundable through rate adjustments

Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within a period ranging from 12 to 28 months from the time such costs are paid. Natural gas costs refundable through rate adjustments were $16.9 million and $35.3 million at December 31, 2013 and 2012, respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $12.1 million and $3.0 million at December 31, 2013 and 2012, respectively, which is included in prepayments and other current assets.

Insurance

Certain subsidiaries of the Company are insured for workers' compensation losses, subject to deductibles ranging up to $1 million per occurrence. Automobile liability and general liability losses are insured, subject to deductibles ranging up to $1 million per accident or occurrence. These subsidiaries have excess coverage above the primary automobile and general liability policies on a claims first-made and reported basis beyond the deductible levels. The subsidiaries of the Company are retaining losses up to the deductible amounts accrued on the basis of estimates of liability for claims incurred and for claims incurred but not reported.

Income taxes

The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.

The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.

Tax positions taken or expected to be taken in an income tax return are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.

Foreign currency translation adjustment

The functional currency of the Company's investment in ECTE, as discussed in Note 4, is the Brazilian Real. Translation from the Brazilian Real to the U.S. dollar for assets and liabilities is performed using the exchange rate in effect at the balance sheet date. Revenues and expenses are translated on a year-to-date basis using an average of the daily exchange rates.

Transaction gains and losses resulting from the effect of exchange rate changes on transactions denominated in a currency other than the functional currency of the reporting entity would be recorded in income.

Earnings (loss) per common share

Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding stock options and performance share awards. In 2013 and 2011, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the year ended December 31, 2012, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the year. Due to the loss on common stock for the year ended December 31, 2012, the effect of outstanding performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive.

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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:

	2013	2012	2011
	(In thousands)
Weighted average common shares outstanding - basic	188,855	188,826	188,763
Effect of dilutive stock options and performance share awards	838	—	142
Weighted average common shares outstanding - diluted	189,693	188,826	188,905
Shares excluded from the calculation of diluted earnings per share	—	58	—

Use of estimates

The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as impairment testing of long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; oil, NGL and natural gas proved reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Cash flow information

Cash expenditures for interest and income taxes for the years ended December 31 were as follows:

	2013		2012		2011
	(In thousands)
Interest, net of amount capitalized	$	81,689	$	74,378	$	78,133
Income taxes paid (refunded), net	$	24,857	$	3,277	$	(12,287	)

Noncash investing transactions at December 31 were as follows:

	2013		2012		2011
	(In thousands)
Property, plant and equipment additions in accounts payable	$	67,129	$	76,205	$	41,540

New accounting standards

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income In February 2013, the FASB issued guidance on the reporting of amounts reclassified out of accumulated other comprehensive income. This guidance requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. Entities may present this information either on the face of the statement where net income is presented or in the notes. This guidance was effective for the Company on January 1, 2013, and is to be applied prospectively. The guidance required additional disclosures, however it did not impact the Company's results of operations, financial position or cash flows.

Disclosures about Offsetting Assets and Liabilities In December 2011, the FASB issued guidance on the disclosure requirements related to balance sheet offsetting. The new disclosure requirements relate to the nature of an entity's rights of offset and related arrangements associated with its financial instruments and derivative instruments. In January 2013, the FASB issued guidance clarifying the scope of the disclosures related to balance sheet offsetting. The amendments clarify that this guidance only applies to derivative instruments, repurchase agreements and securities lending transactions that are either offset or subject to an enforceable master netting arrangement. The guidance was effective for the Company on January 1, 2013, and must be applied retrospectively. The guidance required additional disclosures, however it did not impact the Company's results of operations, financial position or cash flows.

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Variable interest entities

The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.

A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.

The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement.

Comprehensive income (loss)

Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges, postretirement liability adjustments, foreign currency translation adjustments and gains (losses) on available-for-sale investments. For more information on derivative instruments, see Note 7.

The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2013, 2012 and 2011, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency  Translation  Adjustment			Net Unrealized Gains on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2011	$	6,275		$	(53,320	)	$	(38	)	$	82		$	(47,001	)
Current-period other comprehensive income (loss)	(257		)	(1,027		)	(473		)	37			(1,720		)
Balance at December 31, 2012	6,018			(54,347		)	(511		)	119			(48,721		)
Other comprehensive income (loss) before reclassifications	(5,594		)	18,539			(299		)	(194		)	12,452
Amounts reclassified from accumulated other comprehensive loss	(4,189		)	2,001			143			109			(1,936		)
Net current-period other comprehensive income (loss)	(9,783		)	20,540			(156		)	(85		)	10,516
Balance at December 31, 2013	$	(3,765	)	$	(33,807	)	$	(667	)	$	34		$	(38,205	)

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Reclassifications out of accumulated other comprehensive loss for the year ended December 31 were as follows:

	2013			Location on Consolidated Statements of Income
	(In thousands)
Reclassification adjustment for gain (loss) on derivative instruments included in net income:
Commodity derivative instruments	$	7,803		Operating revenues
Interest rate derivative instruments	(1,066		)	Interest expense
	6,737
	(2,548		)	Income taxes
	4,189
Amortization of postretirement liability losses included in net periodic benefit cost	(3,277		)	(a)
	1,276			Income taxes
	(2,001		)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income	(213		)	Earnings (loss) from equity method investments
	70			Earnings (loss) from equity method investments
	(143		)
Reclassification adjustment for loss on available-for-sale investments included in net income	(168		)	Other income
	59			Income taxes
	(109		)
Total reclassifications	$	1,936

(a) Included in net periodic benefit cost (credit). For more information, see Note 16.

Note 2 - Acquisitions

In 2012, the Company acquired a 50 percent undivided interest in natural gas and oil midstream assets in western North Dakota. The acquisition includes a natural gas processing plant and a natural gas gathering pipeline system, along with an oil gathering system, an oil storage terminal and an oil pipeline. The total purchase consideration for acquisitions was approximately $67.5 million, including the Company's interest in the above facilities and contingent consideration related to an acquisition made prior to 2012. The Company recognizes its proportionate share of the assets, liabilities, revenues and expenses related to the natural gas and oil midstream assets acquisition.

In 2011, contingent consideration, consisting of the Company's common stock and cash, of $298,000 was made with respect to an acquisition made prior to 2011.

The acquisitions were accounted for under the acquisition method of accounting and, accordingly, the acquired assets and liabilities assumed have been recorded at their respective fair values as of the date of acquisition. The results of operations of the acquired businesses and properties are included in the financial statements since the date of each acquisition. Pro forma financial amounts reflecting the effects of the acquisitions are not presented, as such acquisitions were not material to the Company's financial position or results of operations.

Note 3 - Discontinued Operations

In 2007, Centennial Resources sold CEM to Bicent. In connection with the sale, Centennial Resources had 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 incurs legal expenses and has accrued liabilities related to this matter. In the fourth quarter of 2011, the Company accrued $21.0 million ($13.0 million after tax) related to the guarantee as a result of an arbitration award against CEM. In 2011, the Company also incurred legal expenses related to this matter and in the first quarter had an income tax benefit related to favorable resolution of certain tax matters. In the second quarter of 2012, discontinued operations reflected the settlement of certain liabilities and estimated insurance recoveries resulting in a net benefit related to this matter. In the

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fourth quarter of 2012, the Company reversed its previously recorded accrual for the arbitration charge due to a favorable court ruling, which was partially offset by the reversal of estimated insurance recoveries. These items are reflected as discontinued operations in the consolidated financial statements and accompanying notes. Discontinued operations are included in the Other category. For more information, see Note 19.

Note 4 - Equity Method Investments

Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. At December 31, 2013, the Company had no significant equity method investments.

In August 2006, MDU Brasil acquired ownership interests in the Brazilian Transmission Lines. The electric transmission lines are primarily in northeastern and southern Brazil. The transmission contracts provide for revenues denominated in the Brazilian Real, annual inflation adjustments and change in tax law adjustments. The functional currency for the Brazilian Transmission Lines is the Brazilian Real.

In 2009, multiple sales agreements were signed with three separate parties for the Company to sell its ownership interests in the Brazilian Transmission Lines. In November 2010, the Company completed the sale of its entire ownership interest in ENTE and ERTE and 59.96 percent of the Company's ownership interest in ECTE. The Company's remaining interest in ECTE is being sold over a four-year period. In August 2013 and 2012, and November 2011, the Company completed the sale of one-fourth of the remaining interest in each year. The Company recognized immaterial gains in 2013 and 2012 and a $1.0 million ($600,000 after tax) gain in 2011. The Company's remaining ownership interest in ECTE is being accounted for under the cost method.

At December 31, 2012, the equity method investments had total assets of $129.0 million and long-term debt of $65.5 million. The Company's investment in its equity method investments was approximately $6.9 million, including undistributed earnings of $3.4 million, at December 31, 2012.

Note 5 - Goodwill and Other Intangible Assets

The changes in the carrying amount of goodwill for the year ended December 31, 2013, were as follows:

	Balance at January 1, 2013		*	Goodwill Acquired During the Year		Balance at December 31, 2013		*
	(In thousands)
Natural gas distribution	$	345,736		$	—	$	345,736
Pipeline and energy services	9,737			—		9,737
Construction materials and contracting	176,290			—		176,290
Construction services	104,276			—		104,276
Total	$	636,039		$	—	$	636,039

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

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The changes in the carrying amount of goodwill for the year ended December 31, 2012, were as follows:

	Balance at January 1, 2012		*	Goodwill Acquired During the Year		**	Balance at December 31, 2012		*
	(In thousands)
Natural gas distribution	$	345,736		$	—		$	345,736
Pipeline and energy services	9,737			—			9,737
Construction materials and contracting	176,290			—			176,290
Construction services	103,168			1,108			104,276
Total	$	634,931		$	1,108		$	636,039

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

** Includes contingent consideration that was not material related to an acquisition in a prior period.

Other amortizable intangible assets at December 31 were as follows:

	2013			2012
	(In thousands)
Customer relationships	$	21,310		$	21,310
Accumulated amortization	(13,726		)	(11,701		)
	7,584			9,609
Noncompete agreements	6,186			7,236
Accumulated amortization	(4,840		)	(5,326		)
	1,346			1,910
Other	10,995			10,979
Accumulated amortization	(6,826		)	(5,369		)
	4,169			5,610
Total	$	13,099		$	17,129

Amortization expense for amortizable intangible assets for the years ended December 31, 2013, 2012 and 2011, was $4.0 million, $3.8 million and $3.7 million, respectively. Estimated amortization expense for intangible assets is $3.2 million in 2014, $2.5 million in 2015, $2.2 million in 2016, $2.0 million in 2017, $1.0 million in 2018 and $2.2 million thereafter.

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Note 6 - Regulatory Assets and Liabilities

The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:

	Estimated Recovery Period	*	2013			2012
			(In thousands)
Regulatory assets:
Deferred income taxes	**		$	125,607		$	121,781
Pension and postretirement benefits (a)	(e)		105,123			166,477
Taxes recoverable from customers (a)	Over plant lives		18,266			9,078
Manufactured gas plant sites remediation (a)	Up to 4 years		15,797			15,828
Natural gas costs recoverable through rate adjustments (b)	Up to 28 months		12,060			2,981
Long-term debt refinancing costs (a)	Up to 25 years		8,697			9,144
Costs related to identifying generation development (a)	Up to 13 years		4,512			5,773
Other (a) (b)	Largely within 1- 5 years		15,311			20,132
Total regulatory assets			305,373			351,194
Regulatory liabilities:
Plant removal and decommissioning costs (c)			308,431			296,037
Deferred income taxes**			64,914			82,077
Taxes refundable to customers (c)			20,180			24,212
Natural gas costs refundable through rate adjustments (d)			16,932			35,328
Other (c) (d)			21,868			12,828
Total regulatory liabilities			432,325			450,482
Net regulatory position			$	(126,952	)	$	(99,288	)

  * Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.

** Represents deferred income taxes related to regulatory assets and liabilities. The deferred income tax assets are not earning a rate of return.

(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.

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. Excluding deferred income taxes, as of December 31, 2013 and 2012, approximately $163.7 million and $215.6 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 as an extraordinary item in the period in which the discontinuance of regulatory accounting occurs.

Note 7 - 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

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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. In the event of a sale, termination or extinguishment of a foreign currency derivative, the resulting gain or loss would be recognized immediately in earnings. The Company's policy requires approval to terminate a derivative instrument prior to its original maturity. As of December 31, 2013, the Company had no outstanding foreign currency hedges.

The fair value of the derivative instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or liability.

The Company evaluates counterparty credit risk on its derivative assets and the Company's credit risk on its derivative liabilities. As of December 31, 2013 and 2012, credit risk was not material.

Fidelity

At December 31, 2013 and 2012, Fidelity held oil swap and collar agreements with total forward notional volumes of 2.9 million and 2.6 million Bbl, respectively, and natural gas swap agreements with total forward notional volumes of 18.3 million and 11.0 million MMBtu, respectively. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on its forecasted sales of oil and natural gas production.

Effective April 1, 2013, Fidelity elected to de-designate all commodity derivative contracts previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively for all of its commodity derivative instruments. When the criteria for hedge accounting is not met or when hedge accounting is not elected, realized gains and losses and unrealized gains and losses are both recorded in operating revenues on the Consolidated Statements of Income. As a result of discontinuing hedge accounting on commodity derivative instruments, gains and losses on the oil and natural gas derivative instruments remain in accumulated other comprehensive income (loss) as of the de-designation date and are reclassified into earnings in future periods as the underlying hedged transactions affect earnings. At April 1, 2013, accumulated other comprehensive income (loss) included $1.8 million of unrealized gains, representing the mark-to-market value of the Company's commodity derivative instruments that qualified as cash flow hedges as of the balance sheet date. The Company expects to reclassify into earnings from accumulated other comprehensive income (loss) the remaining value related to de-designating commodity derivative instruments over the next 12 months.

Prior to April 1, 2013, changes in the fair value attributable to the effective portion of the hedging instruments, net of tax, were recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). To the extent that the hedges were not effective or did not qualify for hedge accounting, the ineffective portion of the changes in fair market value was recorded directly in earnings. Gains and losses on the oil and natural gas derivative instruments were reclassified from accumulated other comprehensive income (loss) into operating revenues on the Consolidated Statements of Income at the date the oil and natural gas quantities were settled.

Centennial

At December 31, 2013, Centennial had no outstanding interest rate swap agreements. At December 31, 2012, Centennial held interest rate swap agreements with a total notional amount of $50.0 million, which were designated as cash flow hedging instruments. Centennial entered into these interest rate derivative instruments to manage a portion of its interest rate exposure on the forecasted issuance of long-term debt.

Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. Gains and losses on the interest rate derivatives are reclassified from accumulated other comprehensive income (loss) into interest expense on the Consolidated Statements of Income in the same period the hedged item affects earnings.

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.

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The gains and losses on derivative instruments for the years ended December 31 were as follows:

	2013			2012			2011
	(In thousands)
Commodity derivatives designated as cash flow hedges:
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	$	(6,153	)	$	10,209		$	10,806
Amount of gain reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax	(4,916		)	(8,788		)	—
Amount of gain (loss) recognized in operating revenues (ineffective portion), before tax	(1,422		)	(730		)	1,827
Interest rate derivatives designated as cash flow hedges:
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	559			(1,712		)	(2,906		)
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax	727			34			—
Amount of loss recognized in interest expense (ineffective portion), before tax	(769		)	—			—
Commodity derivatives not designated as hedging instruments:
Amount of gain (loss) recognized in operating revenues, before tax	(4,845		)	106			—

Based on December 31, 2013, fair values, over the next 12 months net losses of approximately $700,000 (after tax) are estimated to be reclassified from accumulated other comprehensive income (loss) into earnings, as the hedged transactions affect earnings.

Certain of Fidelity's and Centennial's derivative instruments contain cross-default provisions that state if Fidelity or any of its affiliates or Centennial fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of derivative instruments in liability positions. The aggregate fair value of Fidelity's and Centennial's derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2013 and 2012, were $7.5 million and $6.3 million, respectively. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on December 31, 2013 and 2012, were $7.5 million and $6.3 million, respectively.

The location and fair value of the Company's derivative instruments on the Consolidated Balance Sheets were as follows:

Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2013		Fair Value at December 31, 2012
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	18,084
		—		18,084
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	1,447		220
	Other assets - noncurrent	503		—
		1,950		220
Total asset derivatives		$	1,950	$	18,304

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Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2013		Fair Value at December 31, 2012
		(In thousands)
Designated as hedges:
Interest rate derivatives	Other accrued liabilities	$	—	$	6,255
		—		6,255
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	7,483		—
		7,483		—
Total liability derivatives		$	7,483	$	6,255

All of the Company's commodity and interest rate derivative instruments at December 31, 2013 and 2012, were subject to legally enforceable master netting agreements. However, the Company's policy is to not offset fair value amounts for derivative instruments and, as a result, the Company's derivative assets and liabilities are presented gross on the Consolidated Balance Sheets. The gross derivative assets and liabilities (excluding settlement receivables and payables that may be subject to the same master netting agreements) presented on the Consolidated Balance Sheets and the amount eligible for offset under the master netting agreements is presented in the following table:

December 31, 2013	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	1,950	$	(1,950	)	$	—
Total assets	$	1,950	$	(1,950	)	$	—
Liabilities:
Commodity derivatives	$	7,483	$	(1,950	)	$	5,533
Total liabilities	$	7,483	$	(1,950	)	$	5,533

December 31, 2012	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets		Net
	(In thousands)
Assets:
Commodity derivatives	$	18,304	$	—	$	18,304
Total assets	$	18,304	$	—	$	18,304
Liabilities:
Interest rate derivatives	$	6,255	$	—	$	6,255
Total liabilities	$	6,255	$	—	$	6,255

Note 8 - 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 $62.4 million and $48.9 million as of December 31, 2013 and 2012, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gains on these investments for the year ended December 31, 2013 and 2012, were $13.5 million and $5.2 million, respectively. The net unrealized loss on these investments for the year ended December 31, 2011, was $1.1 million. 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.

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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, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193
U.S. Treasury securities	1,906		15		(4		)	1,917
Total	$	10,057	$	84	$	(31	)	$	10,110

December 31, 2012	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,054	$	144	$	(3	)	$	8,195
U.S. Treasury securities	1,763		43		—			1,806
Total	$	9,817	$	187	$	(3	)	$	10,001

The fair value of the Company's money market funds approximates cost.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs.

The estimated fair values of the Company's assets and liabilities measured on a recurring basis are determined using the market approach.

The Company's Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company's Level 2 mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources.

The estimated fair value of the Company's Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.

The estimated fair value of the Company's Level 2 commodity derivative instruments is based upon futures prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company's and the counterparties' nonperformance risk is also evaluated.

The estimated fair value of the Company's Level 2 interest rate derivative instruments is measured using quoted market prices or pricing models using prevailing market interest rates as of the measurement date. Counterparty statements are utilized to determine the value of the interest rate derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company's and the counterparties' nonperformance risk is evaluated.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2013 and 2012, there were no transfers between Levels 1 and 2.

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The Company's assets and liabilities measured at fair value on a recurring basis were as follows:

	Fair Value Measurements at December 31, 2013, 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, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	19,227	$	—	$	19,227
Insurance contract*	—		62,370		—		62,370
Available-for-sale securities:
Mortgage-backed securities	—		8,193		—		8,193
U.S. Treasury securities	—		1,917		—		1,917
Commodity derivative instruments	—		1,950		—		1,950
Total assets measured at fair value	$	—	$	93,657	$	—	$	93,657
Liabilities:
Commodity derivative instruments	$	—	$	7,483	$	—	$	7,483
Total liabilities measured at fair value	$	—	$	7,483	$	—	$	7,483

* The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Money market funds	$	—	$	24,240	$	—	$	24,240
Insurance contract*	—		48,898		—		48,898
Available-for-sale securities:
Mortgage-backed securities	—		8,195		—		8,195
U.S. Treasury securities	—		1,806		—		1,806
Commodity derivative instruments	—		18,304		—		18,304
Total assets measured at fair value	$	—	$	101,443	$	—	$	101,443
Liabilities:
Interest rate derivative instruments	$	—	$	6,255	$	—	$	6,255
Total liabilities measured at fair value	$	—	$	6,255	$	—	$	6,255

* The insurance contract invests approximately 28 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including long-lived asset impairments. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company reviews the carrying value of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying amounts may not be recoverable. During the second quarters of 2013 and 2012, coalbed natural gas gathering assets were reviewed for impairment and found to be impaired and were written down to their estimated fair value using the income approach. Under this approach, fair value is determined by using the present value of future estimated cash flows. The factors used to determine

84

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, 2012, certain coalbed natural gas gathering assets were written down to the nonrecurring fair value measurement of $2.5 million. At June 30, 2013, additional coalbed natural gas gathering assets were written down to the nonrecurring fair value measurement of $9.7 million. The fair value of these coalbed natural gas gathering assets have been categorized as Level 3 (Significant Unobservable Inputs) in the fair value hierarchy.

The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The fair value was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt at December 31 was as follows:

	2013				2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
Long-term debt	$	1,854,563	$	1,912,590	$	1,744,975	$	1,888,135

The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.

Note 9 - 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, 2013			Amount Outstanding at December 31, 2012			Letters of Credit at December 31, 2013			Expiration Date
			(In millions)
MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement	(a)	$	125.0		$	78.9	(b)	$	76.0	(b)	$	—		10/4/17
Cascade Natural Gas Corporation	Revolving credit agreement		$	50.0	(c)	$	11.5		$	2.0		$	2.2	(d)	7/9/18
Intermountain Gas Company	Revolving credit agreement		$	65.0	(e)	$	3.0		$	26.2		$	—		7/13/18
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	75.0	(b)	$	217.0	(b)	$	—		6/8/17

(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 $150 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 million.

(d) The outstanding letter of credit, as discussed in Note 19, reduces the amount available under the credit agreement.

(e) Certain provisions allow for increased borrowings, up to a maximum of $90 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 $650 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

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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

Cascade Natural Gas Corporation On July 9, 2013, Cascade entered into a revolving credit agreement which replaced the previous revolving credit agreement and extended the termination date to July 9, 2018. Any borrowings under the revolving credit agreement would be classified as short-term borrowings as Cascade intends to repay the borrowings within one year. The weighted average interest rate for borrowings outstanding at December 31, 2013, was 3.3 percent.

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.

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. 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). 

On December 12, 2013, MDU Energy Capital entered into a note purchase agreement. MDU Energy Capital contracted to issue $30.0 million of Senior Notes under the agreement on January 27, 2014, with due dates ranging from January 2029 to January 2044 at a weighted average interest rate of 5.3 percent.

Intermountain Gas Company On July 15, 2013, Intermountain entered into a revolving credit agreement which replaced the previous revolving credit agreement and extended the termination date to July 13, 2018. These borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings. The borrowings outstanding as of December 31, 2012, were classified as short-term borrowings because the previous revolving credit agreement expired within one year.

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.

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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.

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. On September 12, 2013, WBI Energy Transmission entered into a $175 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, 2013, 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:

	2013			2012
	(In thousands)
Senior Notes at a weighted average rate of 5.52%, due on dates ranging from June 19, 2015 to April 15, 2044	$	1,545,078		$	1,349,160
Commercial paper at a weighted average rate of .40%, supported by revolving credit agreements	153,924			293,000
Term Loan Agreements at a weighted average rate of 2.08%, due on dates ranging from April 22, 2014 to April 22, 2023	75,000			—
Medium-Term Notes at a weighted average rate of 7.32%, due on dates ranging from September 15, 2027 to March 16, 2029	35,000			59,000
Other notes at a weighted average rate of 5.23%, due on dates ranging from September 1, 2020 to February 1, 2035	39,863			40,090
Credit agreements at a weighted average rate of 4.11%, due on dates ranging from February 28, 2014 to November 30, 2038	5,701			3,768
Discount	(3		)	(43		)
Total long-term debt	1,854,563			1,744,975
Less current maturities	12,277			134,108
Net long-term debt	$	1,842,286		$	1,610,867

The amounts of scheduled long-term debt maturities for the five years and thereafter following December 31, 2013, aggregate $12.3 million in 2014; $269.4 million in 2015; $293.8 million in 2016; $204.9 million in 2017; $130.2 million in 2018 and $944.0 million thereafter.

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Note 10 - Asset Retirement Obligations

The Company records obligations related to the plugging and abandonment of oil and natural gas wells, decommissioning of certain electric generating facilities, reclamation of certain aggregate properties, special handling and disposal of hazardous materials at certain electric generating facilities, natural gas distribution facilities and buildings, and certain other obligations.

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:

	2013			2012
	(In thousands)
Balance at beginning of year	$	102,545		$	98,151
Liabilities incurred	5,610			6,523
Liabilities acquired	—			—
Liabilities settled	(22,257		)	(10,472		)
Accretion expense	4,574			4,266
Revisions in estimates	7,671			3,655
Other	386			422
Balance at end of year	$	98,529		$	102,545

The Company believes that any expenses related to asset retirement obligations at the Company's regulated operations will be recovered in rates over time and, accordingly, defers such expenses as regulatory assets.

The fair value of assets that are legally restricted for purposes of settling asset retirement obligations at December 31, 2013 and 2012, was $4.1 million and $5.0 million, respectively. The legally restricted assets consist primarily of money market funds and are reflected in other assets on the Consolidated Balance Sheets.

Note 11 - Preferred Stocks

Preferred stocks at December 31 were as follows:

	2013		2012
(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 2013, 2012 and 2011, 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

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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.

Note 12 - Common Stock

For the years 2013, 2012 and 2011, dividends declared on common stock were $.6950, $.6750 and $.6550 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 2011 through December 2013, purchases of shares of common stock on the open market were used to fund the Stock Purchase Plan and K-Plan. At December 31, 2013, there were 15.6 million shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan.

The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on common stock. The declaration and payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by the Company's credit agreements, federal and state laws, and applicable regulatory limitations. In addition, the Company and Centennial are generally restricted to paying dividends out of capital accounts or net assets. The following discusses the most restrictive limitations.

Pursuant to a covenant under a credit agreement, Centennial may only make distributions to the Company in an amount up to 100 percent of Centennial's consolidated net income after taxes, excluding noncash write-downs, for the immediately preceding fiscal year. Intermountain and Cascade have regulatory limitations on the amount of dividends each can pay. Based on these limitations, approximately $2.1 billion of the net assets of the Company's subsidiaries were restricted from being used to transfer funds to the Company at December 31, 2013. 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 $219 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, 2013. 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.

Note 13 - 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, 2013, there are 6.2 million remaining shares available to grant under these plans. The Company generally issues new shares of common stock to satisfy restricted stock, stock and performance share awards.

Total stock-based compensation expense (after tax) was $3.9 million, $4.0 million and $3.5 million in 2013, 2012 and 2011, respectively.

As of December 31, 2013, total remaining unrecognized compensation expense related to stock-based compensation was approximately $7.0 million (before income taxes) which will be amortized over a weighted average period of 1.6 years.

Stock options

The Company had granted stock options to directors, key employees and employees. The Company has not granted stock options since 2003 and as of December 31, 2013 and 2012, there were no stock options outstanding.

The Company received cash of $88,000 and $5.7 million from the exercise of stock options for the years ended December 31, 2012 and 2011, respectively. The aggregate intrinsic value of options exercised during the years ended December 31, 2012 and 2011, was $60,000 and $3.3 million, respectively.

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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 36,713 shares with a fair value of $1.1 million, 53,888 shares with a fair value of $1.1 million and 55,141 shares with a fair value of $1.1 million issued under this plan during the years ended December 31, 2013, 2012 and 2011, respectively.

A key employee of the Company received an award of 43,103 shares of common stock under a long-term incentive plan with a fair value of $930,000 during the year ended December 31, 2012.

Performance share awards

Since 2003, key employees of the Company have been awarded performance share awards each year. Entitlement to performance shares is based on the Company's total shareholder return over designated performance periods as measured against a selected peer group.

Target grants of performance shares outstanding at December 31, 2013, were as follows:

Grant Date	Performance Period	Target Grant of Shares
February 2011	2011-2013	254,514
February 2012	2012-2014	251,196
March 2013	2013-2015	244,281

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 2013, 2012 and 2011 were:

				2013						2012						2011
Grant-date fair value					$29.01						$17.18						$19.99
Blended volatility range	16.10	%	-	19.39		%	24.29	%	-	25.81		%	23.20	%	-	32.18		%
Risk-free interest rate range	.09	%	-	.40		%	.10	%	-	.35		%	.09	%	-	1.34		%
Discounted dividends per share					$2.12						$1.19						$1.23

There were no performance shares that vested in 2013, 2012 or 2011.

A summary of the status of the performance share awards for the year ended December 31, 2013, was as follows:

	Number of Shares		Weighted Average Grant-Date Fair Value
Nonvested at beginning of period	786,136		$	18.17
Granted	264,614		29.01
Vested	—		—
Forfeited	(300,759	)	18.20
Nonvested at end of period	749,991		$	21.99

Note 14 - Income Taxes

The components of income (loss) before income taxes from continuing operations for each of the years ended December 31 were as follows:

	2013		2012			2011
	(In thousands)
United States	$	415,202	$	(47,175	)	$	333,486
Foreign	416		1,708			2,740
Income (loss) before income taxes from continuing operations	$	415,618	$	(45,467	)	$	336,226

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Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:

	2013			2012			2011
	(In thousands)
Current:
Federal	$	45,518		$	(26,858	)	$	(7,188	)
State	4,311			858			778
Foreign	(29		)	(75		)	127
	49,800			(26,075		)	(6,283		)
Deferred:
Income taxes:
Federal	78,953			(1,224		)	105,528
State	8,031			(6,323		)	13,157
Investment tax credit - net	(206		)	44			240
	86,778			(7,503		)	118,925
Change in uncertain tax positions	—			1,974			(1,048		)
Change in accrued interest	158			458			(1,320		)
Total income tax expense (benefit)	$	136,736		$	(31,146	)	$	110,274

Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:

	2013			2012
	(In thousands)
Deferred tax assets:
Regulatory matters	$	125,607		$	121,781
Accrued pension costs	74,320			85,037
Alternative minimum tax credit carryforward	33,304			—
Compensation-related	31,550			23,441
Asset retirement obligations	29,578			26,748
Legal and environmental contingencies	10,710			8,046
Other	45,101			39,792
Total deferred tax assets	350,170			304,845
Deferred tax liabilities:
Depreciation and basis differences on property, plant and equipment	813,597			755,392
Basis differences on oil and natural gas producing properties	266,168			167,113
Regulatory matters	64,914			82,077
Intangible asset amortization	13,579			14,078
Other	26,170			18,441
Total deferred tax liabilities	1,184,428			1,037,101
Net deferred income tax liability	$	(834,258	)	$	(732,256	)

As of December 31, 2013 and 2012, no valuation allowance has been recorded associated with the previously identified deferred tax assets. The alternative minimum tax credit carryforwards do not expire.

The following table reconciles the change in the net deferred income tax liability from December 31, 2012, to December 31, 2013, to deferred income tax expense:

	2013
(In thousands)
Change in net deferred income tax liability from the preceding table	$	102,002
Deferred taxes associated with other comprehensive loss	(7,277		)
Other	(7,947		)
Deferred income tax expense for the period	$	86,778

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Total income tax expense (benefit) differs from the amount computed by applying the statutory federal income tax rate to income (loss) before taxes. The reasons for this difference were as follows:

Years ended December 31,	2013					2012					2011
	Amount			%		Amount			%		Amount			%
	(Dollars in thousands)
Computed tax at federal statutory rate	$	145,466		35.0		$	(15,914	)	35.0		$	117,679		35.0
Increases (reductions) resulting from:
State income taxes, net of federal income tax	10,524			2.5		2,469			(5.4	)	10,653			3.2
Nonqualified benefit plans	(5,173		)	(1.2	)	(2,359		)	5.2		(2,918		)	(.9	)
Depletion allowance	(3,764		)	(.9	)	(3,728		)	8.2		(3,266		)	(1.0	)
Federal renewable energy credit	(3,404		)	(.8	)	(3,401		)	7.5		(3,485		)	(1.0	)
Deductible K-Plan dividends	(1,593		)	(.4	)	(2,829		)	6.2		(2,282		)	(.7	)
AFUDC equity	(1,074		)	(.3	)	(1,500		)	3.3		(873		)	(.3	)
Resolution of tax matters and uncertain tax positions	(859		)	(.2	)	2,559			(5.6	)	(3,906		)	(1.2	)
Deferred tax rate changes	741			.2		(3,083		)	6.8		(417		)	(.1	)
Other	(4,128		)	(1.0	)	(3,360		)	7.3		(911		)	(.2	)
Total income tax expense (benefit)	$	136,736		32.9		$	(31,146	)	68.5		$	110,274		32.8

The income tax benefit in 2012 resulted largely from the Company's write-downs of oil and natural gas properties, as discussed in Note 1.

Deferred income taxes have been accrued with respect to temporary differences related to the Company's foreign operations. The amount of cumulative undistributed earnings for which there are temporary differences is approximately $7.0 million at December 31, 2013. The amount of deferred tax liability, net of allowable foreign tax credits, associated with the undistributed earnings at December 31, 2013, was approximately $2.2 million.

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state, local and foreign jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years ending prior to 2007. The 2007 through 2009 tax years are currently under audit.

A reconciliation of the unrecognized tax benefits (excluding interest) for the years ended December 31 was as follows:

	2013		2012		2011
	(In thousands)
Balance at beginning of year	$	14,914	$	11,206	$	9,378
Additions for tax positions of prior years	—		3,708		4,172
Settlements	—		—		(2,344		)
Balance at end of year	$	14,914	$	14,914	$	11,206

Included in the balance of unrecognized tax benefits at December 31, 2013 and 2012, were $8.4 million and $8.4 million, respectively, of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate was $9.0 million, including approximately $2.5 million for the payment of interest and penalties at December 31, 2013, and was $8.5 million, including approximately $2.0 million for the payment of interest and penalties at December 31, 2012.

It is likely that substantially all of the unrecognized tax benefits, as well as interest, at December 31, 2013, will be settled in the next twelve months due to the anticipated settlement of federal and state audits.

For the years ended December 31, 2013, 2012 and 2011, the Company recognized approximately $1.2 million, $740,000 and $780,000, respectively, in interest expense. Penalties were not material in 2013, 2012 and 2011. The Company recognized interest income of approximately $660,000, $290,000 and $1.9 million for the years ended December 31, 2013, 2012 and 2011,

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respectively. The Company had accrued liabilities of approximately $2.8 million and $1.4 million at December 31, 2013 and 2012, respectively, for the payment of interest.

In September 2013, the Internal Revenue Service released final regulations relating to the capitalization of tangible personal property which are effective for tax years beginning on or after January 1, 2014. The Company does not expect these new regulations to have a material effect on its results of operations, financial position or cash flows.

Note 15 - Business Segment Data

The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The internal reporting of these operating segments is defined based on the reporting and review process used by the Company's chief executive officer. The vast majority of the Company's operations are located within the United States. The Company also has an investment in a foreign country, which consists of Centennial Resources' investment in ECTE.

The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added services.

The pipeline and energy services segment provides natural gas transportation, underground storage, processing and gathering services, as well as oil gathering, through regulated and nonregulated pipeline systems and processing facilities primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment is constructing Dakota Prairie Refinery in conjunction with Calumet to refine crude oil and also provides cathodic protection and other energy-related services.

The exploration and production segment is engaged in oil and natural gas acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent/Gulf States 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 specializes in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment.

The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies' general liability, automobile liability and pollution liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' investment in ECTE.

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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:

	2013			2012			2011
	(In thousands)
External operating revenues:
Electric	$	257,260		$	236,895		$	225,468
Natural gas distribution	851,945			754,848			907,400
Pipeline and energy services	155,369			139,883			210,846
	1,264,574			1,131,626			1,343,714
Exploration and production	490,924			412,651			359,873
Construction materials and contracting	1,675,444			1,597,257			1,509,538
Construction services	1,029,909			932,013			834,918
Other	1,553			1,884			2,449
	3,197,830			2,943,805			2,706,778
Total external operating revenues	$	4,462,404		$	4,075,431		$	4,050,492
Intersegment operating revenues:
Electric	$	—		$	—		$	—
Natural gas distribution	—			—			—
Pipeline and energy services	46,699			53,274			67,497
Exploration and production	45,099			35,966			93,713
Construction materials and contracting	36,693			20,168			472
Construction services	9,930			6,545			19,471
Other	8,067			8,486			8,997
Intersegment eliminations	(146,488		)	(124,439		)	(190,150		)
Total intersegment operating revenues	$	—		$	—		$	—
Depreciation, depletion and amortization:
Electric	$	32,789		$	32,509		$	32,177
Natural gas distribution	50,031			45,731			44,641
Pipeline and energy services	29,119			27,684			25,502
Exploration and production	186,458			160,681			142,645
Construction materials and contracting	74,470			79,527			85,459
Construction services	11,939			11,063			11,399
Other	2,050			2,010			1,572
Total depreciation, depletion and amortization	$	386,856		$	359,205		$	343,395
Interest expense:
Electric	$	12,590		$	12,421		$	13,745
Natural gas distribution	25,123			28,726			29,444
Pipeline and energy services	10,330			7,742			10,516
Exploration and production	14,315			9,018			7,445
Construction materials and contracting	17,394			15,211			16,241
Construction services	4,306			4,435			4,473
Other	15			13			—
Intersegment eliminations	(156		)	(867		)	(510		)
Total interest expense	$	83,917		$	76,699		$	81,354

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	2013			2012			2011
	(In thousands)
Income taxes:
Electric	$	9,683		$	8,975		$	7,242
Natural gas distribution	16,633			12,005			16,931
Pipeline and energy services	3,390			15,291			12,912
Exploration and production	53,197			(108,264		)	46,298
Construction materials and contracting	24,765			14,099			11,227
Construction services	29,504			24,128			13,426
Other	2,433			2,620			2,238
Intersegment eliminations	(2,869		)	—			—
Total income taxes	$	136,736		$	(31,146	)	$	110,274
Earnings (loss) on common stock:
Electric	$	34,837		$	30,634		$	29,258
Natural gas distribution	37,656			29,409			38,398
Pipeline and energy services	7,629			26,588			23,082
Exploration and production	94,450			(177,283		)	80,282
Construction materials and contracting	50,946			32,420			26,430
Construction services	52,213			38,429			21,627
Other	5,136			4,797			6,190
Intersegment eliminations	(4,307		)	—			—
Earnings (loss) on common stock before income (loss) from discontinued operations	278,560			(15,006		)	225,267
Income (loss) from discontinued operations, net of tax*	(312		)	13,567			(12,926		)
Total earnings (loss) on common stock	$	278,248		$	(1,439	)	$	212,341
Capital expenditures:
Electric	$	168,557		$	112,035		$	52,072
Natural gas distribution	101,279			130,178			70,624
Pipeline and energy services	127,092			133,787			45,556
Exploration and production	391,315			554,528			272,855
Construction materials and contracting	34,607			45,083			52,303
Construction services	15,102			14,835			9,711
Other	2,249			791			18,759
Net proceeds from sale or disposition of property and other	(112,131		)	(57,460		)	(40,857		)
Total net capital expenditures	$	728,070		$	933,777		$	481,023
Assets:
Electric**	$	884,283		$	760,324		$	672,940
Natural gas distribution**	1,786,068			1,703,459			1,679,091
Pipeline and energy services	798,701			622,470			526,797
Exploration and production	1,616,131			1,539,017			1,481,556
Construction materials and contracting	1,305,808			1,371,252			1,374,026
Construction services	450,614			429,547			418,519
Other***	219,727			256,422			403,196
Total assets	$	7,061,332		$	6,682,491		$	6,556,125

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	2013			2012		2011
	(In thousands)
Property, plant and equipment:
Electric**	$	1,315,822		$	1,150,584	$	1,068,524
Natural gas distribution**	1,776,901			1,689,950		1,568,866
Pipeline and energy services	962,172			816,533		719,291
Exploration and production	3,060,848			2,764,560		2,615,146
Construction materials and contracting	1,510,355			1,504,981		1,499,852
Construction services	134,948			130,624		124,796
Other	49,997			50,519		49,747
Eliminations	(7,177		)	—		—
Less accumulated depreciation, depletion and amortization	3,872,487			3,608,912		3,361,208
Net property, plant and equipment	$	4,931,379		$	4,498,839	$	4,285,014

    * Reflected in the Other category.

  ** Includes allocations of common utility property.

*** Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

Note: The results reflect $391.8 million ($246.8 million after tax) of noncash write-downs of oil and natural gas properties in 2012.

Excluding the impairments of the coalbed natural gas gathering assets of $9.0 million (after tax) and $1.7 million (after tax) in 2013 and 2012, respectively, and the reversal of the natural gas gathering arbitration charge of $1.5 million (after tax) and $15.0 million (after tax) in 2013 and 2012, respectively, as discussed in Notes 1 and 19, respectively, earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from exploration and production, construction materials and contracting, construction services and other are all from nonregulated operations.

Capital expenditures for 2013, 2012 and 2011 include noncash capital expenditure-related accounts payable and exclude capital expenditures of the noncontrolling interest related to Dakota Prairie Refinery. The net transactions were $(56.8) million in 2013, $33.7 million in 2012 and $24.0 million in 2011.

Note 16 - Employee Benefit Plans

Pension and other postretirement benefit plans

The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans.

Defined pension plan benefits to all nonunion and certain union employees hired after December 31, 2005, were discontinued. In 2010, all benefit and service accruals for nonunion and certain union plans were frozen. In 2011 and 2012, all benefit and service accruals for certain additional union employees were frozen. These employees will be eligible to receive additional defined contribution plan benefits.

Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company's businesses. Employees who attain 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 is replaced by a fixed-dollar subsidy for retirees and spouses to be used to purchase individual insurance through an exchange.

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Changes in benefit obligation and plan assets for the years ended December 31, 2013 and 2012, and amounts recognized in the Consolidated Balance Sheets at December 31, 2013 and 2012, were as follows:

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	459,111		$	435,618		$	103,358		$	110,689
Service cost	155			1,078			1,675			1,747
Interest cost	16,249			17,598			3,215			4,166
Plan participants' contributions	—			—			1,472			2,688
Amendments	—			—			—			(11,418		)
Actuarial (gain) loss	(44,551		)	30,939			(20,985		)	3,469
Benefits paid	(28,192		)	(26,122		)	(7,009		)	(7,983		)
Benefit obligation at end of year	402,772			459,111			81,726			103,358
Change in net plan assets:
Fair value of plan assets at beginning of year	309,184			278,000			74,361			68,085
Actual gain on plan assets	35,539			34,493			13,819			6,497
Employer contribution	18,313			22,813			1,900			5,074
Plan participants' contributions	—			—			1,472			2,688
Benefits paid	(28,192		)	(26,122		)	(7,009		)	(7,983		)
Fair value of net plan assets at end of year	334,844			309,184			84,543			74,361
Funded status - (under) over	$	(67,928	)	$	(149,927	)	$	2,817		$	(28,997	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	$	—		$	—		$	9,679		$	—
Other accrued liabilities (current)	—			—			(381		)	(655		)
Other liabilities (noncurrent)	(67,928		)	(149,927		)	(6,481		)	(28,342		)
Net amount recognized	$	(67,928	)	$	(149,927	)	$	2,817		$	(28,997	)
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	$	135,061		$	202,406		$	11,314		$	43,589
Prior service cost (credit)	365			437			(17,137		)	(18,594		)
Total	$	135,426		$	202,843		$	(5,823	)	$	24,995

Employer contributions and benefits paid in the preceding table include only those amounts contributed directly to, or paid directly from, plan assets. Accumulated other comprehensive (income) loss in the above table includes amounts related to regulated operations, which are recorded as regulatory assets (liabilities) and are expected to be reflected in rates charged to customers over time. For more information on regulatory assets (liabilities), see Note 6.

Unrecognized pension actuarial losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets are amortized on a straight-line basis over the expected average remaining service lives of active participants for non-frozen plans and over the average life expectancy of plan participants for frozen plans. The market-related value of assets is determined using a five-year average of assets. Unrecognized postretirement net transition obligation was amortized over a 20-year period ending 2012.

The pension plans all have accumulated benefit obligations in excess of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for these plans at December 31 were as follows:

	2013		2012
	(In thousands)
Projected benefit obligation	$	402,772	$	459,111
Accumulated benefit obligation	$	402,772	$	459,111
Fair value of plan assets	$	334,844	$	309,184

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Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows:

	Pension Benefits									Other Postretirement Benefits
	2013			2012			2011			2013			2012			2011
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	155		$	1,078		$	2,252		$	1,675		$	1,747		$	1,443
Interest cost	16,249			17,598			19,500			3,215			4,166			4,700
Expected return on assets	(19,917		)	(23,536		)	(22,809		)	(4,343		)	(4,890		)	(5,051		)
Amortization of prior service cost (credit)	71			(46		)	45			(1,457		)	(1,438		)	(2,677		)
Recognized net actuarial loss	7,173			7,070			4,656			1,814			2,134			753
Curtailment loss (gain)	—			(1,023		)	1,218			—			—			—
Amortization of net transition obligation	—			—			—			—			2,128			2,125
Net periodic benefit cost, including amount capitalized	3,731			1,141			4,862			904			3,847			1,293
Less amount capitalized	727			937			1,196			164			910			(50		)
Net periodic benefit cost	3,004			204			3,666			740			2,937			1,343
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	(60,173		)	19,982			76,310			(30,461		)	1,863			23,863
Prior service credit	—			—			—			—			(11,418		)	—
Amortization of actuarial loss	(7,173		)	(7,070		)	(4,656		)	(1,814		)	(2,134		)	(753		)
Amortization of prior service (cost) credit	(71		)	1,069			(1,263		)	1,457			1,438			2,677
Amortization of net transition obligation	—			—			—			—			(2,128		)	(2,125		)
Total recognized in accumulated other comprehensive (income) loss	(67,417		)	13,981			70,391			(30,818		)	(12,379		)	23,662
Total recognized in net periodic benefit cost and accumulated other comprehensive (income) loss	$	(64,413	)	$	14,185		$	74,057		$	(30,078	)	$	(9,442	)	$	25,005

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are $4.8 million and $71,000, respectively. The estimated net loss and prior service credit for the other postretirement benefit plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are $793,000 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
	2013		2012		2013		2012
Discount rate	4.53	%	3.65	%	4.48	%	3.67	%
Expected return on plan assets	7.00	%	7.00	%	6.00	%	6.00	%
Rate of compensation increase	N/A		N/A		3.00	%	4.00	%

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Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows:

	Pension Benefits				Other Postretirement Benefits
	2013		2012		2013		2012
Discount rate	3.65	%	4.16	%	3.67	%	4.13	%
Expected return on plan assets	7.00	%	7.75	%	6.00	%	6.75	%
Rate of compensation increase	N/A*		N/A*		4.00	%	4.00	%

* Effective September 30, 2012, all benefit and service accruals for a union plan were frozen. Compensation increases had previously been frozen for all other plans.

The expected rate of return on pension plan assets is based on the targeted asset allocation range of 60 percent to 70 percent equity securities and 30 percent to 40 percent fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 65 percent to 75 percent equity securities and 25 percent to 35 percent fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.

Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:

				2013					2012
Health care trend rate assumed for next year	6.0	%	-	7.0	%	6.0	%	-	8.0	%
Health care cost trend rate - ultimate	5.0	%	-	6.0	%	5.0	%	-	6.0	%
Year in which ultimate trend rate achieved				2017					2017

The Company's other postretirement benefit plans include health care and life insurance benefits for certain retirees. The plans underlying these benefits may require contributions by the retiree depending on such retiree's age and years of service at retirement or the date of retirement. The accounting for the health care plans anticipates future cost-sharing changes that are consistent with the Company's expressed intent to generally increase retiree contributions each year by the excess of the expected health care cost trend rate over six percent.

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates would have had the following effects at December 31, 2013:

	1 Percentage  Point Increase		1 Percentage Point  Decrease
	(In thousands)
Effect on total of service and interest cost components	$	159	$	(135	)
Effect on postretirement benefit obligation	$	3,352	$	(2,920	)

The Company's pension assets are managed by 16 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.

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The carrying value of the pension plans' Level 1 and 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.

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.

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. Treasury securities are valued based on quoted prices on an active market.

The estimated fair value of the pension plans' Level 2 U.S. Treasury 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 endedDecember 31, 2013 and 2012, 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, 2013, 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, 2013
	(In thousands)
Assets:
Cash equivalents	$	—	$	9,406	$	—	$	9,406
Equity securities:
U.S. companies	62,599		—		—		62,599
International companies	39,437		—		—		39,437
Collective and mutual funds*	116,265		42,483		—		158,748
Corporate bonds	—		42,721		—		42,721
Municipal bonds	—		7,561		—		7,561
U.S. Treasury securities	7,487		4,335		—		11,822
Total assets measured at fair value	$	225,788	$	106,506	$	—	$	332,294

* Collective and mutual funds invest approximately 11 percent in common stock of mid-cap U.S. companies, 34 percent in common stock of large-cap U.S. companies, 11 percent in U.S. Treasuries, 27 percent in corporate bonds and 17 percent in other investments.

The fair value of the Company's pension plans' assets by class were as follows:

100

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Cash equivalents	$	2,145	$	10,460	$	—	$	12,605
Equity securities:
U.S. companies	86,981		—		—		86,981
International companies	39,818		—		—		39,818
Collective and mutual funds*	82,787		20,065		—		102,852
Corporate bonds	—		45,112		—		45,112
Municipal bonds	—		9,302		—		9,302
U.S. Treasury securities	7,980		4,534		—		12,514
Total assets measured at fair value	$	219,711	$	89,473	$	—	$	309,184

* Collective and mutual funds invest approximately 12 percent in common stock of mid-cap U.S. companies, 26 percent in common stock of large-cap U.S. companies, 13 percent in U.S. Treasuries, 41 percent in corporate bonds and 8 percent in other investments.

The following table sets forth a summary of changes in the fair value of the pension plans' Level 3 assets for the year ended December 31, 2012:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Corporate Bonds
	(In thousands)
Balance at beginning of year	$	289
Total realized/unrealized losses	(47		)
Purchases, issuances and settlements (net)	(242		)
Balance at end of year	$	—

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 1 and 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.

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, 2013 and 2012, there were no transfers between Levels 1 and 2.

101

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, 2013, 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, 2013
	(In thousands)
Assets:
Cash equivalents	$	—	$	2,142	$	—	$	2,142
Equity securities:
U.S. companies	2,802		—		—		2,802
International companies	221		—		—		221
Insurance contract*	—		79,374		—		79,374
Total assets measured at fair value	$	3,023	$	81,516	$	—	$	84,539

* The insurance contract invests approximately 55 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Treasuries, 8 percent in mortgage-backed securities, 8 percent in common stock of mid-cap U.S. companies, 9 percent in corporate bonds and 8 percent in other investments.

The fair value of the Company's other postretirement benefit plans' assets by asset class were as follows:

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Cash equivalents	$	1,053	$	1,991	$	—	$	3,044
Equity securities:
U.S. companies	2,207		—		—		2,207
International companies	260		—		—		260
Insurance contract*	—		68,850		—		68,850
Total assets measured at fair value	$	3,520	$	70,841	$	—	$	74,361

* The insurance contract invests approximately 51 percent in common stock of large-cap U.S. companies, 15 percent in U.S. Treasuries, 10 percent in mortgage-backed securities, 11 percent in corporate bonds and 13 percent in other investments.

The Company expects to contribute approximately $32.5 million to its defined benefit pension plans and approximately $1.5 million to its postretirement benefit plans in 2014.

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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)
2014	$	23,391	$	5,596	$	237
2015	23,645		5,584		230
2016	23,911		5,583		221
2017	24,439		5,543		211
2018	24,814		5,483		200
2019 - 2023	130,026		26,038		823

Nonqualified benefit plans

In addition to the qualified plan defined pension benefits reflected in the table at the beginning of this note, the Company also has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for these plans was $7.3 million, $8.1 million and $8.1 million in 2013, 2012 and 2011, respectively. The total projected benefit obligation for these plans was $106.9 million and $113.0 million at December 31, 2013 and 2012, respectively. The accumulated benefit obligation for these plans was $99.7 million and $107.5 million at December 31, 2013 and 2012, respectively. A weighted average discount rate of 4.32 percent and 3.44 percent at December 31, 2013 and 2012, respectively, and a rate of compensation increase of 4.00 percent and 3.00 percent at December 31, 2013 and 2012, were used to determine benefit obligations. A discount rate of 3.44 percent and 4.00 percent at December 31, 2013 and 2012, respectively, and a rate of compensation increase of 3.00 percent and 4.00 percent at December 31, 2013 and 2012, were used to determine net periodic benefit cost.

The amount of benefit payments for the unfunded, nonqualified benefit plans are expected to aggregate $5.7 million in 2014; $6.7 million in 2015; $6.5 million in 2016; $6.7 million in 2017; $7.2 million in 2018 and $37.5 million for the years 2019 through 2023.

In 2012, the Company established a nonqualified defined contribution plan for certain key management employees. Costs incurred under this plan for 2013 and 2012 were $304,000 and $84,000, respectively.

The Company had investments of $98.1 million and $84.4 million at December 31, 2013 and 2012, respectively, consisting of equity securities of $53.5 million and $41.9 million, respectively, life insurance carried on plan participants (payable upon the employee's death) of $31.4 million and $32.7 million, respectively, and other investments of $13.2 million and $9.8 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 $33.2 million in 2013, $29.3 million in 2012 and $27.1 million in 2011.

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 multiemployer plan 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 multiemployer plans, 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 2013 and 2012 is for the plan's year-end at December 31, 2012, and December 31, 2011, respectively. The zone status is based on information that the Company received from the plan and is certified by the plan's

103

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		2013	2012		2013		2012		2011
					(In thousands)
Edison Pension Plan	93-6061681-001	Green as of 12/31/2013	Green as of 12/31/2012	No	$	6,358	$	5,171	$	2,700	No	12/31/2014
IBEW Local 38 Pension Plan	34-6574238-001	Yellow as of 4/30/2013	Yellow as of 4/30/2012	Implemented	1,041		2,771		1,469		No	4/27/2014
IBEW Local No. 82 Pension Plan	31-6127268-001	Red as of 6/30/2013	Red as of 6/30/2012	Implemented	1,284		1,093		1,331		No	11/30/2014
IBEW Local 648 Pension Plan	31-6134845-001	Red as of 2/28/2013	Red as of 2/29/2012	Implemented	1,489		564		722		No	8/31/2015
Laborers Pension Trust Fund for Northern California	94-6277608-001	Yellow as of 5/31/2013	Yellow as of 5/31/2012	Implemented	921		567		628		No	6/30/2016
National Electrical Benefit Fund	53-0181657-001	Green	Green	No	5,883		5,603		4,841		No	5/31/2012*– 8/31/2017
OE Pension Trust Fund	94-6090764-001	Yellow	Yellow as of 12/31/2012	Implemented	1,510		1,156		1,367		No	6/30/2013*– 3/31/2016
Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming	83-6011320-001	Red as of 12/31/2013	Red as of 12/31/2012	Implemented	76		91		96		No	10/31/2005*
Operating Engineers Pension Trust	95-6032478-001	Red as of 6/30/2013	Red as of 6/30/2012	Implemented	493		761		458		No	7/1/2013*– 7/20/2014
Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525	88-6003864-001	Green as of 6/30/2012	Green as of 6/30/2011	No	1,657		1,202		759		No	5/31/2010*
Sheet Metal Workers' Pension Plan of Southern CA, AZ and NV	95-6052257-001	Red as of 12/31/2013	Red as of 12/31/2012	Implemented	512		467		336		No	6/30/2014
Other funds					18,036		15,333		14,451
Total contributions					$	39,260	$	34,779	$	29,158

* 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.

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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	2012 and 2011
IBEW Local 38 Pension Plan	2012 and 2011
IBEW Local No. 82 Pension Plan	2012 and 2011
Local Union No. 124 IBEW Pension Trust Fund	2012 and 2011
Local Union 212 IBEW Pension Trust Fund	2012 and 2011
IBEW Local Union No. 357 Pension Plan A	2012 and 2011
IBEW Local 648 Pension Plan	2012 and 2011
Idaho Plumbers and Pipefitters Pension Plan	2012 and 2011
Minnesota Teamsters Construction Division Pension Fund	2012 and 2011
Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming	2012 and 2011
Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525	2012 and 2011

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 $37.1 million, $31.4 million and $24.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Amounts contributed in 2013, 2012 and 2011 to defined contribution multiemployer plans were $20.6 million, $18.7 million and $15.3 million, respectively.

Note 17 - 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:

	2013		2012
	(In thousands)
Big Stone Station:
Utility plant in service	$	63,890	$	63,146
Less accumulated depreciation	41,323		40,859
	$	22,567	$	22,287
Coyote Station:
Utility plant in service	$	138,261	$	135,073
Less accumulated depreciation	89,528		87,524
	$	48,733	$	47,549
Wygen III:
Utility plant in service	$	64,332	$	63,462
Less accumulated depreciation	4,639		3,368
	$	59,693	$	60,094

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Note 18 - Regulatory Matters and Revenues Subject to Refund

On September 26, 2012, Montana-Dakota filed an application with the MTPSC for a natural gas rate increase. Montana-Dakota requested a total increase of $3.5 million annually or approximately 5.9 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, an operations building, automated meter reading and a new customer billing system. Montana-Dakota requested an interim increase, subject to refund, of $1.7 million or approximately 2.9 percent. On April 12, 2013, the MTPSC issued an interim order authorizing an interim increase of $850,000 annually to be effective with service rendered on or after April 15, 2013, subject to refund. A hearing was held August 5-6, 2013. On December 5, 2013, Montana-Dakota and the Montana Consumer Counsel filed a stipulation with the MTPSC with an increase of $1.5 million annually. On December 12, 2013, the MTPSC approved the stipulation to be effective with service rendered on or after December 15, 2013.

On February 11, 2013, Montana-Dakota filed an application with the NDPSC for approval of an environmental cost recovery rider for recovery of Montana-Dakota's share of the costs resulting from the environmental retrofit required to be installed at the Big Stone Station. The costs proposed to be recovered are associated with the ongoing construction costs for the installation of the BART air-quality control system. On February 27, 2013, the NDPSC suspended the filing pending further review. On May 31, 2013, Montana-Dakota filed revisions to its filing to reflect revised budget amounts. A hearing was held on September 16, 2013. On December 18, 2013, the NDPSC approved the environmental cost recovery rider tariff and adjustment.

On September 18, 2013, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase. Montana-Dakota requested a total increase of $6.8 million annually or approximately 6.4 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and a new customer billing system. Montana-Dakota requested an interim increase, subject to refund, of $4.5 million or approximately 4.2 percent. On October 9, 2013, the NDPSC approved the interim increase to be effective with service rendered on or after November 17, 2013. On October 23, 2013, Montana-Dakota and the NDPSC Advocacy Staff filed a settlement agreement that resolved the revenue requirement portion of the application and reflected a natural gas rate increase of $4.3 million annually or approximately 4.0 percent, and agreed that Montana-Dakota will only implement $4.3 million of interim rate relief. The NDPSC held an informal hearing on the settlement on November 13, 2013. Montana-Dakota implemented the interim rate increase of $4.3 million effective with service rendered on or after November 17, 2013. On December 30, 2013, the NDPSC approved the settlement on the revenue requirement. A hearing on the rate design portion of the case was held February 5, 2014.

On October 31, 2013, WBI Energy Transmission filed a general natural gas rate change application with the FERC for an increase of $28.9 million annually to cover increased investments of $312 million, increased operating costs, and the effect of lower storage and off system volumes. WBI Energy Transmission will begin collecting the requested rates effective May 1, 2014, subject to refund.

Note 19 - 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 $29.5 million and $22.5 million for contingencies, including litigation, production taxes, royalty claims and environmental matters as of December 31, 2013 and 2012, respectively, which include amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note.

Litigation

Guarantee Obligation Under a Construction Contract Centennial guaranteed CEM's obligations under a construction contract with LPP for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. Centennial Resources sold CEM in July 2007 to Bicent. In February 2009, Centennial received a Notice and Demand from LPP under the guarantee agreement alleging that CEM did not meet certain of its obligations under the construction contract and demanding that Centennial indemnify LPP against all losses, damages, claims, costs, charges and expenses arising from CEM's alleged failures. In December 2009, LPP submitted a demand for arbitration of its dispute with CEM to the American Arbitration Association seeking compensatory damages of $149.7 million. An arbitration award was issued January 13, 2012, awarding LPP $22.0 million. Centennial subsequently received a demand from LPP for payment of the arbitration award plus interest and attorneys' fees. An accrual related to the guarantee as a result of the arbitration award was recorded in discontinued operations

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on the Consolidated Statement of Income in the fourth quarter of 2011. CEM filed a petition with the New York Supreme Court to vacate the arbitration award in favor of LPP. On October 19, 2012, Centennial moved to intervene in the New York Supreme Court action to vacate the arbitration award and also filed a complaint with the New York Supreme Court seeking a declaration that LPP is not entitled to indemnification from Centennial under the guaranty for the arbitration award. The New York Supreme Court granted CEM's petition to vacate the arbitration award on November 20, 2012, and entered an order and judgment to that effect on June 5, 2013. LPP appealed the order and judgment and on February 20, 2014, the New York Supreme Court Appellate Division ruled the arbitration award was properly vacated. Due to the vacation of the arbitration award, the Company no longer believes the loss related to this matter to be probable and thus the liability that was previously recorded in 2011 was reversed in the fourth quarter of 2012. The effect of this was recorded in discontinued operations on the Consolidated Statement of Income. For more information regarding discontinued operations, see Note 3.

Construction MaterialsUntil the fall of 2011 when it discontinued active mining operations at the pit, JTL operated the Target Range Gravel Pit in Missoula County, Montana under a 1975 reclamation contract pursuant to the Montana Opencut Mining Act. In September 2009, the Montana DEQ sent a letter asserting JTL was in violation of the Montana Opencut Mining Act by conducting mining operations outside a permitted area. JTL filed a complaint in Montana First Judicial District Court in June 2010, seeking a declaratory order that the reclamation contract is a valid permit under the Montana Opencut Mining Act. The Montana DEQ filed an answer and counterclaim to the complaint in August 2011, alleging JTL was in violation of the Montana Opencut Mining Act and requesting imposition of penalties of not more than $3.7 million plus not more than $5,000 per day from the date of the counterclaim. The Company believes the operation of the Target Range Gravel Pit was conducted under a valid permit; however, the imposition of civil penalties is reasonably possible. The Company filed an application for amendment of its opencut mining permit and intends to resolve this matter through settlement or continuation of the Montana First Judicial District Court litigation.

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. An arbitration hearing was held in August 2010. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. As a result, WBI Energy Midstream, which is included in the pipeline and energy services segment, recorded a $26.6 million charge ($16.5 million after tax) in the third quarter of 2010. On April 20, 2011, the Colorado State District Court confirmed the arbitration award as a court judgment. WBI Energy Midstream filed an appeal from the Colorado State District Court's order and judgment to the Colorado Court of Appeals. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. As a result of the Colorado Court of Appeals decision, in the second quarter of 2012, WBI Energy Midstream changed its estimated loss related to this matter. This resulted in a reduction of expense of $24.1 million ($15.0 million after tax), which was largely reflected in operation and maintenance expense on the Consolidated Statements of Income. On August 2, 2012, SourceGas filed a petition for writ of certiorari with the Colorado Supreme Court for review of the Colorado Court of Appeals decision which was denied on July 22, 2013. On remand of the matter to the Colorado State District Court, SourceGas may assert claims similar to those asserted in the arbitration proceeding.

In a related matter, Omimex filed a complaint against WBI Energy Midstream in Montana Seventeenth Judicial District Court in July 2010 alleging WBI Energy Midstream breached a separate gathering contract with Omimex as a result of the increased operating pressures demanded by SourceGas on the same natural gas gathering system. In December 2011, Omimex filed an amended complaint alleging WBI Energy Midstream breached obligations to operate its gathering system as a common carrier under United States and Montana law. WBI Energy Midstream removed the action to the United States District Court for the District of Montana. The parties subsequently settled the breach of contract claim and, subject to final determination on liability, stipulated to the damages on the common carrier claim, for amounts that are not material. A trial on the common carrier claim was held during July 2013, but a decision has not been issued.

Exploration and Production During the ordinary course of its business, Fidelity is subject to audit for various production related taxes by certain state and federal tax authorities for varying periods as well as claims for royalty obligations under lease agreements for oil and gas production. Disputes may exist regarding facts and questions of law relating to the tax and royalty obligations.

On May 15, 2013, Austin Holdings, LLC filed an action against Fidelity in Wyoming State District Court alleging Fidelity violated the Wyoming Royalty Payment Act and implied lease covenants by deducting production costs from and by failing to properly report and pay royalties for coalbed methane gas production in Wyoming. The plaintiff, in addition to declaratory and

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injunctive relief, seeks class certification for similarly situated persons and an unspecified amount of monetary damages on behalf of the class for unpaid royalties, interest, reporting violations and attorney fees. Fidelity believes it has meritorious defenses against class certification and the claims.

The Company also is subject to other litigation, and actual and potential claims in the ordinary course of its business which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. Accruals are based on the best information available but actual losses in future periods are affected by various factors making them uncertain. After taking into account liabilities accrued for the foregoing matters, management believes that the outcomes with respect to the above issues and other probable and reasonably possible losses in excess of the amounts accrued, while uncertain, will not have a material effect upon the Company's financial position, results of operations or cash flows.

Environmental matters

Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include Knife River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. Knife River - Northwest also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Portland Harbor Natural Resource Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.

Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, Knife River - Northwest does not believe it is a Responsible Party. In addition, Knife River - Northwest has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement. Knife River - Northwest has entered into an agreement tolling the statute of limitations in connection with the LWG's potential claim for contribution to the costs of the remedial investigation and feasibility study. By letter in March 2009, LWG stated its intent to file suit against Knife River - Northwest and others to recover LWG's investigation costs to the extent Knife River - Northwest cannot demonstrate its non-liability for the contamination or is unwilling to participate in an alternative dispute resolution process that has been established to address the matter. At this time, Knife River - Northwest has agreed to participate in the alternative dispute resolution process.

The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced administrative action.

Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade's predecessors.

The first claim is for contamination at a site in Eugene, Oregon which was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. The Oregon DEQ is preparing a staff report which will recommend a cleanup alternative for the site. 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 $1.3 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 an order reauthorizing the deferred accounting for the 12 months starting November 30, 2013.

The second claim is for contamination at a site in Bremerton, Washington which was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in

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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 $12.0 million for the remedial investigation, feasibility study and remediation of this site. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.

The third claim is for contamination at a site in Bellingham, Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade and its predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. Other PRPs have reached an agreed order and work plan with the Washington Department of Ecology for completion of a remedial investigation and feasibility study for the site. A report documenting the initial phase of the remedial investigation was completed in June 2011. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim although Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, it converted the plant to a propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas.

Cascade has received notices from and entered into agreement with certain of its insurance carriers that they will participate in defense of Cascade for these contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers. The accruals related to these matters are reflected in regulatory assets. For more information, see Note 6.

Operating leases

The Company leases certain equipment, facilities and land under operating lease agreements. The amounts of annual minimum lease payments due under these leases as of December 31, 2013, were $32.8 million in 2014, $26.6 million in 2015, $22.2 million in 2016, $17.8 million in 2017, $13.5 million in 2018 and $45.7 million thereafter. Rent expense was $48.1 million, $42.9 million and $40.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Purchase commitments

The Company has entered into various commitments, largely construction, natural gas and coal supply, purchased power, natural gas transportation and storage, service, shipping and construction materials supply contracts, some of which are subject to variability in volume and price. These commitments range from one to 47 years. The commitments under these contracts as of December 31, 2013, were $635.8 million in 2014, $281.6 million in 2015, $170.7 million in 2016, $100.3 million in 2017, $73.4 million in 2018 and $910.8 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, 2013, 2012 and 2011, were $861.8 million, $718.4 million and $626.3 million, respectively.

Guarantees

Centennial guaranteed CEM's obligations under a construction contract. For more information, see Litigation in this note.

In connection with the sale of the Brazilian Transmission Lines, as discussed in Note 4, Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines.

WBI Holdings has guaranteed certain of Fidelity's oil and natural gas swap agreement obligations. There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices. The amount of derivative activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap agreements at December 31, 2013, expire in the years ranging from 2014 to 2015; however, Fidelity continues to enter into additional derivative instruments and, as a result, WBI Holdings from time to time may issue additional guarantees on these derivative instruments. The amount outstanding by Fidelity was $4.8 million and

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was reflected on the Consolidated Balance Sheet at December 31, 2013. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees.

Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts and certain other guarantees. At December 31, 2013, the fixed maximum amounts guaranteed under these agreements aggregated $54.4 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $32.5 million in 2014; $2.1 million in 2015; $700,000 in 2016; $600,000 in 2017; $500,000 in 2018; $500,000 in 2019; $13.5 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $200,000 and was reflected on the Consolidated Balance Sheet at December 31, 2013. 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, 2013, the fixed maximum amounts guaranteed under these letters of credit, aggregated $36.0 million and are scheduled to expire in 2014. There were no amounts outstanding under the above letters of credit at December 31, 2013.

WBI Holdings has an outstanding guarantee to WBI Energy Transmission. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of Prairielands. At December 31, 2013, the fixed maximum amount guaranteed under this agreement was $5.0 million and is scheduled to expire in 2014. In the event of Prairielands' default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $800,000. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at December 31, 2013, because this intercompany transaction was eliminated in consolidation.

In addition, Centennial, Knife River and MDU Construction Services have issued guarantees to third parties related to the routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under these obligations, Centennial, Knife River and MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these guarantees were reflected on the Consolidated Balance Sheet at December 31, 2013.

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, 2013, approximately $516 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, LLCOn February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate Dakota Prairie Refinery in southwestern North Dakota. WBI Energy and Calumet each have a 50 percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments, based on a total project cost of $300 million, under the agreement are $150 million and $75 million, respectively. Capital commitments in excess of $300 million are expected to be shared equally between WBI Energy and Calumet. The total project cost is currently estimated at $350 million. Dakota Prairie Refining entered into a term loan for project debt financing of $75 million on April 22, 2013. The operating agreement provides for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt will be allocated to Calumet. Calumet's future cash distributions from Dakota Prairie Refining will be decreased by the principal and interest to be paid on the project debt, while the cash distributions to WBI Energy will not be decreased. Pursuant to the operating agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan.

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Dakota Prairie Refining has been determined to be a VIE, and the Company has determined that it is the primary beneficiary as it has an obligation to absorb losses that could be potentially significant to the VIE through WBI Energy's equity investment and Centennial's guarantee of the third-party term loan. Accordingly, the Company consolidates Dakota Prairie Refining in its financial statements and records a noncontrolling interest for Calumet's ownership interest.

Construction of Dakota Prairie Refinery began in early 2013 and the plant is not yet operational. Therefore, the results of operations of Dakota Prairie Refining did not have a material effect on the Company's Consolidated Statements of Income. The assets of Dakota Prairie Refining shall be used solely for the benefit of Dakota Prairie Refining. The total assets and liabilities of Dakota Prairie Refining reflected on the Company's Consolidated Balance Sheets at December 31 were as follows:

	2013
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	4,774
Other current assets	26
Total current assets	4,800
Net property, plant and equipment	172,073
Total assets	$	176,873
Liabilities
Current liabilities:
Long-term debt due within one year	$	3,000
Accounts payable	8,904
Taxes payable	5
Accrued compensation	26
Other accrued liabilities	461
Total current liabilities	12,396
Long-term debt	72,000
Total liabilities	$	84,396

Fuel Contract On October 10, 2012, the Coyote Station entered into a new coal supply agreement with Coyote Creek that will replace a coal supply agreement expiring in May 2016. The new agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for the period May 2016 through December 2040.

The new coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal will cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station, with no primary beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements.

At December 31, 2013, 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, 2013, was $7.7 million.

Note 20 - Subsequent Event

On January 28, 2014, the Company entered into a note purchase agreement. The Company contracted to issue $50.0 million and $100.0 million of Senior Notes under the agreement on April 15, 2014 and July 15, 2014, respectively, with due dates ranging from July 2024 to April 2044 at a weighted average interest rate of 4.6 percent.

On December 12, 2013, MDU Energy Capital entered into a note purchase agreement. MDU Energy Capital contracted to issue $30.0 million of Senior Notes under the agreement on January 27, 2014, with due dates ranging from January 2029 to January 2044 at a weighted average interest rate of 5.3 percent.

111

On February 10, 2014, the Company entered into an agreement to purchase working interests and leasehold positions in oil and natural gas production assets in the southern Powder River Basin of Wyoming for approximately $183.0 million, subject to accounting and purchase price adjustments customary with acquisitions of this type. The effective date of the acquisition is October 1, 2013, with the expected closing date to occur on or before April 1, 2014, conditioned upon completing a due diligence process, including environmental reviews, and satisfying other standard closing conditions.

Supplementary Financial Information

Quarterly Data (Unaudited)

The following unaudited information shows selected items by quarter for the years 2013 and 2012:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(In thousands, except per share amounts)
2013
Operating revenues	$	931,604		$	1,060,595		$	1,285,782		$	1,184,423
Operating expenses	827,073			969,217			1,135,909			1,037,306
Operating income	104,531			91,378			149,873			147,117
Income from continuing operations	56,592			46,392			84,550			91,348
Loss from discontinued operations, net of tax	(77		)	(59		)	(118		)	(58		)
Net income attributable to the Company	56,515			46,512			84,456			91,450
Earnings per common share - basic:
Earnings before discontinued operations	.30			.25			.45			.48
Discontinued operations, net of tax	—			—			—			—
Earnings per common share - basic	.30			.25			.45			.48
Earnings per common share - diluted:
Earnings before discontinued operations	.30			.24			.44			.48
Discontinued operations, net of tax	—			—			—			—
Earnings per common share - diluted	.30			.24			.44			.48
Weighted average common shares outstanding:
Basic	188,831			188,831			188,831			188,929
Diluted	189,222			189,463			189,638			189,766
2012
Operating revenues	$	852,807		$	967,962		$	1,173,518		$	1,081,144
Operating expenses	781,750			876,248			1,207,553			1,190,673
Operating income (loss)	71,057			91,714			(34,035		)	(109,529		)
Income (loss) from continuing operations	35,890			49,007			(29,532		)	(69,686		)
Income (loss) from discontinued operations, net of tax	(100		)	5,106			(139		)	8,700
Net income (loss) attributable to the Company	35,790			54,113			(29,671		)	(60,986		)
Earnings per common share - basic:
Earnings (loss) before discontinued operations	.19			.26			(.16		)	(.37		)
Discontinued operations, net of tax	—			.03			—			.05
Earnings (loss) per common share - basic	.19			.29			(.16		)	(.32		)
Earnings (loss) per common share - diluted:
Earnings (loss) before discontinued operations	.19			.26			(.16		)	(.37		)
Discontinued operations, net of tax	—			.03			—			.05
Earnings (loss) per common share - diluted	.19			.29			(.16		)	(.32		)
Weighted average common shares outstanding:
Basic	188,811			188,831			188,831			188,831
Diluted	189,182			189,107			188,831			188,831

Notes:

• First quarter 2013 reflects an unrealized loss on commodity derivatives of $3.7 million (after tax). First quarter 2012 reflects an unrealized loss on commodity derivatives of $2.6 million (after tax).

• Second quarter 2013 reflects an impairment of coalbed natural gas gathering assets of $9.0 million (after tax) and an unrealized gain on commodity derivatives of $8.2 million (after tax). Second quarter 2012 reflects a net benefit of $15.0 million (after tax) related to natural gas gathering operations litigation, a net benefit largely related to estimated insurance recoveries related to the guarantee of a construction contract (reflected in income (loss) from discontinued

112

operations), an unrealized gain on commodity derivatives of $3.0 million (after tax) and an impairment of coalbed natural gas gathering assets of $1.7 million (after tax). For more information, see Notes 1 and 19.

• Third quarter 2013 reflects an unrealized loss on commodity derivatives of $7.9 million (after tax). Third quarter 2012 reflects a $100.9 million (after tax) noncash write-down of oil and natural gas properties and an unrealized loss on commodity derivatives of $700,000 (after tax). For more information, see Note 1.

• Fourth quarter 2013 reflects a net benefit of $1.5 million (after tax) related to natural gas gathering operations litigation and an unrealized loss on commodity derivatives of $500,000 (after tax). Fourth quarter 2012 reflects a $145.9 million (after tax) noncash write-down of oil and natural gas properties, the reversal of an arbitration charge of $13.0 million (after tax) related to a guarantee of a construction contract, which was partially offset by the reversal of estimated insurance recoveries (reflected in income (loss) from discontinued operations), as well as an unrealized loss on commodity derivatives of $200,000 (after tax). For more information, see Notes 1 and 19.

Certain Company operations are highly seasonal and revenues from and certain expenses for such operations may fluctuate significantly among quarterly periods. Accordingly, quarterly financial information may not be indicative of results for a full year.

113

Exploration and Production Activities (Unaudited)

Fidelity is involved in the acquisition, exploration, development and production of oil and natural gas resources. Fidelity shares revenues and expenses from the development of specified properties in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States in proportion to its ownership interests.

The information that follows includes Fidelity's proportionate share of all its oil and natural gas interests.

The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31:

	2013		2012		2011
	(In thousands)
Subject to amortization	$	2,893,010	$	2,531,562	$	2,345,114
Not subject to amortization	124,869		191,794		232,462
Total capitalized costs	3,017,879		2,723,356		2,577,576
Less accumulated depreciation, depletion and amortization	1,562,116		1,383,386		1,229,654
Net capitalized costs	$	1,455,763	$	1,339,970	$	1,347,922
Note: Net capitalized costs reflect noncash write-downs of the Company's oil and natural gas properties, as discussed in Note 1.

Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities were as follows:

Years ended December 31,	2013		*	2012		*	2011		*
	(In thousands)
Acquisitions:
Proved properties	$	1,817		$	839		$	3,999
Unproved properties	4,608			31,109			63,354
Exploration	26,975			235,906			41,775
Development	355,421			275,959			161,647
Total capital expenditures	$	388,821		$	543,813		$	270,775

* Excludes net additions/(reductions) to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of oil and natural gas wells, as discussed in Note 10, of $(10.7) million, $(200,000) and $(1.8) million for the years ended December 31, 2013, 2012 and 2011, respectively.

The preceding table excludes proceeds from the sales of oil and natural gas properties of $83.6 million, $6.0 million and $12.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

114

The following summary reflects income resulting from the Company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs:

Years ended December 31,	2013			2012			2011
	(In thousands)
Revenues:
Sales to affiliates	$	45,099		$	35,966		$	93,713
Sales to external customers	497,018			379,647			348,428
Realized gain on commodity derivatives	173			33,628			9,618
Unrealized gain (loss) on commodity derivatives	(6,267		)	(624		)	1,827
Production costs	144,136			134,795			140,606
Depreciation, depletion and amortization*	182,352			157,078			139,539
Write-downs of oil and natural gas properties	—			391,800			—
Pretax income (loss)	209,535			(235,056		)	173,441
Income tax expense (benefit)	75,836			(88,612		)	63,655
Results of operations for producing activities	$	133,699		$	(146,444	)	$	109,786

* Includes accretion of discount for asset retirement obligations of $3.6 million, $3.3 million and $3.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, as discussed in Note 10.

Estimates of proved reserves were prepared in accordance with guidelines established by the industry and the SEC. The estimates are arrived at using actual historical wellhead production trends and/or standard reservoir engineering methods utilizing available geological, geophysical, engineering and economic data. The proved reserve estimates as of December 31, 2013, 2012 and 2011, were calculated using SEC Defined Prices. Other factors used in the proved reserve estimates are current estimates of well operating and future development costs (which include asset retirement costs), taxes, timing of operations, and the interests owned by the Company in the properties. These estimates are refined as new information becomes available.

The reserve estimates are prepared by internal engineers assigned to an asset team by geographic area. Senior management reviews and approves the reserve estimates to ensure they are materially accurate. In addition, the Company engaged Ryder Scott, an independent third party, to audit its proved reserve quantity estimates.

Estimates of economically recoverable oil, NGL and natural gas reserves and future net revenues therefrom are based upon a number of variable factors and assumptions. For these reasons, estimates of economically recoverable reserves and future net revenues may vary from actual results.

The Company's interests in oil, NGL and natural gas reserves are located in the United States and in and around the Gulf of Mexico.

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 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

115

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2012, were as follows:

	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	27,005		7,342		379,827		97,651
Production	(3,694	)	(828	)	(33,214	)	(10,058	)
Extensions and discoveries	9,874		1,817		18,386		14,756
Improved recovery	—		—		—		—
Purchases of proved reserves	—		—		—		—
Sales of proved reserves	(39	)	—		(2,307	)	(423	)
Revisions of previous estimates	307		(1,178	)	(123,414	)	(21,440	)
Balance at end of year	33,453		7,153		239,278		80,486

Significant changes in proved reserves for the year ended December 31, 2012, include:

• Extension and discoveries of 14.8 MMBOE primarily due to drilling activity at the Company's Bakken, South Texas and Paradox properties

• Revisions of previous estimates of (21.4) MMBOE, largely the result of lower natural gas prices resulting in a reduction of PDP and PUD reserves principally in the Company's Coalbed, Baker, Bowdoin, East Texas and Green River Basin natural gas properties

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2011, were as follows:

	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	25,666		7,201		448,397		107,599
Production	(2,724	)	(776	)	(45,598	)	(11,099	)
Extensions and discoveries	4,717		1,421		28,221		10,842
Improved recovery	—		—		—		—
Purchases of proved reserves	223		16		54		247
Sales of proved reserves	—		—		—		—
Revisions of previous estimates	(877	)	(520	)	(51,247	)	(9,938	)
Balance at end of year	27,005		7,342		379,827		97,651

Significant changes in proved reserves for the year ended December 31, 2011, include:

• Extensions and discoveries of 10.8 MMBOE primarily due to drilling activity at the Company's Bakken and Big Horn properties

• Revisions of previous estimates of (9.9) MMBOE, largely the result of a reduction in PUD reserves of 8.9 MMBOE resulting principally in the Company's Bowdoin, Baker, Coalbed, East Texas and Big Horn Basin properties. The remaining negative revisions were a reduction in PDP natural gas reserves.

116

The following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31:

	2013	2012	2011
Proved developed reserves:
Oil (MBbls)	31,394	27,412	23,653
NGL (MBbls)	5,322	5,342	5,225
Natural Gas (MMcf)	176,546	218,259	303,495
Total (MBOE)	66,140	69,131	79,460
PUD reserves:
Oil (MBbls)	9,625	6,041	3,352
NGL (MBbls)	1,280	1,811	2,117
Natural Gas (MMcf)	21,899	21,019	76,332
Total (MBOE)	14,555	11,355	18,191
Total proved reserves:
Oil (MBbls)	41,019	33,453	27,005
NGL (MBbls)	6,602	7,153	7,342
Natural Gas (MMcf)	198,445	239,278	379,827
Total (MBOE)	80,695	80,486	97,651

As of December 31, 2013, the Company had 14.6 MMBOE of PUD reserves, which is an increase of 3.2 MMBOE from December 31, 2012. The increase relates to the Company adding 11.9 MMBOE of new PUD reserves, primarily in the Company's oil properties. This was partially offset by the Company converting 7.1 MMBOE, requiring $127.3 million of drilling and completion capital in 2013 and PUD revision of (1.6) MMBOE. At December 31, 2013, the Company did not have any PUD locations that remained undeveloped for five years or more. Future development costs estimated to be spent in each of the next three years to develop PUD reserves as of December 31, 2013, are $143.6 million in 2014, $116.0 million in 2015 and $18.1 million in 2016.

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:

	2013		2012		2011
	(In thousands)
Future cash inflows	$	4,507,000	$	3,696,200	$	4,188,000
Future production costs	1,734,800		1,536,500		1,560,300
Future development costs	403,000		301,600		285,300
Future net cash flows before income taxes	2,369,200		1,858,100		2,342,400
Future income tax expense	545,200		304,900		531,100
Future net cash flows	1,824,000		1,553,200		1,811,300
10% annual discount for estimated timing of cash flows	810,000		669,800		832,500
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$	1,014,000	$	883,400	$	978,800

117

The following are the sources of change in the standardized measure of discounted future net cash flows by year:

	2013			2012			2011
	(In thousands)
Beginning of year	$	883,400		$	978,800		$	896,100
Net revenues from production	(398,000		)	(280,800		)	(301,500		)
Net change in sales prices and production costs related to future production	162,200			(406,300		)	82,300
Extensions and discoveries, net of future production-related costs	366,500			355,300			226,300
Improved recovery, net of future production-related costs	—			—			—
Purchases of proved reserves, net of future production-related costs	—			—			9,500
Sales of proved reserves	(37,800		)	(2,600		)	—
Changes in estimated future development costs	6,700			37,600			51,100
Development costs incurred during the current year	141,500			77,700			56,300
Accretion of discount	94,600			121,400			105,000
Net change in income taxes	(141,400		)	110,000			(55,800		)
Revisions of previous estimates	(55,800		)	(100,700		)	(92,900		)
Other	(7,900		)	(7,000		)	2,400
Net change	130,600			(95,400		)	82,700
End of year	$	1,014,000		$	883,400		$	978,800

The estimated discounted future cash inflows from estimated future production of proved reserves were computed using prices as previously discussed. Future production and development costs, which include asset retirement costs, attributable to proved reserves were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying statutory tax rates to the estimated net future pretax cash flows less the tax basis of the oil and gas properties, adjusted for permanent differences and tax credits.

The standardized measure of discounted future net cash flows does not purport to represent the fair market value of oil and natural gas properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. In addition, future realization of oil, NGL and natural gas prices over the remaining reserve lives may vary significantly from SEC Defined Prices.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company.

Evaluation of Disclosure Controls and Procedures

The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. The Company's disclosure controls and other procedures are designed to provide reasonable assurance that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The Company's disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed is accumulated and communicated to management, including the Company's chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company's chief executive officer and chief financial officer, has evaluated the effectiveness of the Company's disclosure controls and procedures. Based upon that evaluation, the chief executive officer and the chief financial officer have concluded that, as of the end of the period covered by this report, such controls and procedures were effective at a reasonable assurance level.

118

Changes in Internal Controls

No change in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended December 31, 2013, that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Annual Report on Internal Control Over Financial Reporting

The information required by this item is included in this Form 10-K at Item 8 - Management's Report on Internal Control Over Financial Reporting.

Attestation Report of the Registered Public Accounting Firm

The information required by this item is included in this Form 10-K at Item 8 - Report of Independent Registered Public Accounting Firm.

Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is included in the last sentence of the third paragraph under the caption "Item 1. Election of Directors" and under the captions "Item 1. Election of Directors - Director Nominees," "Information Concerning Executive Officers," the first paragraph and the second, third and fifth sentences of the second paragraph under "Corporate Governance - Audit Committee," "Corporate Governance - Code of Conduct," the second sentence of the last paragraph under "Corporate Governance - Board Meetings and Committees" and "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement, which information is incorporated herein by reference.

Item 11. Executive Compensation

The information required by this item is included under the caption "Executive Compensation" in the Proxy Statement, which information is incorporated herein by reference.

119

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Equity Compensation Plan Information

The following table includes information as of December 31, 2013, with respect to the Company's equity compensation plans:

Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by stockholders (1)	749,991	(2)	$	21.99	6,176,556	(3)(4)
Equity compensation plans not approved by stockholders	N/A		N/A		N/A
(1) Consists of the Non-Employee Director Long-Term Incentive Compensation Plan, the Long-Term Performance-Based Incentive Plan and the Non-Employee Director Stock Compensation Plan.
(2) Consists of performance shares.
(3) 357,757 shares remain available for future issuance under the Non-Employee Director Long-Term Incentive Compensation Plan in connection with grants of restricted stock, performance units, performance shares or other equity-based awards. 5,643,041 shares under the Long-Term Performance-Based Incentive Plan remain available for future issuance in connection with grants of restricted stock, performance units, performance shares or other equity-based awards.
(4) This amount also includes 175,758 shares available for issuance under the Non-Employee Director Stock Compensation Plan. Under this plan, in addition to a cash retainer, non-employee directors are awarded shares equal in value to $110,000 annually. A non-employee director may acquire additional shares under the plan in lieu of receiving the cash portion of the director's retainer or fees.

The remaining information required by this item is included under the caption "Security Ownership" in the Proxy Statement, which information is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is included under the captions "Related Person Transaction Disclosure," "Corporate Governance - Director Independence" and the second sentence of the third paragraph under "Corporate Governance - Board Meetings and Committees" in the Proxy Statement, which information is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

The information required by this item is included under the caption "Accounting and Auditing Matters" in the Proxy Statement, which information is incorporated herein by reference.

120

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) Financial Statements, Financial Statement Schedules and Exhibits

Index to Financial Statements and Financial Statement Schedules

1. Financial Statements
The following consolidated financial statements required under this item are included under Item 8 - Financial Statements and Supplementary Data.	Page
Consolidated Statements of Income for each of the three years in the period ended December 31, 2013	62
Consolidated Statements of Comprehensive Income for each of the three years in the period ended December 31, 2013	63
Consolidated Balance Sheets at December 31, 2013 and 2012	64
Consolidated Statements of Equity for each of the three years in the period ended December 31, 2013	65
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2013	66
Notes to Consolidated Financial Statements	67

2. Financial Statement Schedules The following financial statement schedules are included in Part IV of this report.	Page
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Statements of Income and Comprehensive Income for each of the three years in the period ended December 31, 2013	122
Condensed Balance Sheets at December 31, 2013 and 2012	123
Condensed Statements of Cash Flows for each of the three years in the period ended December 31, 2013	124
Notes to Condensed Financial Statements	125
Schedule II - Consolidated Valuation and Qualifying Accounts	125

121

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Statements of Income and Comprehensive Income

Years ended December 31,	2013		2012			2011
	(In thousands)
Operating revenues	$	549,239	$	472,302		$	518,268
Operating expenses	473,917		405,095			450,579
Operating income	75,322		67,207			67,689
Other income	3,709		3,925			2,710
Interest expense	17,386		17,297			18,660
Income before income taxes	61,645		53,835			51,739
Income taxes	13,520		11,798			10,476
Equity in earnings (loss) of subsidiaries	230,808		(42,791		)	171,763
Net income (loss) attributable to the Company	278,933		(754		)	213,026
Dividends declared on preferred stocks	685		685			685
Earnings (loss) on common stock	$	278,248	$	(1,439	)	$	212,341
Comprehensive income (loss)	$	289,449	$	(2,474	)	$	197,286

The accompanying notes are an integral part of these condensed financial statements.

122

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Balance Sheets

December 31,	2013			2012
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents	$	5,051		$	3,596
Receivables, net	88,529			89,238
Accounts receivable from subsidiaries	31,372			2,957
Inventories	29,312			41,469
Deferred income taxes	3,196			3,685
Prepayments and other current assets	14,231			9,120
Total current assets	171,691			150,065
Investments	60,687			52,123
Investment in subsidiaries	2,380,829			2,253,294
Property, plant and equipment	1,785,861			1,581,776
Less accumulated depreciation, depletion and amortization	660,693			621,623
Net property, plant and equipment	1,125,168			960,153
Deferred charges and other assets:
Goodwill	4,812			4,812
Other	121,253			155,483
Total deferred charges and other assets	126,065			160,295
Total assets	$	3,864,440		$	3,575,930
Liabilities and Stockholders' Equity
Current liabilities:
Long-term debt due within one year	$	109		$	108
Accounts payable	45,282			42,149
Accounts payable to subsidiaries	4,839			6,423
Taxes payable	12,337			12,399
Dividends payable	33,737			171
Accrued compensation	16,076			10,282
Other accrued liabilities	28,042			29,490
Total current liabilities	140,422			101,022
Long-term debt	434,598			356,760
Deferred credits and other liabilities:
Deferred income taxes	205,639			172,769
Other liabilities	260,617			297,131
Total deferred credits and other liabilities	466,256			469,900
Commitments and contingencies
Stockholders' equity:
Preferred stocks	15,000			15,000
Common stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value
Issued - 189,868,780 shares in 2013 and 189,369,450 shares in 2012	189,869			189,369
Other paid-in capital	1,056,996			1,039,080
Retained earnings	1,603,130			1,457,146
Accumulated other comprehensive loss	(38,205		)	(48,721		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)
Total common stockholders' equity	2,808,164			2,633,248
Total stockholders' equity	2,823,164			2,648,248
Total liabilities and stockholders' equity	$	3,864,440		$	3,575,930

The accompanying notes are an integral part of these condensed financial statements.

123

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Statements of Cash Flows

Years ended December 31,	2013			2012			2011
	(In thousands)
Net cash provided by operating activities	$	188,259		$	225,968		$	217,514
Investing activities:
Capital expenditures	(211,013		)	(150,337		)	(74,580		)
Net proceeds from sale or disposition of property and other	20,624			1,120			720
Investments in and advances to subsidiaries	(1,016		)	(1,387		)	(5,701		)
Investments from and advances from subsidiaries	10,000			5,000			—
Investments	613			12			—
Net cash used in investing activities	(180,792		)	(145,592		)	(79,561		)
Financing activities:
Repayment of short-term borrowings	—			—			(20,000		)
Issuance of long-term debt	77,924			76,000			—
Repayment of long-term debt	(85		)	(21		)	(107		)
Proceeds from issuance of common stock	14,554			88			5,744
Dividends paid	(98,405		)	(159,768		)	(123,323		)
Excess tax benefit on stock-based compensation	—			21			358
Net cash used in financing activities	(6,012		)	(83,680		)	(137,328		)
Increase (decrease) in cash and cash equivalents	1,455			(3,304		)	625
Cash and cash equivalents - beginning of year	3,596			6,900			6,275
Cash and cash equivalents - end of year	$	5,051		$	3,596		$	6,900

The accompanying notes are an integral part of these condensed financial statements.

124

Notes to Condensed Financial Statements

Note 1 - Summary of Significant Accounting Policies

Basis of presentationThe condensed financial information reported in Schedule I is being presented to comply with Rule 12-04 of Regulation S-X. The information is unconsolidated and is presented for the parent company only, which is comprised of MDU Resources Group, Inc. (the Company) and Montana-Dakota and Great Plains, public utility divisions of the Company. In Schedule I, investments in subsidiaries are presented under the equity method of accounting where the assets and liabilities of the subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded on the Condensed Balance Sheets. The income (loss) from subsidiaries is reported as equity in earnings (loss) of subsidiaries on the Condensed Statements of Income. The consolidated financial statements of MDU Resources Group, Inc. reflect certain businesses as discontinued operations. In Schedule I, amounts from discontinued operations have not been separately stated. These statements should be read in conjunction with the consolidated financial statements and notes thereto of MDU Resources Group, Inc.

Earnings (loss) per common share Please refer to the Consolidated Statements of Income of the registrant for earnings (loss) per common share. In addition, see Note 1 of Notes to Consolidated Financial Statements for information on the computation of earnings (loss) per common share.

Note 2 - Debt The Company has long-term debt obligations outstanding of $434.7 million at December 31, 2013, with annual maturities of $100,000 in 2014, $100,000 in 2015, $50.1 million in 2016, $79.0 million in 2017, $100.0 million in 2018 and $205.4 million scheduled to mature in years after 2018.

For more information on debt, see Note 9 of Notes to Consolidated Financial Statements.

Note 3 - Dividends The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on common stock. Cash dividends paid to the Company by subsidiaries were $77.6 million, $125.8 million and $96.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

MDU RESOURCES GROUP, INC.

Schedule II - Consolidated Valuation and Qualifying Accounts

For the years ended December 31, 2013, 2012 and 2011
			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:
2013	$	10,818	$	5,725	$	1,395		$	7,853		$	10,085
2012	12,407		7,064		1,754			10,407			10,818
2011	15,284		3,977		2,112			8,966			12,407

* 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.

125

3. Exhibits

3(a)	Restated Certificate of Incorporation of the Company, as amended, dated May 13, 2010, filed as Exhibit 3(a) to Form 10-Q for the quarter ended September 30, 2010, filed on November 3, 2010, in File No. 1-3480*
3(b)	Company Bylaws, as amended and restated, on March 4, 2013, filed as Exhibit 3 to Form 10-Q for the quarter ended March 31, 2013, filed on May 7, 2013, in File No. 1-3480*
4(a)	Indenture, dated as of December 15, 2003, between the Company and The Bank of New York, as trustee, filed as Exhibit 4(f) to Form S-8 on January 21, 2004, in Registration No. 333-112035*
4(b)	First Supplemental Indenture, dated as of November 17, 2009, between the Company and The Bank of New York Mellon, as trustee, filed as Exhibit 4(c) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
4(c)	Centennial Energy Holdings, Inc. Master Shelf Agreement, dated April 29, 2005, among Centennial Energy Holdings, Inc. and the Prudential Insurance Company of America, filed as Exhibit 4(a) to Form 10-Q for the quarter ended June 30, 2005, filed on August 3, 2005, in File No. 1-3480*
4(d)	Letter Amendment No. 1 to Amended and Restated Master Shelf Agreement, dated May 17, 2006, among Centennial Energy Holdings, Inc., the Prudential Insurance Company of America, and certain investors described in the Letter Amendment, filed as Exhibit 4(a) to Form 10-Q for the quarter ended June 30, 2006, filed on August 4, 2006, in File No. 1-3480*
4(e)	MDU Resources Group, Inc. Credit Agreement, dated May 26, 2011, among MDU Resources Group, Inc., Various Lenders, and Wells Fargo Bank, National Association, as Administrative Agent, filed as Exhibit 4(e) to Form 10-K for the year ended December 31, 2011, filed on February 24, 2012, in File No. 1-3480*
4(f)	First Amendment to Credit Agreement, dated October 4, 2012, among MDU Resources Group, Inc., Various Lenders, and Wells Fargo Bank, National Association, as Administrative Agent, filed as Exhibit 4 to Form 10-Q for the quarter ended September 30, 2012, filed on November 7, 2012, in File No. 1-3480*
4(g)	Centennial Energy Holdings, Inc. Credit Agreement, dated June 8, 2012, among Centennial Energy Holdings, Inc., U.S. Bank National Association, as Administrative Agent, and The Other Financial Institutions party thereto, filed as Exhibit 4 to Form 10-Q for the quarter ended June 30, 2012, filed on August 7, 2012, in File No. 1-3480*
4(h)	MDU Energy Capital, LLC Master Shelf Agreement, dated as of August 9, 2007, among MDU Energy Capital, LLC and the Prudential Insurance Company of America, filed as Exhibit 4 to Form 8-K dated August 16, 2007, filed on August 16, 2007, in File No. 1-3480*
4(i)	Amendment No. 1 to Master Shelf Agreement, dated October 1, 2008, among MDU Energy Capital, LLC, Prudential Investment Management, Inc., the Prudential Insurance Company of America, and the holders of the notes thereunder, filed as Exhibit 4(b) to Form 10-Q for the quarter ended September 30, 2008, filed on November 5, 2008, in File No. 1-3480*
4(j)	Indenture dated as of August 1, 1992, between Cascade Natural Gas Corporation and The Bank of New York relating to Medium-Term Notes, filed by Cascade Natural Gas Corporation as Exhibit 4 to Form 8-K dated August 12, 1992, in File No. 1-7196*
4(k)	First Supplemental Indenture dated as of October 25, 1993, between Cascade Natural Gas Corporation and The Bank of New York relating to Medium-Term Notes and the 7.5% Notes due November 15, 2031, filed by Cascade Natural Gas Corporation as Exhibit 4 to Form 10-Q for the quarter ended June 30, 1993, in File No. 1-7196*
4(l)	Second Supplemental Indenture, dated January 25, 2005, between Cascade Natural Gas Corporation and The Bank of New York, as trustee, filed by Cascade Natural Gas Corporation as Exhibit 4.1 to Form 8-K dated January 25, 2005, filed on January 26, 2005, in File No. 1-7196*
4(m)	Third Supplemental Indenture dated as of March 8, 2007, between Cascade Natural Gas Corporation and The Bank of New York Trust Company, N.A., as Successor Trustee, filed by Cascade Natural Gas Corporation as Exhibit 4.1 to Form 8-K dated March 8, 2007, filed on March 8, 2007, in File No. 1-7196*

126

+10(a)	Supplemental Income Security Plan, as amended and restated November 12, 2009, filed as Exhibit 10(b) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
+10(b)	Director Compensation Policy, as amended May 16, 2013, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2013, filed on August 7, 2013, in File No. 1-3480*
+10(c)	Deferred Compensation Plan for Directors, as amended May 15, 2008, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2008, filed on August 7, 2008, in File No. 1-3480*
+10(d)	Non-Employee Director Stock Compensation Plan, as amended May 12, 2011, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2011, filed on August 5, 2011, in File No. 1-3480*
+10(e)	MDU Resources Group, Inc. Non-Employee Director Long-Term Incentive Compensation Plan, as amended May 17, 2012, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2012, filed on August 7, 2012, in File No. 1-3480*
+10(f)	Long-Term Performance-Based Incentive Plan, as amended November 17, 2011, filed as Exhibit 10(h) to Form 10-K for the year ended December 31, 2011, filed on February 24, 2012, in File No. 1-3480*
+10(g)	MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended March 4, 2013, and Rules and Regulations, as amended March 4, 2013, filed as Exhibit 10(a) to Form 10-Q for the quarter ended March 31, 2013, filed on May 7, 2013, in File No. 1-3480*
+10(h)	Supplemental Executive Retirement Plan for John G. Harp, dated December 4, 2006, filed as Exhibit 10(ag) to Form 10-K for the year ended December 31, 2006, filed on February 21, 2007, in File No. 1-3480*
+10(i)	Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended November 14, 2012, filed as Exhibit 10.1 to Form 8-K dated November 14, 2012, filed on November 20, 2012, in File No. 1-3480*
+10(j)	Form of Annual Incentive Award Agreement under the Long-Term Performance-Based Incentive Plan as amended March 4, 2013, filed as Exhibit 10.2 to Form 8-K dated March 4, 2013, filed on March 7, 2013, in File No. 1-3480*
+10(k)	Form of MDU Resources Group, Inc. Indemnification Agreement for Section 16 Officers and Directors, filed as Exhibit 10.1 to Form 8-K dated August 12, 2010, filed on August 17, 2010, in File No. 1-3480*
+10(l)	MDU Resources Group, Inc. Section 16 Officers and Directors with Indemnification Agreements Chart, as of January 3, 2014**
+10(m)	Employment Letter for J. Kent Wells, dated March 9, 2011, filed as Exhibit 10(v) to Form 10-K for the year ended December 31, 2011, filed on February 24, 2012, in File No. 1-3480*
+10(n)	MDU Resources Group, Inc. Nonqualified Defined Contribution Plan, as adopted November 17, 2011, filed as Exhibit 10(x) to Form 10-K for the year ended December 31, 2011, filed on February 24, 2012, in File No. 1-3480*
+10(o)	MDU Resources Group, Inc. 401(k) Retirement Plan, as restated March 1, 2011, filed as Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 2011, filed on November 4, 2011, in File No. 1-3480*
+10(p)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated March 29, 2011, filed as Exhibit 10(b) to Form 10-Q for the quarter ended March 31, 2011, filed on May 5, 2011, in File No. 1-3480*
+10(q)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated June 30, 2011, filed as Exhibit 10(d) to Form 10-Q for the quarter ended June 30, 2011, filed on August 5, 2011, in File No. 1-3480*
+10(r)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated September 9, 2011, filed as Exhibit 10(b) to Form 10-Q for the quarter ended September 30, 2011, filed on November 4, 2011, in File No. 1-3480*
+10(s)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated December 29, 2011, filed as Exhibit 10(ac) to Form 10-K for the year ended December 31, 2011, filed on February 24, 2012, in File No. 1-3480*

127

+10(t)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated May 24, 2012, filed as Exhibit 10(b) to Form 10-Q for the quarter ended June 30, 2012, filed on August 7, 2012, in File No. 1-3480*
+10(u)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated August 29, 2012, filed as Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 2012, filed on November 7, 2012, in File No. 1-3480*
+10(v)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated August 29, 2012, filed as Exhibit 10(b) to Form 10-Q for the quarter ended September 30, 2012, filed on November 7, 2012, in File No. 1-3480*
+10(w)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated December 19, 2012, filed as Exhibit 10(z) to Form 10-K for the year ended December 31, 2012, filed on February 28, 2013, in File No. 1-3480*
+10(x)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated September 9, 2013, filed as Exhibit 10(b) to Form 10-Q for the quarter ended September 30, 2013, filed on November 7, 2013, in File No. 1-3480*
+10(y)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated September 9, 2013, filed as Exhibit 10(c) to Form 10-Q for the quarter ended September 30, 2013, filed on November 7, 2013, in File No. 1-3480*
+10(z)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated September 23, 2013, filed as Exhibit 10(d) to Form 10-Q for the quarter ended September 30, 2013, filed on November 7, 2013, in File No. 1-3480*
+10(aa)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated December 31, 2013**
+10(ab)	Employment Letter for Jeffrey S. Thiede, dated May 16, 2013**
12	Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends**
21	Subsidiaries of MDU Resources Group, Inc.**
23(a)	Consent of Independent Registered Public Accounting Firm**
23(b)	Consent of Ryder Scott Company, L.P.**
31(a)	Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002**
31(b)	Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002**
32	Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**
95	Mine Safety Disclosures**
99(a)	Ryder Scott Company, L.P. report dated January 27, 2014**
99(b)	Equity Distribution Agreement entered into between MDU Resources Group, Inc. and Wells Fargo Securities, LLC, filed as Exhibit 1 to Form 8-K dated May 20, 2013, filed on May 20, 2013, in File No. 1-3480*
99(c)	First Amendment to Equity Distribution Agreement, dated December 2, 2013, entered into between MDU Resources Group, Inc. and Wells Fargo Securities, LLC**

128

101 The following materials from MDU Resources Group, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Equity, (v) the Consolidated Statements of Cash Flows, (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail, (vii) Schedule I - Condensed Financial Information of Registrant, tagged in summary and detail and (viii) Schedule II - Consolidated Valuation and Qualifying Accounts, tagged in summary and detail

  * Incorporated herein by reference as indicated.

** Filed herewith.

  + Management contract, compensatory plan or arrangement.

MDU Resources Group, Inc. agrees to furnish to the SEC upon request any instrument with respect to long-term debt that MDU Resources Group, Inc. has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.

129

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		MDU Resources Group, Inc.
Date:	February 21, 2014	By:	/s/ David L. Goodin
			David L. Goodin (President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the date indicated.

Signature	Title	Date
/s/ David L. Goodin	Chief Executive Officer and Director	February 21, 2014
David L. Goodin (President and Chief Executive Officer)
/s/ Doran N. Schwartz	Chief Financial Officer	February 21, 2014
Doran N. Schwartz (Vice President and Chief Financial Officer)
/s/ Nathan W. Ring	Chief Accounting Officer	February 21, 2014
Nathan W. Ring (Vice President, Controller and Chief Accounting Officer)
/s/ Harry J. Pearce	Director	February 21, 2014
Harry J. Pearce
(Chairman of the Board)
/s/ Thomas Everist	Director	February 21, 2014
Thomas Everist
/s/ Karen B. Fagg	Director	February 21, 2014
Karen B. Fagg
/s/ Mark A. Hellerstein	Director	February 21, 2014
Mark A. Hellerstein
/s/ A. Bart Holaday	Director	February 21, 2014
A. Bart Holaday
/s/ Dennis W. Johnson	Director	February 21, 2014
Dennis W. Johnson
/s/ Thomas C. Knudson	Director	February 21, 2014
Thomas C. Knudson
/s/ William E. McCracken	Director	February 21, 2014
William E. McCracken
/s/ Patricia L. Moss	Director	February 21, 2014
Patricia L. Moss
/s/ J. Kent Wells	Director	February 21, 2014
J. Kent Wells
/s/ John K. Wilson	Director	February 21, 2014
John K. Wilson

130

EX-10.L

MDU Resources Group, Inc. Section 16 Officers and Directors

with Indemnification Agreements Chart

Section 16 Officers

Name	Title	Date of Agreement
David L. Goodin	President and Chief Executive Officer, MDU Resources Group, Inc.	August 12, 2010
Steven L. Bietz	President and Chief Executive Officer, WBI Holdings, Inc.	August 12, 2010
William R. Connors	Vice President - Renewable Resources, MDU Resources Group, Inc.	August 12, 2010
Mark A. Del Vecchio	Vice President - Human Resources, MDU Resources Group, Inc.	August 12, 2010
Nicole A. Kivisto	Vice President, Controller and Chief Accounting Officer, MDU Resources Group, Inc. until January 3, 2014	August 12, 2010
Cynthia J. Norland	Vice President - Administration, MDU Resources Group, Inc.	August 12, 2010
Paul K. Sandness	General Counsel and Secretary, MDU Resources Group, Inc.	August 12, 2010
Doran N. Schwartz	Vice President and Chief Financial Officer, MDU Resources Group, Inc.	August 12, 2010
John P. Stumpf	Vice President - Strategic Planning, MDU Resources Group, Inc.	August 12, 2010
Douglass A. Mahowald	Treasurer and Assistant Secretary, MDU Resources Group, Inc.	August 12, 2010
J. Kent Wells	Vice Chairman, MDU Resources Group, Inc.; President and Chief Executive Officer, Fidelity Exploration & Production Company	May 2, 2011
K. Frank Morehouse	President and Chief Executive Officer, Montana-Dakota Utilities Co., Great Plains Natural Gas Co., Cascade Natural Gas Corporation, and Intermountain Gas Company	January 4, 2013
David C. Barney	President and Chief Executive Officer, Knife River Corporation	May 16, 2013
Jeffrey S. Thiede	President and Chief Executive Officer, MDU Construction Services Group, Inc.	May 16, 2013
Dennis L. Haider	Executive Vice President - Business Development, MDU Resources Group, Inc.	June 1, 2013
Nathan W. Ring	Vice President, Controller and Chief Accounting Officer, MDU Resources Group, Inc. effective January 3, 2014	January 3, 2014

Directors

Name	Title	Date of Agreement
Harry J. Pearce	Chairman of the Board of Directors	August 12, 2010
David L. Goodin	Director	August 12, 2010
Thomas Everist	Director	August 12, 2010
Karen B. Fagg	Director	August 12, 2010
Mark A. Hellerstein	Director	August 1, 2013
A. Bart Holaday	Director	August 12, 2010
Dennis W. Johnson	Director	August 12, 2010
Thomas C. Knudson	Director	August 12, 2010
William E. McCracken	Director	August 1, 2013
Patricia L. Moss	Director	August 12, 2010
J. Kent Wells	Director	May 2, 2011
John K. Wilson	Director	August 12, 2010

EX-10.AA

INSTRUMENT OF AMENDMENT TO THE

MDU RESOURCES GROUP, INC.

401(k) RETIREMENT PLAN

The MDU Resources Group, Inc. 401(k) Retirement Plan (as amended and restated March 1, 2011) (the “K-Plan”), is hereby further amended, effective January 1, 2014, unless otherwise indicated, as follows:

1. By replacing the table in Section D‑1‑2 Eligibility to Share in the Profit Sharing Feature of Supplement D-1, Provisions Relating to the Profit Sharing Feature for Certain Participating Affiliates, in its entirety, with the following:

Participating Affiliate	Current Effective Date (Original Effective Date)2
Anchorage Sand & Gravel Company, Inc. (excluding President)	January 1, 1999
Baldwin Contracting Company, Inc.	January 1, 1999
Cascade Natural Gas Corporation	January 1, 2011 July 2, 2007
Concrete, Inc.	January 1, 2001
Connolly-Pacific Co.	January 1, 2007
DSS Company	January 1, 2004 (July 8, 1999)
E.S.I., Inc.	January 1, 2008 (January 1, 2003)
Fairbanks Materials, Inc.	May 1, 2008
Granite City Ready Mix, Inc.	June 1, 2002
Great Plains Natural Gas Co.	January 1, 2008
Hawaiian Cement (non-union employees hired after December 31, 2005)	January 1, 2009

Participating Affiliate	Current Effective Date (Original Effective Date)2
Intermountain Gas Company	January 1, 2011
Jebro Incorporated	November 1, 2005
Kent’s Oil Service4	January 1, 2007
Knife River Corporation - Northwest (the Central Oregon Division, f/k/a HTS)	January 1, 2010 (January 1, 1999)
Knife River Corporation - Northwest (the Southern Idaho Division)	January 1, 2010 (January 1, 2006)
Knife River Corporation - Northwest (the Southern Oregon Division)	January 1, 2012
Knife River Corporation - Northwest (the Spokane Division)	January 1, 2010 (January 1, 2006)
Knife River Corporation - Northwest (the Western Oregon Division)	January 1, 2012
Knife River Corporation - South (f/k/a Young Contractors, Inc.)	January 1, 2008 (January 1, 2007)
LTM, Incorporated	January 1, 2003
Montana-Dakota Utilities Co. (including union employees)	January 1, 2008
Oregon Electric Construction, Inc.3	March 7, 2011
Prairielands Energy Marketing, Inc.	January 1, 2012
Wagner Industrial Electric, Inc.	January 1, 2008
Wagner Smith Equipment Co.	January 1, 2008 (July 1, 2000)
WBI Energy, Inc.1/3	May 1, 2012
WBI Energy Midstream, LLC1/3	July 1, 2012 (January 1, 2001)

Participating Affiliate	Current Effective Date (Original Effective Date)2
WBI Energy Transmission, Inc.1/3	July 1, 2012 (January 1, 2009)
WHC, Ltd.	September 1, 2001

¹Eligible employees participating in a management incentive compensation plan or an executive incentive compensation plan are not eligible for a Profit Sharing Contribution. Employees of the WBI Energy Corrosion Services division of WBI Energy Midstream, LLC are excluded from this feature.

²In the event a Participating Affiliate adopts a Profit Sharing Feature on a date other than January 1, effective as of the date of participation in the Plan, the amount of any such contribution allocated to a Supplement D-1 Participant shall be based upon Compensation, received while in the employ of the Participating Affiliate after the date of acquisition by the Company or any Affiliate.

³Requirement to be an Active Employee on the last day of the Plan Year does not apply.

⁴The following participants of Kent’s Oil Service are granted vesting service for prior years of service with Spirit Road Oils: Isaias Jaimes, Hideo Lewis, Christopher Niffenegger, Jose Padilla, George Velador, and Anthony Willis.

Explanation: This amendment removes Bell Electrical Contractors, Inc. as a Participating Affiliate, as a result of standardizing benefits with other MDU Construction Services, Group, Inc. (“CSG”) companies.

2. By replacing the table in Section D‑2‑2 Eligibility to Share in the Retirement Contribution of Supplement D-2, Provisions Relating to the Retirement Contribution Feature for Certain Participating Affiliates, in its entirety, with the following:

Participating Affiliate	Current Effective Date (Original Effective Date)	Retirement Contribution Amount - Percentage of Compensation
Cascade Natural Gas Corporation (non-bargaining)	January 1, 2011 (July 2, 2007)	5%
Cascade Natural Gas Corporation (Field Operations Bargaining Unit employees hired on or after 1/1/2007)	July 2, 2007	4%
Fidelity Exploration & Production Company2	January 1, 2006 (July 2, 2001)	5%
Great Plains Natural Gas Co.	January 1, 2003	5%

Participating Affiliate	Current Effective Date (Original Effective Date)	Retirement Contribution Amount - Percentage of Compensation
Intermountain Gas Company	January 1, 2011 (October 12, 2008)	5%
Oregon Electric Construction, Inc.	March 7, 2011	6%
Rocky Mountain Contractors, Inc. (Union)3	January 1, 2008	3%
Rocky Mountain Contractors, Inc.	January 1, 2005	5%
WBI Energy Midstream, LLC1	July 1, 2012 (January 1, 2001)	5%

¹The following participants of WBI Energy Midstream, LLC are excluded:, Grady Breipohl, Jon Forbes, Richard Guderjahn, Steven Haag, Raymond Harms, Wade Hasler, Douglas Henry, Pamela Lynn, Todd Mandeville, Marlin Mogan, and Dale Sudbrack due to participation in the appropriate pension plan replacement contribution.

²The following participants of Fidelity Exploration & Production Company are excluded: Harlan R. Jirges, Marvin E. Rygh, Judy A. Schmitt, and Dennis M. Zander due to participation in the appropriate pension plan replacement contribution.

³Requirement to be compensated for 1,000 hours of service does not apply to Rocky Mountain Contractors, Inc. (Union).

3. By replacing the following entry in Schedule A:

Bell Electrical Contractors, Inc. (“Bell”) shall not make a matching contribution of each Bell employee’s participating savings contribution.

Effective November 1, 2001 - December 31, 2013

***************************************

Explanation: This amendment provides an end date to the matching contribution provisions for this division as a result of adopting the standard match provisions of Section 3.3(a), due to standardizing benefits with other CSG companies.

IN WITNESS WHEREOF, MDU Resources Group, Inc., as Sponsoring Employer of the Plan, has caused this amendment to be duly executed by a member of the MDU Resources Group, Inc. Employee Benefits Committee (“EBC”) on this   31st   day of December, 2013.

MDU RESOURCES GROUP, INC.

    EMPLOYEE BENEFITS COMMITTEE

By:  /s/ Doran N. Schwartz                        

       Doran N. Schwartz, Chairman

EX-10.AB

INTERNAL CORRESPONDENCE	LOCATION	Corporate Campus
	DATE	May 16, 2013
	WRITER	David L. Goodin
	SUBJECT	Promotion

Jeff Thiede

MDU Construction Services Group, Inc.

I am pleased to offer you the position of President and Chief Executive Officer of MDU Construction Services Group (“CSG”). This position will report to me and will be a member of the Management Policy Committee. Your leadership in continuing to drive high returns on invested capital at CSG along with helping to leverage our talents across all business units to grow our whole corporation is critical. I have every confidence in your abilities to build on past successes and to keep the momentum going.

This position is a Section 16 officer, effective May 16, 2013.

The Compensation Committee of the Board of Directors determined your pay package with input from me. It is a regular, full-time position terminable at will by either party that includes the following terms:

• Effective Date: The effective date of the promotion is April 30, 2013.

• Salary Grade and Base Salary: Your salary grade will increase from “H” to “J”, and your base salary will increase 16.67 percent, from $330,000 annually to $385,000 annually. Future salary increases will be determined by the Compensation Committee, and the timing of such increases is typically in November to become effective the following January.

• EICP: Your Executive Incentive Compensation Plan (EICP) target award will remain at 90 percent of base salary for 2013. Your 2013 EICP will be calculated using your prorated 2013 base salary (i.e., four months at an annualized salary of $330,000 and eight months at an annualized salary of $385,000). For 2014, 2015, 2016 and 2017, I will recommend to the Compensation Committee that your EICP target will decrease from the current 90 percent of base salary to 85 percent, 80 percent, 75 percent and 65 percent of base salary, respectively. The 65 percent of base salary would be consistent with other current executives in this salary grade. I will be recommending to the Compensation Committee that your Long-Term Incentive target be gradually increased to 90 percent of base salary which is discussed below.

In terms of your EICP performance measures, your 2013 EICP results will be tied to CSG’s earnings, and we will use the earnings levels and associated payment levels approved at the November, 2012 Compensation Committee meeting. In future years, your measures will be structured consistent with the other Business Unit President and CEOs’, which is currently 75 percent of the EICP target tied to their Business Unit’s financial results and 25 percent of the EICP target tied to MDUR’s EPS.

Long-Term Performance Based Incentive Plan (Performance Shares): I will recommend to the Compensation Committee that your targeted Performance Share Award for 2014 will be 60 percent of base salary. This grant would be made in February 2014. For 2015, 2016 and 2017, I will recommend that your Long-Term Incentive target increase to 70 percent,

80 percent and 90 percent of base salary, respectively. Mark Del Vecchio will be discussing with you how the incentive program works.

• Benefits: Your current employee benefits package will not change, and you will continue to participate in the various plans consistent with CSG Corporate status.

• Non-Qualified Defined Contribution Plan (NQDCP): Recall that you began participating in the NQDCP on January 1, 2013. As a reminder, the NQDCP is an executive retirement program whereby the Company credits to an account in your name at New York Life (“NYL”), and you can invest the account balance in a number of investment vehicles. After four years of continuous employment from the date of the Company’s initial credit, the credit and any investment earnings (or losses) become “vested” and will be distributed to you in accordance with the distribution election you made upon joining the NQDCP.

At the Compensation Committee’s November, 2013 meeting, I will recommend that the Compensation Committee credit $75,000 to your NYL account effective January 1, 2014. Additional account credits after 2014 will be considered by the Compensation Committee each year thereafter. Please note that the January 1, 2014, account credit (if approved), and any subsequent account credits, are made pursuant to the terms of the Plan, including the aforementioned four-year employment requirement.

• Relocation: As we discussed, my expectation is that Bismarck is intended to be your headquarters. However, given your current situation I did agree to you basing out of the Portland area for now and that we will revisit the location over the next 12 months. Longer term I feel Bismarck is the appropriate location.

• Background Check: As you are now leading the CSG Business Unit, we will be conducting a background check to ensure we are setting a proper “tone at the top”.

• Complete Agreement: This outlines the complete agreement of the compensation related terms and conditions of your employment. This supersedes any prior agreements or understandings.

The forgoing information is for overview purposes, and the specific terms and conditions of each program is outlined in the appropriate plan documents and/or award letters.

Jeff, congratulations on your increased roles and responsibilities. I am grateful to have you on the leadership team and look forward to many future successes.

		Sincerely,
		/s/ David L. Goodin
		David L. Goodin
		President and Chief
		Executive Officer
		MDU Resources Group, Inc.
cc:D. Anderson	M. Del Vecchio	F. Richard

EX-12

MDU RESOURCES GROUP, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

AND COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

	Years Ended December 31,
	2013			2012				2011			2010			2009
	(In thousands of dollars)
Earnings Available for Fixed Charges:
Net Income (a)	$	281,163		$	(14,939	)		$	223,842		$	218,205		$	(126,653	)
Income Taxes	136,736			(31,146		)		110,273			122,530			(96,092		)
	417,899			(46,085		)		334,115			340,735			(222,745		)
Rents (b)	16,035			13,716				13,568			12,897			14,475
Interest (c)	92,481			83,781				86,505			88,930			89,943
Total Earnings Available for Fixed Charges	$	526,415		$	51,412			$	434,188		$	442,562		$	(118,327	)
Preferred Dividend Requirements	$	685		$	685			$	685		$	685		$	685
Ratio of Income Before Income Taxes to Net Income	149		%	308		%		149		%	156		%	176		%
Preferred Dividend Factor on Pretax Basis	1,021			2,110				1,021			1,069			1,206
Fixed Charges (d)	107,892			100,516				106,348			107,552			109,117
Combined Fixed Charges and Preferred Stock Dividends	$	108,913		$	102,626			$	107,369		$	108,621		$	110,323
Ratio of Earnings to Fixed Charges	4.9x			—			(e)	4.1x			4.1x			—			(f)
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends	4.8x			—			(e)	4.0x			4.1x			—			(f)

(a) Net income excludes undistributed income for equity investees.

(b) Represents interest portion of rents estimated at 33 1/3%.

(c) Represents interest, amortization of debt discount and expense on all indebtedness and amortization of interest capitalized, and excludes amortization of gains or losses on reacquired debt (which, under the Federal Energy Regulatory Commission Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income) and interest capitalized.

(d) Represents rents (as defined above), interest, amortization of debt discount and expense on all indebtedness, and excludes amortization of gains or losses on reacquired debt (which, under the Federal Energy Regulatory Commission Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income).

(e) Due to the $246.8 million after-tax noncash write-downs of oil and natural gas properties in 2012, earnings were insufficient by $51.2 million to cover fixed charges for the 12 months ended December 31, 2012. If the $246.8 million after-tax noncash write-downs were excluded, the ratio of earnings to fixed charges and the ratio of earnings to combined fixed charges and preferred stock dividends would both have been 4.4 times for the twelve months ended December 31, 2012.

(f) Due to the $384.4 million after-tax noncash write-down of oil and natural gas properties in 2009, earnings were insufficient by $228.7 million to cover combined fixed charges and preferred stock dividends for the twelve months ended December 31, 2009. If the $384.4 million after-tax noncash write-down is excluded, the ratio of earnings to fixed charges and the ratio of earnings to combined fixed charges and preferred stock dividends would both have been 4.6 times for the twelve months ended December 31, 2009.

The above ratios related to fixed charges and combined fixed charges and preferred stock dividends that exclude the effect of after-tax noncash write-downs of oil and natural gas properties are non-GAAP financial measures. The Company believes that these non-GAAP financial measures are useful because the write-downs excluded are not indicative of the Company’s cash flows available to meet its fixed charges obligations. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.

EX-21

MDU RESOURCES GROUP, INC.

List of Subsidiaries

(effective December 31, 2013)

	Jurisdiction of
Subsidiaries	Formation
Alaska Basic Industries, Inc.	Alaska
Ames Sand & Gravel, Inc.	North Dakota
Anchorage Sand and Gravel Company, Inc.	Alaska
Baldwin Contracting Company, Inc.	California
BEH Electric Holdings, LLC	Nevada
Bell Electrical Contractors, Inc.	Missouri
BMH Mechanical Holdings, LLC	Nevada
Bombard Electric, LLC	Nevada
Bombard Mechanical, LLC	Nevada
Capital Electric Construction Company, Inc.	Kansas
Capital Electric Line Builders, Inc.	Kansas
Cascade Natural Gas Corporation	Washington
Centennial Energy Holdings, Inc.	Delaware
Centennial Energy Resources International, Inc.	Delaware
Centennial Energy Resources LLC	Delaware
Centennial Holdings Capital LLC	Delaware
Central Oregon Redi-Mix, LLC	Oregon
CGC Resources, Inc.	Washington
Concrete, Inc.	California
Connolly-Pacific Co.	California
Continental Line Builders, Inc.	Delaware
Coordinating and Planning Services, Inc.	Delaware
D S S Company	California
Desert Fire Holdings, Inc.	Nevada
Desert Fire Protection, a Nevada Limited Partnership	Nevada
Desert Fire Protection, Inc.	Nevada
Desert Fire Protection, LLC	Nevada
E.S.I., Inc.	Ohio
Fairbanks Materials, Inc.	Alaska
Fidelity Exploration & Production Company	Delaware
Fidelity Oil Co.	Delaware
Frebco, Inc.	Ohio
FutureSource Capital Corp.	Delaware
Granite City Ready Mix, Inc.	Minnesota
Hamlin Electric Company	Colorado
Harp Engineering, Inc.	Montana
Hawaiian Cement, a partnership	Hawaii
ILB Hawaii, Inc.	Hawaii

Independent Fire Fabricators, LLC	Nevada
Intermountain Gas Company	Idaho
International Line Builders, Inc.	Delaware
InterSource Insurance Company	Vermont
Jebro Incorporated	Iowa
JTL Group, Inc. (Montana corporation)	Montana
JTL Group, Inc. (Wyoming corporation)	Wyoming
Kent’s Oil Service	California
Knife River Corporation	Delaware
Knife River Corporation - North Central	Minnesota
Knife River Corporation - Northwest	Oregon
Knife River Corporation - South	Texas
Knife River Dakota, Inc.	Delaware
Knife River Hawaii, Inc.	Delaware
Knife River Marine, Inc.	Delaware
Knife River Midwest, LLC	Delaware
KRC Holdings, Inc.	Delaware
LME&U Holdings, LLC	Nevada
Lone Mountain Excavation & Utilities, LLC	Nevada
Loy Clark Pipeline Co.	Oregon
LTM, Incorporated	Oregon
MDU Brasil Ltda.	Brazil
MDU Construction Services Group, Inc.	Delaware
MDU Energy Capital, LLC	Delaware
MDU Industrial Services, Inc.	Delaware
MDU Resources International LLC	Delaware
MDU Resources Luxembourg I LLC S.a.r.l.	Luxembourg
MDU Resources Luxembourg II LLC S.a.r.l.	Luxembourg
MDU United Construction Solutions, Inc.	Delaware
Midland Technical Crafts, Inc.	Delaware
Nevada Solar Solutions, LLC	Delaware
Northstar Materials, Inc.	Minnesota
Oregon Electric Construction, Inc.	Oregon
Pouk & Steinle, Inc.	California
Prairie Cascade Energy Holdings, LLC	Delaware
Prairie Intermountain Energy Holdings, LLC	Delaware
Prairielands Energy Marketing, Inc.	Delaware
Rocky Mountain Contractors, Inc.	Montana
USI Industrial Services, Inc.	Delaware
Wagner Group, Inc., The	Delaware
Wagner Industrial Electric, Inc.	Delaware
Wagner-Smith Company, The	Ohio
Wagner-Smith Equipment Co.	Delaware
Wagner-Smith Pumps & Systems, Inc.	Ohio
Warner Enterprises, Inc.	Nevada
WBI Canadian Pipeline, Ltd.	Canada

WBI Energy Midstream Utah, LLC	Delaware
WBI Energy Midstream, LLC	Colorado
WBI Energy Services, Inc.	Delaware
WBI Energy Transmission, Inc.	Delaware
WBI Energy, Inc.	Delaware
WBI Holdings, Inc.	Delaware
WHC, Ltd.	Hawaii

EX-23.A

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements No. 333-178042 and No. 333-174326on Form S‑3, and No. 333-27877, No. 333‑118622, No. 333‑114488, and No. 333-158572 on Form S‑8, of our reports dated February 21, 2014, relating to the consolidated financial statements and financial statement schedules of MDU Resources Group, Inc. and subsidiaries (the “Company”), and the effectiveness of the Company's internal control over financial reporting, appearing in this Annual Report on Form 10‑K of the Company for the year ended December 31, 2013.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 21, 2014

EX-23.B

RYDER SCOTT COMPANY
PETROLEUM CONSULTANTS
TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA STREET SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

CONSENT OF RYDER SCOTT COMPANY, L.P.

As independent oil and gas consultants, Ryder Scott Company, L.P. hereby consents to the incorporation by reference in Registration Statement No. 333-178042 and No. 333-174326 on Form S-3, and No. 333-27877, No. 333-118622, No. 333-114488, and No. 333-158572 on Form S-8, of all references to our firm’s name and audit of portions of Fidelity Exploration & Production Company’s (“Fidelity”) proved oil, NGL and natural gas reserves estimates as of December 31, 2013, as described in our letter to Fidelity dated January 27, 2014, included in or made a part of MDU Resources Group, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013. Ryder Scott Company, L.P. recognizes Fidelity is an indirect wholly owned subsidiary of MDU Resources Group, Inc. who makes filings with the Securities and Exchange Commission.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm License No. F-1580

Houston, Texas

February 21, 2014

SUITE 600, 1015 4TH STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790
621 17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

EX-31.A

CERTIFICATION

I, David L. Goodin, certify that:

1. I have reviewed this annual report on Form 10-K of MDU Resources Group, Inc.;

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

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

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

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

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

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

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

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

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

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

Date:  February 21, 2014

/s/ David L. Goodin

David L. Goodin

President and Chief Executive Officer

EX-31.B

CERTIFICATION

I, Doran N. Schwartz, certify that:

1. I have reviewed this annual report on Form 10-K of MDU Resources Group, Inc.;

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

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

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

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

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

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

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

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

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

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

Date:  February 21, 2014

/s/ Doran N. Schwartz  

Doran N. Schwartz

Vice President and Chief Financial Officer

EX-32

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

Each of the undersigned, David L. Goodin, the President and Chief Executive Officer, and Doran N. Schwartz, the Vice President and Chief Financial Officer of MDU Resources Group, Inc. (the "Company"), DOES HEREBY CERTIFY that:

1.  The Company's Annual Report on Form 10-K for the year ended December 31, 2013 (the "Report"), fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

2.  Information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.

IN WITNESS WHEREOF, each of the undersigned has executed this statement this 21^st day of February, 2014.

 /s/ David L. Goodin

David L. Goodin

President and Chief Executive Officer

 /s/ Doran N. Schwartz

Doran N. Schwartz

Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to MDU Resources Group, Inc. and will be retained by MDU Resources Group, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-95

MDU RESOURCES GROUP, INC.

MINE SAFETY INFORMATION

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Federal Mine Safety and Health Act of 1977 (Mine Act), as amended by the Mine Improvement and New Emergency Response Act of 2006 (Mine Safety Act). The Dodd-Frank Act requires reporting of the following types of citations or orders:

1. Citations issued under Section 104 of the Mine Safety Act for violations that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard.

2. Orders issued under Section 104(b) of the Mine Safety Act. Orders are issued under this section when citations issued under Section 104 have not been totally abated within the time period allowed by the citation or subsequent extensions.

3. Citations or orders issued under Section 104(d) of the Mine Safety Act. Citations or orders are issued under this section when it has been determined that the violation is caused by an unwarrantable failure of the mine operator to comply with the standards. An unwarrantable failure occurs when the mine operator is deemed to have engaged in aggravated conduct constituting more than ordinary negligence.

4. Citations issued under Section 110(b)(2) of the Mine Safety Act for flagrant violations. Violations are considered flagrant for repeat or reckless failures to make reasonable efforts to eliminate a known violation of a mandatory health and safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury.

5. Imminent danger orders issued under Section 107(a) of the Mine Safety Act. An imminent danger is defined as the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated.

6. Notice received under Section 104(e) of the Mine Safety Act of a pattern of violations or the potential to have such a pattern of violations that could significantly and substantially contribute to the cause and effect of mine health and safety standards.

During the twelve months ended December 31, 2013, none of the Company's operating subsidiaries received citations or orders under the following sections of the Mine Safety Act: 104(b), 104(d), 110(b)(2) or 104(e). During the twelve months ended December 31, 2013, two of the company's operating subsidiaries received orders under Section 107(a) of the Mine Safety Act. The Company did not have any mining-related fatalities during this period.

1

MSHA Identification Number	Section 104 S&S Citations (#)	Section 107(a) Orders (#)	Total Dollar Value of MSHA Assessments Proposed ($)		Legal Actions Pending as of Last Day of Period (#)	Legal Actions Initiated During Period (#)	Legal Actions Resolved During Period (#)
04-00081	—	—	$	—	4	—	—
04-01698	2	—	1,625		—	—	5
04-05140	—	—	100		—	—	3
04-05459	1	1	1,240		1	1	—
10-02089	1	—	550		—	—	1
21-00462	3	—	52,500		1	—	—
21-00519	—	—	200		—	—	—
21-02702	—	—	200		—	—	—
21-03112	—	—	100		—	—	—
21-03133	—	—	100		—	—	—
21-03248	1	—	400		—	—	—
21-03348	—	—	200		—	—	—
21-03416	—	—	200		—	—	—
21-03560	—	—	100		—	—	—
21-03790	—	—	200		—	—	—
24-00462	—	—	200		—	—	—
24-00478	1	—	600		—	—	—
24-01935	—	—	600		—	—	—
24-02022	2	—	617		1	1	—
24-02095	—	—	100		—	—	—
24-02414	—	—	300		—	1	1
24-02656	2	1	1,009		—	—	—
32-00774	1	—	408		—	—	—
32-00776	—	—	100		—	—	—
32-00777	—	—	200		—	—	—
32-00778	2	—	—		—	—	—
32-00950	2	—	2,092		2	2	—
32-00963	—	—	100		—	—	—
35-00463	—	—	100		—	—	—
35-00495	—	—	390		—	—	—
35-02906	—	—	100		—	—	—
35-02968	—	—	700		—	—	—
35-03022	1	—	890		—	—	—
35-03131	—	—	200		—	—	—
35-03321	1	—	492		—	—	—
35-03449	—	—	—		—	—	5
35-03478	—	—	300		—	—	—
35-03496	1	—	792		—	—	—
35-03505	—	—	100		—	—	—
35-03527	3	—	490		—	—	—
35-03581	—	—	200		—	—	—
35-03590	—	—	200		—	—	—

2

MSHA Identification Number	Section 104 S&S Citations (#)	Section 107(a) Orders (#)	Total Dollar Value of MSHA Assessments Proposed ($)		Legal Actions Pending as of Last Day of Period (#)	Legal Actions Initiated During Period (#)	Legal Actions Resolved During Period (#)
35-03605	—	—	100		—	—	—
35-03642	—	—	100		—	—	—
35-03667	1	—	8,100		—	1	4
35-03678	—	—	100		—	—	—
41-02639	—	—	100		—	—	1
41-03931	1	—	500		—	—	—
48-01383	—	—	2,369		—	4	4
50-00883	3	—	824		—	—	—
50-01196	2	—	1,120		—	—	—
51-00036	6	—	7,723		5	5	—
51-00171	—	—	100		—	—	—
51-00195	—	—	100		—	—	—
51-00241	—	—	100		—	—	—
51-00245	—	—	412		—	—	—
51-00305	—	—	100		—	—	—
	37	2	$	90,843	14	15	24

Legal actions pending before the Federal Mine Safety and Health Review Commission (the Commission) may involve, among other questions, challenges by operators to citations, orders and penalties they have received from the Federal Mine Safety and Health Administration (MSHA) or complaints of discrimination by miners under section 105 of the Mine Act. The following is a brief description of the types of legal actions that may be brought before the Commission.

• Contests of Citations and Orders - A contest proceeding may be filed with the Commission by operators, miners or miners' representatives to challenge the issuance of a citation or order issued by MSHA.

• Contests of Proposed Penalties (Petitions for Assessment of Penalties) - A contest of a proposed penalty is an administrative proceeding before the Commission challenging a civil penalty that MSHA has proposed for the alleged violation contained in a citation or order.

• Complaints for Compensation - A complaint for compensation may be filed with the Commission by miners entitled to compensation when a mine is closed by certain withdrawal orders issued by MSHA. The purpose of the proceeding is to determine the amount of compensation, if any, due miners idled by the orders.

• Complaints of Discharge, Discrimination or Interference - A discrimination proceeding is a case that involves a miner's allegation that he or she has suffered a wrong by the operator because he or she engaged in some type of activity protected under the Mine Act, such as making a safety complaint.

• Applications for Temporary Relief - Applications for temporary relief from any modification or termination of any order or from any order issued under section 104 of the Mine Act.

• Appeals of Judges' Decisions or Orders to the Commission - A filing with the Commission for discretionary review of a judge's decision or order by a person who has been adversely affected or aggrieved by such decision or order.

The following table reflects the types of legal actions pending before the Commission as of December 31, 2013:

3

MSHA Identification Number	Contests of Citations and Orders	Contests of Proposed Penalties	Complaints for Compensation	Complaints of Discharge, Discrimination or Interference	Applications for Temporary Relief	Appeals of Judges' Decisions or Orders to the Commission
04-00081	—	—	—	—	—	4
04-05459	1	—	—	—	—	—
21-00462	—	1	—	—	—	—
24-02022	1	—	—	—	—	—
32-00950	2	—	—	—	—	—
51-00036	—	5	—	—	—	—
	4	6	—	—	—	4

4

EX-99.A

FIDELITY EXPLORATION & PRODUCTION COMPANY

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2013

/s/ Joseph E. Blankenship

Joseph E. Blankenship, P.E.

TBPE License No. 62093

Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

RYDER SCOTT COMPANY
PETROLEUM CONSULTANTS
TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA STREET SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191
	January 27, 2014

Fidelity Exploration & Production Company

1700 Lincoln, Suite 2800

Denver, Colorado 80203

Gentlemen:

At the request of Fidelity Exploration & Production Company (Fidelity), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2013 prepared by Fidelity’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Fidelity Exploration & Production Company is an indirect wholly owned subsidiary of MDU Resources (MDU).

Our third party reserves audit, completed on January 23, 2014 and presented herein, was prepared for public disclosure by MDU in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Fidelity’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by Fidelity, which were all reviewed by Ryder Scott, as of December 31, 2013. The properties reviewed by Ryder Scott incorporate 3222 reserve determinations and are located in the states of Alabama, Arkansas, Colorado, Louisiana, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah, Wyoming, and in federal waters offshore Louisiana and Texas.

The properties reviewed by Ryder Scott account for 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Fidelity as of December 31, 2013.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

Based on our review, including the data, technical processes and interpretations presented by Fidelity, it is our opinion that the overall procedures and methodologies utilized by Fidelity in preparing their estimates of the proved reserves as of December 31, 2013 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Fidelity are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

Fidelity Exploration & Production Company

January 27, 2014

Page 2

The estimated reserves presented in this report are related to hydrocarbon prices. Fidelity has informed us that in the preparation of their reserve and income projections, as of December 31, 2013, they used average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Fidelity attributable to Fidelity's interests in properties that we reviewed are summarized as follows:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests of

Fidelity Exploration & Production Company

As of December 31, 2013

	Proved
	Developed			Total
	Producing	Non-Producing	Undeveloped	Proved
Total Net Reserves All Audited by Ryder Scott
Oil/Condensate - Barrels	30,340,787	1,053,097	9,624,858	41,018,742
Plant Products - Barrels	4,396,622	925,791	1,279,878	6,602,291
Gas – MMCF	143,048	33,498	21,899	198,445

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Fidelity Exploration & Production Company

January 27, 2014

Page 3

than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Fidelity’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered,could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Fidelity Exploration & Production Company

January 27, 2014

Page 4

proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation, which utilized extrapolations of historical production and pressure data available through October 2013, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Fidelity or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 5 percent of the proved producing reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 100 percent of the proved developed non-producing and undeveloped reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods.The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Fidelity for our review or which we have obtained from public data sources that were available through October 2013. The data utilized from the analogues as wellas well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.

Fidelity’s reserves are in conventional formations, coal seams and shales. Although most of Fidelity’s reserves are based on primary recovery, some of Fidelity’s reserves are based on secondary recovery; examples would include some of Fidelity’s properties operated by Denbury Resources Inc. in Montana and North Dakota. Although most of Fidelity’s reserves will be produced through vertical wellbores, some of Fidelity’s reserves will be produced through horizontal wellbores; examples would include Fidelity’s wells producing the Bakken Shale and Barnett Shale.

To estimate economically recoverable proved oil and gas reserves, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Fidelity Exploration & Production Company

January 27, 2014

Page 5

reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Fidelity relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Fidelity for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2013 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Fidelity for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by Fidelity to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used by Fidelity were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Fidelity.

The table below summarizes Fidelity’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Fidelity’s “average realized prices.” The average realized prices shown in the table below were determined from Fidelity’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Fidelity’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$96.94/Bbl	$90.23/Bbl
	NGLs	WTI Cushing	$96.94/Bbl	$36.30/Bbl
	Gas	Colorado Interstate	$3.53/MMBTU	$2.85/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Fidelity’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Fidelity Exploration & Production Company

January 27, 2014

Page 6

Operating costs used by Fidelity are based on the operating expense reports of Fidelity and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by Fidelity were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Fidelity. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Fidelity are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Fidelity were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Fidelity. The estimated net cost of abandonment after salvage was included by Fidelity for properties where abandonment costs net of salvage were significant. Fidelity’s estimates of the net abandonment costs were accepted without independent verification.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Fidelity’s plans to develop these reserves as of December 31, 2013. The implementation of Fidelity’s development plans as presented to us is subject to the approval process adopted by Fidelity’s management. As the result of our inquires during the course of our review, Fidelity has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Fidelity’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Fidelity. Additionally, Fidelity has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans. All of Fidelity’s proved undeveloped reserves are scheduled to be developed within the five year window, from the first booked date, as prescribed by the SEC.

Current costs used by Fidelity were held constant throughout the life of the properties.

Fidelity’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend had been established, future production rates were held constant, or inclined during the dewatering phase for coal seam gas, as appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend had been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Fidelity to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Fidelity. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Fidelity’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Fidelity Exploration & Production Company

January 27, 2014

Page 7

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Fidelity’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Fidelity owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Fidelity for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Fidelity are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Fidelity has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Fidelity’s forecast of future proved production, we have relied upon data furnished by Fidelity with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Fidelity. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by Fidelity to be appropriate and sufficient for the purpose of our review of Fidelity’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Fidelity and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Fidelity, it is our opinion that the overall procedures and methodologies utilized by Fidelity in preparing their estimates of the proved reserves as of December 31, 2013 comply with the current SEC

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Fidelity Exploration & Production Company

January 27, 2014

Page 8

regulations and that the overall proved reserves for the reviewed properties as estimated by Fidelity are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

We were in reasonable agreement with Fidelity's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Fidelity's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Fidelity when its reserve estimates were prepared.However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Fidelity.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Fidelity. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

Fidelity Exploration & Production Company is an indirect wholly owned subsidiary of MDU Resources (MDU). The results of our third party audit, presented in report form herein, were prepared

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Fidelity Exploration & Production Company

January 27, 2014

Page 9

in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by MDU.

MDU makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, MDU has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8of MDU of the references to our name as well as to the references to our third party report for Fidelity, which appears in the December 31, 2013 annual report on Form 10-Kof MDU. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by MDU.

We have provided Fidelity with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Fidelity and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Joseph E. Blankenship

Joseph E. Blankenship, P.E.

TBPE License No. 62093

Senior Vice President

[SEAL]

JEB (DPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Joseph E. Blankenship was the primary technical person responsible for overseeing the estimation and evaluation process with respect to the preparation of this report.

Mr. Blankenship, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1982, is a Senior Vice President and also serves as Chief Technical Advisor for unconventional reserves evaluation. Mr. Blankenship is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Blankenship served in a number of engineering positions with Exxon Company USA. For more information regarding Mr. Blankenship’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Blankenship earned a Bachelor of Science degree in Mechanical Engineering from the University of Alabama in 1977. He is a member of the Honorary Engineering Society Pi Tau Sigma and is a licensed Professional Engineer in the State of Texas. He attended Exxon schools on Reservoir Engineering, Well Log Analysis, Economic Evaluation, Oil and Gas Facility Design, and Offshore Platform Design. He is also a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE). He has served as Chairman of the SPE Newsletter Committee and has been invited by the SPEE to lecture on the subject of Coal Seam evaluation.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Blankenship fulfills. Mr. Blankenship’s continuing education in 2013 included training on Booking of Enhanced Oil Recovery (EOR) Reserves, Formation Fracturing Statistics, SEC Reserves Disclosures, Analysis of Shale Reserves, and Reserves Reconciliation. Mr. Blankenship also served as instructor in two courses on Unconventional Resource Evaluation.

In 2012, Mr. Blankenship’s attended classes on The Application of SPEE Monograph 3, Statistical Review of Shale Plays, the Simulation Model Review Process, A New SEC Data Gathering Program, Reserves Impact on Book Value Calculations, Comparison of Different Reserves Standards, Different Production Decline Models Used for Resource Plays, and Eagle Ford Shale Play Volumetric Analysis. Mr. Blankenship also served as instructor in some short courses on Unconventional Resource Evaluation.

In 2011, Mr. Blankenship attended classes on Professional Resource Planning, Microsoft Access Utilization in the Area of Reserves Evaluation, Fekete Reservoir Engineering Software Optimization and Utilization, and the Utilization of Correct SEC Reserves and PRMS Resource Evaluation Criteria.

Based on his educational background, professional training and more than 36 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Blankenship has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-99.C

MDU Resources Group, Inc.

7,500,000 Shares of Common Stock

FIRST AMENDMENT TO EQUITY DISTRIBUTION AGREEMENT

December 2, 2013

Wells Fargo Securities, LLC

375 Park Avenue

New York, New York 10152

Ladies and Gentlemen:

Reference is hereby made to that certain Equity Distribution Agreement between MDU Resources Group, Inc., a Delaware corporation (the “Company”), and Wells Fargo Securities, LLC (“Wells Fargo Securities”), dated May 20, 2013 (the “Equity Distribution Agreement”).

Pursuant to Section 12(h) of the Equity Distribution Agreement, the Company and Wells Fargo Securities hereby agree to amend the Equity Distribution Agreement by (i) deleting the last sentence of Section 5(a)(4) thereof and replacing it in its entirety as follows:

“As of the date of this Agreement, the only subsidiaries of the Company are the subsidiaries listed on Exhibit G attached hereto, and Exhibit G hereto accurately sets forth the type of entity and jurisdiction of organization of each such subsidiary.”

and (ii) deleting Exhibit E thereof and replacing it in its entirety with Exhibit E attached to this First Amendment to Equity Distribution Agreement (this “Amendment”).

Except as specifically provided herein, the Equity Distribution Agreement shall remain in full force and effect in accordance with its terms and is hereby ratified and confirmed in all respects. This Amendment is limited as specified and the execution, delivery and effectiveness of this Amendment shall not operate as a modification, acceptance or waiver of any provision of the Equity Distribution Agreement except as specifically set forth herein. From and after the date of this Amendment, the Equity Distribution Agreement shall be deemed amended hereby.

This Amendment shall be governed by and construed in accordance with the laws of the State of New York.

{SIGNATURE PAGE FOLLOWS}

If the foregoing is in accordance with your understanding of our agreement, please sign and return to the Company a counterpart of this Amendment, whereupon this instrument, along with all counterparts, will become a binding agreement between Wells Fargo Securities and the Company in accordance with its terms and the Equity Distribution Agreement shall be deemed amended hereby.

Very truly yours,

MDU Resources Group, Inc.
By:	/s/ Doran N. Schwartz
	Name: Doran N. Schwartz
	Title: Vice President and
	Chief Financial Officer

CONFIRMED AND ACCEPTED,

as of the date first above written:

WELLS FARGO SECURITIES, LLC

By:
	Name:
	Title:

If the foregoing is in accordance with your understanding of our agreement, please sign and return to the Company a counterpart of this Amendment, whereupon this instrument, along with all counterparts, will become a binding agreement between Wells Fargo Securities and the Company in accordance with its terms and the Equity Distribution Agreement shall be deemed amended hereby.

Very truly yours,

MDU Resources Group, Inc.
By:
	Name:
	Title:

CONFIRMED AND ACCEPTED,

as of the date first above written:

WELLS FARGO SECURITIES, LLC

By:	/s/ Gregory M. Ogborn
	Name: Gregory M. Ogborn
	Title: Vice President

EXHIBIT E

OFFICER’S CERTIFICATE

The undersigned, {the}{a} duly qualified and elected {__________} of MDU Resources Group, Inc., a Delaware corporation (“Company”), does hereby certify in such capacity and on behalf of the Company, pursuant to Section 7(o) of the Equity Distribution Agreement dated May 20, 2013, as amended (the “Agreement”), between the Company and Wells Fargo Securities, LLC, that, to the knowledge of the undersigned:

(i)the representations and warranties of the Company in Section 5 of the Agreement (A) to the extent such representations and warranties are subject to qualifications and exceptions contained therein relating to materiality or Material Adverse Change (as defined therein), are true and correct on and as of the date hereof with the same force and effect as if expressly made on and as of the date hereof, except for those representations and warranties that speak solely as of a specific date and that were true and correct as of such date, and (B) to the extent such representations and warranties are not subject to any such qualifications or exceptions, are true and correct in all material respects on and as of the date hereof with the same force and effect as if expressly made on and as of the date hereof, except for those representations and warranties that speak solely as of a specific date and that were true and correct as of such date;

(ii)the Company has complied in all material respects with all agreements and satisfied all conditions on its part to be performed or satisfied pursuant to the Agreement at or prior to the date hereof (other than those conditions that may have been waived by Wells Fargo Securities, LLC); and

(iii) as of the date hereof, the only subsidiaries of the Company are the subsidiaries listed on Schedule 1 attached hereto, and Schedule 1 hereto accurately sets forth the type of entity and jurisdiction of organization of each such subsidiary.

{Schedule 1 to be attached}

XML

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

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:

	2013			2012
	(In thousands)
Balance at beginning of year	$	102,545		$	98,151
Liabilities incurred	5,610			6,523
Liabilities acquired	—			—
Liabilities settled	(22,257		)	(10,472		)
Accretion expense	4,574			4,266
Revisions in estimates	7,671			3,655
Other	386			422
Balance at end of year	$	98,529		$	102,545

XML

Regulatory matters and revenues subject to refund (Details) (USD $)	0 Months Ended
	Dec. 05, 2013 MTPSC [Member]	Apr. 12, 2013 MTPSC [Member]	Sep. 26, 2012 MTPSC [Member]	Nov. 17, 2013 NDPSC [Member]	Oct. 23, 2013 NDPSC [Member]	Sep. 18, 2013 NDPSC [Member]	Oct. 31, 2013 FERC [Member]
Regulatory matters and revenues subject to refund [Line Items]
Total gas rate increase requested			$ 3,500,000			$ 6,800,000
Percent above current rates requested			5.90%			6.40%
Amount of requested interim increase in annual gas rates			1,700,000			4,500,000
Requested percentage of interim gas rate increase			2.90%			4.20%
Interim rate increase (decrease), amount		850,000		4,300,000	4,300,000
Stipulation, amount	1,500,000
Settlement agreement, amount					4,300,000
Settlement agreement, percent					4.00%
Rate change application annual increase, amount							28,900,000
Increased expenditures covered by change application							$ 312,000,000

XML

Oil and natural gas properties (Details 6) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Natural gas and oil properties [Abstract]
Discount rate used in calculating present value of future net cash flows from proved reserves (in hundredths)			10.00%
NYMEX oil price	94.71	94.97		94.71
Henry Hub natural gas price	2.76	2.83		2.76
Write-downs of oil and natural gas properties	$ 231,700,000	$ 160,100,000	$ 0	$ 391,800,000	$ 0
Noncash write-downs of oil and natural gas properties, after tax	145,900,000	100,900,000		246,800,000
Additional write-downs of its oil and natural gas properties that would have been recognized without effects of cash flow hedges	20,800,000	19,500,000		20,800,000
Additional write-downs of its oil and natural gas properties that would have been recognized without effects of cash flow hedges, after tax	13,100,000	12,300,000		13,100,000
Oil and natural gas properties not subject to amortization [Abstract]
Acquisition			93,758,000
Development			14,824,000
Exploration			14,547,000
Capitalized interest			1,740,000
Total costs not subject to amortization	191,794,000		124,869,000	191,794,000	232,462,000
Acquisition costs, period cost			1,514,000	23,588,000	28,543,000	40,113,000
Development costs, period cost			12,622,000	1,633,000	271,000	298,000
Exploration costs, period cost			9,952,000	4,346,000	198,000	51,000
Capitalized interest costs, period costs			340,000	418,000	410,000	572,000
Capitalized costs of unproved properties excluded from amortization, period cost			$ 24,428,000	$ 29,985,000	$ 29,422,000	$ 41,034,000
Time period for evaluating majority of costs not subject to amortization			5 years

XML

Exploration and Production Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas In Process Activities [Line Items]

Capital expenditures related to natural gas and oil producing activities [Table Text Block]

The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31:

	2013		2012		2011
	(In thousands)
Subject to amortization	$	2,893,010	$	2,531,562	$	2,345,114
Not subject to amortization	124,869		191,794		232,462
Total capitalized costs	3,017,879		2,723,356		2,577,576
Less accumulated depreciation, depletion and amortization	1,562,116		1,383,386		1,229,654
Net capitalized costs	$	1,455,763	$	1,339,970	$	1,347,922
Note: Net capitalized costs reflect noncash write-downs of the Company's oil and natural gas properties, as discussed in Note 1.

Cost incurred in oil and gas property acquisition, exploration, and development activities disclosure [Table Text Block]

Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities were as follows:

Years ended December 31,	2013		*	2012		*	2011		*
	(In thousands)
Acquisitions:
Proved properties	$	1,817		$	839		$	3,999
Unproved properties	4,608			31,109			63,354
Exploration	26,975			235,906			41,775
Development	355,421			275,959			161,647
Total capital expenditures	$	388,821		$	543,813		$	270,775

* Excludes net additions/(reductions) to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of oil and natural gas wells, as discussed in Note 10, of $(10.7) million, $(200,000) and $(1.8) million for the years ended December 31, 2013, 2012 and 2011, respectively.

Results of operations for oil and gas producing activities disclosure [Table Text Block]

The following summary reflects income resulting from the Company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs:

Years ended December 31,	2013			2012			2011
	(In thousands)
Revenues:
Sales to affiliates	$	45,099		$	35,966		$	93,713
Sales to external customers	497,018			379,647			348,428
Realized gain on commodity derivatives	173			33,628			9,618
Unrealized gain (loss) on commodity derivatives	(6,267		)	(624		)	1,827
Production costs	144,136			134,795			140,606
Depreciation, depletion and amortization*	182,352			157,078			139,539
Write-downs of oil and natural gas properties	—			391,800			—
Pretax income (loss)	209,535			(235,056		)	173,441
Income tax expense (benefit)	75,836			(88,612		)	63,655
Results of operations for producing activities	$	133,699		$	(146,444	)	$	109,786

* Includes accretion of discount for asset retirement obligations of $3.6 million, $3.3 million and $3.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, as discussed in Note 10.

Schedule of proved developed and undeveloped oil and gas reserve quantities [Table Text Block]

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 changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2012, were as follows:

	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	27,005		7,342		379,827		97,651
Production	(3,694	)	(828	)	(33,214	)	(10,058	)
Extensions and discoveries	9,874		1,817		18,386		14,756
Improved recovery	—		—		—		—
Purchases of proved reserves	—		—		—		—
Sales of proved reserves	(39	)	—		(2,307	)	(423	)
Revisions of previous estimates	307		(1,178	)	(123,414	)	(21,440	)
Balance at end of year	33,453		7,153		239,278		80,486

Significant changes in proved reserves for the year ended December 31, 2012, include:

• Extension and discoveries of 14.8 MMBOE primarily due to drilling activity at the Company's Bakken, South Texas and Paradox properties

• Revisions of previous estimates of (21.4) MMBOE, largely the result of lower natural gas prices resulting in a reduction of PDP and PUD reserves principally in the Company's Coalbed, Baker, Bowdoin, East Texas and Green River Basin natural gas properties

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2011, were as follows:

	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	25,666		7,201		448,397		107,599
Production	(2,724	)	(776	)	(45,598	)	(11,099	)
Extensions and discoveries	4,717		1,421		28,221		10,842
Improved recovery	—		—		—		—
Purchases of proved reserves	223		16		54		247
Sales of proved reserves	—		—		—		—
Revisions of previous estimates	(877	)	(520	)	(51,247	)	(9,938	)
Balance at end of year	27,005		7,342		379,827		97,651

Significant changes in proved reserves for the year ended December 31, 2011, include:

• Extensions and discoveries of 10.8 MMBOE primarily due to drilling activity at the Company's Bakken and Big Horn properties

• Revisions of previous estimates of (9.9) MMBOE, largely the result of a reduction in PUD reserves of 8.9 MMBOE resulting principally in the Company's Bowdoin, Baker, Coalbed, East Texas and Big Horn Basin properties. The remaining negative revisions were a reduction in PDP natural gas reserves.

The following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31:

	2013	2012	2011
Proved developed reserves:
Oil (MBbls)	31,394	27,412	23,653
NGL (MBbls)	5,322	5,342	5,225
Natural Gas (MMcf)	176,546	218,259	303,495
Total (MBOE)	66,140	69,131	79,460
PUD reserves:
Oil (MBbls)	9,625	6,041	3,352
NGL (MBbls)	1,280	1,811	2,117
Natural Gas (MMcf)	21,899	21,019	76,332
Total (MBOE)	14,555	11,355	18,191
Total proved reserves:
Oil (MBbls)	41,019	33,453	27,005
NGL (MBbls)	6,602	7,153	7,342
Natural Gas (MMcf)	198,445	239,278	379,827
Total (MBOE)	80,695	80,486	97,651

Standardized measure of discounted future cash flows relating to proved reserves disclosure [Table Text Block]

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:

	2013		2012		2011
	(In thousands)
Future cash inflows	$	4,507,000	$	3,696,200	$	4,188,000
Future production costs	1,734,800		1,536,500		1,560,300
Future development costs	403,000		301,600		285,300
Future net cash flows before income taxes	2,369,200		1,858,100		2,342,400
Future income tax expense	545,200		304,900		531,100
Future net cash flows	1,824,000		1,553,200		1,811,300
10% annual discount for estimated timing of cash flows	810,000		669,800		832,500
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$	1,014,000	$	883,400	$	978,800

The following are the sources of change in the standardized measure of discounted future net cash flows by year:

	2013			2012			2011
	(In thousands)
Beginning of year	$	883,400		$	978,800		$	896,100
Net revenues from production	(398,000		)	(280,800		)	(301,500		)
Net change in sales prices and production costs related to future production	162,200			(406,300		)	82,300
Extensions and discoveries, net of future production-related costs	366,500			355,300			226,300
Improved recovery, net of future production-related costs	—			—			—
Purchases of proved reserves, net of future production-related costs	—			—			9,500
Sales of proved reserves	(37,800		)	(2,600		)	—
Changes in estimated future development costs	6,700			37,600			51,100
Development costs incurred during the current year	141,500			77,700			56,300
Accretion of discount	94,600			121,400			105,000
Net change in income taxes	(141,400		)	110,000			(55,800		)
Revisions of previous estimates	(55,800		)	(100,700		)	(92,900		)
Other	(7,900		)	(7,000		)	2,400
Net change	130,600			(95,400		)	82,700
End of year	$	1,014,000		$	883,400		$	978,800

XML

Capitalized costs and AD&D related to oil and natural gas producing activities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Subject to amortization	$ 2,893,010	$ 2,531,562	$ 2,345,114
Not subject to amortization	124,869	191,794	232,462
Total capitalized costs	3,017,879	2,723,356	2,577,576
Less accumulated depreciation, depletion and amortization	1,562,116	1,383,386	1,229,654
Net capitalized costs	$ 1,455,763	$ 1,339,970	$ 1,347,922

XML

Regulatory assets and liabilities (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets and liabilities
Regulatory assets:	$ 305,373,000		$ 351,194,000
Regulatory liabilities:	432,325,000		450,482,000
Net regulatory position	(126,952,000)		(99,288,000)
Regulatory assets not earning a rate of return	163,700,000		215,600,000
Plant removal and decommissioning costs (c)
Regulatory assets and liabilities
Regulatory liabilities:	308,431,000	[1]	296,037,000	[1]
Deferred income taxes
Regulatory assets and liabilities
Regulatory liabilities:	64,914,000	[2]	82,077,000	[2]
Taxes refundable to customers (c)
Regulatory assets and liabilities
Regulatory liabilities:	20,180,000	[1]	24,212,000	[1]
Natural gas costs refundable through rate adjustments (d)
Regulatory assets and liabilities
Regulatory liabilities:	16,932,000	[3]	35,328,000	[3]
Other (c) (d)
Regulatory assets and liabilities
Regulatory liabilities:	21,868,000	[1],[3]	12,828,000	[1],[3]
Deferred income taxes
Regulatory assets and liabilities
Estimated recovery period	**	[2]
Regulatory assets:	125,607,000		121,781,000
Pension and postretirement benefits (a)
Regulatory assets and liabilities
Estimated recovery period	(e)	[4]
Regulatory assets:	105,123,000	[5]	166,477,000	[5]
Taxes recoverable from customers (a)
Regulatory assets and liabilities
Estimated recovery period	Over plant lives	[6]
Regulatory assets:	18,266,000	[5]	9,078,000	[5]
Manufactured gas plant sites remediation (a)
Regulatory assets and liabilities
Estimated recovery period	Up to 4 years	[6]
Regulatory assets:	15,797,000	[5]	15,828,000	[5]
Natural gas costs recoverable through rate adjustments (b)
Regulatory assets and liabilities
Estimated recovery period	Up to 28 months	[6]
Regulatory assets:	12,060,000	[7]	2,981,000	[7]
Long-term debt refinancing costs (a)
Regulatory assets and liabilities
Estimated recovery period	Up to 25 years	[6]
Regulatory assets:	8,697,000	[5]	9,144,000	[5]
Costs related to identifying generation development (a)
Regulatory assets and liabilities
Estimated recovery period	Up to 13 years	[6]
Regulatory assets:	4,512,000	[5]	5,773,000	[5]
Other (a) (b)
Regulatory assets and liabilities
Estimated recovery period	Largely within 1- 5 years	[6]
Regulatory assets:	$ 15,311,000	[5],[7]	$ 20,132,000	[5],[7]

[1] Included in other liabilities on the Consolidated Balance Sheets.

[2] Represents deferred income taxes related to regulatory assets and liabilities. The deferred income tax assets are not earning a rate of return.

[3] Included in other accrued liabilities on the Consolidated Balance Sheets.

[4] Recovered as expense is incurred.

[5] Included in deferred charges and other assets - other on the Consolidated Balance Sheets.

[6] Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.

[7] Included in prepayments and other current assets on the Consolidated Balance Sheets.

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Estimated quantities of proved reserves (Details 4)	12 Months Ended
	Dec. 31, 2013 MBoe	Dec. 31, 2012 MBoe	Dec. 31, 2011 MBoe
Proved developed and undeveloped reserves:
Balance at beginning of year, BOE	80,486	97,651	107,599
Production, BOE	(10,264)	(10,058)	(11,099)
Extensions and discoveries, BOE	19,050	14,756	10,842
Improved recovery, BOE	0	0	0
Purchases of proved reserves, BOE	0	0	247
Sales revisions, BOE	(7,987)	(423)	0
Revisions of previous estimate, BOE	(590)	(21,440)	(9,938)
Balance at end of year, BOE	80,695	80,486	97,651
Reduction in proved undeveolped reserves specified properties			8,900
Oil (MBbls)
Proved developed and undeveloped reserves:
Balance at beginning of year	33,453	27,005	25,666
Production	(4,815)	(3,694)	(2,724)
Extensions and discoveries	13,313	9,874	4,717
Improved recovery	0	0	0
Purchases of proved reserves	0	0	223
Sales of proved reserves	(1,286)	(39)	0
Revisions of previous estimates	354	307	(877)
Balance at end of year	41,019	33,453	27,005
NGL (MBbls)
Proved developed and undeveloped reserves:
Balance at beginning of year	7,153	7,342	7,201
Production	(781)	(828)	(776)
Extensions and discoveries	1,333	1,817	1,421
Improved recovery	0	0	0
Purchases of proved reserves	0	0	16
Sales of proved reserves	(25)	0	0
Revisions of previous estimates	(1,078)	(1,178)	(520)
Balance at end of year	6,602	7,153	7,342
Natural Gas (MMcf)
Proved developed and undeveloped reserves:
Balance at beginning of year	239,278	379,827	448,397
Production	(28,008)	(33,214)	(45,598)
Extensions and discoveries	26,428	18,386	28,221
Improved recovery	0	0	0
Purchases of proved reserves	0	0	54
Sales of proved reserves	(40,055)	(2,307)	0
Revisions of previous estimates	802	(123,414)	(51,247)
Balance at end of year	198,445	239,278	379,827

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Revenue recognition (Details 7) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain	$ 107.4	$ 85.9

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Credit facilities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Line of credit facility and other debt [Abstract]
Letters of credit at end of period	$ 36.0
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	125.0
Amount outstanding, end of period	78.9	[1]	76.0	[1]
Expiration date	Oct. 04, 2017
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	500.0
Amount outstanding, end of period	75.0	[1]	217.0	[1]
Expiration date	Jun. 08, 2017
Long-term debt [Member] | Revolving credit agreement [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	150
Long-term debt [Member] | Revolving credit agreement [Member] | Intermountain Gas Company [Member]
Line of credit facility and other debt [Abstract]
Facility limit	65.0	[2]
Amount outstanding, end of period	3.0		26.2
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 agreement [Member] | Centennial Energy Holdings, Inc [Member]
Line of credit facility and other debt [Abstract]
Letters of credit at end of period	0
Option to increase borrowings, maximum amount	650
Short-term debt [Member] | Revolving credit agreement [Member] | Cascade Natural Gas Corporation [Member]
Line of credit facility and other debt [Abstract]
Facility limit	50.0	[3]
Amount outstanding, end of period	11.5		2.0
Letters of credit at end of period	2.2	[4]
Expiration date	Jul. 09, 2018
Option to increase borrowings, maximum amount	$ 75

[1] Amount outstanding under commercial paper program

[2] Certain provisions allow for increased borrowings, up to a maximum of $90 million.

[3] Certain provisions allow for increased borrowings, up to a maximum of $75 million.

[4] The outstanding letter of credit, as discussed in Note 19, reduces the amount available under the credit agreement.

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Fair value - pension and postretirement (Details 9) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	$ 334,844,000		$ 309,184,000		$ 278,000,000
Percentage investment in common stock of large-cap U.S. companies	34.00%		26.00%
Percentage investment in US Treasuries	11.00%		13.00%
Percentage investment in common stock of mid-cap U.S. companies	11.00%		12.00%
Percentage investment in corporate bonds	27.00%		41.00%
Percentage investment in other investments	17.00%		8.00%
Estimated future employer contributions in next fiscal year	32,500,000
Pension Benefits | Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	9,406,000		12,605,000
Pension Benefits | Equity securities of U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	62,599,000		86,981,000
Pension Benefits | Equities Securities of International companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	39,437,000		39,818,000
Pension Benefits | Collective and Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	158,748,000	[1]	102,852,000	[2]
Pension Benefits | Corporate debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	42,721,000		45,112,000
Pension Benefits | Municipal bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	7,561,000		9,302,000
Pension Benefits | U.S. Treasury securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	11,822,000		12,514,000
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	332,294,000		309,184,000
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		2,145,000
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities of U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	62,599,000		86,981,000
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	39,437,000		39,818,000
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	116,265,000	[1]	82,787,000	[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. Treasury securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	7,487,000		7,980,000
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	225,788,000		219,711,000
Pension Benefits | Significant Other Observable Inputs (Level 2) | Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	9,406,000		10,460,000
Pension Benefits | Significant Other Observable Inputs (Level 2) | Equity securities of U.S. companies
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	42,483,000	[1]	20,065,000	[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	42,721,000		45,112,000
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	7,561,000		9,302,000
Pension Benefits | Significant Other Observable Inputs (Level 2) | U.S. Treasury securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	4,335,000		4,534,000
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	106,506,000		89,473,000
Pension Benefits | Significant Unobservable Inputs (Level 3) | Cash equivalents
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
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. Treasury securities
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	84,543,000		74,361,000		68,085,000
Percentage investment in common stock of large-cap U.S. companies	55.00%		51.00%
Percentage investment in US Treasuries	12.00%		15.00%
Percentage investment in mortgage backed securities	8.00%		10.00%
Percentage investment in common stock of mid-cap U.S. companies	8.00%
Percentage investment in corporate bonds	9.00%		11.00%
Percentage investment in other investments	8.00%		13.00%
Estimated future employer contributions in next fiscal year	1,500,000
Other Postretirement Benefits | Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,142,000		3,044,000
Other Postretirement Benefits | Equity securities of U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,802,000		2,207,000
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	221,000		260,000
Other Postretirement Benefits | Insurance investment contract [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	79,374,000	[3]	68,850,000	[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	84,539,000		74,361,000
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	3,023,000		3,520,000
Other Postretirement Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	0		1,053,000
Other Postretirement Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities of U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,802,000		2,207,000
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	221,000		260,000
Other Postretirement Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Insurance investment contract [Member]
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	81,516,000		70,841,000
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) | Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	2,142,000		1,991,000
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) | Equity securities of U.S. companies
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 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of net plan assets at end of year	79,374,000	[3]	68,850,000	[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
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
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 [Member]
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 11 percent in common stock of mid-cap U.S. companies, 34 percent in common stock of large-cap U.S. companies, 11 percent in U.S. Treasuries, 27 percent in corporate bonds and 17 percent in other investments.

[2] Collective and mutual funds invest approximately 12 percent in common stock of mid-cap U.S. companies, 26 percent in common stock of large-cap U.S. companies, 13 percent in U.S. Treasuries, 41 percent in corporate bonds and 8 percent in other investments.

[3] The insurance contract invests approximately 55 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Treasuries, 8 percent in mortgage-backed securities, 8 percent in common stock of mid-cap U.S. companies, 9 percent in corporate bonds and 8 percent in other investments.

[4] The insurance contract invests approximately 51 percent in common stock of large-cap U.S. companies, 15 percent in U.S. Treasuries, 10 percent in mortgage-backed securities, 11 percent in corporate bonds and 13 percent in other investments.

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Commitment and Contingencies Disclosure (Tables)

12 Months Ended

Dec. 31, 2013

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:

	2013
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	4,774
Other current assets	26
Total current assets	4,800
Net property, plant and equipment	172,073
Total assets	$	176,873
Liabilities
Current liabilities:
Long-term debt due within one year	$	3,000
Accounts payable	8,904
Taxes payable	5
Accrued compensation	26
Other accrued liabilities	461
Total current liabilities	12,396
Long-term debt	72,000
Total liabilities	$	84,396

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Summary of significant accounting policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Inventories

Inventories at December 31 consisted of:

	2013		2012
	(In thousands)
Aggregates held for resale	$	101,568	$	87,715
Materials and supplies	69,808		69,390
Asphalt oil	38,099		67,480
Merchandise for resale	21,720		31,172
Natural gas in storage (current)	16,417		29,030
Other	34,779		32,628
Total	$	282,391	$	317,415

AFUDC and interest capitailized

The amount of AFUDC and interest capitalized for the years ended December 31 were as follows:

	2013		2012		2011
	(In thousands)
Interest capitalized	$	6,033	$	8,659	$	10,821
AFUDC - borrowed	$	2,767	$	2,483	$	1,666
AFUDC - equity	$	3,322	$	4,530	$	2,587

Property, plant and equipment

Property, plant and equipment at December 31 was as follows:

	2013			2012		Weighted Average Depreciable Life in  Years
	(Dollars in thousands, where applicable)
Regulated:
Electric:
Generation	$	570,394		$	546,011	42
Distribution	308,202			276,446		39
Transmission	196,824			180,543		48
Construction in progress	141,365			62,123		-
Other	99,037			85,461		14
Natural gas distribution:
Distribution	1,384,587			1,308,314		40
Construction in progress	46,763			71,679		-
Other	345,551			309,957		25
Pipeline and energy services:
Transmission	418,594			403,126		52
Gathering	39,597			42,420		19
Storage	42,939			42,058		51
Construction in progress	6,937			13,667		-
Other	39,504			38,386		29
Nonregulated:
Pipeline and energy services:
Midstream	213,063			233,840		17
Construction in progress	188,641			29,657		-
Other	12,897			13,379		11
Exploration and production:
Oil and natural gas properties	3,017,879			2,723,356		*
Other	42,969			41,204		8
Construction materials and contracting:
Land	125,551			126,788		-
Buildings and improvements	70,000			73,884		19
Machinery, vehicles and equipment	906,774			899,592		12
Construction in progress	13,315			11,165		-
Aggregate reserves	394,715			393,552		**
Construction services:
Land	4,821			4,723		-
Buildings and improvements	16,628			16,563		20
Machinery, vehicles and equipment	105,991			100,445		6
Other	7,508			8,893		4
Other:
Land	2,837			2,837		-
Other	47,160			47,682		23
Eliminations	(7,177		)	—
Less accumulated depreciation, depletion and amortization	3,872,487			3,608,912
Net property, plant and equipment	$	4,931,379		$	4,498,839

  *  Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $17.41, $15.28 and $12.25 for the years ended December 31, 2013, 2012 and 2011, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $124.9 million and $191.8 million were excluded from amortization at December 31, 2013 and 2012, respectively.

** Depleted on the units-of-production method.

Summary of natural gas and oil properties not subject to amortization

The following table summarizes the Company's oil and natural gas properties not subject to amortization at December 31, 2013, in total and by the year in which such costs were incurred:

			Year Costs Incurred
	Total		2013		2012		2011		2010 and prior
	(In thousands)
Acquisition	$	93,758	$	1,514	$	23,588	$	28,543	$	40,113
Development	14,824		12,622		1,633		271		298
Exploration	14,547		9,952		4,346		198		51
Capitalized interest	1,740		340		418		410		572
Total costs not subject to amortization	$	124,869	$	24,428	$	29,985	$	29,422	$	41,034

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:

	2013		2012
	(In thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	60,828	$	64,996
Billings in excess of costs and estimated earnings on uncompleted contracts	$	84,189	$	83,167

Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31, were as follows:

	2013		2012
	(In thousands)
Short-term retainage *	$	55,906	$	54,256
Long-term retainage **	4,229		2,038
Total retainage	$	60,135	$	56,294

  * 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:

	2013	2012	2011
	(In thousands)
Weighted average common shares outstanding - basic	188,855	188,826	188,763
Effect of dilutive stock options and performance share awards	838	—	142
Weighted average common shares outstanding - diluted	189,693	188,826	188,905
Shares excluded from the calculation of diluted earnings per share	—	58	—

Cash expenditures for interest and income taxes and noncash investing transactions

Cash expenditures for interest and income taxes for the years ended December 31 were as follows:

	2013		2012		2011
	(In thousands)
Interest, net of amount capitalized	$	81,689	$	74,378	$	78,133
Income taxes paid (refunded), net	$	24,857	$	3,277	$	(12,287	)

Noncash investing transactions at December 31 were as follows:

	2013		2012		2011
	(In thousands)
Property, plant and equipment additions in accounts payable	$	67,129	$	76,205	$	41,540

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, 2013, 2012 and 2011, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency  Translation  Adjustment			Net Unrealized Gains on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2011	$	6,275		$	(53,320	)	$	(38	)	$	82		$	(47,001	)
Current-period other comprehensive income (loss)	(257		)	(1,027		)	(473		)	37			(1,720		)
Balance at December 31, 2012	6,018			(54,347		)	(511		)	119			(48,721		)
Other comprehensive income (loss) before reclassifications	(5,594		)	18,539			(299		)	(194		)	12,452
Amounts reclassified from accumulated other comprehensive loss	(4,189		)	2,001			143			109			(1,936		)
Net current-period other comprehensive income (loss)	(9,783		)	20,540			(156		)	(85		)	10,516
Balance at December 31, 2013	$	(3,765	)	$	(33,807	)	$	(667	)	$	34		$	(38,205	)

Reclassification out of accumulated other comprehensive income (loss)

Reclassifications out of accumulated other comprehensive loss for the year ended December 31 were as follows:

	2013			Location on Consolidated Statements of Income
	(In thousands)
Reclassification adjustment for gain (loss) on derivative instruments included in net income:
Commodity derivative instruments	$	7,803		Operating revenues
Interest rate derivative instruments	(1,066		)	Interest expense
	6,737
	(2,548		)	Income taxes
	4,189
Amortization of postretirement liability losses included in net periodic benefit cost	(3,277		)	(a)
	1,276			Income taxes
	(2,001		)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income	(213		)	Earnings (loss) from equity method investments
	70			Earnings (loss) from equity method investments
	(143		)
Reclassification adjustment for loss on available-for-sale investments included in net income	(168		)	Other income
	59			Income taxes
	(109		)
Total reclassifications	$	1,936

(a) Included in net periodic benefit cost (credit). For more information, see Note 16.

XML

Short-term borrowings (Details 2) (Short-term debt [Member], Cascade Natural Gas Corporation [Member], Revolving credit agreement [Member])	Dec. 31, 2013
Short-term debt [Member] | Cascade Natural Gas Corporation [Member] | Revolving credit agreement [Member]
Short-term debt [Line Items]
Weighted average interest rate	3.30%
Ratio of total debt to total capitalization as specified in debt convenants.	65.00%

XML

Variable interest entities (Details) (USD $)	Dec. 31, 2013
Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Percent of ownership	50.00%
Total project costs	$ 300,000,000
Portion of capital commitment	150,000,000
Partner portion of capital commitment	75,000,000
Excess capital commitments	300,000,000
Estimated project cost	350,000,000
Term loan for project debt financing	75,000,000
Fuel contract [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	7,700,000
Cash and Cash Equivalents [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	4,774,000
Other Current Assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	26,000
Total current assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	4,800,000
Net property, plant and equipment [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	172,073,000
Total assets [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	176,873,000
Long-term debt due within one year [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	3,000,000
Accounts payable [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	8,904,000
Taxes payable [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	5,000
Accrued compensation [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	26,000
Other accrued liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	461,000
Total current liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	12,396,000
Long-term debt [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	72,000,000
Total liabilities [Member] | Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	$ 84,396,000

XML

Change in discounted future net cash flows (Details 7) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Beginning of year	$ 883,400	$ 978,800	$ 896,100
Net revenues from production	(398,000)	(280,800)	(301,500)
Net change in sales prices and production costs related to future production	162,200	(406,300)	82,300
Extensions and discoveries, net of future production-related costs	366,500	355,300	226,300
Improved recovery, net of future production-related costs	0	0	0
Purchases of proved reserves, net of future production-related costs	0	0	9,500
Sales of proved reserves	(37,800)	(2,600)	0
Changes in estimated future development costs	6,700	37,600	51,100
Development costs incurred during the current year	141,500	77,700	56,300
Accretion of discount	94,600	121,400	105,000
Net change in income taxes	(141,400)	110,000	(55,800)
Revisions of previous estimates	(55,800)	(100,700)	(92,900)
Other	(7,900)	(7,000)	2,400
Net change	130,600	(95,400)	82,700
End of year	$ 1,014,000	$ 883,400	$ 978,800

XML

Fair value derivative instruments (Details 3) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives, fair value [Line Items]
Derivative asset, fair value, gross asset	$ 1,950	$ 18,304
Derivative liability, fair value, gross liability	7,483	6,255
Designated as hedging instrument [Member]
Derivatives, fair value [Line Items]
Derivative instruments in hedges, assets, at fair value	0	18,084
Derivative instruments in hedges, liabilities, at fair value	0	6,255
Designated as hedging instrument [Member] | Commodity derivatives | Commodity derivative instruments assets, current [Member]
Derivatives, fair value [Line Items]
Derivative instruments in hedges, assets, at fair value	0	18,084
Designated as hedging instrument [Member] | Interest rate derivative instruments | Other accrued liabilities [Member]
Derivatives, fair value [Line Items]
Derivative instruments in hedges, liabilities, at fair value	0	6,255
Not designated as hedging instruments [Member]
Derivatives, fair value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	1,950	220
Other derivatives not designated as hedging instruments liabilities at fair value	7,483	0
Not designated as hedging instruments [Member] | Commodity derivatives | Commodity derivative instruments assets, current [Member]
Derivatives, fair value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	1,447	220
Not designated as hedging instruments [Member] | Commodity derivatives | Other assets noncurrent [Member]
Derivatives, fair value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	503	0
Not designated as hedging instruments [Member] | Commodity derivatives | Commodity derivative instruments liabilities [Member]
Derivatives, fair value [Line Items]
Other derivatives not designated as hedging instruments liabilities at fair value	$ 7,483	$ 0

XML

Components of income (loss) before income taxes from continuing operations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
United States	$ 415,202	$ (47,175)	$ 333,486
Foreign	416	1,708	2,740
Income (loss) before income taxes	$ 415,618	$ (45,467)	$ 336,226

XML

Derivative instruments (Details 9)	12 Months Ended
	Dec. 31, 2013
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 foreign currency	12-month period
Maximum length of time allowed to hedge forecasted purchases	three years
Maximum period for settlement of all interest rate derivative transactions	90 days
Maximum period for settlement of foreign currency derivative transactions	12-month period

XML

Multiemployer plans (Details 14) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
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	$ 39,260		$ 34,779	$ 29,158
Edison Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	936061681
Multiemployer plan number	001
Multiemployer plans, certified zone status	Green		Green
Multiemployer plans, certified zone status, date	Dec. 31, 2013		Dec. 31, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	No
Multiemployer plan, period contributions	6,358		5,171	2,700
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Dec. 31, 2014
IBEW Local 38 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	346574238
Multiemployer plan number	001
Multiemployer plans, certified zone status	Yellow		Yellow
Multiemployer plans, certified zone status, date	Apr. 30, 2013		Apr. 30, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	1,041		2,771	1,469
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Apr. 27, 2014
IBEW Local No. 82 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	316127268
Multiemployer plan number	001
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	Jun. 30, 2013		Jun. 30, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	1,284		1,093	1,331
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Nov. 30, 2014
IBEW Local 648 Pension Plan [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	316134845
Multiemployer plan number	001
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	Feb. 28, 2013		Feb. 29, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	1,489		564	722
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Aug. 31, 2015
Laborers Pension Trust Fund for Northern California [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	946277608
Multiemployer plan number	001
Multiemployer plans, certified zone status	Yellow		Yellow
Multiemployer plans, certified zone status, date	May 31, 2013		May 31, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	921		567	628
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Jun. 30, 2016
National Electrical Benefit Fund [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	530181657
Multiemployer plan number	001
Multiemployer plans, certified zone status	Green		Green
Multiemployer plans, funding improvement plan and rehabilitation plan	No
Multiemployer plan, period contributions	5,883		5,603	4,841
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Aug. 31, 2017
Multiemployer plans, collective-bargaining, date range - initial	May 31, 2012	[1]
OE Pension Trust Fund [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	946090764
Multiemployer plan number	001
Multiemployer plans, certified zone status	Yellow		Yellow
Multiemployer plans, certified zone status, date			Dec. 31, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	1,510		1,156	1,367
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Mar. 31, 2026
Multiemployer plans, collective-bargaining, date range - initial	Jun. 30, 2013	[1]
Operating Engineers Local 800 and WY Contractors Association Pension Plan for WY [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	836011320
Multiemployer plan number	001
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	Dec. 31, 2013		Dec. 31, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	76		91	96
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Oct. 31, 2005	[1]
Operating Engineers Pension Trust [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	956032478
Multiemployer plan number	001
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	Jun. 30, 2013		Jun. 30, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	493		761	458
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Jul. 20, 2014
Multiemployer plans, collective-bargaining, date range - initial	Jul. 01, 2013	[1]
Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525 [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	886003864
Multiemployer plan number	001
Multiemployer plans, certified zone status	Green		Green
Multiemployer plans, certified zone status, date	Jun. 30, 2012		Jun. 30, 2011
Multiemployer plans, funding improvement plan and rehabilitation plan	No
Multiemployer plan, period contributions	1,657		1,202	759
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	May 31, 2010	[1]
Sheet Metal Workers Pension Plan of Southern CA, AZ, and NV [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Entity tax identification number	956052257
Multiemployer plan number	001
Multiemployer plans, certified zone status	Red		Red
Multiemployer plans, certified zone status, date	Dec. 31, 2013		Dec. 31, 2012
Multiemployer plans, funding improvement plan and rehabilitation plan	Implemented
Multiemployer plan, period contributions	512		467	336
Multiemployer plans, surcharge	No
Multiemployer plans, collective-bargaining arrangement, expiration date	Jun. 30, 2014
Other funds [Member] | Multiemployer plans, pension [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions	$ 18,036		$ 15,333	$ 14,451

[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.

XML

Fair value measurements (Details 2) (USD $)	Dec. 31, 2013		Jun. 30, 2013	Dec. 31, 2012		Jun. 30, 2012
Concentration risks, percentage [Abstract]
Percentage investment in common stock of mid-cap companies	29.00%			28.00%
Percentage investment in common stock of small-cap companies	28.00%			28.00%
Percentage investment in common stock of large-cap companies	28.00%			29.00%
Percentage in fixed-income investments	15.00%			15.00%
Assets, fair value disclosure, nonrecurring			$ 9,700,000			$ 2,500,000
Fair value, measurements, recurring [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	93,657,000			101,443,000
Liabilities:	7,483,000			6,255,000
Fair value, measurements, recurring [Member] | Commodity derivative instruments liabilities [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:	7,483,000
Fair value, measurements, recurring [Member] | Interest rate derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:				6,255,000
Fair value, measurements, recurring [Member] | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	19,227,000			24,240,000
Fair value, measurements, recurring [Member] | Insurance contract
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	62,370,000	[1]		48,898,000	[2]
Fair value, measurements, recurring [Member] | Mortgage-backed securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	8,193,000			8,195,000
Fair value, measurements, recurring [Member] | U.S. Treasury securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	1,917,000			1,806,000
Fair value, measurements, recurring [Member] | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	1,950,000			18,304,000
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0			0
Liabilities:	0			0
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivative instruments liabilities [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) | Interest rate derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:				0
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0			0
Fair value, measurements, recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Insurance contract
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] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0			0
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2)
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	93,657,000			101,443,000
Liabilities:	7,483,000			6,255,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Commodity derivative instruments liabilities [Member]
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:	7,483,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Interest rate derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:				6,255,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	19,227,000			24,240,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Insurance contract
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	62,370,000	[1]		48,898,000	[2]
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	8,193,000			8,195,000
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:	1,917,000			1,806,000
Fair value, measurements, recurring [Member] | Significant Other Observable Inputs (Level 2) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	1,950,000			18,304,000
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3)
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0			0
Liabilities:	0			0
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Commodity derivative instruments liabilities [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) | Interest rate derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Liabilities:				0
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Money market funds
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	0			0
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Insurance contract
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
Fair value, measurements, recurring [Member] | Significant Unobservable Inputs (Level 3) | Commodity derivative instruments
Fair value, assets and liabilities measured on recurring and nonrecurring basis [Line Items]
Assets:	$ 0			$ 0

[1] The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

[2] The insurance contract invests approximately 28 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

XML

Stock options (Details 2) (Stock Option [Member], USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Stock Option [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Proceeds from stock options exercised	$ 88,000	$ 5,700,000
Share-based compensation arrangement by share-based payment award, options, exercises in period, total intrinsic value	$ 60,000	$ 3,300,000

XML

Long-term debt outstanding (Details 4) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Long-term debt maturities [Abstract]
2014	$ 12,300,000
2015	269,400,000
2016	293,800,000
2017	204,900,000
2018	130,200,000
Thereafter	944,000,000
Senior notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	5.52%
Commercial paper [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	0.40%
Term loan agreements [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	2.08%
Medium-term notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	7.32%
Other notes [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	5.23%
Loans payable [Member]
Long term debt outstanding [Abstract]
Weighted average interest rate	4.11%
Long-term debt [Member]
Long term debt outstanding [Abstract]
Long-term debt	1,854,563,000	1,744,975,000
Less current maturities	12,277,000	134,108,000
Long-term debt	1,842,286,000	1,610,867,000
Long-term debt [Member] | Senior notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	1,545,078,000	1,349,160,000
Long-term debt [Member] | Commercial paper [Member]
Long term debt outstanding [Abstract]
Long-term debt	153,924,000	293,000,000
Long-term debt [Member] | Term loan agreements [Member]
Long term debt outstanding [Abstract]
Long-term debt	75,000,000	0
Long-term debt [Member] | Medium-term notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	35,000,000	59,000,000
Long-term debt [Member] | Other notes [Member]
Long term debt outstanding [Abstract]
Long-term debt	39,863,000	40,090,000
Long-term debt [Member] | Loans payable [Member]
Long term debt outstanding [Abstract]
Long-term debt	5,701,000	3,768,000
Long-term debt [Member] | Discount on commercial paper program [Member]
Long term debt outstanding [Abstract]
Long-term debt	$ (3,000)	$ (43,000)

XML

Stock awards (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Compensation Plan [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Nonemployee director stock compensation plan, number of shares granted	36,713	53,888	55,141
Nonemployee director stock compensation plan, fair value of shares granted	$ 1,100,000	$ 1,100,000	$ 1,100,000
Long-term incentive plan [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Common shares granted under a long-term incentive plan		43,103
Fair value of common stock granted under a long-term incentive plan		$ 930,000

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Fair value measurements (Details 3) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Carrying amount
Fair value, balance sheet grouping, financial statement captions [Line Items]
Long-term debt	$ 1,854,563	$ 1,744,975
Fair value
Fair value, balance sheet grouping, financial statement captions [Line Items]
Long-term debt	$ 1,912,590	$ 1,888,135

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Derivative instruments (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
Derivative instruments [Line Items]
Amount of unrealized gain (loss) on hedge at de-designation date to be reclassified into AOCI		$ 1,800,000
Amount of time remaining to transfer accumulated other comprehensive income to earnings	12 months
Cash flow hedge gain (loss) to be reclassified within twelve months	(700,000)
Derivatives with credit-risk-related contingent feature in net liability position, aggregate fair value	7,500,000		6,300,000
Assets needed for immediate settlement aggregate fair value for cash flow heding instruments	7,500,000		6,300,000
Oil swap and or collar [Member]
Derivative instruments [Line Items]
Derivative, nonmonetary notional amount	2,900,000		2,600,000
Natural gas swap or and collar [Member]
Derivative instruments [Line Items]
Derivative, nonmonetary notional amount	18,300,000		11,000,000
Interest rate derivative instruments
Derivative instruments [Line Items]
Notional amount of interest rate cash flow hedge derivatives			$ 50,000,000

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Regulatory Matters and Revenues Subject to Refund

12 Months Ended

Dec. 31, 2013

Regulated Operations [Abstract]

Regulatory matters and revenues subject to refund

Regulatory Matters and Revenues Subject to Refund

On September 26, 2012, Montana-Dakota filed an application with the MTPSC for a natural gas rate increase. Montana-Dakota requested a total increase of $3.5 million annually or approximately 5.9 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, an operations building, automated meter reading and a new customer billing system. Montana-Dakota requested an interim increase, subject to refund, of $1.7 million or approximately 2.9 percent. On April 12, 2013, the MTPSC issued an interim order authorizing an interim increase of $850,000 annually to be effective with service rendered on or after April 15, 2013, subject to refund. A hearing was held August 5-6, 2013. On December 5, 2013, Montana-Dakota and the Montana Consumer Counsel filed a stipulation with the MTPSC with an increase of $1.5 million annually. On December 12, 2013, the MTPSC approved the stipulation to be effective with service rendered on or after December 15, 2013.

On February 11, 2013, Montana-Dakota filed an application with the NDPSC for approval of an environmental cost recovery rider for recovery of Montana-Dakota's share of the costs resulting from the environmental retrofit required to be installed at the Big Stone Station. The costs proposed to be recovered are associated with the ongoing construction costs for the installation of the BART air-quality control system. On February 27, 2013, the NDPSC suspended the filing pending further review. On May 31, 2013, Montana-Dakota filed revisions to its filing to reflect revised budget amounts. A hearing was held on September 16, 2013. On December 18, 2013, the NDPSC approved the environmental cost recovery rider tariff and adjustment.

On September 18, 2013, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase. Montana-Dakota requested a total increase of $6.8 million annually or approximately 6.4 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and a new customer billing system. Montana-Dakota requested an interim increase, subject to refund, of $4.5 million or approximately 4.2 percent. On October 9, 2013, the NDPSC approved the interim increase to be effective with service rendered on or after November 17, 2013. On October 23, 2013, Montana-Dakota and the NDPSC Advocacy Staff filed a settlement agreement that resolved the revenue requirement portion of the application and reflected a natural gas rate increase of $4.3 million annually or approximately 4.0 percent, and agreed that Montana-Dakota will only implement $4.3 million of interim rate relief. The NDPSC held an informal hearing on the settlement on November 13, 2013. Montana-Dakota implemented the interim rate increase of $4.3 million effective with service rendered on or after November 17, 2013. On December 30, 2013, the NDPSC approved the settlement on the revenue requirement. A hearing on the rate design portion of the case was held February 5, 2014.

On October 31, 2013, WBI Energy Transmission filed a general natural gas rate change application with the FERC for an increase of $28.9 million annually to cover increased investments of $312 million, increased operating costs, and the effect of lower storage and off system volumes. WBI Energy Transmission will begin collecting the requested rates effective May 1, 2014, subject to refund.

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Inventories and natural gas in storage (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Aggregates held for resale	$ 101,568,000	$ 87,715,000
Materials and supplies	69,808,000	69,390,000
Asphalt oil	38,099,000	67,480,000
Merchandise for resale	21,720,000	31,172,000
Natural gas in storage (current)	16,417,000	29,030,000
Other	34,779,000	32,628,000
Total	282,391,000	317,415,000
Natural gas in storage noncurrent	$ 48,300,000	$ 49,700,000

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Components of income (loss) before income taxes

The components of income (loss) before income taxes from continuing operations for each of the years ended December 31 were as follows:

	2013		2012			2011
	(In thousands)
United States	$	415,202	$	(47,175	)	$	333,486
Foreign	416		1,708			2,740
Income (loss) before income taxes from continuing operations	$	415,618	$	(45,467	)	$	336,226

Income tax expense (benefit)

Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:

	2013			2012			2011
	(In thousands)
Current:
Federal	$	45,518		$	(26,858	)	$	(7,188	)
State	4,311			858			778
Foreign	(29		)	(75		)	127
	49,800			(26,075		)	(6,283		)
Deferred:
Income taxes:
Federal	78,953			(1,224		)	105,528
State	8,031			(6,323		)	13,157
Investment tax credit - net	(206		)	44			240
	86,778			(7,503		)	118,925
Change in uncertain tax positions	—			1,974			(1,048		)
Change in accrued interest	158			458			(1,320		)
Total income tax expense (benefit)	$	136,736		$	(31,146	)	$	110,274

Deferred tax assets and deferred tax liabilities

Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:

	2013			2012
	(In thousands)
Deferred tax assets:
Regulatory matters	$	125,607		$	121,781
Accrued pension costs	74,320			85,037
Alternative minimum tax credit carryforward	33,304			—
Compensation-related	31,550			23,441
Asset retirement obligations	29,578			26,748
Legal and environmental contingencies	10,710			8,046
Other	45,101			39,792
Total deferred tax assets	350,170			304,845
Deferred tax liabilities:
Depreciation and basis differences on property, plant and equipment	813,597			755,392
Basis differences on oil and natural gas producing properties	266,168			167,113
Regulatory matters	64,914			82,077
Intangible asset amortization	13,579			14,078
Other	26,170			18,441
Total deferred tax liabilities	1,184,428			1,037,101
Net deferred income tax liability	$	(834,258	)	$	(732,256	)

Schedule of change in net deferred income tax liability reconciliation [Table Text Block]

The following table reconciles the change in the net deferred income tax liability from December 31, 2012, to December 31, 2013, to deferred income tax expense:

	2013
(In thousands)
Change in net deferred income tax liability from the preceding table	$	102,002
Deferred taxes associated with other comprehensive loss	(7,277		)
Other	(7,947		)
Deferred income tax expense for the period	$	86,778

Reconciliation of income tax expense (benefit) at statutory federal rate versus actual rate

Total income tax expense (benefit) differs from the amount computed by applying the statutory federal income tax rate to income (loss) before taxes. The reasons for this difference were as follows:

Years ended December 31,	2013					2012					2011
	Amount			%		Amount			%		Amount			%
	(Dollars in thousands)
Computed tax at federal statutory rate	$	145,466		35.0		$	(15,914	)	35.0		$	117,679		35.0
Increases (reductions) resulting from:
State income taxes, net of federal income tax	10,524			2.5		2,469			(5.4	)	10,653			3.2
Nonqualified benefit plans	(5,173		)	(1.2	)	(2,359		)	5.2		(2,918		)	(.9	)
Depletion allowance	(3,764		)	(.9	)	(3,728		)	8.2		(3,266		)	(1.0	)
Federal renewable energy credit	(3,404		)	(.8	)	(3,401		)	7.5		(3,485		)	(1.0	)
Deductible K-Plan dividends	(1,593		)	(.4	)	(2,829		)	6.2		(2,282		)	(.7	)
AFUDC equity	(1,074		)	(.3	)	(1,500		)	3.3		(873		)	(.3	)
Resolution of tax matters and uncertain tax positions	(859		)	(.2	)	2,559			(5.6	)	(3,906		)	(1.2	)
Deferred tax rate changes	741			.2		(3,083		)	6.8		(417		)	(.1	)
Other	(4,128		)	(1.0	)	(3,360		)	7.3		(911		)	(.2	)
Total income tax expense (benefit)	$	136,736		32.9		$	(31,146	)	68.5		$	110,274		32.8

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:

	2013		2012		2011
	(In thousands)
Balance at beginning of year	$	14,914	$	11,206	$	9,378
Additions for tax positions of prior years	—		3,708		4,172
Settlements	—		—		(2,344		)
Balance at end of year	$	14,914	$	14,914	$	11,206

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Available-for-sale securities (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Available-for-sale securities [Line Items]
Investments used to satisfy obligations under nonqualified benefit plans	$ 62,400,000	$ 48,900,000
Net unrealized gain (loss) of investments used to satify obligations under nonqualified benefit plans	13,500,000	5,200,000	(1,100,000)
Available-for-sale securities:
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	10,057,000	9,817,000
Available-for-sale securities, gross unrealized gains	84,000	187,000
Available-for-sale securities, gross unrealized losses	(31,000)	(3,000)
Available-for-sale securities	10,110,000	10,001,000
Mortgage-backed securities
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	8,151,000	8,054,000
Available-for-sale securities, gross unrealized gains	69,000	144,000
Available-for-sale securities, gross unrealized losses	(27,000)	(3,000)
Available-for-sale securities	8,193,000	8,195,000
U.S. Treasury securities
Available-for-sale securities [Abstract]
Available-for-sale securities, amortized cost basis	1,906,000	1,763,000
Available-for-sale securities, gross unrealized gains	15,000	43,000
Available-for-sale securities, gross unrealized losses	(4,000)	0
Available-for-sale securities	$ 1,917,000	$ 1,806,000

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Benefit obligations in excess of plan assets (Details 2) (Pension Benefits, USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 402,772	$ 459,111
Accumulated benefit obligation	402,772	459,111
Fair value of plan assets	$ 334,844	$ 309,184

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Fair value measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Available-for-sale securities

Details of available-for-sale securities were as follows:

December 31, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193
U.S. Treasury securities	1,906		15		(4		)	1,917
Total	$	10,057	$	84	$	(31	)	$	10,110

December 31, 2012	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,054	$	144	$	(3	)	$	8,195
U.S. Treasury securities	1,763		43		—			1,806
Total	$	9,817	$	187	$	(3	)	$	10,001

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, 2013, 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, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	19,227	$	—	$	19,227
Insurance contract*	—		62,370		—		62,370
Available-for-sale securities:
Mortgage-backed securities	—		8,193		—		8,193
U.S. Treasury securities	—		1,917		—		1,917
Commodity derivative instruments	—		1,950		—		1,950
Total assets measured at fair value	$	—	$	93,657	$	—	$	93,657
Liabilities:
Commodity derivative instruments	$	—	$	7,483	$	—	$	7,483
Total liabilities measured at fair value	$	—	$	7,483	$	—	$	7,483

* The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Money market funds	$	—	$	24,240	$	—	$	24,240
Insurance contract*	—		48,898		—		48,898
Available-for-sale securities:
Mortgage-backed securities	—		8,195		—		8,195
U.S. Treasury securities	—		1,806		—		1,806
Commodity derivative instruments	—		18,304		—		18,304
Total assets measured at fair value	$	—	$	101,443	$	—	$	101,443
Liabilities:
Interest rate derivative instruments	$	—	$	6,255	$	—	$	6,255
Total liabilities measured at fair value	$	—	$	6,255	$	—	$	6,255

* The insurance contract invests approximately 28 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

Fair value of long-term debt outstanding

The estimated fair value of the Company's Level 2 long-term debt at December 31 was as follows:

	2013				2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
Long-term debt	$	1,854,563	$	1,912,590	$	1,744,975	$	1,888,135

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Impairment of long-lived assets (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Asset impairment charges	$ 9.0	$ 1.7	$ 9.0	$ 1.7

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Equity method investments (Details) (USD $)		12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011 Brazilian transmission lines [Member]	Aug. 31, 2013 ECTE [Member]	Aug. 31, 2012 ECTE [Member]	Nov. 30, 2011 ECTE [Member]	Nov. 30, 2010 ECTE [Member]	Nov. 30, 2010 ENTE [Member]	Nov. 30, 2010 ERTE [Member]
Schedule of equity method investments [Line Items]
Percentage ownership interest in equity method investment sold						59.96%	100.00%	100.00%
Number of years over which remaining ownership interest in equity method investment will be sold						4 years
Portion of remaining interest sold			25.00%	25.00%	25.00%
Recognized gain on sale of ownership interests		$ 1,000,000
Recognized gain on sale of ownership interests, after tax		600,000
Total assets of equity method investments	129,000,000
Total long-term debt of equity method investments	65,500,000
Investment in equity method investments	6,900,000
Undistributed earnings of equity method investments	$ 3,400,000

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Jointly owned facilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Big Stone Station:
Jointly owned facilities [Line Items]
Utility plant in service	$ 63,890	$ 63,146
Less accumulated depreciation	41,323	40,859
Utility plant in services net	22,567	22,287
Coyote Station:
Jointly owned facilities [Line Items]
Utility plant in service	138,261	135,073
Less accumulated depreciation	89,528	87,524
Utility plant in services net	48,733	47,549
Wygen III:
Jointly owned facilities [Line Items]
Utility plant in service	64,332	63,462
Less accumulated depreciation	4,639	3,368
Utility plant in services net	$ 59,693	$ 60,094

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Earnings (loss) percommon share (Details 13) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Weighted average common shares outstanding - basic	188,929	188,831	188,831	188,831	188,831	188,831	188,831	188,811	188,855	188,826	188,763
Effect of dilutive stock options and performance share awards									838	0	142
Weighted average common shares outstanding - diluted	189,766	189,638	189,463	189,222	188,831	188,831	189,107	189,182	189,693	188,826	188,905
Shares excluded from the calculation of diluted earnings per share									0	58	0

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Quarterly Financial Information Disclosure (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Quarterly financial data

The following unaudited information shows selected items by quarter for the years 2013 and 2012:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(In thousands, except per share amounts)
2013
Operating revenues	$	931,604		$	1,060,595		$	1,285,782		$	1,184,423
Operating expenses	827,073			969,217			1,135,909			1,037,306
Operating income	104,531			91,378			149,873			147,117
Income from continuing operations	56,592			46,392			84,550			91,348
Loss from discontinued operations, net of tax	(77		)	(59		)	(118		)	(58		)
Net income attributable to the Company	56,515			46,512			84,456			91,450
Earnings per common share - basic:
Earnings before discontinued operations	.30			.25			.45			.48
Discontinued operations, net of tax	—			—			—			—
Earnings per common share - basic	.30			.25			.45			.48
Earnings per common share - diluted:
Earnings before discontinued operations	.30			.24			.44			.48
Discontinued operations, net of tax	—			—			—			—
Earnings per common share - diluted	.30			.24			.44			.48
Weighted average common shares outstanding:
Basic	188,831			188,831			188,831			188,929
Diluted	189,222			189,463			189,638			189,766
2012
Operating revenues	$	852,807		$	967,962		$	1,173,518		$	1,081,144
Operating expenses	781,750			876,248			1,207,553			1,190,673
Operating income (loss)	71,057			91,714			(34,035		)	(109,529		)
Income (loss) from continuing operations	35,890			49,007			(29,532		)	(69,686		)
Income (loss) from discontinued operations, net of tax	(100		)	5,106			(139		)	8,700
Net income (loss) attributable to the Company	35,790			54,113			(29,671		)	(60,986		)
Earnings per common share - basic:
Earnings (loss) before discontinued operations	.19			.26			(.16		)	(.37		)
Discontinued operations, net of tax	—			.03			—			.05
Earnings (loss) per common share - basic	.19			.29			(.16		)	(.32		)
Earnings (loss) per common share - diluted:
Earnings (loss) before discontinued operations	.19			.26			(.16		)	(.37		)
Discontinued operations, net of tax	—			.03			—			.05
Earnings (loss) per common share - diluted	.19			.29			(.16		)	(.32		)
Weighted average common shares outstanding:
Basic	188,811			188,831			188,831			188,831
Diluted	189,182			189,107			188,831			188,831

Notes:

• First quarter 2013 reflects an unrealized loss on commodity derivatives of $3.7 million (after tax). First quarter 2012 reflects an unrealized loss on commodity derivatives of $2.6 million (after tax).

• Second quarter 2013 reflects an impairment of coalbed natural gas gathering assets of $9.0 million (after tax) and an unrealized gain on commodity derivatives of $8.2 million (after tax). Second quarter 2012 reflects a net benefit of $15.0 million (after tax) related to natural gas gathering operations litigation, a net benefit largely related to estimated insurance recoveries related to the guarantee of a construction contract (reflected in income (loss) from discontinued operations), an unrealized gain on commodity derivatives of $3.0 million (after tax) and an impairment of coalbed natural gas gathering assets of $1.7 million (after tax). For more information, see Notes 1 and 19.

• Third quarter 2013 reflects an unrealized loss on commodity derivatives of $7.9 million (after tax). Third quarter 2012 reflects a $100.9 million (after tax) noncash write-down of oil and natural gas properties and an unrealized loss on commodity derivatives of $700,000 (after tax). For more information, see Note 1.

• Fourth quarter 2013 reflects a net benefit of $1.5 million (after tax) related to natural gas gathering operations litigation and an unrealized loss on commodity derivatives of $500,000 (after tax). Fourth quarter 2012 reflects a $145.9 million (after tax) noncash write-down of oil and natural gas properties, the reversal of an arbitration charge of $13.0 million (after tax) related to a guarantee of a construction contract, which was partially offset by the reversal of estimated insurance recoveries (reflected in income (loss) from discontinued operations), as well as an unrealized loss on commodity derivatives of $200,000 (after tax). For more information, see Notes 1 and 19.

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Acquisitions

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Acquisitions

Acquisitions

In 2012, the Company acquired a 50 percent undivided interest in natural gas and oil midstream assets in western North Dakota. The acquisition includes a natural gas processing plant and a natural gas gathering pipeline system, along with an oil gathering system, an oil storage terminal and an oil pipeline. The total purchase consideration for acquisitions was approximately $67.5 million, including the Company's interest in the above facilities and contingent consideration related to an acquisition made prior to 2012. The Company recognizes its proportionate share of the assets, liabilities, revenues and expenses related to the natural gas and oil midstream assets acquisition.

In 2011, contingent consideration, consisting of the Company's common stock and cash, of $298,000 was made with respect to an acquisition made prior to 2011.

The acquisitions were accounted for under the acquisition method of accounting and, accordingly, the acquired assets and liabilities assumed have been recorded at their respective fair values as of the date of acquisition. The results of operations of the acquired businesses and properties are included in the financial statements since the date of each acquisition. Pro forma financial amounts reflecting the effects of the acquisitions are not presented, as such acquisitions were not material to the Company's financial position or results of operations.

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Purchase commitments (Details 4) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrecorded Unconditional Purchase Obligation [Line Items]
Term of unrecorded unconditional purchase obligation	one to 47 years
Purchase commitments due
2014	$ 635.8
2015	281.6
2016	170.7
2017	100.3
2018	73.4
Thereafter	910.8
Unrecorded Unconditional Purchase Obligation, Purchases	$ 861.8	$ 718.4	$ 626.3

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Cash flow information (Details 14) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Interest paid, net	$ 81,689	$ 74,378	$ 78,133
Income taxes paid, net	24,857	3,277	(12,287)
Capital expenditures incurred but not yet paid	$ 67,129	$ 76,205	$ 41,540

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Condensed Statements of Income and Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
Operating revenues	$ 1,184,423	$ 1,285,782	$ 1,060,595	$ 931,604	$ 1,081,144	$ 1,173,518	$ 967,962	$ 852,807	$ 4,462,404	$ 4,075,431	$ 4,050,492
Operating expenses	1,037,306	1,135,909	969,217	827,073	1,190,673	1,207,553	876,248	781,750	3,969,505	4,056,224	3,644,125
Operating income	147,117	149,873	91,378	104,531	(109,529)	(34,035)	91,714	71,057	492,899	19,207	406,367
Other income									6,768	6,642	6,520
Interest expense									83,917	76,699	81,354
Income (loss) before income taxes									415,618	(45,467)	336,226
Income taxes									136,736	(31,146)	110,274
Net income (loss) attributable to parent	91,450	84,456	46,512	56,515	(60,986)	(29,671)	54,113	35,790
Earnings (loss) on common stock									278,248	(1,439)	212,341
Comprehensive income (loss)									289,449	(2,474)	197,286
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Operating revenues									549,239	472,302	518,268
Operating expenses									473,917	405,095	450,579
Operating income									75,322	67,207	67,689
Other income									3,709	3,925	2,710
Interest expense									17,386	17,297	18,660
Income (loss) before income taxes									61,645	53,835	51,739
Income taxes									13,520	11,798	10,476
Equity in earnings of subsidiaries									230,808	(42,791)	171,763
Net income (loss) attributable to parent									278,933	(754)	213,026
Dividends declared on preferred stocks									685	685	685
Earnings (loss) on common stock									278,248	(1,439)	212,341
Comprehensive income (loss)									$ 289,449	$ (2,474)	$ 197,286

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Business segment data (Tables)

12 Months Ended

Dec. 31, 2013

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:

	2013			2012			2011
	(In thousands)
External operating revenues:
Electric	$	257,260		$	236,895		$	225,468
Natural gas distribution	851,945			754,848			907,400
Pipeline and energy services	155,369			139,883			210,846
	1,264,574			1,131,626			1,343,714
Exploration and production	490,924			412,651			359,873
Construction materials and contracting	1,675,444			1,597,257			1,509,538
Construction services	1,029,909			932,013			834,918
Other	1,553			1,884			2,449
	3,197,830			2,943,805			2,706,778
Total external operating revenues	$	4,462,404		$	4,075,431		$	4,050,492
Intersegment operating revenues:
Electric	$	—		$	—		$	—
Natural gas distribution	—			—			—
Pipeline and energy services	46,699			53,274			67,497
Exploration and production	45,099			35,966			93,713
Construction materials and contracting	36,693			20,168			472
Construction services	9,930			6,545			19,471
Other	8,067			8,486			8,997
Intersegment eliminations	(146,488		)	(124,439		)	(190,150		)
Total intersegment operating revenues	$	—		$	—		$	—
Depreciation, depletion and amortization:
Electric	$	32,789		$	32,509		$	32,177
Natural gas distribution	50,031			45,731			44,641
Pipeline and energy services	29,119			27,684			25,502
Exploration and production	186,458			160,681			142,645
Construction materials and contracting	74,470			79,527			85,459
Construction services	11,939			11,063			11,399
Other	2,050			2,010			1,572
Total depreciation, depletion and amortization	$	386,856		$	359,205		$	343,395
Interest expense:
Electric	$	12,590		$	12,421		$	13,745
Natural gas distribution	25,123			28,726			29,444
Pipeline and energy services	10,330			7,742			10,516
Exploration and production	14,315			9,018			7,445
Construction materials and contracting	17,394			15,211			16,241
Construction services	4,306			4,435			4,473
Other	15			13			—
Intersegment eliminations	(156		)	(867		)	(510		)
Total interest expense	$	83,917		$	76,699		$	81,354

	2013			2012			2011
	(In thousands)
Income taxes:
Electric	$	9,683		$	8,975		$	7,242
Natural gas distribution	16,633			12,005			16,931
Pipeline and energy services	3,390			15,291			12,912
Exploration and production	53,197			(108,264		)	46,298
Construction materials and contracting	24,765			14,099			11,227
Construction services	29,504			24,128			13,426
Other	2,433			2,620			2,238
Intersegment eliminations	(2,869		)	—			—
Total income taxes	$	136,736		$	(31,146	)	$	110,274
Earnings (loss) on common stock:
Electric	$	34,837		$	30,634		$	29,258
Natural gas distribution	37,656			29,409			38,398
Pipeline and energy services	7,629			26,588			23,082
Exploration and production	94,450			(177,283		)	80,282
Construction materials and contracting	50,946			32,420			26,430
Construction services	52,213			38,429			21,627
Other	5,136			4,797			6,190
Intersegment eliminations	(4,307		)	—			—
Earnings (loss) on common stock before income (loss) from discontinued operations	278,560			(15,006		)	225,267
Income (loss) from discontinued operations, net of tax*	(312		)	13,567			(12,926		)
Total earnings (loss) on common stock	$	278,248		$	(1,439	)	$	212,341
Capital expenditures:
Electric	$	168,557		$	112,035		$	52,072
Natural gas distribution	101,279			130,178			70,624
Pipeline and energy services	127,092			133,787			45,556
Exploration and production	391,315			554,528			272,855
Construction materials and contracting	34,607			45,083			52,303
Construction services	15,102			14,835			9,711
Other	2,249			791			18,759
Net proceeds from sale or disposition of property and other	(112,131		)	(57,460		)	(40,857		)
Total net capital expenditures	$	728,070		$	933,777		$	481,023
Assets:
Electric**	$	884,283		$	760,324		$	672,940
Natural gas distribution**	1,786,068			1,703,459			1,679,091
Pipeline and energy services	798,701			622,470			526,797
Exploration and production	1,616,131			1,539,017			1,481,556
Construction materials and contracting	1,305,808			1,371,252			1,374,026
Construction services	450,614			429,547			418,519
Other***	219,727			256,422			403,196
Total assets	$	7,061,332		$	6,682,491		$	6,556,125

	2013			2012		2011
	(In thousands)
Property, plant and equipment:
Electric**	$	1,315,822		$	1,150,584	$	1,068,524
Natural gas distribution**	1,776,901			1,689,950		1,568,866
Pipeline and energy services	962,172			816,533		719,291
Exploration and production	3,060,848			2,764,560		2,615,146
Construction materials and contracting	1,510,355			1,504,981		1,499,852
Construction services	134,948			130,624		124,796
Other	49,997			50,519		49,747
Eliminations	(7,177		)	—		—
Less accumulated depreciation, depletion and amortization	3,872,487			3,608,912		3,361,208
Net property, plant and equipment	$	4,931,379		$	4,498,839	$	4,285,014

    * Reflected in the Other category.

  ** Includes allocations of common utility property.

*** Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

Note: The results reflect $391.8 million ($246.8 million after tax) of noncash write-downs of oil and natural gas properties in 2012.

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Exploration and Production Activities (Unaudited) (Notes)

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

Exploration and Production Activities (Unaudited)

Fidelity is involved in the acquisition, exploration, development and production of oil and natural gas resources. Fidelity shares revenues and expenses from the development of specified properties in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States in proportion to its ownership interests.

The information that follows includes Fidelity's proportionate share of all its oil and natural gas interests.

The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31:

	2013		2012		2011
	(In thousands)
Subject to amortization	$	2,893,010	$	2,531,562	$	2,345,114
Not subject to amortization	124,869		191,794		232,462
Total capitalized costs	3,017,879		2,723,356		2,577,576
Less accumulated depreciation, depletion and amortization	1,562,116		1,383,386		1,229,654
Net capitalized costs	$	1,455,763	$	1,339,970	$	1,347,922
Note: Net capitalized costs reflect noncash write-downs of the Company's oil and natural gas properties, as discussed in Note 1.

Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities were as follows:

Years ended December 31,	2013		*	2012		*	2011		*
	(In thousands)
Acquisitions:
Proved properties	$	1,817		$	839		$	3,999
Unproved properties	4,608			31,109			63,354
Exploration	26,975			235,906			41,775
Development	355,421			275,959			161,647
Total capital expenditures	$	388,821		$	543,813		$	270,775

* Excludes net additions/(reductions) to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of oil and natural gas wells, as discussed in Note 10, of $(10.7) million, $(200,000) and $(1.8) million for the years ended December 31, 2013, 2012 and 2011, respectively.

The preceding table excludes proceeds from the sales of oil and natural gas properties of $83.6 million, $6.0 million and $12.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

The following summary reflects income resulting from the Company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs:

Years ended December 31,	2013			2012			2011
	(In thousands)
Revenues:
Sales to affiliates	$	45,099		$	35,966		$	93,713
Sales to external customers	497,018			379,647			348,428
Realized gain on commodity derivatives	173			33,628			9,618
Unrealized gain (loss) on commodity derivatives	(6,267		)	(624		)	1,827
Production costs	144,136			134,795			140,606
Depreciation, depletion and amortization*	182,352			157,078			139,539
Write-downs of oil and natural gas properties	—			391,800			—
Pretax income (loss)	209,535			(235,056		)	173,441
Income tax expense (benefit)	75,836			(88,612		)	63,655
Results of operations for producing activities	$	133,699		$	(146,444	)	$	109,786

* Includes accretion of discount for asset retirement obligations of $3.6 million, $3.3 million and $3.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, as discussed in Note 10.

Estimates of proved reserves were prepared in accordance with guidelines established by the industry and the SEC. The estimates are arrived at using actual historical wellhead production trends and/or standard reservoir engineering methods utilizing available geological, geophysical, engineering and economic data. The proved reserve estimates as of December 31, 2013, 2012 and 2011, were calculated using SEC Defined Prices. Other factors used in the proved reserve estimates are current estimates of well operating and future development costs (which include asset retirement costs), taxes, timing of operations, and the interests owned by the Company in the properties. These estimates are refined as new information becomes available.

The reserve estimates are prepared by internal engineers assigned to an asset team by geographic area. Senior management reviews and approves the reserve estimates to ensure they are materially accurate. In addition, the Company engaged Ryder Scott, an independent third party, to audit its proved reserve quantity estimates.

Estimates of economically recoverable oil, NGL and natural gas reserves and future net revenues therefrom are based upon a number of variable factors and assumptions. For these reasons, estimates of economically recoverable reserves and future net revenues may vary from actual results.

The Company's interests in oil, NGL and natural gas reserves are located in the United States and in and around the Gulf of Mexico.

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 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 changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2012, were as follows:

	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	27,005		7,342		379,827		97,651
Production	(3,694	)	(828	)	(33,214	)	(10,058	)
Extensions and discoveries	9,874		1,817		18,386		14,756
Improved recovery	—		—		—		—
Purchases of proved reserves	—		—		—		—
Sales of proved reserves	(39	)	—		(2,307	)	(423	)
Revisions of previous estimates	307		(1,178	)	(123,414	)	(21,440	)
Balance at end of year	33,453		7,153		239,278		80,486

Significant changes in proved reserves for the year ended December 31, 2012, include:

• Extension and discoveries of 14.8 MMBOE primarily due to drilling activity at the Company's Bakken, South Texas and Paradox properties

• Revisions of previous estimates of (21.4) MMBOE, largely the result of lower natural gas prices resulting in a reduction of PDP and PUD reserves principally in the Company's Coalbed, Baker, Bowdoin, East Texas and Green River Basin natural gas properties

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2011, were as follows:

	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	25,666		7,201		448,397		107,599
Production	(2,724	)	(776	)	(45,598	)	(11,099	)
Extensions and discoveries	4,717		1,421		28,221		10,842
Improved recovery	—		—		—		—
Purchases of proved reserves	223		16		54		247
Sales of proved reserves	—		—		—		—
Revisions of previous estimates	(877	)	(520	)	(51,247	)	(9,938	)
Balance at end of year	27,005		7,342		379,827		97,651

Significant changes in proved reserves for the year ended December 31, 2011, include:

• Extensions and discoveries of 10.8 MMBOE primarily due to drilling activity at the Company's Bakken and Big Horn properties

• Revisions of previous estimates of (9.9) MMBOE, largely the result of a reduction in PUD reserves of 8.9 MMBOE resulting principally in the Company's Bowdoin, Baker, Coalbed, East Texas and Big Horn Basin properties. The remaining negative revisions were a reduction in PDP natural gas reserves.

The following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31:

	2013	2012	2011
Proved developed reserves:
Oil (MBbls)	31,394	27,412	23,653
NGL (MBbls)	5,322	5,342	5,225
Natural Gas (MMcf)	176,546	218,259	303,495
Total (MBOE)	66,140	69,131	79,460
PUD reserves:
Oil (MBbls)	9,625	6,041	3,352
NGL (MBbls)	1,280	1,811	2,117
Natural Gas (MMcf)	21,899	21,019	76,332
Total (MBOE)	14,555	11,355	18,191
Total proved reserves:
Oil (MBbls)	41,019	33,453	27,005
NGL (MBbls)	6,602	7,153	7,342
Natural Gas (MMcf)	198,445	239,278	379,827
Total (MBOE)	80,695	80,486	97,651

As of December 31, 2013, the Company had 14.6 MMBOE of PUD reserves, which is an increase of 3.2 MMBOE from December 31, 2012. The increase relates to the Company adding 11.9 MMBOE of new PUD reserves, primarily in the Company's oil properties. This was partially offset by the Company converting 7.1 MMBOE, requiring $127.3 million of drilling and completion capital in 2013 and PUD revision of (1.6) MMBOE. At December 31, 2013, the Company did not have any PUD locations that remained undeveloped for five years or more. Future development costs estimated to be spent in each of the next three years to develop PUD reserves as of December 31, 2013, are $143.6 million in 2014, $116.0 million in 2015 and $18.1 million in 2016.

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:

	2013		2012		2011
	(In thousands)
Future cash inflows	$	4,507,000	$	3,696,200	$	4,188,000
Future production costs	1,734,800		1,536,500		1,560,300
Future development costs	403,000		301,600		285,300
Future net cash flows before income taxes	2,369,200		1,858,100		2,342,400
Future income tax expense	545,200		304,900		531,100
Future net cash flows	1,824,000		1,553,200		1,811,300
10% annual discount for estimated timing of cash flows	810,000		669,800		832,500
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$	1,014,000	$	883,400	$	978,800

The following are the sources of change in the standardized measure of discounted future net cash flows by year:

	2013			2012			2011
	(In thousands)
Beginning of year	$	883,400		$	978,800		$	896,100
Net revenues from production	(398,000		)	(280,800		)	(301,500		)
Net change in sales prices and production costs related to future production	162,200			(406,300		)	82,300
Extensions and discoveries, net of future production-related costs	366,500			355,300			226,300
Improved recovery, net of future production-related costs	—			—			—
Purchases of proved reserves, net of future production-related costs	—			—			9,500
Sales of proved reserves	(37,800		)	(2,600		)	—
Changes in estimated future development costs	6,700			37,600			51,100
Development costs incurred during the current year	141,500			77,700			56,300
Accretion of discount	94,600			121,400			105,000
Net change in income taxes	(141,400		)	110,000			(55,800		)
Revisions of previous estimates	(55,800		)	(100,700		)	(92,900		)
Other	(7,900		)	(7,000		)	2,400
Net change	130,600			(95,400		)	82,700
End of year	$	1,014,000		$	883,400		$	978,800

The estimated discounted future cash inflows from estimated future production of proved reserves were computed using prices as previously discussed. Future production and development costs, which include asset retirement costs, attributable to proved reserves were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying statutory tax rates to the estimated net future pretax cash flows less the tax basis of the oil and gas properties, adjusted for permanent differences and tax credits.

The standardized measure of discounted future net cash flows does not purport to represent the fair market value of oil and natural gas properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. In addition, future realization of oil, NGL and natural gas prices over the remaining reserve lives may vary significantly from SEC Defined Prices.

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Quarterly Data (Unaudited)

12 Months Ended

Dec. 31, 2013

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 2013 and 2012:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(In thousands, except per share amounts)
2013
Operating revenues	$	931,604		$	1,060,595		$	1,285,782		$	1,184,423
Operating expenses	827,073			969,217			1,135,909			1,037,306
Operating income	104,531			91,378			149,873			147,117
Income from continuing operations	56,592			46,392			84,550			91,348
Loss from discontinued operations, net of tax	(77		)	(59		)	(118		)	(58		)
Net income attributable to the Company	56,515			46,512			84,456			91,450
Earnings per common share - basic:
Earnings before discontinued operations	.30			.25			.45			.48
Discontinued operations, net of tax	—			—			—			—
Earnings per common share - basic	.30			.25			.45			.48
Earnings per common share - diluted:
Earnings before discontinued operations	.30			.24			.44			.48
Discontinued operations, net of tax	—			—			—			—
Earnings per common share - diluted	.30			.24			.44			.48
Weighted average common shares outstanding:
Basic	188,831			188,831			188,831			188,929
Diluted	189,222			189,463			189,638			189,766
2012
Operating revenues	$	852,807		$	967,962		$	1,173,518		$	1,081,144
Operating expenses	781,750			876,248			1,207,553			1,190,673
Operating income (loss)	71,057			91,714			(34,035		)	(109,529		)
Income (loss) from continuing operations	35,890			49,007			(29,532		)	(69,686		)
Income (loss) from discontinued operations, net of tax	(100		)	5,106			(139		)	8,700
Net income (loss) attributable to the Company	35,790			54,113			(29,671		)	(60,986		)
Earnings per common share - basic:
Earnings (loss) before discontinued operations	.19			.26			(.16		)	(.37		)
Discontinued operations, net of tax	—			.03			—			.05
Earnings (loss) per common share - basic	.19			.29			(.16		)	(.32		)
Earnings (loss) per common share - diluted:
Earnings (loss) before discontinued operations	.19			.26			(.16		)	(.37		)
Discontinued operations, net of tax	—			.03			—			.05
Earnings (loss) per common share - diluted	.19			.29			(.16		)	(.32		)
Weighted average common shares outstanding:
Basic	188,811			188,831			188,831			188,831
Diluted	189,182			189,107			188,831			188,831

Notes:

• First quarter 2013 reflects an unrealized loss on commodity derivatives of $3.7 million (after tax). First quarter 2012 reflects an unrealized loss on commodity derivatives of $2.6 million (after tax).

• Second quarter 2013 reflects an impairment of coalbed natural gas gathering assets of $9.0 million (after tax) and an unrealized gain on commodity derivatives of $8.2 million (after tax). Second quarter 2012 reflects a net benefit of $15.0 million (after tax) related to natural gas gathering operations litigation, a net benefit largely related to estimated insurance recoveries related to the guarantee of a construction contract (reflected in income (loss) from discontinued operations), an unrealized gain on commodity derivatives of $3.0 million (after tax) and an impairment of coalbed natural gas gathering assets of $1.7 million (after tax). For more information, see Notes 1 and 19.

• Third quarter 2013 reflects an unrealized loss on commodity derivatives of $7.9 million (after tax). Third quarter 2012 reflects a $100.9 million (after tax) noncash write-down of oil and natural gas properties and an unrealized loss on commodity derivatives of $700,000 (after tax). For more information, see Note 1.

• Fourth quarter 2013 reflects a net benefit of $1.5 million (after tax) related to natural gas gathering operations litigation and an unrealized loss on commodity derivatives of $500,000 (after tax). Fourth quarter 2012 reflects a $145.9 million (after tax) noncash write-down of oil and natural gas properties, the reversal of an arbitration charge of $13.0 million (after tax) related to a guarantee of a construction contract, which was partially offset by the reversal of estimated insurance recoveries (reflected in income (loss) from discontinued operations), as well as an unrealized loss on commodity derivatives of $200,000 (after tax). For more information, see Notes 1 and 19.

Certain Company operations are highly seasonal and revenues from and certain expenses for such operations may fluctuate significantly among quarterly periods. Accordingly, quarterly financial information may not be indicative of results for a full year.

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Weighted average assumptions (Details 5)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Used to determine benefit obligation
Discount rate	4.53%	3.65%
Expected return on plan assets	7.00%	7.00%
Used to determine benefit cost
Discount rate	3.65%	4.16%
Expected return on plan assets	7.00%	7.75%
Other Postretirement Benefits
Used to determine benefit obligation
Discount rate	4.48%	3.67%
Expected return on plan assets	6.00%	6.00%
Rate of compensation increase	3.00%	4.00%
Used to determine benefit cost
Discount rate	3.67%	4.13%
Expected return on plan assets	6.00%	6.75%
Rate of compensation increase	4.00%	4.00%

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Percentage-of-completion method (Details 8) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Accounting Policies [Abstract]
Costs and estimated earnings in excess of billings on uncompleted contracts	$ 60,828		$ 64,996
Billings in excess of costs and estimated earnings on uncompleted contracts	84,189		83,167
Short-term retainage	55,906	[1]	54,256	[1]
Long-term retainage	4,229	[2]	2,038	[2]
Total retainage	$ 60,135		$ 56,294

[1] Expected to be paid within one year or less and included in receivables, net.

[2] Included in deferred charges and other assets - other.

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Changes in benefit obligation and plan assets

Changes in benefit obligation and plan assets for the years ended December 31, 2013 and 2012, and amounts recognized in the Consolidated Balance Sheets at December 31, 2013 and 2012, were as follows:

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	459,111		$	435,618		$	103,358		$	110,689
Service cost	155			1,078			1,675			1,747
Interest cost	16,249			17,598			3,215			4,166
Plan participants' contributions	—			—			1,472			2,688
Amendments	—			—			—			(11,418		)
Actuarial (gain) loss	(44,551		)	30,939			(20,985		)	3,469
Benefits paid	(28,192		)	(26,122		)	(7,009		)	(7,983		)
Benefit obligation at end of year	402,772			459,111			81,726			103,358
Change in net plan assets:
Fair value of plan assets at beginning of year	309,184			278,000			74,361			68,085
Actual gain on plan assets	35,539			34,493			13,819			6,497
Employer contribution	18,313			22,813			1,900			5,074
Plan participants' contributions	—			—			1,472			2,688
Benefits paid	(28,192		)	(26,122		)	(7,009		)	(7,983		)
Fair value of net plan assets at end of year	334,844			309,184			84,543			74,361
Funded status - (under) over	$	(67,928	)	$	(149,927	)	$	2,817		$	(28,997	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	$	—		$	—		$	9,679		$	—
Other accrued liabilities (current)	—			—			(381		)	(655		)
Other liabilities (noncurrent)	(67,928		)	(149,927		)	(6,481		)	(28,342		)
Net amount recognized	$	(67,928	)	$	(149,927	)	$	2,817		$	(28,997	)
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	$	135,061		$	202,406		$	11,314		$	43,589
Prior service cost (credit)	365			437			(17,137		)	(18,594		)
Total	$	135,426		$	202,843		$	(5,823	)	$	24,995

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:

	2013		2012
	(In thousands)
Projected benefit obligation	$	402,772	$	459,111
Accumulated benefit obligation	$	402,772	$	459,111
Fair value of plan assets	$	334,844	$	309,184

Components of net periodic benefit cost

Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows:

	Pension Benefits									Other Postretirement Benefits
	2013			2012			2011			2013			2012			2011
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	155		$	1,078		$	2,252		$	1,675		$	1,747		$	1,443
Interest cost	16,249			17,598			19,500			3,215			4,166			4,700
Expected return on assets	(19,917		)	(23,536		)	(22,809		)	(4,343		)	(4,890		)	(5,051		)
Amortization of prior service cost (credit)	71			(46		)	45			(1,457		)	(1,438		)	(2,677		)
Recognized net actuarial loss	7,173			7,070			4,656			1,814			2,134			753
Curtailment loss (gain)	—			(1,023		)	1,218			—			—			—
Amortization of net transition obligation	—			—			—			—			2,128			2,125
Net periodic benefit cost, including amount capitalized	3,731			1,141			4,862			904			3,847			1,293
Less amount capitalized	727			937			1,196			164			910			(50		)
Net periodic benefit cost	3,004			204			3,666			740			2,937			1,343
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	(60,173		)	19,982			76,310			(30,461		)	1,863			23,863
Prior service credit	—			—			—			—			(11,418		)	—
Amortization of actuarial loss	(7,173		)	(7,070		)	(4,656		)	(1,814		)	(2,134		)	(753		)
Amortization of prior service (cost) credit	(71		)	1,069			(1,263		)	1,457			1,438			2,677
Amortization of net transition obligation	—			—			—			—			(2,128		)	(2,125		)
Total recognized in accumulated other comprehensive (income) loss	(67,417		)	13,981			70,391			(30,818		)	(12,379		)	23,662
Total recognized in net periodic benefit cost and accumulated other comprehensive (income) loss	$	(64,413	)	$	14,185		$	74,057		$	(30,078	)	$	(9,442	)	$	25,005

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
	2013		2012		2013		2012
Discount rate	4.53	%	3.65	%	4.48	%	3.67	%
Expected return on plan assets	7.00	%	7.00	%	6.00	%	6.00	%
Rate of compensation increase	N/A		N/A		3.00	%	4.00	%

Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows:

	Pension Benefits				Other Postretirement Benefits
	2013		2012		2013		2012
Discount rate	3.65	%	4.16	%	3.67	%	4.13	%
Expected return on plan assets	7.00	%	7.75	%	6.00	%	6.75	%
Rate of compensation increase	N/A*		N/A*		4.00	%	4.00	%

* Effective September 30, 2012, all benefit and service accruals for a union plan were frozen. Compensation increases had previously been frozen for all other plans.

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:

				2013					2012
Health care trend rate assumed for next year	6.0	%	-	7.0	%	6.0	%	-	8.0	%
Health care cost trend rate - ultimate	5.0	%	-	6.0	%	5.0	%	-	6.0	%
Year in which ultimate trend rate achieved				2017					2017

Assumed health care cost trend rates

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates would have had the following effects at December 31, 2013:

	1 Percentage  Point Increase		1 Percentage Point  Decrease
	(In thousands)
Effect on total of service and interest cost components	$	159	$	(135	)
Effect on postretirement benefit obligation	$	3,352	$	(2,920	)

The fair value of the Company's pension 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, 2013, 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, 2013
	(In thousands)
Assets:
Cash equivalents	$	—	$	9,406	$	—	$	9,406
Equity securities:
U.S. companies	62,599		—		—		62,599
International companies	39,437		—		—		39,437
Collective and mutual funds*	116,265		42,483		—		158,748
Corporate bonds	—		42,721		—		42,721
Municipal bonds	—		7,561		—		7,561
U.S. Treasury securities	7,487		4,335		—		11,822
Total assets measured at fair value	$	225,788	$	106,506	$	—	$	332,294

* Collective and mutual funds invest approximately 11 percent in common stock of mid-cap U.S. companies, 34 percent in common stock of large-cap U.S. companies, 11 percent in U.S. Treasuries, 27 percent in corporate bonds and 17 percent in other investments.

The fair value of the Company's pension plans' assets by class were as follows:

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Cash equivalents	$	2,145	$	10,460	$	—	$	12,605
Equity securities:
U.S. companies	86,981		—		—		86,981
International companies	39,818		—		—		39,818
Collective and mutual funds*	82,787		20,065		—		102,852
Corporate bonds	—		45,112		—		45,112
Municipal bonds	—		9,302		—		9,302
U.S. Treasury securities	7,980		4,534		—		12,514
Total assets measured at fair value	$	219,711	$	89,473	$	—	$	309,184

* Collective and mutual funds invest approximately 12 percent in common stock of mid-cap U.S. companies, 26 percent in common stock of large-cap U.S. companies, 13 percent in U.S. Treasuries, 41 percent in corporate bonds and 8 percent in other investments.

Summary of changes in the fair value of the pension plan's Level 3 assets

The following table sets forth a summary of changes in the fair value of the pension plans' Level 3 assets for the year ended December 31, 2012:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Corporate Bonds
	(In thousands)
Balance at beginning of year	$	289
Total realized/unrealized losses	(47		)
Purchases, issuances and settlements (net)	(242		)
Balance at end of year	$	—

Fair value of other postretirement benefit plan assets by asset class

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, 2013, 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, 2013
	(In thousands)
Assets:
Cash equivalents	$	—	$	2,142	$	—	$	2,142
Equity securities:
U.S. companies	2,802		—		—		2,802
International companies	221		—		—		221
Insurance contract*	—		79,374		—		79,374
Total assets measured at fair value	$	3,023	$	81,516	$	—	$	84,539

* The insurance contract invests approximately 55 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Treasuries, 8 percent in mortgage-backed securities, 8 percent in common stock of mid-cap U.S. companies, 9 percent in corporate bonds and 8 percent in other investments.

The fair value of the Company's other postretirement benefit plans' assets by asset class were as follows:

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Cash equivalents	$	1,053	$	1,991	$	—	$	3,044
Equity securities:
U.S. companies	2,207		—		—		2,207
International companies	260		—		—		260
Insurance contract*	—		68,850		—		68,850
Total assets measured at fair value	$	3,520	$	70,841	$	—	$	74,361

* The insurance contract invests approximately 51 percent in common stock of large-cap U.S. companies, 15 percent in U.S. Treasuries, 10 percent in mortgage-backed securities, 11 percent in corporate bonds and 13 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)
2014	$	23,391	$	5,596	$	237
2015	23,645		5,584		230
2016	23,911		5,583		221
2017	24,439		5,543		211
2018	24,814		5,483		200
2019 - 2023	130,026		26,038		823

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		2013	2012		2013		2012		2011
					(In thousands)
Edison Pension Plan	93-6061681-001	Green as of 12/31/2013	Green as of 12/31/2012	No	$	6,358	$	5,171	$	2,700	No	12/31/2014
IBEW Local 38 Pension Plan	34-6574238-001	Yellow as of 4/30/2013	Yellow as of 4/30/2012	Implemented	1,041		2,771		1,469		No	4/27/2014
IBEW Local No. 82 Pension Plan	31-6127268-001	Red as of 6/30/2013	Red as of 6/30/2012	Implemented	1,284		1,093		1,331		No	11/30/2014
IBEW Local 648 Pension Plan	31-6134845-001	Red as of 2/28/2013	Red as of 2/29/2012	Implemented	1,489		564		722		No	8/31/2015
Laborers Pension Trust Fund for Northern California	94-6277608-001	Yellow as of 5/31/2013	Yellow as of 5/31/2012	Implemented	921		567		628		No	6/30/2016
National Electrical Benefit Fund	53-0181657-001	Green	Green	No	5,883		5,603		4,841		No	5/31/2012*– 8/31/2017
OE Pension Trust Fund	94-6090764-001	Yellow	Yellow as of 12/31/2012	Implemented	1,510		1,156		1,367		No	6/30/2013*– 3/31/2016
Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming	83-6011320-001	Red as of 12/31/2013	Red as of 12/31/2012	Implemented	76		91		96		No	10/31/2005*
Operating Engineers Pension Trust	95-6032478-001	Red as of 6/30/2013	Red as of 6/30/2012	Implemented	493		761		458		No	7/1/2013*– 7/20/2014
Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525	88-6003864-001	Green as of 6/30/2012	Green as of 6/30/2011	No	1,657		1,202		759		No	5/31/2010*
Sheet Metal Workers' Pension Plan of Southern CA, AZ and NV	95-6052257-001	Red as of 12/31/2013	Red as of 12/31/2012	Implemented	512		467		336		No	6/30/2014
Other funds					18,036		15,333		14,451
Total contributions					$	39,260	$	34,779	$	29,158

* 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 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	2012 and 2011
IBEW Local 38 Pension Plan	2012 and 2011
IBEW Local No. 82 Pension Plan	2012 and 2011
Local Union No. 124 IBEW Pension Trust Fund	2012 and 2011
Local Union 212 IBEW Pension Trust Fund	2012 and 2011
IBEW Local Union No. 357 Pension Plan A	2012 and 2011
IBEW Local 648 Pension Plan	2012 and 2011
Idaho Plumbers and Pipefitters Pension Plan	2012 and 2011
Minnesota Teamsters Construction Division Pension Fund	2012 and 2011
Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming	2012 and 2011
Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525	2012 and 2011

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Schedule I-Condensed Financial Information of Registrant

12 Months Ended

Dec. 31, 2013

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule I-Condensed Financial Information of Registrant

Summary of Significant Accounting Policies

Basis of presentationThe condensed financial information reported in Schedule I is being presented to comply with Rule 12-04 of Regulation S-X. The information is unconsolidated and is presented for the parent company only, which is comprised of MDU Resources Group, Inc. (the Company) and Montana-Dakota and Great Plains, public utility divisions of the Company. In Schedule I, investments in subsidiaries are presented under the equity method of accounting where the assets and liabilities of the subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded on the Condensed Balance Sheets. The income (loss) from subsidiaries is reported as equity in earnings (loss) of subsidiaries on the Condensed Statements of Income. The consolidated financial statements of MDU Resources Group, Inc. reflect certain businesses as discontinued operations. In Schedule I, amounts from discontinued operations have not been separately stated. These statements should be read in conjunction with the consolidated financial statements and notes thereto of MDU Resources Group, Inc.

Earnings (loss) per common share Please refer to the Consolidated Statements of Income of the registrant for earnings (loss) per common share. In addition, see Note 1 of Notes to Consolidated Financial Statements for information on the computation of earnings (loss) per common share.

Note 2 - Debt The Company has long-term debt obligations outstanding of $434.7 million at December 31, 2013, with annual maturities of $100,000 in 2014, $100,000 in 2015, $50.1 million in 2016, $79.0 million in 2017, $100.0 million in 2018 and $205.4 million scheduled to mature in years after 2018.

For more information on debt, see Note 9 of Notes to Consolidated Financial Statements.

Note 3 - Dividends The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on common stock. Cash dividends paid to the Company by subsidiaries were $77.6 million, $125.8 million and $96.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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Schedule II Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2013

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

Consolidated Valuation and Qualifying Accounts

For the years ended December 31, 2013, 2012 and 2011
			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:
2013	$	10,818	$	5,725	$	1,395		$	7,853		$	10,085
2012	12,407		7,064		1,754			10,407			10,818
2011	15,284		3,977		2,112			8,966			12,407

* Recoveries.

** Uncollectible accounts written off.

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Summary of significant accounting policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Summary of significant accounting policies

Summary of Significant Accounting Policies

Basis of presentation

The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline and energy services, exploration and production, construction materials and contracting, construction services and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Exploration and production, construction materials and contracting, construction services and other are nonregulated. For further descriptions of the Company's businesses, see Note 15. Intercompany balances and transactions have been eliminated in consolidation, except for certain transactions related to the Company's regulated operations in accordance with GAAP. The statements also include the ownership interests in the assets, liabilities and expenses of jointly owned electric generating facilities.

The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by the Company's nonregulated businesses.

The Company's regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals.

Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.

Management has also evaluated the impact of events occurring after December 31, 2013, up to the date of issuance of these consolidated financial statements.

Cash and cash equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts receivable and allowance for doubtful accounts

Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. For more information, see Percentage-of-completion method in this note. The total balance of receivables past due 90 days or more was $36.4 million and $34.3 million as of December 31, 2013 and 2012, 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 as of December 31, 2013 and 2012, was $10.1 million and $10.8 million, respectively.

Inventories and natural gas in storage

Inventories, other than natural gas in storage for the Company's regulated operations, were stated at the lower of average cost or market value. Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories. Inventories at December 31 consisted of:

	2013		2012
	(In thousands)
Aggregates held for resale	$	101,568	$	87,715
Materials and supplies	69,808		69,390
Asphalt oil	38,099		67,480
Merchandise for resale	21,720		31,172
Natural gas in storage (current)	16,417		29,030
Other	34,779		32,628
Total	$	282,391	$	317,415

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 $48.3 million and $49.7 million at December 31, 2013 and 2012, respectively.

Investments

The Company's investments include its equity method and cost method investments as discussed in Note 4, the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company measures its investment in the insurance contract at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated other comprehensive income (loss). For more information, see Notes 8 and 16.

Property, plant and equipment

Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for exploration and production properties as described in Oil and natural gas properties in this note, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, at the exploration and production segment only on costs that have been excluded from the full cost amortization pool and on certain construction projects associated with its other operations. The amount of AFUDC and interest capitalized for the years ended December 31 were as follows:

	2013		2012		2011
	(In thousands)
Interest capitalized	$	6,033	$	8,659	$	10,821
AFUDC - borrowed	$	2,767	$	2,483	$	1,666
AFUDC - equity	$	3,322	$	4,530	$	2,587

Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable aggregate reserves, which are depleted based on the units-of-production method, and exploration and production properties, which are amortized on the units-of-production method based on total proved reserves. The Company collects removal costs for plant assets in regulated utility rates. These amounts are recorded as regulatory liabilities, which are included in other liabilities.

Property, plant and equipment at December 31 was as follows:

	2013			2012		Weighted Average Depreciable Life in  Years
	(Dollars in thousands, where applicable)
Regulated:
Electric:
Generation	$	570,394		$	546,011	42
Distribution	308,202			276,446		39
Transmission	196,824			180,543		48
Construction in progress	141,365			62,123		-
Other	99,037			85,461		14
Natural gas distribution:
Distribution	1,384,587			1,308,314		40
Construction in progress	46,763			71,679		-
Other	345,551			309,957		25
Pipeline and energy services:
Transmission	418,594			403,126		52
Gathering	39,597			42,420		19
Storage	42,939			42,058		51
Construction in progress	6,937			13,667		-
Other	39,504			38,386		29
Nonregulated:
Pipeline and energy services:
Midstream	213,063			233,840		17
Construction in progress	188,641			29,657		-
Other	12,897			13,379		11
Exploration and production:
Oil and natural gas properties	3,017,879			2,723,356		*
Other	42,969			41,204		8
Construction materials and contracting:
Land	125,551			126,788		-
Buildings and improvements	70,000			73,884		19
Machinery, vehicles and equipment	906,774			899,592		12
Construction in progress	13,315			11,165		-
Aggregate reserves	394,715			393,552		**
Construction services:
Land	4,821			4,723		-
Buildings and improvements	16,628			16,563		20
Machinery, vehicles and equipment	105,991			100,445		6
Other	7,508			8,893		4
Other:
Land	2,837			2,837		-
Other	47,160			47,682		23
Eliminations	(7,177		)	—
Less accumulated depreciation, depletion and amortization	3,872,487			3,608,912
Net property, plant and equipment	$	4,931,379		$	4,498,839

  *  Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $17.41, $15.28 and $12.25 for the years ended December 31, 2013, 2012 and 2011, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $124.9 million and $191.8 million were excluded from amortization at December 31, 2013 and 2012, respectively.

** Depleted on the units-of-production method.

Impairment of long-lived assets

The Company reviews the carrying values of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. In 2013 and 2012, the Company recognized impairments of $9.0 million (after tax) and $1.7 million (after tax), respectively, which are recorded in operation and maintenance expense on the Consolidated Statements of Income. The impairments are related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a significant decline in natural gas development and production activity largely due to low natural gas prices. The coalbed natural gas gathering assets were written down to fair value that was determined using the income approach. For more information on this nonrecurring fair value measurement, see Note 8.

No significant impairment losses were recorded in 2011. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired.

The goodwill impairment test is a two-step process performed at the reporting unit level. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. For more information on the Company's operating segments, see Note 15. The first step of the impairment test involves comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the years ended December 31, 2013, 2012 and 2011, there were no impairment losses recorded. At December 31, 2013, 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 10 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 2013. Under the market approach, the Company estimates fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants. The Company believes that the estimates and assumptions used in its impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.

Oil and natural gas properties

The Company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized.

Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash outflows associated with asset retirement obligations that have been accrued on the balance sheet. If capitalized costs, less accumulated amortization and related deferred income taxes, exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.

At December 31, 2013, the Company's full-cost ceiling exceeded the Company's capitalized cost. However, there is risk that lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in additional future noncash write-downs of the Company's oil and natural gas properties.

The Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at September 30, 2012 and December 31, 2012. SEC Defined Prices, adjusted for market differentials, are used to calculate the ceiling test. SEC Defined Prices as of September 30, 2012 and December 31, 2012, were $94.97 per Bbl for NYMEX oil and $2.83 per MMBtu for Henry Hub natural gas and $94.71 per Bbl for NYMEX oil and $2.76 per MMBtu for Henry Hub natural gas, respectively. Accordingly, the Company was required to write down its oil and natural gas producing properties. The noncash write-downs amounted to $160.1 million and $231.7 million ($100.9 million and $145.9 million after tax) for the three months ended September 30, 2012 and December 31, 2012, respectively.

The Company hedged a portion of its oil and natural gas production and the effects of the cash flow hedges were used in determining the full-cost ceiling at September 30, 2012 and December 31, 2012. The Company would have recognized additional write-downs of its oil and natural gas properties of $19.5 million ($12.3 million after tax) at September 30, 2012, and $20.8 million ($13.1 million after tax) at December 31, 2012, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 7.

The following table summarizes the Company's oil and natural gas properties not subject to amortization at December 31, 2013, in total and by the year in which such costs were incurred:

			Year Costs Incurred
	Total		2013		2012		2011		2010 and prior
	(In thousands)
Acquisition	$	93,758	$	1,514	$	23,588	$	28,543	$	40,113
Development	14,824		12,622		1,633		271		298
Exploration	14,547		9,952		4,346		198		51
Capitalized interest	1,740		340		418		410		572
Total costs not subject to amortization	$	124,869	$	24,428	$	29,985	$	29,422	$	41,034

Costs not subject to amortization as of December 31, 2013, consisted primarily of unevaluated leaseholds and development costs in the Bakken area, Texas properties and the Paradox Basin. The Company expects that the majority of these costs will be evaluated within the next five years and included in the amortization base as the properties are evaluated and/or developed.

Revenue recognition

Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is reasonably assured. The Company recognizes utility revenue each month based on the services provided to all utility customers during the month. Accrued unbilled revenue which is included in receivables, net, represents revenues recognized in excess of amounts billed. Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain was $107.4 million and $85.9 million at December 31, 2013 and 2012, 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:

	2013		2012
	(In thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	60,828	$	64,996
Billings in excess of costs and estimated earnings on uncompleted contracts	$	84,189	$	83,167

Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31, were as follows:

	2013		2012
	(In thousands)
Short-term retainage *	$	55,906	$	54,256
Long-term retainage **	4,229		2,038
Total retainage	$	60,135	$	56,294

  * 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, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions, and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties.

The Company's policy generally allows the hedging of monthly forecasted sales of oil and natural gas production at Fidelity for a period up to 42 months from the time the Company enters into the hedge. The Company's policy requires that interest rate derivative instruments not exceed a period of 24 months and foreign currency derivative instruments not exceed a 12-month period. The Company's policy allows the hedging of monthly forecasted purchases of natural gas at Cascade and Intermountain for a period up to three years.

The Company's policy requires that each month as physical oil and natural gas production at Fidelity occurs and the commodity is sold, the related portion of the derivative agreement for that month's production must settle with its counterparties. Settlements represent the exchange of cash between the Company and its counterparties based on the notional quantities and prices for each month's physical delivery as specified within the agreements. The fair value of the remaining notional amounts on the derivative agreements is recorded on the balance sheet as an asset or liability measured at fair value. The Company's policy also requires settlement of natural gas derivative instruments at Cascade and Intermountain monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days, and any foreign currency derivative transaction settlement periods may not exceed a 12-month period. The Company has policies and procedures that management believes minimize credit-risk exposure. Accordingly, the Company does not anticipate any material effect on its financial position or results of operations as a result of nonperformance by counterparties. For more information on derivative instruments, see Note 7.

The Company's derivative instruments are reflected at fair value. For more information, see Note 8.

Asset retirement obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its nonregulated operations or incurs a regulatory asset or liability at its regulated operations. For more information on asset retirement obligations, see Note 10.

Legal costs

The Company expenses external legal fees as they are incurred.

Natural gas costs recoverable or refundable through rate adjustments

Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within a period ranging from 12 to 28 months from the time such costs are paid. Natural gas costs refundable through rate adjustments were $16.9 million and $35.3 million at December 31, 2013 and 2012, respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $12.1 million and $3.0 million at December 31, 2013 and 2012, respectively, which is included in prepayments and other current assets.

Insurance

Certain subsidiaries of the Company are insured for workers' compensation losses, subject to deductibles ranging up to $1 million per occurrence. Automobile liability and general liability losses are insured, subject to deductibles ranging up to $1 million per accident or occurrence. These subsidiaries have excess coverage above the primary automobile and general liability policies on a claims first-made and reported basis beyond the deductible levels. The subsidiaries of the Company are retaining losses up to the deductible amounts accrued on the basis of estimates of liability for claims incurred and for claims incurred but not reported.

Income taxes

The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.

The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.

Tax positions taken or expected to be taken in an income tax return are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.

Foreign currency translation adjustment

The functional currency of the Company's investment in ECTE, as discussed in Note 4, is the Brazilian Real. Translation from the Brazilian Real to the U.S. dollar for assets and liabilities is performed using the exchange rate in effect at the balance sheet date. Revenues and expenses are translated on a year-to-date basis using an average of the daily exchange rates.

Transaction gains and losses resulting from the effect of exchange rate changes on transactions denominated in a currency other than the functional currency of the reporting entity would be recorded in income.

Earnings (loss) per common share

Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding stock options and performance share awards. In 2013 and 2011, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the year ended December 31, 2012, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the year. Due to the loss on common stock for the year ended December 31, 2012, the effect of outstanding performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury. Net income (loss) was the same for both the basic and diluted earnings (loss) per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings (loss) per share calculation was as follows:

	2013	2012	2011
	(In thousands)
Weighted average common shares outstanding - basic	188,855	188,826	188,763
Effect of dilutive stock options and performance share awards	838	—	142
Weighted average common shares outstanding - diluted	189,693	188,826	188,905
Shares excluded from the calculation of diluted earnings per share	—	58	—

Use of estimates

The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as impairment testing of long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; oil, NGL and natural gas proved reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Cash flow information

Cash expenditures for interest and income taxes for the years ended December 31 were as follows:

	2013		2012		2011
	(In thousands)
Interest, net of amount capitalized	$	81,689	$	74,378	$	78,133
Income taxes paid (refunded), net	$	24,857	$	3,277	$	(12,287	)

Noncash investing transactions at December 31 were as follows:

	2013		2012		2011
	(In thousands)
Property, plant and equipment additions in accounts payable	$	67,129	$	76,205	$	41,540

New accounting standards

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income In February 2013, the FASB issued guidance on the reporting of amounts reclassified out of accumulated other comprehensive income. This guidance requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. Entities may present this information either on the face of the statement where net income is presented or in the notes. This guidance was effective for the Company on January 1, 2013, and is to be applied prospectively. The guidance required additional disclosures, however it did not impact the Company's results of operations, financial position or cash flows.

Disclosures about Offsetting Assets and Liabilities In December 2011, the FASB issued guidance on the disclosure requirements related to balance sheet offsetting. The new disclosure requirements relate to the nature of an entity's rights of offset and related arrangements associated with its financial instruments and derivative instruments. In January 2013, the FASB issued guidance clarifying the scope of the disclosures related to balance sheet offsetting. The amendments clarify that this guidance only applies to derivative instruments, repurchase agreements and securities lending transactions that are either offset or subject to an enforceable master netting arrangement. The guidance was effective for the Company on January 1, 2013, and must be applied retrospectively. The guidance required additional disclosures, however it did not impact the Company's results of operations, financial position or cash flows.

Variable interest entities

The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.

A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.

The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement.

Comprehensive income (loss)

Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges, postretirement liability adjustments, foreign currency translation adjustments and gains (losses) on available-for-sale investments. For more information on derivative instruments, see Note 7.

The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2013, 2012 and 2011, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency  Translation  Adjustment			Net Unrealized Gains on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2011	$	6,275		$	(53,320	)	$	(38	)	$	82		$	(47,001	)
Current-period other comprehensive income (loss)	(257		)	(1,027		)	(473		)	37			(1,720		)
Balance at December 31, 2012	6,018			(54,347		)	(511		)	119			(48,721		)
Other comprehensive income (loss) before reclassifications	(5,594		)	18,539			(299		)	(194		)	12,452
Amounts reclassified from accumulated other comprehensive loss	(4,189		)	2,001			143			109			(1,936		)
Net current-period other comprehensive income (loss)	(9,783		)	20,540			(156		)	(85		)	10,516
Balance at December 31, 2013	$	(3,765	)	$	(33,807	)	$	(667	)	$	34		$	(38,205	)

Reclassifications out of accumulated other comprehensive loss for the year ended December 31 were as follows:

	2013			Location on Consolidated Statements of Income
	(In thousands)
Reclassification adjustment for gain (loss) on derivative instruments included in net income:
Commodity derivative instruments	$	7,803		Operating revenues
Interest rate derivative instruments	(1,066		)	Interest expense
	6,737
	(2,548		)	Income taxes
	4,189
Amortization of postretirement liability losses included in net periodic benefit cost	(3,277		)	(a)
	1,276			Income taxes
	(2,001		)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income	(213		)	Earnings (loss) from equity method investments
	70			Earnings (loss) from equity method investments
	(143		)
Reclassification adjustment for loss on available-for-sale investments included in net income	(168		)	Other income
	59			Income taxes
	(109		)
Total reclassifications	$	1,936

(a) Included in net periodic benefit cost (credit). For more information, see Note 16.

XML

Summary of significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Basis of presentation

Basis of presentation

The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline and energy services, exploration and production, construction materials and contracting, construction services and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Exploration and production, construction materials and contracting, construction services and other are nonregulated. For further descriptions of the Company's businesses, see Note 15. Intercompany balances and transactions have been eliminated in consolidation, except for certain transactions related to the Company's regulated operations in accordance with GAAP. The statements also include the ownership interests in the assets, liabilities and expenses of jointly owned electric generating facilities.

The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by the Company's nonregulated businesses.

The Company's regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals.

Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.

Management has also evaluated the impact of events occurring after December 31, 2013, up to the date of issuance of these consolidated financial statements.

Cash and cash equivalents

Cash and cash equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts receivable and allowance for doubtful accounts

Accounts receivable and allowance for doubtful accounts

Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. For more information, see Percentage-of-completion method in this note. The total balance of receivables past due 90 days or more was $36.4 million and $34.3 million as of December 31, 2013 and 2012, 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 as of December 31, 2013 and 2012, was $10.1 million and $10.8 million, respectively.

Inventories and natural gas in storage

Inventories and natural gas in storage

Inventories, other than natural gas in storage for the Company's regulated operations, were stated at the lower of average cost or market value. Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories. Inventories at December 31 consisted of:

	2013		2012
	(In thousands)
Aggregates held for resale	$	101,568	$	87,715
Materials and supplies	69,808		69,390
Asphalt oil	38,099		67,480
Merchandise for resale	21,720		31,172
Natural gas in storage (current)	16,417		29,030
Other	34,779		32,628
Total	$	282,391	$	317,415

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 $48.3 million and $49.7 million at December 31, 2013 and 2012, respectively.

Investments

Investments

The Company's investments include its equity method and cost method investments as discussed in Note 4, the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company measures its investment in the insurance contract at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated other comprehensive income (loss). For more information, see Notes 8 and 16.

Property, plant and equipment

Property, plant and equipment

Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for exploration and production properties as described in Oil and natural gas properties in this note, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, at the exploration and production segment only on costs that have been excluded from the full cost amortization pool and on certain construction projects associated with its other operations. The amount of AFUDC and interest capitalized for the years ended December 31 were as follows:

	2013		2012		2011
	(In thousands)
Interest capitalized	$	6,033	$	8,659	$	10,821
AFUDC - borrowed	$	2,767	$	2,483	$	1,666
AFUDC - equity	$	3,322	$	4,530	$	2,587

Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable aggregate reserves, which are depleted based on the units-of-production method, and exploration and production properties, which are amortized on the units-of-production method based on total proved reserves. The Company collects removal costs for plant assets in regulated utility rates. These amounts are recorded as regulatory liabilities, which are included in other liabilities.

Property, plant and equipment at December 31 was as follows:

	2013			2012		Weighted Average Depreciable Life in  Years
	(Dollars in thousands, where applicable)
Regulated:
Electric:
Generation	$	570,394		$	546,011	42
Distribution	308,202			276,446		39
Transmission	196,824			180,543		48
Construction in progress	141,365			62,123		-
Other	99,037			85,461		14
Natural gas distribution:
Distribution	1,384,587			1,308,314		40
Construction in progress	46,763			71,679		-
Other	345,551			309,957		25
Pipeline and energy services:
Transmission	418,594			403,126		52
Gathering	39,597			42,420		19
Storage	42,939			42,058		51
Construction in progress	6,937			13,667		-
Other	39,504			38,386		29
Nonregulated:
Pipeline and energy services:
Midstream	213,063			233,840		17
Construction in progress	188,641			29,657		-
Other	12,897			13,379		11
Exploration and production:
Oil and natural gas properties	3,017,879			2,723,356		*
Other	42,969			41,204		8
Construction materials and contracting:
Land	125,551			126,788		-
Buildings and improvements	70,000			73,884		19
Machinery, vehicles and equipment	906,774			899,592		12
Construction in progress	13,315			11,165		-
Aggregate reserves	394,715			393,552		**
Construction services:
Land	4,821			4,723		-
Buildings and improvements	16,628			16,563		20
Machinery, vehicles and equipment	105,991			100,445		6
Other	7,508			8,893		4
Other:
Land	2,837			2,837		-
Other	47,160			47,682		23
Eliminations	(7,177		)	—
Less accumulated depreciation, depletion and amortization	3,872,487			3,608,912
Net property, plant and equipment	$	4,931,379		$	4,498,839

  *  Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $17.41, $15.28 and $12.25 for the years ended December 31, 2013, 2012 and 2011, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $124.9 million and $191.8 million were excluded from amortization at December 31, 2013 and 2012, respectively.

** Depleted on the units-of-production method.

Impairment of long-lived assets

Impairment of long-lived assets

The Company reviews the carrying values of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. In 2013 and 2012, the Company recognized impairments of $9.0 million (after tax) and $1.7 million (after tax), respectively, which are recorded in operation and maintenance expense on the Consolidated Statements of Income. The impairments are related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a significant decline in natural gas development and production activity largely due to low natural gas prices. The coalbed natural gas gathering assets were written down to fair value that was determined using the income approach. For more information on this nonrecurring fair value measurement, see Note 8.

No significant impairment losses were recorded in 2011. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.

Goodwill

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired.

The goodwill impairment test is a two-step process performed at the reporting unit level. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. For more information on the Company's operating segments, see Note 15. The first step of the impairment test involves comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the years ended December 31, 2013, 2012 and 2011, there were no impairment losses recorded. At December 31, 2013, 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 10 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 2013. Under the market approach, the Company estimates fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants. The Company believes that the estimates and assumptions used in its impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.

Oil and natural gas properties

Oil and natural gas properties

The Company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized.

Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash outflows associated with asset retirement obligations that have been accrued on the balance sheet. If capitalized costs, less accumulated amortization and related deferred income taxes, exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.

At December 31, 2013, the Company's full-cost ceiling exceeded the Company's capitalized cost. However, there is risk that lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in additional future noncash write-downs of the Company's oil and natural gas properties.

The Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at September 30, 2012 and December 31, 2012. SEC Defined Prices, adjusted for market differentials, are used to calculate the ceiling test. SEC Defined Prices as of September 30, 2012 and December 31, 2012, were $94.97 per Bbl for NYMEX oil and $2.83 per MMBtu for Henry Hub natural gas and $94.71 per Bbl for NYMEX oil and $2.76 per MMBtu for Henry Hub natural gas, respectively. Accordingly, the Company was required to write down its oil and natural gas producing properties. The noncash write-downs amounted to $160.1 million and $231.7 million ($100.9 million and $145.9 million after tax) for the three months ended September 30, 2012 and December 31, 2012, respectively.

The Company hedged a portion of its oil and natural gas production and the effects of the cash flow hedges were used in determining the full-cost ceiling at September 30, 2012 and December 31, 2012. The Company would have recognized additional write-downs of its oil and natural gas properties of $19.5 million ($12.3 million after tax) at September 30, 2012, and $20.8 million ($13.1 million after tax) at December 31, 2012, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 7.

The following table summarizes the Company's oil and natural gas properties not subject to amortization at December 31, 2013, in total and by the year in which such costs were incurred:

			Year Costs Incurred
	Total		2013		2012		2011		2010 and prior
	(In thousands)
Acquisition	$	93,758	$	1,514	$	23,588	$	28,543	$	40,113
Development	14,824		12,622		1,633		271		298
Exploration	14,547		9,952		4,346		198		51
Capitalized interest	1,740		340		418		410		572
Total costs not subject to amortization	$	124,869	$	24,428	$	29,985	$	29,422	$	41,034

Costs not subject to amortization as of December 31, 2013, consisted primarily of unevaluated leaseholds and development costs in the Bakken area, Texas properties and the Paradox Basin. The Company expects that the majority of these costs will be evaluated within the next five years and included in the amortization base as the properties are evaluated and/or developed.

Revenue recognition

Revenue recognition

Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is reasonably assured. The Company recognizes utility revenue each month based on the services provided to all utility customers during the month. Accrued unbilled revenue which is included in receivables, net, represents revenues recognized in excess of amounts billed. Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain was $107.4 million and $85.9 million at December 31, 2013 and 2012, 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:

	2013		2012
	(In thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	60,828	$	64,996
Billings in excess of costs and estimated earnings on uncompleted contracts	$	84,189	$	83,167

Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31, were as follows:

	2013		2012
	(In thousands)
Short-term retainage *	$	55,906	$	54,256
Long-term retainage **	4,229		2,038
Total retainage	$	60,135	$	56,294

  * 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, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions, and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties.

The Company's policy generally allows the hedging of monthly forecasted sales of oil and natural gas production at Fidelity for a period up to 42 months from the time the Company enters into the hedge. The Company's policy requires that interest rate derivative instruments not exceed a period of 24 months and foreign currency derivative instruments not exceed a 12-month period. The Company's policy allows the hedging of monthly forecasted purchases of natural gas at Cascade and Intermountain for a period up to three years.

The Company's policy requires that each month as physical oil and natural gas production at Fidelity occurs and the commodity is sold, the related portion of the derivative agreement for that month's production must settle with its counterparties. Settlements represent the exchange of cash between the Company and its counterparties based on the notional quantities and prices for each month's physical delivery as specified within the agreements. The fair value of the remaining notional amounts on the derivative agreements is recorded on the balance sheet as an asset or liability measured at fair value. The Company's policy also requires settlement of natural gas derivative instruments at Cascade and Intermountain monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days, and any foreign currency derivative transaction settlement periods may not exceed a 12-month period. The Company has policies and procedures that management believes minimize credit-risk exposure. Accordingly, the Company does not anticipate any material effect on its financial position or results of operations as a result of nonperformance by counterparties. For more information on derivative instruments, see Note 7.

The Company's derivative instruments are reflected at fair value. For more information, see Note 8.

Asset retirement obligations

Asset retirement obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its nonregulated operations or incurs a regulatory asset or liability at its regulated operations. For more information on asset retirement obligations, see Note 10.

Legal costs

Legal costs

The Company expenses external legal fees as they are incurred.

Natural gas costs recoverable or refundable through rate adjustments

Natural gas costs recoverable or refundable through rate adjustments

Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within a period ranging from 12 to 28 months from the time such costs are paid. Natural gas costs refundable through rate adjustments were $16.9 million and $35.3 million at December 31, 2013 and 2012, respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $12.1 million and $3.0 million at December 31, 2013 and 2012, respectively, which is included in prepayments and other current assets.

Insurance

Insurance

Certain subsidiaries of the Company are insured for workers' compensation losses, subject to deductibles ranging up to $1 million per occurrence. Automobile liability and general liability losses are insured, subject to deductibles ranging up to $1 million per accident or occurrence. These subsidiaries have excess coverage above the primary automobile and general liability policies on a claims first-made and reported basis beyond the deductible levels. The subsidiaries of the Company are retaining losses up to the deductible amounts accrued on the basis of estimates of liability for claims incurred and for claims incurred but not reported.

Income taxes

Income taxes

The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.

The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.

Tax positions taken or expected to be taken in an income tax return are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.

Foreign currency translation adjustment

Foreign currency translation adjustment

The functional currency of the Company's investment in ECTE, as discussed in Note 4, is the Brazilian Real. Translation from the Brazilian Real to the U.S. dollar for assets and liabilities is performed using the exchange rate in effect at the balance sheet date. Revenues and expenses are translated on a year-to-date basis using an average of the daily exchange rates.

Transaction gains and losses resulting from the effect of exchange rate changes on transactions denominated in a currency other than the functional currency of the reporting entity would be recorded in income.

Earnings (loss) per common share

Earnings (loss) per common share

Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding stock options and performance share awards. In 2013 and 2011, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the year ended December 31, 2012, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the year. Due to the loss on common stock for the year ended December 31, 2012, the effect of outstanding performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury. Net income (loss) was the same for both the basic and diluted earnings (loss) per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings (loss) per share calculation was as follows:

	2013	2012	2011
	(In thousands)
Weighted average common shares outstanding - basic	188,855	188,826	188,763
Effect of dilutive stock options and performance share awards	838	—	142
Weighted average common shares outstanding - diluted	189,693	188,826	188,905
Shares excluded from the calculation of diluted earnings per share	—	58	—

Use of estimates

Use of estimates

The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as impairment testing of long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; oil, NGL and natural gas proved reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Cash flow information

Cash flow information

Cash expenditures for interest and income taxes for the years ended December 31 were as follows:

	2013		2012		2011
	(In thousands)
Interest, net of amount capitalized	$	81,689	$	74,378	$	78,133
Income taxes paid (refunded), net	$	24,857	$	3,277	$	(12,287	)

Noncash investing transactions at December 31 were as follows:

	2013		2012		2011
	(In thousands)
Property, plant and equipment additions in accounts payable	$	67,129	$	76,205	$	41,540

New accounting standards

New accounting standards

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income In February 2013, the FASB issued guidance on the reporting of amounts reclassified out of accumulated other comprehensive income. This guidance requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. Entities may present this information either on the face of the statement where net income is presented or in the notes. This guidance was effective for the Company on January 1, 2013, and is to be applied prospectively. The guidance required additional disclosures, however it did not impact the Company's results of operations, financial position or cash flows.

Disclosures about Offsetting Assets and Liabilities In December 2011, the FASB issued guidance on the disclosure requirements related to balance sheet offsetting. The new disclosure requirements relate to the nature of an entity's rights of offset and related arrangements associated with its financial instruments and derivative instruments. In January 2013, the FASB issued guidance clarifying the scope of the disclosures related to balance sheet offsetting. The amendments clarify that this guidance only applies to derivative instruments, repurchase agreements and securities lending transactions that are either offset or subject to an enforceable master netting arrangement. The guidance was effective for the Company on January 1, 2013, and must be applied retrospectively. The guidance required additional disclosures, however it did not impact the Company's results of operations, financial position or cash flows.

Variable interest entities

Variable interest entities

The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.

A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.

The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement.

Comprehensive income (loss)

Comprehensive income (loss)

Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges, postretirement liability adjustments, foreign currency translation adjustments and gains (losses) on available-for-sale investments. For more information on derivative instruments, see Note 7.

The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2013, 2012 and 2011, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency  Translation  Adjustment			Net Unrealized Gains on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2011	$	6,275		$	(53,320	)	$	(38	)	$	82		$	(47,001	)
Current-period other comprehensive income (loss)	(257		)	(1,027		)	(473		)	37			(1,720		)
Balance at December 31, 2012	6,018			(54,347		)	(511		)	119			(48,721		)
Other comprehensive income (loss) before reclassifications	(5,594		)	18,539			(299		)	(194		)	12,452
Amounts reclassified from accumulated other comprehensive loss	(4,189		)	2,001			143			109			(1,936		)
Net current-period other comprehensive income (loss)	(9,783		)	20,540			(156		)	(85		)	10,516
Balance at December 31, 2013	$	(3,765	)	$	(33,807	)	$	(667	)	$	34		$	(38,205	)

Reclassifications out of accumulated other comprehensive loss for the year ended December 31 were as follows:

	2013			Location on Consolidated Statements of Income
	(In thousands)
Reclassification adjustment for gain (loss) on derivative instruments included in net income:
Commodity derivative instruments	$	7,803		Operating revenues
Interest rate derivative instruments	(1,066		)	Interest expense
	6,737
	(2,548		)	Income taxes
	4,189
Amortization of postretirement liability losses included in net periodic benefit cost	(3,277		)	(a)
	1,276			Income taxes
	(2,001		)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income	(213		)	Earnings (loss) from equity method investments
	70			Earnings (loss) from equity method investments
	(143		)
Reclassification adjustment for loss on available-for-sale investments included in net income	(168		)	Other income
	59			Income taxes
	(109		)
Total reclassifications	$	1,936

(a) Included in net periodic benefit cost (credit). For more information, see Note 16.

XML

Preferred Stocks (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Class of Stock [Line Items]
Preferred stock redemption price upon liquidation (in dollars per share)	$ 100
Preferred stocks	$ 15,000	$ 15,000
Cumulative Preferred Stock, Par Value $100 Issuable in Series [Member]
Class of Stock [Line Items]
Authorized preferred cumulative shares (in shares)	500,000	500,000
Cumulative preferred shares, par value (in dollars per share)	$ 100.00	$ 100.00
Preferred stock, series 4.50% [Member]
Class of Stock [Line Items]
Preferred stock redemption price at the option of the company (in dollars per share)	$ 105
Preferred stocks	10,000	10,000
Preferred shares outstanding (in shares)	100,000	100,000
Preferred stock, $100 par value	4.50%	4.50%	4.50%
Preferred stock, dividends per share, declared	$ 4.50	$ 4.50	$ 4.50
Preferred stock, series 4.70% [Member]
Class of Stock [Line Items]
Preferred stock redemption price at the option of the company (in dollars per share)	$ 102
Preferred stocks	$ 5,000	$ 5,000
Preferred shares outstanding (in shares)	50,000	50,000
Preferred stock, $100 par value	4.70%	4.70%	4.70%
Preferred stock, dividends per share, declared	$ 4.70	$ 4.70	$ 4.70
Cumulative preferred stock A, without par value, issuable in series [Member]
Class of Stock [Line Items]
Authorized preferred cumulative shares (in shares)	1,000,000	1,000,000
Cumulative preference stock , without par value, issuable in series [Member]
Class of Stock [Line Items]
Authorized preferred cumulative shares (in shares)	500,000	500,000

XML

Enviromental matters (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013
Portland Harbor Site [Member]
Site Contingency [Line Items]
Environmental matters investigative costs	$ 70,000,000
Eugene, OR Manufactured Gas Plant Site [Member]
Site Contingency [Line Items]
Site contingency, low estimate, loss exposure	500,000
Site contingency, high estimate, loss exposure	11,000,000
Estimated Proportional Share Of Cleanup Liability	50.00%
Accrual for Environmental Loss Contingencies	1,300,000
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	12,000,000
Bellingham, WA Manufactured Gas Plant Site [Member]
Site Contingency [Line Items]
Site contingency, loss exposure not accrued, best estimate	$ 8,000,000

XML

Preferred Stocks (Tables)

12 Months Ended

Dec. 31, 2013

Preferred Stocks [Abstract]

Preferred stock

Preferred stocks at December 31 were as follows:

	2013		2012
(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

XML

Goodwill (Details 5)	3 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]
Fair value inputs discount rate, range bottom	5.00%
Fair value inputs, discount rate, range top	10.00%
Long-term growth rate projections	3.00%

XML

Derivative Instruments Gains and losses on derivative instruments (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	$ (5,594)	$ 8,497	$ 7,900
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	(4,189)	(8,754)	0
Commodity derivatives designated as cash flow hedges:
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	(6,153)	10,209	10,806
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	(4,916)	(8,788)	0
Amount of gain (loss) recognized in income statement (ineffective portion), before tax	(1,422)	(730)	1,827
Interest rate derivatives designated as cash flow hedges:
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	559	(1,712)	(2,906)
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	727	34	0
Amount of gain (loss) recognized in income statement (ineffective portion), before tax	(769)	0	0
Commodity derivatives not designated as hedging instruments:
Derivative instruments [Line Items]
Amount of gain (loss) recognized in operating revenues, before tax	$ (4,845)	$ 106	$ 0

XML

Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$ 1,264,574		$ 1,131,626		$ 1,343,714
Exploration and production, construction materials and contracting, construction services and other	3,197,830		2,943,805		2,706,778
Total operating revenues	4,462,404		4,075,431		4,050,492
Operating expenses:
Fuel and purchased power	83,528		72,380		64,485
Purchased natural gas sold	505,065		425,220		572,187
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services	269,825		254,194		275,866
Exploration and production, construction materials and contracting, construction services and other	2,535,872		2,377,285		2,215,269
Depreciation, depletion and amortization	386,856		359,205		343,395
Taxes, other than income	188,359		176,140		172,923
Write-downs of oil and natural gas properties (Note 1)	0		391,800		0
Total operating expenses	3,969,505		4,056,224		3,644,125
Operating income	492,899		19,207		406,367
Earnings (loss) from equity method investments	(132)		5,383		4,693
Other income	6,768		6,642		6,520
Interest expense	83,917		76,699		81,354
Income (loss) before income taxes	415,618		(45,467)		336,226
Income taxes	136,736		(31,146)		110,274
Income (loss) from continuing operations	278,882		(14,321)		225,952
Income (loss) from discontinued operations, net of tax (Note 3)	(312)	[1]	13,567	[1]	(12,926)	[1]
Net income (loss)	278,570		(754)		213,026
Net loss attributable to noncontrolling interest	(363)		0		0
Dividends declared on preferred stocks	685		685		685
Earnings (loss) on common stock	$ 278,248		$ (1,439)		$ 212,341
Earnings (loss) per common share - basic:
Earnings (loss) before discontinued operations	$ 1.47		$ (0.08)		$ 1.19
Discontinued operations, net of tax	$ 0.00		$ 0.07		$ (0.07)
Earnings (loss) per common share - basic	$ 1.47		$ (0.01)		$ 1.12
Earnings (loss) per common share - diluted:
Earnings (loss) before discontinued operations	$ 1.47		$ (0.08)		$ 1.19
Discontinued operations, net of tax	$ 0.00		$ 0.07		$ (0.07)
Earnings (loss) per common share - diluted	$ 1.47		$ (0.01)		$ 1.12
Weighted average common shares outstanding - basic	188,855		188,826		188,763
Weighted average common shares outstanding - diluted	189,693		188,826		188,905

[1] Reflected in the Other category.

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Jointly owned facilities (Tables)

12 Months Ended

Dec. 31, 2013

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:

	2013		2012
	(In thousands)
Big Stone Station:
Utility plant in service	$	63,890	$	63,146
Less accumulated depreciation	41,323		40,859
	$	22,567	$	22,287
Coyote Station:
Utility plant in service	$	138,261	$	135,073
Less accumulated depreciation	89,528		87,524
	$	48,733	$	47,549
Wygen III:
Utility plant in service	$	64,332	$	63,462
Less accumulated depreciation	4,639		3,368
	$	59,693	$	60,094

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Change in benefit obligations and plan assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	$ 459,111	$ 435,618
Service cost	155	1,078	2,252
Interest cost	16,249	17,598	19,500
Plan participants' contributions	0	0
Amendments	0	0
Actuarial (gain) loss	(44,551)	30,939
Benefits paid	(28,192)	(26,122)
Benefit obligation at end of year	402,772	459,111	435,618
Change in net plan assets:
Fair value of plan assets at beginning of year	309,184	278,000
Actual gain on plan assets	35,539	34,493
Employer contribution	18,313	22,813
Plan participants' contributions	0	0
Benefits paid	(28,192)	(26,122)
Fair value of net plan assets at end of year	334,844	309,184	278,000
Funded status - (under) over	(67,928)	(149,927)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	0	0
Other accrued liabilities (current)	0	0
Other liabilities (noncurrent)	(67,928)	(149,927)
Net amount recognized	(67,928)	(149,927)
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	135,061	202,406
Prior service cost (credit)	365	437
Total	135,426	202,843
Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	103,358	110,689
Service cost	1,675	1,747	1,443
Interest cost	3,215	4,166	4,700
Plan participants' contributions	1,472	2,688
Amendments	0	(11,418)
Actuarial (gain) loss	(20,985)	3,469
Benefits paid	(7,009)	(7,983)
Benefit obligation at end of year	81,726	103,358	110,689
Change in net plan assets:
Fair value of plan assets at beginning of year	74,361	68,085
Actual gain on plan assets	13,819	6,497
Employer contribution	1,900	5,074
Plan participants' contributions	1,472	2,688
Benefits paid	(7,009)	(7,983)
Fair value of net plan assets at end of year	84,543	74,361	68,085
Funded status - (under) over	2,817	(28,997)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	9,679	0
Other accrued liabilities (current)	(381)	(655)
Other liabilities (noncurrent)	(6,481)	(28,342)
Net amount recognized	(2,817)	(28,997)
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	11,314	43,589
Prior service cost (credit)	(17,137)	(18,594)
Total	$ (5,823)	$ 24,995

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Commitments, contingencies and litigation (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2011 Litigation related to construction materials [Member]	Jun. 30, 2012 Natural gas gathering operations [Member]	Oct. 31, 2010 Natural gas gathering operations [Member]	Sep. 30, 2010 Natural gas gathering operations [Member]	Jan. 13, 2012 Guarantee obligation under construction contract [Member]	Dec. 31, 2009 Guarantee obligation under construction contract [Member]
Loss Contingencies [Line Items]
Potential liabilities related to litigation and environmental matters	$ 29,500,000	$ 22,500,000
Amount of compensatory damages in LPP's notice of demand								149,700,000
Arbitration award					26,600,000		22,000,000
Amount of expense (benefit) recorded in operation and maintenance expense related to natural gas gathering contract dispute, before tax				(24,100,000)		26,600,000
Amount of expense (benefit) recorded in operation and maintenance expense related to natural gas gathering contract dispute, after tax				(15,000,000)		16,500,000
Loss contingency, estimate of possible loss			3,700,000
Additional amount per day of potential penalties			$ 5,000

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Consolidated Statements of Equity (USD $) In Thousands, except Share data	Total	Preferred stock	Common Stock	Other Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Treasury Stock	Noncontrolling interest
Balance at Dec. 31, 2010	$ 2,692,802	$ 15,000	$ 188,901	$ 1,026,349	$ 1,497,439	$ (31,261)	$ (3,626)
Balance (in shares) at Dec. 31, 2010		150,000
Balance (in shares) at Dec. 31, 2010			188,901,379
Treasury stock (in shares) at Dec. 31, 2010							(538,921)
Net income (loss) attributable to parent					213,026
Net loss attributable to noncontrolling interest	0
Net income (loss)	213,026
Other comprehensive income	(15,740)					(15,740)
Dividends declared on preferred stocks	(685)				(685)
Dividends declared on common stock	(123,657)				(123,657)
Stock-based compensation - shares			423,591
Stock-based compensation	10,588		424	10,164
Tax benefit (deficit) on stock-based compensation	(909)			(909)
Issuance of common stock - shares			7,515
Issuance of common stock	142		7	135
Balance at Dec. 31, 2011	2,775,567	15,000	189,332	1,035,739	1,586,123	(47,001)	(3,626)
Balance (in shares) at Dec. 31, 2011		150,000
Treasury stock (in shares) at Dec. 31, 2011							(538,921)
Balance (in shares) at Dec. 31, 2011			189,332,485
Net income (loss) attributable to parent					(754)
Net loss attributable to noncontrolling interest	0
Net income (loss)	(754)
Other comprehensive income	(1,720)					(1,720)
Dividends declared on preferred stocks	(685)				(685)
Dividends declared on common stock	(127,538)				(127,538)
Stock-based compensation - shares			25,743
Stock-based compensation	5,120		26	5,094
Tax benefit (deficit) on stock-based compensation	(1,958)			(1,958)
Issuance of common stock - shares			11,222
Issuance of common stock	216		11	205
Balance at Dec. 31, 2012	2,648,248	15,000	189,369	1,039,080	1,457,146	(48,721)	(3,626)
Balance (in shares) at Dec. 31, 2012		150,000
Treasury stock (in shares) at Dec. 31, 2012	(538,921)						(538,921)
Balance (in shares) at Dec. 31, 2012	189,369,450		189,369,450
Net income (loss) attributable to parent					278,933
Net loss attributable to noncontrolling interest	(363)							(363)
Net income (loss)	278,570
Other comprehensive income	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
Tax benefit (deficit) on stock-based compensation	(1,419)			(1,419)
Issuance of common stock - shares			499,330
Issuance of common stock	14,554		500	14,054
Contribution from non-controlling interest	33,101							33,101
Balance at Dec. 31, 2013	$ 2,855,902	$ 15,000	$ 189,869	$ 1,056,996	$ 1,603,130	$ (38,205)	$ (3,626)	$ 32,738
Balance (in shares) at Dec. 31, 2013		150,000
Treasury stock (in shares) at Dec. 31, 2013	(538,921)						(538,921)
Balance (in shares) at Dec. 31, 2013	189,868,780		189,868,780

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Unrecognized tax benefits (Details 6) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 14,914,000	$ 11,206,000	$ 9,378,000
Additions for tax positions of prior years	0	3,708,000	4,172,000
Settlements	0	0	(2,344,000)
Balance at end of year	14,914,000	14,914,000	11,206,000
Unrecognized tax benefits highly certain deductibility	8,400,000	8,400,000
Unrecognized tax benefits that would affect the effective tax rate	9,000,000	8,500,000
Unrecognized tax benefits, interest and penalties	2,500,000	2,000,000
Interest expense	1,200,000	740,000	780,000
Interest income	660,000	290,000	1,900,000
Accrued liability for payment of interest	$ 2,800,000	$ 1,400,000

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Insurance (Details 11) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Accounting Policies [Abstract]
Maximum amount of deductibles for workers' compensation insurance per occurrence	$ 1
Maximum amount of deductibles for automobile liability and general liability insurance per accident or occurrence	$ 1

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Estimated net loss and prior service credit (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, amortization of net gains (losses)	$ (4,800,000)
Defined benefit plan, amortization of net prior service cost (credit)	71,000
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, amortization of net gains (losses)	(793,000)
Defined benefit plan, amortization of net prior service cost (credit)	$ (1,400,000)

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Regulatory assets and liabilities (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory assets and liabilities

The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:

	Estimated Recovery Period	*	2013			2012
			(In thousands)
Regulatory assets:
Deferred income taxes	**		$	125,607		$	121,781
Pension and postretirement benefits (a)	(e)		105,123			166,477
Taxes recoverable from customers (a)	Over plant lives		18,266			9,078
Manufactured gas plant sites remediation (a)	Up to 4 years		15,797			15,828
Natural gas costs recoverable through rate adjustments (b)	Up to 28 months		12,060			2,981
Long-term debt refinancing costs (a)	Up to 25 years		8,697			9,144
Costs related to identifying generation development (a)	Up to 13 years		4,512			5,773
Other (a) (b)	Largely within 1- 5 years		15,311			20,132
Total regulatory assets			305,373			351,194
Regulatory liabilities:
Plant removal and decommissioning costs (c)			308,431			296,037
Deferred income taxes**			64,914			82,077
Taxes refundable to customers (c)			20,180			24,212
Natural gas costs refundable through rate adjustments (d)			16,932			35,328
Other (c) (d)			21,868			12,828
Total regulatory liabilities			432,325			450,482
Net regulatory position			$	(126,952	)	$	(99,288	)

  * Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.

** Represents deferred income taxes related to regulatory assets and liabilities. The deferred income tax assets are not earning a rate of return.

(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.

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Notes to Condensed Financial Statements (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
2014	$ 12,300,000
2015	269,400,000
2016	293,800,000
2017	204,900,000
2018	130,200,000
Thereafter	944,000,000
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Long-term debt	434,700,000
2014	100,000
2015	100,000
2016	50,100,000
2017	79,000,000
2018	100,000,000
Thereafter	205,400,000
Cash dividends paid to parent company by consolidated subsidiaries	$ 77,600,000	$ 125,800,000	$ 96,100,000

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Acquisitions (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Business Combinations [Abstract]
Percent of undivided interest acquired	50.00%
Business acquisitions	$ 67,500,000	$ 298,000

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Business segment data

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Business segment data

Business Segment Data

The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The internal reporting of these operating segments is defined based on the reporting and review process used by the Company's chief executive officer. The vast majority of the Company's operations are located within the United States. The Company also has an investment in a foreign country, which consists of Centennial Resources' investment in ECTE.

The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added services.

The pipeline and energy services segment provides natural gas transportation, underground storage, processing and gathering services, as well as oil gathering, through regulated and nonregulated pipeline systems and processing facilities primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment is constructing Dakota Prairie Refinery in conjunction with Calumet to refine crude oil and also provides cathodic protection and other energy-related services.

The exploration and production segment is engaged in oil and natural gas acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent/Gulf States 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 specializes in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment.

The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies' general liability, automobile liability and pollution liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' investment in ECTE.

The information below follows the same accounting policies as described in the Summary of Significant Accounting Policies. Information on the Company's businesses as of December 31 and for the years then ended was as follows:

	2013			2012			2011
	(In thousands)
External operating revenues:
Electric	$	257,260		$	236,895		$	225,468
Natural gas distribution	851,945			754,848			907,400
Pipeline and energy services	155,369			139,883			210,846
	1,264,574			1,131,626			1,343,714
Exploration and production	490,924			412,651			359,873
Construction materials and contracting	1,675,444			1,597,257			1,509,538
Construction services	1,029,909			932,013			834,918
Other	1,553			1,884			2,449
	3,197,830			2,943,805			2,706,778
Total external operating revenues	$	4,462,404		$	4,075,431		$	4,050,492
Intersegment operating revenues:
Electric	$	—		$	—		$	—
Natural gas distribution	—			—			—
Pipeline and energy services	46,699			53,274			67,497
Exploration and production	45,099			35,966			93,713
Construction materials and contracting	36,693			20,168			472
Construction services	9,930			6,545			19,471
Other	8,067			8,486			8,997
Intersegment eliminations	(146,488		)	(124,439		)	(190,150		)
Total intersegment operating revenues	$	—		$	—		$	—
Depreciation, depletion and amortization:
Electric	$	32,789		$	32,509		$	32,177
Natural gas distribution	50,031			45,731			44,641
Pipeline and energy services	29,119			27,684			25,502
Exploration and production	186,458			160,681			142,645
Construction materials and contracting	74,470			79,527			85,459
Construction services	11,939			11,063			11,399
Other	2,050			2,010			1,572
Total depreciation, depletion and amortization	$	386,856		$	359,205		$	343,395
Interest expense:
Electric	$	12,590		$	12,421		$	13,745
Natural gas distribution	25,123			28,726			29,444
Pipeline and energy services	10,330			7,742			10,516
Exploration and production	14,315			9,018			7,445
Construction materials and contracting	17,394			15,211			16,241
Construction services	4,306			4,435			4,473
Other	15			13			—
Intersegment eliminations	(156		)	(867		)	(510		)
Total interest expense	$	83,917		$	76,699		$	81,354

	2013			2012			2011
	(In thousands)
Income taxes:
Electric	$	9,683		$	8,975		$	7,242
Natural gas distribution	16,633			12,005			16,931
Pipeline and energy services	3,390			15,291			12,912
Exploration and production	53,197			(108,264		)	46,298
Construction materials and contracting	24,765			14,099			11,227
Construction services	29,504			24,128			13,426
Other	2,433			2,620			2,238
Intersegment eliminations	(2,869		)	—			—
Total income taxes	$	136,736		$	(31,146	)	$	110,274
Earnings (loss) on common stock:
Electric	$	34,837		$	30,634		$	29,258
Natural gas distribution	37,656			29,409			38,398
Pipeline and energy services	7,629			26,588			23,082
Exploration and production	94,450			(177,283		)	80,282
Construction materials and contracting	50,946			32,420			26,430
Construction services	52,213			38,429			21,627
Other	5,136			4,797			6,190
Intersegment eliminations	(4,307		)	—			—
Earnings (loss) on common stock before income (loss) from discontinued operations	278,560			(15,006		)	225,267
Income (loss) from discontinued operations, net of tax*	(312		)	13,567			(12,926		)
Total earnings (loss) on common stock	$	278,248		$	(1,439	)	$	212,341
Capital expenditures:
Electric	$	168,557		$	112,035		$	52,072
Natural gas distribution	101,279			130,178			70,624
Pipeline and energy services	127,092			133,787			45,556
Exploration and production	391,315			554,528			272,855
Construction materials and contracting	34,607			45,083			52,303
Construction services	15,102			14,835			9,711
Other	2,249			791			18,759
Net proceeds from sale or disposition of property and other	(112,131		)	(57,460		)	(40,857		)
Total net capital expenditures	$	728,070		$	933,777		$	481,023
Assets:
Electric**	$	884,283		$	760,324		$	672,940
Natural gas distribution**	1,786,068			1,703,459			1,679,091
Pipeline and energy services	798,701			622,470			526,797
Exploration and production	1,616,131			1,539,017			1,481,556
Construction materials and contracting	1,305,808			1,371,252			1,374,026
Construction services	450,614			429,547			418,519
Other***	219,727			256,422			403,196
Total assets	$	7,061,332		$	6,682,491		$	6,556,125

	2013			2012		2011
	(In thousands)
Property, plant and equipment:
Electric**	$	1,315,822		$	1,150,584	$	1,068,524
Natural gas distribution**	1,776,901			1,689,950		1,568,866
Pipeline and energy services	962,172			816,533		719,291
Exploration and production	3,060,848			2,764,560		2,615,146
Construction materials and contracting	1,510,355			1,504,981		1,499,852
Construction services	134,948			130,624		124,796
Other	49,997			50,519		49,747
Eliminations	(7,177		)	—		—
Less accumulated depreciation, depletion and amortization	3,872,487			3,608,912		3,361,208
Net property, plant and equipment	$	4,931,379		$	4,498,839	$	4,285,014

    * Reflected in the Other category.

  ** Includes allocations of common utility property.

*** Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

Note: The results reflect $391.8 million ($246.8 million after tax) of noncash write-downs of oil and natural gas properties in 2012.

Excluding the impairments of the coalbed natural gas gathering assets of $9.0 million (after tax) and $1.7 million (after tax) in 2013 and 2012, respectively, and the reversal of the natural gas gathering arbitration charge of $1.5 million (after tax) and $15.0 million (after tax) in 2013 and 2012, respectively, as discussed in Notes 1 and 19, respectively, earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from exploration and production, construction materials and contracting, construction services and other are all from nonregulated operations.

Capital expenditures for 2013, 2012 and 2011 include noncash capital expenditure-related accounts payable and exclude capital expenditures of the noncontrolling interest related to Dakota Prairie Refinery. The net transactions were $(56.8) million in 2013, $33.7 million in 2012 and $24.0 million in 2011.

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Derivative instruments (Tables)

12 Months Ended

Dec. 31, 2013

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:

	2013			2012			2011
	(In thousands)
Commodity derivatives designated as cash flow hedges:
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	$	(6,153	)	$	10,209		$	10,806
Amount of gain reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax	(4,916		)	(8,788		)	—
Amount of gain (loss) recognized in operating revenues (ineffective portion), before tax	(1,422		)	(730		)	1,827
Interest rate derivatives designated as cash flow hedges:
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	559			(1,712		)	(2,906		)
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax	727			34			—
Amount of loss recognized in interest expense (ineffective portion), before tax	(769		)	—			—
Commodity derivatives not designated as hedging instruments:
Amount of gain (loss) recognized in operating revenues, before tax	(4,845		)	106			—

Derivative instruments

The location and fair value of the Company's derivative instruments on the Consolidated Balance Sheets were as follows:

Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2013		Fair Value at December 31, 2012
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	18,084
		—		18,084
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	1,447		220
	Other assets - noncurrent	503		—
		1,950		220
Total asset derivatives		$	1,950	$	18,304

Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2013		Fair Value at December 31, 2012
		(In thousands)
Designated as hedges:
Interest rate derivatives	Other accrued liabilities	$	—	$	6,255
		—		6,255
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	7,483		—
		7,483		—
Total liability derivatives		$	7,483	$	6,255

Offsetting assets and liabilities master netting

The gross derivative assets and liabilities (excluding settlement receivables and payables that may be subject to the same master netting agreements) presented on the Consolidated Balance Sheets and the amount eligible for offset under the master netting agreements is presented in the following table:

December 31, 2013	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	1,950	$	(1,950	)	$	—
Total assets	$	1,950	$	(1,950	)	$	—
Liabilities:
Commodity derivatives	$	7,483	$	(1,950	)	$	5,533
Total liabilities	$	7,483	$	(1,950	)	$	5,533

December 31, 2012	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets		Net
	(In thousands)
Assets:
Commodity derivatives	$	18,304	$	—	$	18,304
Total assets	$	18,304	$	—	$	18,304
Liabilities:
Interest rate derivatives	$	6,255	$	—	$	6,255
Total liabilities	$	6,255	$	—	$	6,255

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Components of net periodic benefit cost (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 155	$ 1,078	$ 2,252
Interest cost	16,249	17,598	19,500
Expected return on assets	(19,917)	(23,536)	(22,809)
Amortization of prior service cost (credit)	71	(46)	45
Recognized net actuarial loss	7,173	7,070	4,656
Curtailment loss (gain)	0	(1,023)	1,218
Amortization of net transition obligation	0	0	0
Net periodic benefit cost, including amount capitalized	3,731	1,141	4,862
Less amount capitalized	727	937	1,196
Net periodic benefit cost	3,004	204	3,666
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	(60,173)	19,982	76,310
Prior service cost (credit)	0	0	0
Amortization of actuarial loss	(7,173)	(7,070)	(4,656)
Amortization of prior service (cost) credit	(71)	1,069	(1,263)
Amortization of net transition obligation	0	0	0
Total recognized in accumulated other comprehensive (income) loss	(67,417)	13,981	70,391
Total recognized in net periodic benefit cost and accumulated other comprehensive (income) loss	(64,413)	14,185	74,057
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,675	1,747	1,443
Interest cost	3,215	4,166	4,700
Expected return on assets	(4,343)	(4,890)	(5,051)
Amortization of prior service cost (credit)	(1,457)	(1,438)	(2,677)
Recognized net actuarial loss	1,814	2,134	753
Curtailment loss (gain)	0	0	0
Amortization of net transition obligation	0	2,128	2,125
Net periodic benefit cost, including amount capitalized	904	3,847	1,293
Less amount capitalized	164	910	(50)
Net periodic benefit cost	740	2,937	1,343
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	(30,461)	1,863	23,863
Prior service cost (credit)	0	(11,418)	0
Amortization of actuarial loss	(1,814)	(2,134)	(753)
Amortization of prior service (cost) credit	1,457	1,438	2,677
Amortization of net transition obligation	0	(2,128)	(2,125)
Total recognized in accumulated other comprehensive (income) loss	(30,818)	(12,379)	23,662
Total recognized in net periodic benefit cost and accumulated other comprehensive (income) loss	$ (30,078)	$ (9,442)	$ 25,005

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Income resulting from oil and natural gas producing activites (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues:
Sales to affiliates	$ 45,099,000		$ 35,966,000		$ 93,713,000
Sales to external customers	497,018,000		379,647,000		348,428,000
Realized gain on commodity derivatives	173,000		33,628,000		9,618,000
Unrealized (gain) loss on commodity derivatives	(6,267,000)		(624,000)		1,827,000
Production costs	144,136,000		134,795,000		140,606,000
Depreciation, depletion and amortization	182,352,000	[1]	157,078,000	[1]	139,539,000	[1]
Write-downs of oil and natural gas properties	0		391,800,000		0
Pretax income (loss)	209,535,000		(235,056,000)		173,441,000
Income tax expense (benefit)	75,836,000		(88,612,000)		63,655,000
Results of operations for producing activities	133,699,000		(146,444,000)		109,786,000
Accretion of discount for asset retirement obligations oil and gas	$ 3,600,000		$ 3,300,000		$ 3,600,000

[1] Includes accretion of discount for asset retirement obligations of $3.6 million, $3.3 million and $3.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, as discussed in Note 10.

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Jointly owned facilities

12 Months Ended

Dec. 31, 2013

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:

	2013		2012
	(In thousands)
Big Stone Station:
Utility plant in service	$	63,890	$	63,146
Less accumulated depreciation	41,323		40,859
	$	22,567	$	22,287
Coyote Station:
Utility plant in service	$	138,261	$	135,073
Less accumulated depreciation	89,528		87,524
	$	48,733	$	47,549
Wygen III:
Utility plant in service	$	64,332	$	63,462
Less accumulated depreciation	4,639		3,368
	$	59,693	$	60,094

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Goodwill and other intangible assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Goodwill [Roll Forward]
Balance as of beginning of period	$ 636,039	[1]	$ 634,931	[1]
Goodwill acquired during the year	0		1,108
Balance as of end of period	636,039	[1]	636,039	[1]
Natural gas distribution:
Goodwill [Roll Forward]
Balance as of beginning of period	345,736		345,736
Goodwill acquired during the year	0		0
Balance as of end of period	345,736		345,736
Pipeline and energy services:
Goodwill [Roll Forward]
Balance as of beginning of period	9,737	[1]	9,737	[1]
Goodwill acquired during the year	0		0
Balance as of end of period	9,737	[1]	9,737	[1]
Accumulated impairment which occurred in prior periods	12,300		12,300
Construction materials and contracting:
Goodwill [Roll Forward]
Balance as of beginning of period	176,290		176,290
Goodwill acquired during the year	0		0
Balance as of end of period	176,290		176,290
Construction services:
Goodwill [Roll Forward]
Balance as of beginning of period	104,276		103,168
Goodwill acquired during the year	0		1,108	[2]
Balance as of end of period	$ 104,276		$ 104,276

[1] Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

[2] Includes contingent consideration that was not material related to an acquisition in a prior period.

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Defined contribution plans (Details 13) (Defined contribution pension [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined contribution pension [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan, cost recognized	$ 33,200,000	$ 29,300,000	$ 27,100,000

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating activities:
Net income (loss)	$ 278,570		$ (754)		$ 213,026
Income (loss) from discontinued operations, net of tax	(312)	[1]	13,567	[1]	(12,926)	[1]
Income (loss) from continuing operations	278,882		(14,321)		225,952
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	386,856		359,205		343,395
Earnings (loss), net of distributions, from equity method investments	2,281		(618)		(2,111)
Deferred income taxes	86,778		(7,503)		118,925
Unrealized (gain) loss on commodity derivatives	6,267		624		(1,827)
Write-downs of oil and natural gas properties (Note 1)	0		391,800		0
Changes in current assets and liabilities, net of acquisitions:
Receivables	(40,669)		(13,416)		(30,452)
Inventories	30,452		(42,334)		(24,226)
Other current assets	(9,474)		297		7,729
Accounts payable	15,084		6,352		(12,263)
Other current liabilities	29,392		(59,001)		33,738
Other noncurrent changes	(43,937)		(33,665)		(31,538)
Net cash provided by continuing operations	741,912		587,420		627,322
Net cash provided by (used in) discontinued operations	281		(2,680)		(674)
Net cash provided by operating activities	742,193		584,740		626,648
Investing activities:
Capital expenditures	(909,400)		(872,920)		(497,000)
Acquisitions, net of cash acquired	0		(67,261)		(157)
Net proceeds from sale or disposition of property and other	124,541		40,110		40,107
Investments	302		9,725		(10,302)
Proceeds from sale of equity method investments	1,896		2,394		2,807
Net cash used in continuing operations	(782,661)		(887,952)		(464,545)
Net cash provided by discontinued operations	0		0		0
Net cash used in investing activities	(782,661)		(887,952)		(464,545)
Financing activities:
Issuance of short-term borrowings	9,500		20,100		0
Repayment of short-term borrowings	0		0		(20,000)
Issuance of long-term debt	507,924		467,957		300
Repayment of long-term debt	(423,707)		(138,775)		(85,151)
Proceeds from issuance of common stock	14,554		88		5,744
Dividends paid	(98,405)		(159,768)		(123,323)
Excess tax benefit on stock-based compensation	0		26		1,239
Contribution from noncontrolling interest	27,000		0		0
Net cash provided by (used in) continuing operations	36,866		189,628		(221,191)
Net cash provided by discontinued operations	0		0		0
Net cash provided by (used in) financing activities	36,866		189,628		(221,191)
Effect of exchange rate changes on cash and cash equivalents	(215)		(146)		(214)
Decrease in cash and cash equivalents	(3,817)		(113,730)		(59,302)
Cash and cash equivalents - beginning of year	49,042		162,772		222,074
Cash and cash equivalents - end of year	$ 45,225		$ 49,042		$ 162,772

[1] Reflected in the Other category.

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Consolidiated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income (loss)	$ 278,570	$ (754)	$ 213,026
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $(3,116), $4,829 and $4,683 in 2013, 2012 and 2011, respectively	(5,594)	8,497	7,900
Reclassification adjustment for (gain) loss on derivative instruments included in net income, net of tax of $(2,548), $(5,141) and $0 in 2013, 2012 and 2011, respectively	(4,189)	(8,754)	0
Net unrealized gain (loss) on derivative instruments qualifying as hedges	(9,783)	(257)	7,900
Postretirement liability adjustment:
Postretirement liability gains (losses) arising during the period, net of tax of $11,818, $(2,060) and $(14,205) in 2013, 2012 and 2011, respectively	18,539	(3,106)	(23,473)
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $1,276, $1,379 and $632 in 2013, 2012 and 2011, respectively	2,001	2,079	1,046
Postretirement liability adjustment	20,540	(1,027)	(22,427)
Foreign currency translation adjustment:
Foreign currency translation adjustment recognized during the period, net of tax of $(177), $(296) and $(767) in 2013, 2012 and 2011, respectively	(299)	(476)	(1,189)
Reclassification adjustment for (gain) loss on foreign currency translation adjustment included in net income, net of tax of $70, $2 and $(65) in 2013, 2012 and 2011, respectively	143	3	(106)
Foreign currency translation adjustment	(156)	(473)	(1,295)
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(105), $(52) and $(20) in 2013, 2012 and 2011, respectively	(194)	(97)	(36)
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $59, $72 and $64 in 2013, 2012 and 2011, respectively	109	134	118
Net unrealized gain (loss) on available-for-sale investments	(85)	37	82
Other comprehensive income (loss)	10,516	(1,720)	(15,740)
Comprehensive income (loss)	289,086	(2,474)	197,286
Comprehensive loss attributable to noncontrolling interest	(363)	0	0
Comprehensive income (loss) attributable to common stockholders	289,449	(2,474)	197,286
Other Comprehensive Income (Loss), Tax, Parenthetical Disclosures [Abstract]
Net unrealized gain (loss) on derivative instruments arising during the period, tax	(3,116)	4,829	4,683
Reclassification adjustment for (gain) loss on derivative instruments included in net income, tax	(2,548)	(5,141)	0
Postretirement liability gains (losses) arising during the period, tax	11,818	(2,060)	(14,205)
Amortization of postretirement liability losses included in net periodic benefit cost, tax	1,276	1,379	632
Foreign currency translation adjustment recognized during the period, tax	(177)	(296)	(767)
Reclassification adjustment for (gain) loss on foreign currency translation adjustment included in net income, tax	70	2	(65)
Net unrealized gains (losses) on available-for-sale investments arising during the period, tax	(105)	(52)	(20)
Reclassification adjustments for (gain) loss on available-for-sale investments included in net income, tax	$ 59	$ 72	$ 64

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation [Abstract]

Asset retirement obligations

Asset Retirement Obligations

The Company records obligations related to the plugging and abandonment of oil and natural gas wells, decommissioning of certain electric generating facilities, reclamation of certain aggregate properties, special handling and disposal of hazardous materials at certain electric generating facilities, natural gas distribution facilities and buildings, and certain other obligations.

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:

	2013			2012
	(In thousands)
Balance at beginning of year	$	102,545		$	98,151
Liabilities incurred	5,610			6,523
Liabilities acquired	—			—
Liabilities settled	(22,257		)	(10,472		)
Accretion expense	4,574			4,266
Revisions in estimates	7,671			3,655
Other	386			422
Balance at end of year	$	98,529		$	102,545

The Company believes that any expenses related to asset retirement obligations at the Company's regulated operations will be recovered in rates over time and, accordingly, defers such expenses as regulatory assets.

The fair value of assets that are legally restricted for purposes of settling asset retirement obligations at December 31, 2013 and 2012, was $4.1 million and $5.0 million, respectively. The legally restricted assets consist primarily of money market funds and are reflected in other assets on the Consolidated Balance Sheets.

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Fair value (Details 8)	Dec. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Number of investment managers of plan assets	16
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Number of investment managers of plan assets	1

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Income tax expense (benefit) statutory rate versus actual rate (Details 5) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Computed tax at federal statutory rate
Computed tax at federal statutory rate	$ 145,466,000	$ (15,914,000)	$ 117,679,000
Federal statutory rate (in hundredths)	35.00%	35.00%	35.00%
Increases (reductions) resulting from:
State income taxes, net of federal income tax	10,524,000	2,469,000	10,653,000
State income tax rate (in hundredths)	2.50%	(5.40%)	3.20%
Nonqualified benefit plans	(5,173,000)	(2,359,000)	(2,918,000)
Nonqualified benefit plans (in hundredths)	(1.20%)	5.20%	(0.90%)
Depletion allowance	(3,764,000)	(3,728,000)	(3,266,000)
Depletion allowance rate (in hundredths)	(0.90%)	8.20%	(1.00%)
Federal renewable energy credit	(3,404,000)	(3,401,000)	(3,485,000)
Federal renewable energy credit rate (in hundreths)	(0.80%)	7.50%	(1.00%)
Deductible K-Plan dividends	(1,593,000)	(2,829,000)	(2,282,000)
Deductible K-Plan dividends rate (in hundredths)	(0.40%)	6.20%	(0.70%)
AFUDC equity	(1,074,000)	(1,500,000)	(873,000)
AFUDC equity rate (in hundredths)	(0.30%)	3.30%	(0.30%)
Resolution of tax matters and uncertain tax positions	(859,000)	2,559,000	(3,906,000)
Resolution of tax matters and uncertain tax positions rate (in hundredths)	(0.20%)	(5.60%)	(1.20%)
Deferred tax rate changes	741,000	(3,083,000)	(417,000)
Deferred tax rate changes rate (in hundredths)	0.20%	6.80%	(0.10%)
Other	(4,128,000)	(3,360,000)	(911,000)
Other rate (in hundredths)	(1.00%)	7.30%	(0.20%)
Total income tax expense (benefit)	136,736,000	(31,146,000)	110,274,000
Total income tax expense (benefit) rate (in hundredths)	32.90%	68.50%	32.80%
Temporary differences [Abstract]
Undistributed earnings from foreign operations	7,000,000
Deferred tax liabilities, undistributed foreign earnings	$ 2,200,000

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Components of deferred tax assets and liabilities (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Valuation Allowance, Amount	$ 0	$ 0
Deferred tax assets:
Regulatory matters	125,607,000	121,781,000
Accrued pension costs	74,320,000	85,037,000
Alternative minimum tax credit carryforward	33,304,000	0
Compensation-related	31,550,000	23,441,000
Asset retirement obligations	29,578,000	26,748,000
Legal and environmental contingencies	10,710,000	8,046,000
Other	45,101,000	39,792,000
Total deferred tax assets	350,170,000	304,845,000
Deferred tax liabilities:
Depreciation and basis differences on property, plant and equipment	813,597,000	755,392,000
Basis differences on oil and natural gas producing properties	266,168,000	167,113,000
Regulatory matters	64,914,000	82,077,000
Intangible asset amortization	13,579,000	14,078,000
Other	26,170,000	18,441,000
Total deferred tax liabilities	1,184,428,000	1,037,101,000
Net deferred income tax liability	$ (834,258,000)	$ (732,256,000)

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Capital expenditures related to oil and natural gas producing activities (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Acquisitions:
Proved properties	$ 1,817,000	[1]	$ 839,000	[1]	$ 3,999,000	[1]
Unproved properties	4,608,000	[1]	31,109,000	[1]	63,354,000	[1]
Exploration	26,975,000	[1]	235,906,000	[1]	41,775,000	[1]
Development	355,421,000	[1]	275,959,000	[1]	161,647,000	[1]
Total capital expenditures	388,821,000	[1]	543,813,000	[1]	270,775,000	[1]
Net change in property, plant and equipment related to future liabilities for asset retirement obligations that are excluded	(10,700,000)		(200,000)		(1,800,000)
Proceeds from Sale of Oil and Gas Property and Equipment	$ 83,600,000		$ 6,000,000		$ 12,400,000

[1] Excludes net additions/(reductions) to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of oil and natural gas wells, as discussed in Note 10, of $(10.7) million, $(200,000) and $(1.8) million for the years ended December 31, 2013, 2012 and 2011, respectively.

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Schedule II Valuation and Qualifying Accounts (Details) (Allowance for Doubtful Accounts [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Allowance for Doubtful Accounts [Member]
Allowance for doubtful accounts:
Balance, beginning of period	$ 10,818		$ 12,407		$ 15,284
Charged to Costs and Expenses	5,725		7,064		3,977
Other	1,395	[1]	1,754	[1]	2,112	[1]
Deductions	7,853	[2]	10,407	[2]	8,966	[2]
Balance, end of period	$ 10,085		$ 10,818		$ 12,407

[1] Recoveries.

[2] Uncollectible accounts written off.

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Subsequent Events Subsequent Events (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended			0 Months Ended
	Jul. 15, 2014 MDU Resources Group, Inc [Member]	Apr. 15, 2014 MDU Resources Group, Inc [Member]	Feb. 10, 2014 MDU Resources Group, Inc [Member]	Jan. 27, 2014 MDU Energy Capital [Member]
Subsequent Event [Line Items]
Senior notes issued	$ 100.0	$ 50.0		$ 30.0
Senior notes weighted average interest rate	4.60%	4.60%		5.30%
Purchase Price of Acquisition			$ 183.0

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 30, 2013
Document and entity information [Abstract]
Entity Registrant Name	MDU RESOURCES GROUP INC
Entity Central Index Key	0000067716
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			$ 4,892,599,006
Entity Common Stock, Shares Outstanding		189,370,016
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013

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Proved reserves (Details 5) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 MBoe	Dec. 31, 2012 MBoe	Dec. 31, 2011 MBoe
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, energy	66,140	69,131	79,460
Proved undeveloped reserves, energy	14,555	11,355	18,191
Balance at end of year, energy	80,695	80,486	97,651
Changes in proved and undeveloped reserves [Abstract]
Change in PUD reserve	3,200
Negative revision to PUD reserves	(1,600)
New PUD reserves	11,900
Converting PUD reserves	7,100
Drilling, completion and future development costs [Abstract]
Drilling and completion capital	$ 127.3
Future development costs estimated to be spent to develop PUD reserves year one	143.6
Future development costs estimated to be spent to develop PUD reserves year two	116.0
Future development costs estimated to be spent to develop PUD reserves year three	$ 18.1
Oil (MBbls)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume	31,394	27,412	23,653
Proved undeveloped reserves, volume	9,625	6,041	3,352
Balance at end of year, volume	41,019	33,453	27,005
NGL (MBbls)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume	5,322	5,342	5,225
Proved undeveloped reserves, volume	1,280	1,811	2,117
Balance at end of year, volume	6,602	7,153	7,342
Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed reserves, volume	176,546	218,259	303,495
Proved undeveloped reserves, volume	21,899	21,019	76,332
Balance at end of year, volume	198,445	239,278	379,827

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Preferred Stocks

12 Months Ended

Dec. 31, 2013

Preferred Stocks [Abstract]

Preferred stocks

Preferred Stocks

Preferred stocks at December 31 were as follows:

	2013		2012
(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 2013, 2012 and 2011, 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.

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Long-term borrowings (Details 3) (Long-term debt [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 12, 2013
MDU Resources Group, Inc [Member] | Commercial paper revolving credit agreement [Member]
Debt instrument [Line Items]
Ratio of funded debt to capitalization - Company alone, as specified in debt convenants	65.00%
Ratio of funded debt to total capitalization as specified in debt convenants	65.00%
MDU Energy Capital, LLC [Member] | Master shelf agreement member [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%
MDU Energy Capital, LLC [Member] | Note purchase agreement [Member]
Debt instrument [Line Items]
Weighted average interest rate	5.30%
Contracted issuance of senior notes	$ 30.0
Intermountain Gas Company [Member] | Revolving credit agreement [Member]
Debt instrument [Line Items]
Ratio of total debt to total capitalization as specified in debt convenants.	65.00%
Centennial Energy Holdings, Inc [Member] | Revolving credit agreement [Member]
Debt instrument [Line Items]
Ratio of total debt to total capitalization as specified in debt convenants.	65.00%
Centennial Energy Holdings, Inc [Member] | Master shelf agreement member [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%
WBI Energy Transmission, Inc. [Member] | Uncommitted long-term private shelf agreement [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	$ 100.0

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Income tax expense (benefit) (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:
Federal	$ 45,518	$ (26,858)	$ (7,188)
State	4,311	858	778
Foreign	(29)	(75)	127
Current income taxes	49,800	(26,075)	(6,283)
Deferred:
Federal	78,953	(1,224)	105,528
State	8,031	(6,323)	13,157
Investment tax credit - net	(206)	44	240
Deferred income taxes	86,778	(7,503)	118,925
Change in uncertain tax positions	0	1,974	(1,048)
Change in accrued interest	158	458	(1,320)
Total income tax expense (benefit)	$ 136,736	$ (31,146)	$ 110,274

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 45,225		$ 49,042
Receivables, net	713,067		678,123
Inventories	282,391		317,415
Deferred income taxes	25,048		22,846
Commodity derivative instruments	1,447		18,304
Prepayments and other current assets	49,510		42,351
Total current assets	1,116,688		1,128,081
Investments	112,939		103,243
Property, plant and equipment (Note 1)	8,803,866		8,107,751
Less accumulated depreciation, depletion and amortization	3,872,487		3,608,912
Net property, plant and equipment	4,931,379		4,498,839
Deferred charges and other assets:
Goodwill (Note 5)	636,039	[1]	636,039	[1]
Other intangible assets, net (Note 5)	13,099		17,129
Other	251,188		299,160
Total deferred charges and other assets	900,326		952,328
Total assets	7,061,332		6,682,491
Current liabilities:
Short-term borrowings (Note 9)	11,500		28,200
Long-term debt due within one year	12,277		134,108
Accounts payable	404,961		388,015
Taxes payable	74,175		46,475
Dividends payable	33,737		171
Accrued compensation	69,661		48,448
Commodity derivative instruments	7,483		0
Other accrued liabilities	171,106		204,698
Total current liabilities	784,900		850,115
Long-term debt (Note 9)	1,842,286		1,610,867
Deferred credits and other liabilities:
Deferred income taxes	859,306		755,102
Other liabilities	718,938		818,159
Total deferred credits and other liabilities	1,578,244		1,573,261
Equity:
Preferred stocks (Note 11)	15,000		15,000
Common stockholders' equity:
Common stock (Note 12) Authorized - 500,000,000 shares, $1.00 par value Issued - 189,868,780 shares in 2013 and 189,369,450 shares in 2012	189,869		189,369
Other paid-in capital	1,056,996		1,039,080
Retained earnings	1,603,130		1,457,146
Accumulated other comprehensive loss	(38,205)		(48,721)
Treasury stock at cost - 538,921 shares	(3,626)		(3,626)
Total common stockholders' equity	2,808,164		2,633,248
Total stockholders' equity	2,823,164		2,648,248
Noncontrolling interest	32,738		0
Total equity	2,855,902		2,648,248
Total liabilities and equity	$ 7,061,332		$ 6,682,491

[1] Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

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Goodwill and other intangible assets

12 Months Ended

Dec. 31, 2013

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, 2013, were as follows:

	Balance at January 1, 2013		*	Goodwill Acquired During the Year		Balance at December 31, 2013		*
	(In thousands)
Natural gas distribution	$	345,736		$	—	$	345,736
Pipeline and energy services	9,737			—		9,737
Construction materials and contracting	176,290			—		176,290
Construction services	104,276			—		104,276
Total	$	636,039		$	—	$	636,039

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

The changes in the carrying amount of goodwill for the year ended December 31, 2012, were as follows:

	Balance at January 1, 2012		*	Goodwill Acquired During the Year		**	Balance at December 31, 2012		*
	(In thousands)
Natural gas distribution	$	345,736		$	—		$	345,736
Pipeline and energy services	9,737			—			9,737
Construction materials and contracting	176,290			—			176,290
Construction services	103,168			1,108			104,276
Total	$	634,931		$	1,108		$	636,039

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

** Includes contingent consideration that was not material related to an acquisition in a prior period.

Other amortizable intangible assets at December 31 were as follows:

	2013			2012
	(In thousands)
Customer relationships	$	21,310		$	21,310
Accumulated amortization	(13,726		)	(11,701		)
	7,584			9,609
Noncompete agreements	6,186			7,236
Accumulated amortization	(4,840		)	(5,326		)
	1,346			1,910
Other	10,995			10,979
Accumulated amortization	(6,826		)	(5,369		)
	4,169			5,610
Total	$	13,099		$	17,129

Amortization expense for amortizable intangible assets for the years ended December 31, 2013, 2012 and 2011, was $4.0 million, $3.8 million and $3.7 million, respectively. Estimated amortization expense for intangible assets is $3.2 million in 2014, $2.5 million in 2015, $2.2 million in 2016, $2.0 million in 2017, $1.0 million in 2018 and $2.2 million thereafter.

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Equity method investments

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

Equity method investments

Equity Method Investments

Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. At December 31, 2013, the Company had no significant equity method investments.

In August 2006, MDU Brasil acquired ownership interests in the Brazilian Transmission Lines. The electric transmission lines are primarily in northeastern and southern Brazil. The transmission contracts provide for revenues denominated in the Brazilian Real, annual inflation adjustments and change in tax law adjustments. The functional currency for the Brazilian Transmission Lines is the Brazilian Real.

In 2009, multiple sales agreements were signed with three separate parties for the Company to sell its ownership interests in the Brazilian Transmission Lines. In November 2010, the Company completed the sale of its entire ownership interest in ENTE and ERTE and 59.96 percent of the Company's ownership interest in ECTE. The Company's remaining interest in ECTE is being sold over a four-year period. In August 2013 and 2012, and November 2011, the Company completed the sale of one-fourth of the remaining interest in each year. The Company recognized immaterial gains in 2013 and 2012 and a $1.0 million ($600,000 after tax) gain in 2011. The Company's remaining ownership interest in ECTE is being accounted for under the cost method.

At December 31, 2012, the equity method investments had total assets of $129.0 million and long-term debt of $65.5 million. The Company's investment in its equity method investments was approximately $6.9 million, including undistributed earnings of $3.4 million, at December 31, 2012.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Pension and other postretirement benefit plans

The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans.

Defined pension plan benefits to all nonunion and certain union employees hired after December 31, 2005, were discontinued. In 2010, all benefit and service accruals for nonunion and certain union plans were frozen. In 2011 and 2012, all benefit and service accruals for certain additional union employees were frozen. These employees will be eligible to receive additional defined contribution plan benefits.

Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company's businesses. Employees who attain 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 is 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, 2013 and 2012, and amounts recognized in the Consolidated Balance Sheets at December 31, 2013 and 2012, were as follows:

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	459,111		$	435,618		$	103,358		$	110,689
Service cost	155			1,078			1,675			1,747
Interest cost	16,249			17,598			3,215			4,166
Plan participants' contributions	—			—			1,472			2,688
Amendments	—			—			—			(11,418		)
Actuarial (gain) loss	(44,551		)	30,939			(20,985		)	3,469
Benefits paid	(28,192		)	(26,122		)	(7,009		)	(7,983		)
Benefit obligation at end of year	402,772			459,111			81,726			103,358
Change in net plan assets:
Fair value of plan assets at beginning of year	309,184			278,000			74,361			68,085
Actual gain on plan assets	35,539			34,493			13,819			6,497
Employer contribution	18,313			22,813			1,900			5,074
Plan participants' contributions	—			—			1,472			2,688
Benefits paid	(28,192		)	(26,122		)	(7,009		)	(7,983		)
Fair value of net plan assets at end of year	334,844			309,184			84,543			74,361
Funded status - (under) over	$	(67,928	)	$	(149,927	)	$	2,817		$	(28,997	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Other assets (noncurrent)	$	—		$	—		$	9,679		$	—
Other accrued liabilities (current)	—			—			(381		)	(655		)
Other liabilities (noncurrent)	(67,928		)	(149,927		)	(6,481		)	(28,342		)
Net amount recognized	$	(67,928	)	$	(149,927	)	$	2,817		$	(28,997	)
Amounts recognized in accumulated other comprehensive (income) loss consist of:
Actuarial loss	$	135,061		$	202,406		$	11,314		$	43,589
Prior service cost (credit)	365			437			(17,137		)	(18,594		)
Total	$	135,426		$	202,843		$	(5,823	)	$	24,995

Employer contributions and benefits paid in the preceding table include only those amounts contributed directly to, or paid directly from, plan assets. Accumulated other comprehensive (income) loss in the above table includes amounts related to regulated operations, which are recorded as regulatory assets (liabilities) and are expected to be reflected in rates charged to customers over time. For more information on regulatory assets (liabilities), see Note 6.

Unrecognized pension actuarial losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets are amortized on a straight-line basis over the expected average remaining service lives of active participants for non-frozen plans and over the average life expectancy of plan participants for frozen plans. The market-related value of assets is determined using a five-year average of assets. Unrecognized postretirement net transition obligation was amortized over a 20-year period ending 2012.

The pension plans all have accumulated benefit obligations in excess of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for these plans at December 31 were as follows:

	2013		2012
	(In thousands)
Projected benefit obligation	$	402,772	$	459,111
Accumulated benefit obligation	$	402,772	$	459,111
Fair value of plan assets	$	334,844	$	309,184

Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows:

	Pension Benefits									Other Postretirement Benefits
	2013			2012			2011			2013			2012			2011
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	155		$	1,078		$	2,252		$	1,675		$	1,747		$	1,443
Interest cost	16,249			17,598			19,500			3,215			4,166			4,700
Expected return on assets	(19,917		)	(23,536		)	(22,809		)	(4,343		)	(4,890		)	(5,051		)
Amortization of prior service cost (credit)	71			(46		)	45			(1,457		)	(1,438		)	(2,677		)
Recognized net actuarial loss	7,173			7,070			4,656			1,814			2,134			753
Curtailment loss (gain)	—			(1,023		)	1,218			—			—			—
Amortization of net transition obligation	—			—			—			—			2,128			2,125
Net periodic benefit cost, including amount capitalized	3,731			1,141			4,862			904			3,847			1,293
Less amount capitalized	727			937			1,196			164			910			(50		)
Net periodic benefit cost	3,004			204			3,666			740			2,937			1,343
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
Net (gain) loss	(60,173		)	19,982			76,310			(30,461		)	1,863			23,863
Prior service credit	—			—			—			—			(11,418		)	—
Amortization of actuarial loss	(7,173		)	(7,070		)	(4,656		)	(1,814		)	(2,134		)	(753		)
Amortization of prior service (cost) credit	(71		)	1,069			(1,263		)	1,457			1,438			2,677
Amortization of net transition obligation	—			—			—			—			(2,128		)	(2,125		)
Total recognized in accumulated other comprehensive (income) loss	(67,417		)	13,981			70,391			(30,818		)	(12,379		)	23,662
Total recognized in net periodic benefit cost and accumulated other comprehensive (income) loss	$	(64,413	)	$	14,185		$	74,057		$	(30,078	)	$	(9,442	)	$	25,005

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are $4.8 million and $71,000, respectively. The estimated net loss and prior service credit for the other postretirement benefit plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are $793,000 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
	2013		2012		2013		2012
Discount rate	4.53	%	3.65	%	4.48	%	3.67	%
Expected return on plan assets	7.00	%	7.00	%	6.00	%	6.00	%
Rate of compensation increase	N/A		N/A		3.00	%	4.00	%

Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows:

	Pension Benefits				Other Postretirement Benefits
	2013		2012		2013		2012
Discount rate	3.65	%	4.16	%	3.67	%	4.13	%
Expected return on plan assets	7.00	%	7.75	%	6.00	%	6.75	%
Rate of compensation increase	N/A*		N/A*		4.00	%	4.00	%

* Effective September 30, 2012, all benefit and service accruals for a union plan were frozen. Compensation increases had previously been frozen for all other plans.

The expected rate of return on pension plan assets is based on the targeted asset allocation range of 60 percent to 70 percent equity securities and 30 percent to 40 percent fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 65 percent to 75 percent equity securities and 25 percent to 35 percent fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.

Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:

				2013					2012
Health care trend rate assumed for next year	6.0	%	-	7.0	%	6.0	%	-	8.0	%
Health care cost trend rate - ultimate	5.0	%	-	6.0	%	5.0	%	-	6.0	%
Year in which ultimate trend rate achieved				2017					2017

The Company's other postretirement benefit plans include health care and life insurance benefits for certain retirees. The plans underlying these benefits may require contributions by the retiree depending on such retiree's age and years of service at retirement or the date of retirement. The accounting for the health care plans anticipates future cost-sharing changes that are consistent with the Company's expressed intent to generally increase retiree contributions each year by the excess of the expected health care cost trend rate over six percent.

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates would have had the following effects at December 31, 2013:

	1 Percentage  Point Increase		1 Percentage Point  Decrease
	(In thousands)
Effect on total of service and interest cost components	$	159	$	(135	)
Effect on postretirement benefit obligation	$	3,352	$	(2,920	)

The Company's pension assets are managed by 16 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 1 and 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.

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.

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. Treasury securities are valued based on quoted prices on an active market.

The estimated fair value of the pension plans' Level 2 U.S. Treasury 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 endedDecember 31, 2013 and 2012, 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, 2013, 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, 2013
	(In thousands)
Assets:
Cash equivalents	$	—	$	9,406	$	—	$	9,406
Equity securities:
U.S. companies	62,599		—		—		62,599
International companies	39,437		—		—		39,437
Collective and mutual funds*	116,265		42,483		—		158,748
Corporate bonds	—		42,721		—		42,721
Municipal bonds	—		7,561		—		7,561
U.S. Treasury securities	7,487		4,335		—		11,822
Total assets measured at fair value	$	225,788	$	106,506	$	—	$	332,294

* Collective and mutual funds invest approximately 11 percent in common stock of mid-cap U.S. companies, 34 percent in common stock of large-cap U.S. companies, 11 percent in U.S. Treasuries, 27 percent in corporate bonds and 17 percent in other investments.

The fair value of the Company's pension plans' assets by class were as follows:

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Cash equivalents	$	2,145	$	10,460	$	—	$	12,605
Equity securities:
U.S. companies	86,981		—		—		86,981
International companies	39,818		—		—		39,818
Collective and mutual funds*	82,787		20,065		—		102,852
Corporate bonds	—		45,112		—		45,112
Municipal bonds	—		9,302		—		9,302
U.S. Treasury securities	7,980		4,534		—		12,514
Total assets measured at fair value	$	219,711	$	89,473	$	—	$	309,184

* Collective and mutual funds invest approximately 12 percent in common stock of mid-cap U.S. companies, 26 percent in common stock of large-cap U.S. companies, 13 percent in U.S. Treasuries, 41 percent in corporate bonds and 8 percent in other investments.

The following table sets forth a summary of changes in the fair value of the pension plans' Level 3 assets for the year ended December 31, 2012:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Corporate Bonds
	(In thousands)
Balance at beginning of year	$	289
Total realized/unrealized losses	(47		)
Purchases, issuances and settlements (net)	(242		)
Balance at end of year	$	—

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 1 and 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.

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, 2013 and 2012, 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, 2013, 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, 2013
	(In thousands)
Assets:
Cash equivalents	$	—	$	2,142	$	—	$	2,142
Equity securities:
U.S. companies	2,802		—		—		2,802
International companies	221		—		—		221
Insurance contract*	—		79,374		—		79,374
Total assets measured at fair value	$	3,023	$	81,516	$	—	$	84,539

* The insurance contract invests approximately 55 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Treasuries, 8 percent in mortgage-backed securities, 8 percent in common stock of mid-cap U.S. companies, 9 percent in corporate bonds and 8 percent in other investments.

The fair value of the Company's other postretirement benefit plans' assets by asset class were as follows:

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Cash equivalents	$	1,053	$	1,991	$	—	$	3,044
Equity securities:
U.S. companies	2,207		—		—		2,207
International companies	260		—		—		260
Insurance contract*	—		68,850		—		68,850
Total assets measured at fair value	$	3,520	$	70,841	$	—	$	74,361

* The insurance contract invests approximately 51 percent in common stock of large-cap U.S. companies, 15 percent in U.S. Treasuries, 10 percent in mortgage-backed securities, 11 percent in corporate bonds and 13 percent in other investments.

The Company expects to contribute approximately $32.5 million to its defined benefit pension plans and approximately $1.5 million to its postretirement benefit plans in 2014.

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)
2014	$	23,391	$	5,596	$	237
2015	23,645		5,584		230
2016	23,911		5,583		221
2017	24,439		5,543		211
2018	24,814		5,483		200
2019 - 2023	130,026		26,038		823

Nonqualified benefit plans

In addition to the qualified plan defined pension benefits reflected in the table at the beginning of this note, the Company also has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for these plans was $7.3 million, $8.1 million and $8.1 million in 2013, 2012 and 2011, respectively. The total projected benefit obligation for these plans was $106.9 million and $113.0 million at December 31, 2013 and 2012, respectively. The accumulated benefit obligation for these plans was $99.7 million and $107.5 million at December 31, 2013 and 2012, respectively. A weighted average discount rate of 4.32 percent and 3.44 percent at December 31, 2013 and 2012, respectively, and a rate of compensation increase of 4.00 percent and 3.00 percent at December 31, 2013 and 2012, were used to determine benefit obligations. A discount rate of 3.44 percent and 4.00 percent at December 31, 2013 and 2012, respectively, and a rate of compensation increase of 3.00 percent and 4.00 percent at December 31, 2013 and 2012, were used to determine net periodic benefit cost.

The amount of benefit payments for the unfunded, nonqualified benefit plans are expected to aggregate $5.7 million in 2014; $6.7 million in 2015; $6.5 million in 2016; $6.7 million in 2017; $7.2 million in 2018 and $37.5 million for the years 2019 through 2023.

In 2012, the Company established a nonqualified defined contribution plan for certain key management employees. Costs incurred under this plan for 2013 and 2012 were $304,000 and $84,000, respectively.

The Company had investments of $98.1 million and $84.4 million at December 31, 2013 and 2012, respectively, consisting of equity securities of $53.5 million and $41.9 million, respectively, life insurance carried on plan participants (payable upon the employee's death) of $31.4 million and $32.7 million, respectively, and other investments of $13.2 million and $9.8 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 $33.2 million in 2013, $29.3 million in 2012 and $27.1 million in 2011.

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 multiemployer plan 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 multiemployer plans, 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 2013 and 2012 is for the plan's year-end at December 31, 2012, and December 31, 2011, 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		2013	2012		2013		2012		2011
					(In thousands)
Edison Pension Plan	93-6061681-001	Green as of 12/31/2013	Green as of 12/31/2012	No	$	6,358	$	5,171	$	2,700	No	12/31/2014
IBEW Local 38 Pension Plan	34-6574238-001	Yellow as of 4/30/2013	Yellow as of 4/30/2012	Implemented	1,041		2,771		1,469		No	4/27/2014
IBEW Local No. 82 Pension Plan	31-6127268-001	Red as of 6/30/2013	Red as of 6/30/2012	Implemented	1,284		1,093		1,331		No	11/30/2014
IBEW Local 648 Pension Plan	31-6134845-001	Red as of 2/28/2013	Red as of 2/29/2012	Implemented	1,489		564		722		No	8/31/2015
Laborers Pension Trust Fund for Northern California	94-6277608-001	Yellow as of 5/31/2013	Yellow as of 5/31/2012	Implemented	921		567		628		No	6/30/2016
National Electrical Benefit Fund	53-0181657-001	Green	Green	No	5,883		5,603		4,841		No	5/31/2012*– 8/31/2017
OE Pension Trust Fund	94-6090764-001	Yellow	Yellow as of 12/31/2012	Implemented	1,510		1,156		1,367		No	6/30/2013*– 3/31/2016
Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming	83-6011320-001	Red as of 12/31/2013	Red as of 12/31/2012	Implemented	76		91		96		No	10/31/2005*
Operating Engineers Pension Trust	95-6032478-001	Red as of 6/30/2013	Red as of 6/30/2012	Implemented	493		761		458		No	7/1/2013*– 7/20/2014
Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525	88-6003864-001	Green as of 6/30/2012	Green as of 6/30/2011	No	1,657		1,202		759		No	5/31/2010*
Sheet Metal Workers' Pension Plan of Southern CA, AZ and NV	95-6052257-001	Red as of 12/31/2013	Red as of 12/31/2012	Implemented	512		467		336		No	6/30/2014
Other funds					18,036		15,333		14,451
Total contributions					$	39,260	$	34,779	$	29,158

* 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 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	2012 and 2011
IBEW Local 38 Pension Plan	2012 and 2011
IBEW Local No. 82 Pension Plan	2012 and 2011
Local Union No. 124 IBEW Pension Trust Fund	2012 and 2011
Local Union 212 IBEW Pension Trust Fund	2012 and 2011
IBEW Local Union No. 357 Pension Plan A	2012 and 2011
IBEW Local 648 Pension Plan	2012 and 2011
Idaho Plumbers and Pipefitters Pension Plan	2012 and 2011
Minnesota Teamsters Construction Division Pension Fund	2012 and 2011
Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming	2012 and 2011
Pension and Retirement Plan of Plumbers and Pipefitters Union Local No. 525	2012 and 2011

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 $37.1 million, $31.4 million and $24.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Amounts contributed in 2013, 2012 and 2011 to defined contribution multiemployer plans were $20.6 million, $18.7 million and $15.3 million, respectively.

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Common Stock

12 Months Ended

Dec. 31, 2013

Common Stock [Abstract]

Common Stock

Common Stock

For the years 2013, 2012 and 2011, dividends declared on common stock were $.6950, $.6750 and $.6550 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 2011 through December 2013, purchases of shares of common stock on the open market were used to fund the Stock Purchase Plan and K-Plan. At December 31, 2013, there were 15.6 million shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan.

The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on common stock. The declaration and payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by the Company's credit agreements, federal and state laws, and applicable regulatory limitations. In addition, the Company and Centennial are generally restricted to paying dividends out of capital accounts or net assets. The following discusses the most restrictive limitations.

Pursuant to a covenant under a credit agreement, Centennial may only make distributions to the Company in an amount up to 100 percent of Centennial's consolidated net income after taxes, excluding noncash write-downs, for the immediately preceding fiscal year. Intermountain and Cascade have regulatory limitations on the amount of dividends each can pay. Based on these limitations, approximately $2.1 billion of the net assets of the Company's subsidiaries were restricted from being used to transfer funds to the Company at December 31, 2013. 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 $219 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, 2013. 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.

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Common Stock (Details) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Dividends declared per common share	$ 0.6950	$ 0.6750	$ 0.6550
Company's subsidiaries net assets restricted from being used to transfer funds to the Company	$ 2,100,000,000
Credit agreement limitation on company ratio of funded debt to capitalization (excluding subsidiaries)	65.00%
Company's (excluding its subsidiaries) net assets restricted from use for dividend payments	$ 219,000,000
Parent company [Member]
Shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan (in shares)	15.6
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%

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Fair value measurements

12 Months Ended

Dec. 31, 2013

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 $62.4 million and $48.9 million as of December 31, 2013 and 2012, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gains on these investments for the year ended December 31, 2013 and 2012, were $13.5 million and $5.2 million, respectively. The net unrealized loss on these investments for the year ended December 31, 2011, was $1.1 million. 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, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193
U.S. Treasury securities	1,906		15		(4		)	1,917
Total	$	10,057	$	84	$	(31	)	$	10,110

December 31, 2012	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,054	$	144	$	(3	)	$	8,195
U.S. Treasury securities	1,763		43		—			1,806
Total	$	9,817	$	187	$	(3	)	$	10,001

The fair value of the Company's money market funds approximates cost.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs.

The estimated fair values of the Company's assets and liabilities measured on a recurring basis are determined using the market approach.

The Company's Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company's Level 2 mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources.

The estimated fair value of the Company's Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.

The estimated fair value of the Company's Level 2 commodity derivative instruments is based upon futures prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company's and the counterparties' nonperformance risk is also evaluated.

The estimated fair value of the Company's Level 2 interest rate derivative instruments is measured using quoted market prices or pricing models using prevailing market interest rates as of the measurement date. Counterparty statements are utilized to determine the value of the interest rate derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company's and the counterparties' nonperformance risk is evaluated.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2013 and 2012, 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, 2013, 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, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	19,227	$	—	$	19,227
Insurance contract*	—		62,370		—		62,370
Available-for-sale securities:
Mortgage-backed securities	—		8,193		—		8,193
U.S. Treasury securities	—		1,917		—		1,917
Commodity derivative instruments	—		1,950		—		1,950
Total assets measured at fair value	$	—	$	93,657	$	—	$	93,657
Liabilities:
Commodity derivative instruments	$	—	$	7,483	$	—	$	7,483
Total liabilities measured at fair value	$	—	$	7,483	$	—	$	7,483

* The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

	Fair Value Measurements at December 31, 2012, 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, 2012
	(In thousands)
Assets:
Money market funds	$	—	$	24,240	$	—	$	24,240
Insurance contract*	—		48,898		—		48,898
Available-for-sale securities:
Mortgage-backed securities	—		8,195		—		8,195
U.S. Treasury securities	—		1,806		—		1,806
Commodity derivative instruments	—		18,304		—		18,304
Total assets measured at fair value	$	—	$	101,443	$	—	$	101,443
Liabilities:
Interest rate derivative instruments	$	—	$	6,255	$	—	$	6,255
Total liabilities measured at fair value	$	—	$	6,255	$	—	$	6,255

* The insurance contract invests approximately 28 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies and 15 percent in fixed-income investments.

The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including long-lived asset impairments. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company reviews the carrying value of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying amounts may not be recoverable. During the second quarters of 2013 and 2012, coalbed natural gas gathering assets were reviewed for impairment and found to be impaired and were written down to their estimated fair value using the income approach. Under this approach, fair value is determined by using the present value of future estimated cash flows. The factors used to determine the estimated future cash flows include, but are not limited to, internal estimates of gathering revenue, future commodity prices and operating costs and equipment salvage values. The estimated cash flows are discounted using a rate that approximates the weighted average cost of capital of a market participant. These fair value inputs are not typically observable. At June 30, 2012, certain coalbed natural gas gathering assets were written down to the nonrecurring fair value measurement of $2.5 million. At June 30, 2013, additional coalbed natural gas gathering assets were written down to the nonrecurring fair value measurement of $9.7 million. The fair value of these coalbed natural gas gathering assets have been categorized as Level 3 (Significant Unobservable Inputs) in the fair value hierarchy.

The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The fair value was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt at December 31 was as follows:

	2013				2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
Long-term debt	$	1,854,563	$	1,912,590	$	1,744,975	$	1,888,135

The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.

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Income taxes (Details 12)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]
Threshold of likelihood of tax positions being realized upon ultimate settlement with a taxing authority	50.00%

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Multiemployer other postretirement and defined contribution plans (Details 15) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Multiemployer Plans, Postretirement Benefit [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions	$ 37,100	$ 31,400	$ 24,000
Multiemployer Plans, Defined Contribution [Member]
Multiemployer Plans [Line Items]
Multiemployer plan, period contributions	$ 20,600	$ 18,700	$ 15,300

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Regulatory assets and liabilities

12 Months Ended

Dec. 31, 2013

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	*	2013			2012
			(In thousands)
Regulatory assets:
Deferred income taxes	**		$	125,607		$	121,781
Pension and postretirement benefits (a)	(e)		105,123			166,477
Taxes recoverable from customers (a)	Over plant lives		18,266			9,078
Manufactured gas plant sites remediation (a)	Up to 4 years		15,797			15,828
Natural gas costs recoverable through rate adjustments (b)	Up to 28 months		12,060			2,981
Long-term debt refinancing costs (a)	Up to 25 years		8,697			9,144
Costs related to identifying generation development (a)	Up to 13 years		4,512			5,773
Other (a) (b)	Largely within 1- 5 years		15,311			20,132
Total regulatory assets			305,373			351,194
Regulatory liabilities:
Plant removal and decommissioning costs (c)			308,431			296,037
Deferred income taxes**			64,914			82,077
Taxes refundable to customers (c)			20,180			24,212
Natural gas costs refundable through rate adjustments (d)			16,932			35,328
Other (c) (d)			21,868			12,828
Total regulatory liabilities			432,325			450,482
Net regulatory position			$	(126,952	)	$	(99,288	)

  * Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.

** Represents deferred income taxes related to regulatory assets and liabilities. The deferred income tax assets are not earning a rate of return.

(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.

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. Excluding deferred income taxes, as of December 31, 2013 and 2012, approximately $163.7 million and $215.6 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 as an extraordinary item in the period in which the discontinuance of regulatory accounting occurs.

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Derivative instruments

12 Months Ended

Dec. 31, 2013

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. In the event of a sale, termination or extinguishment of a foreign currency derivative, the resulting gain or loss would be recognized immediately in earnings. The Company's policy requires approval to terminate a derivative instrument prior to its original maturity. As of December 31, 2013, the Company had no outstanding foreign currency hedges.

The fair value of the derivative instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or liability.

The Company evaluates counterparty credit risk on its derivative assets and the Company's credit risk on its derivative liabilities. As of December 31, 2013 and 2012, credit risk was not material.

Fidelity

At December 31, 2013 and 2012, Fidelity held oil swap and collar agreements with total forward notional volumes of 2.9 million and 2.6 million Bbl, respectively, and natural gas swap agreements with total forward notional volumes of 18.3 million and 11.0 million MMBtu, respectively. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on its forecasted sales of oil and natural gas production.

Effective April 1, 2013, Fidelity elected to de-designate all commodity derivative contracts previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively for all of its commodity derivative instruments. When the criteria for hedge accounting is not met or when hedge accounting is not elected, realized gains and losses and unrealized gains and losses are both recorded in operating revenues on the Consolidated Statements of Income. As a result of discontinuing hedge accounting on commodity derivative instruments, gains and losses on the oil and natural gas derivative instruments remain in accumulated other comprehensive income (loss) as of the de-designation date and are reclassified into earnings in future periods as the underlying hedged transactions affect earnings. At April 1, 2013, accumulated other comprehensive income (loss) included $1.8 million of unrealized gains, representing the mark-to-market value of the Company's commodity derivative instruments that qualified as cash flow hedges as of the balance sheet date. The Company expects to reclassify into earnings from accumulated other comprehensive income (loss) the remaining value related to de-designating commodity derivative instruments over the next 12 months.

Prior to April 1, 2013, changes in the fair value attributable to the effective portion of the hedging instruments, net of tax, were recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). To the extent that the hedges were not effective or did not qualify for hedge accounting, the ineffective portion of the changes in fair market value was recorded directly in earnings. Gains and losses on the oil and natural gas derivative instruments were reclassified from accumulated other comprehensive income (loss) into operating revenues on the Consolidated Statements of Income at the date the oil and natural gas quantities were settled.

Centennial

At December 31, 2013, Centennial had no outstanding interest rate swap agreements. At December 31, 2012, Centennial held interest rate swap agreements with a total notional amount of $50.0 million, which were designated as cash flow hedging instruments. Centennial entered into these interest rate derivative instruments to manage a portion of its interest rate exposure on the forecasted issuance of long-term debt.

Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. Gains and losses on the interest rate derivatives are reclassified from accumulated other comprehensive income (loss) into interest expense on the Consolidated Statements of Income in the same period the hedged item affects earnings.

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:

	2013			2012			2011
	(In thousands)
Commodity derivatives designated as cash flow hedges:
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	$	(6,153	)	$	10,209		$	10,806
Amount of gain reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax	(4,916		)	(8,788		)	—
Amount of gain (loss) recognized in operating revenues (ineffective portion), before tax	(1,422		)	(730		)	1,827
Interest rate derivatives designated as cash flow hedges:
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	559			(1,712		)	(2,906		)
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax	727			34			—
Amount of loss recognized in interest expense (ineffective portion), before tax	(769		)	—			—
Commodity derivatives not designated as hedging instruments:
Amount of gain (loss) recognized in operating revenues, before tax	(4,845		)	106			—

Based on December 31, 2013, fair values, over the next 12 months net losses of approximately $700,000 (after tax) are estimated to be reclassified from accumulated other comprehensive income (loss) into earnings, as the hedged transactions affect earnings.

Certain of Fidelity's and Centennial's derivative instruments contain cross-default provisions that state if Fidelity or any of its affiliates or Centennial fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of derivative instruments in liability positions. The aggregate fair value of Fidelity's and Centennial's derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2013 and 2012, were $7.5 million and $6.3 million, respectively. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on December 31, 2013 and 2012, were $7.5 million and $6.3 million, respectively.

The location and fair value of the Company's derivative instruments on the Consolidated Balance Sheets were as follows:

Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2013		Fair Value at December 31, 2012
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	18,084
		—		18,084
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	1,447		220
	Other assets - noncurrent	503		—
		1,950		220
Total asset derivatives		$	1,950	$	18,304

Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at December 31, 2013		Fair Value at December 31, 2012
		(In thousands)
Designated as hedges:
Interest rate derivatives	Other accrued liabilities	$	—	$	6,255
		—		6,255
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	7,483		—
		7,483		—
Total liability derivatives		$	7,483	$	6,255

All of the Company's commodity and interest rate derivative instruments at December 31, 2013 and 2012, were subject to legally enforceable master netting agreements. However, the Company's policy is to not offset fair value amounts for derivative instruments and, as a result, the Company's derivative assets and liabilities are presented gross on the Consolidated Balance Sheets. The gross derivative assets and liabilities (excluding settlement receivables and payables that may be subject to the same master netting agreements) presented on the Consolidated Balance Sheets and the amount eligible for offset under the master netting agreements is presented in the following table:

December 31, 2013	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	1,950	$	(1,950	)	$	—
Total assets	$	1,950	$	(1,950	)	$	—
Liabilities:
Commodity derivatives	$	7,483	$	(1,950	)	$	5,533
Total liabilities	$	7,483	$	(1,950	)	$	5,533

December 31, 2012	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets		Net
	(In thousands)
Assets:
Commodity derivatives	$	18,304	$	—	$	18,304
Total assets	$	18,304	$	—	$	18,304
Liabilities:
Interest rate derivatives	$	6,255	$	—	$	6,255
Total liabilities	$	6,255	$	—	$	6,255

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Debt

12 Months Ended

Dec. 31, 2013

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, 2013			Amount Outstanding at December 31, 2012			Letters of Credit at December 31, 2013			Expiration Date
			(In millions)
MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement	(a)	$	125.0		$	78.9	(b)	$	76.0	(b)	$	—		10/4/17
Cascade Natural Gas Corporation	Revolving credit agreement		$	50.0	(c)	$	11.5		$	2.0		$	2.2	(d)	7/9/18
Intermountain Gas Company	Revolving credit agreement		$	65.0	(e)	$	3.0		$	26.2		$	—		7/13/18
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	75.0	(b)	$	217.0	(b)	$	—		6/8/17

(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 $150 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 million.

(d) The outstanding letter of credit, as discussed in Note 19, reduces the amount available under the credit agreement.

(e) Certain provisions allow for increased borrowings, up to a maximum of $90 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 $650 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

Cascade Natural Gas Corporation On July 9, 2013, Cascade entered into a revolving credit agreement which replaced the previous revolving credit agreement and extended the termination date to July 9, 2018. Any borrowings under the revolving credit agreement would be classified as short-term borrowings as Cascade intends to repay the borrowings within one year. The weighted average interest rate for borrowings outstanding at December 31, 2013, was 3.3 percent.

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.

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. 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). 

On December 12, 2013, MDU Energy Capital entered into a note purchase agreement. MDU Energy Capital contracted to issue $30.0 million of Senior Notes under the agreement on January 27, 2014, with due dates ranging from January 2029 to January 2044 at a weighted average interest rate of 5.3 percent.

Intermountain Gas Company On July 15, 2013, Intermountain entered into a revolving credit agreement which replaced the previous revolving credit agreement and extended the termination date to July 13, 2018. These borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings. The borrowings outstanding as of December 31, 2012, were classified as short-term borrowings because the previous revolving credit agreement expired within one year.

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.

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. On September 12, 2013, WBI Energy Transmission entered into a $175 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, 2013, 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:

	2013			2012
	(In thousands)
Senior Notes at a weighted average rate of 5.52%, due on dates ranging from June 19, 2015 to April 15, 2044	$	1,545,078		$	1,349,160
Commercial paper at a weighted average rate of .40%, supported by revolving credit agreements	153,924			293,000
Term Loan Agreements at a weighted average rate of 2.08%, due on dates ranging from April 22, 2014 to April 22, 2023	75,000			—
Medium-Term Notes at a weighted average rate of 7.32%, due on dates ranging from September 15, 2027 to March 16, 2029	35,000			59,000
Other notes at a weighted average rate of 5.23%, due on dates ranging from September 1, 2020 to February 1, 2035	39,863			40,090
Credit agreements at a weighted average rate of 4.11%, due on dates ranging from February 28, 2014 to November 30, 2038	5,701			3,768
Discount	(3		)	(43		)
Total long-term debt	1,854,563			1,744,975
Less current maturities	12,277			134,108
Net long-term debt	$	1,842,286		$	1,610,867

The amounts of scheduled long-term debt maturities for the five years and thereafter following December 31, 2013, aggregate $12.3 million in 2014; $269.4 million in 2015; $293.8 million in 2016; $204.9 million in 2017; $130.2 million in 2018 and $944.0 million thereafter.

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Reclassifications out of accumulated other comprehensive (loss) (Details 16) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reclassification adjustment out of accumulated other comprehensive income
Operating revenues	$ 1,184,423	$ 1,285,782	$ 1,060,595	$ 931,604	$ 1,081,144	$ 1,173,518	$ 967,962	$ 852,807	$ 4,462,404	$ 4,075,431	$ 4,050,492
Interest expense									(83,917)	(76,699)	(81,354)
Earnings (loss) from equity method investments									(132)	5,383	4,693
Income before income taxes									415,618	(45,467)	336,226
Income taxes									136,736	(31,146)	110,274
Net income (loss)									278,570	(754)	213,026
Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income
Income before income taxes									6,737
Income taxes									(2,548)
Net income (loss)									4,189
Amortization of postretirement liability losses included in net periodic benefit cost
Reclassification adjustment out of accumulated other comprehensive income
Net periodic benefit cost									(3,277)
Income taxes									1,276
Net income (loss)									(2,001)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income
Reclassification adjustment out of accumulated other comprehensive income
Earnings (loss) from equity method investments									(213)
Earnings (loss) from equity method investments, tax									70
Net income (loss)									(143)
Reclassification adjustment for loss on available-for-sale investments included in net income [Member]
Reclassification adjustment out of accumulated other comprehensive income
Other income									(168)
Income taxes									59
Net income (loss)									(109)
Total reclassifications
Reclassification adjustment out of accumulated other comprehensive income
Net income (loss)									(1,936)
Commodity derivative instruments [Member] | Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income
Operating revenues									7,803
Interest rate derivative instruments [Member] | Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income
Interest expense									$ (1,066)

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Quarterly Financial Information (Unaudited) (Details) (USD $) Share data in Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating revenues	$ 1,184,423,000	$ 1,285,782,000	$ 1,060,595,000	$ 931,604,000	$ 1,081,144,000	$ 1,173,518,000	$ 967,962,000	$ 852,807,000	$ 4,462,404,000		$ 4,075,431,000		$ 4,050,492,000
Total operating expenses	1,037,306,000	1,135,909,000	969,217,000	827,073,000	1,190,673,000	1,207,553,000	876,248,000	781,750,000	3,969,505,000		4,056,224,000		3,644,125,000
Operating income	147,117,000	149,873,000	91,378,000	104,531,000	(109,529,000)	(34,035,000)	91,714,000	71,057,000	492,899,000		19,207,000		406,367,000
Income from continuing operations	91,348,000	84,550,000	46,392,000	56,592,000	(69,686,000)	(29,532,000)	49,007,000	35,890,000	278,882,000		(14,321,000)		225,952,000
Income (loss) from discontinued operations, net of tax	(58,000)	(118,000)	(59,000)	(77,000)	8,700,000	(139,000)	5,106,000	(100,000)	(312,000)	[1]	13,567,000	[1]	(12,926,000)	[1]
Net income (loss) attributable to parent	91,450,000	84,456,000	46,512,000	56,515,000	(60,986,000)	(29,671,000)	54,113,000	35,790,000
Earnings (loss) per common share - basic [Abstract]
Earnings before discontinued operations	$ 0.48	$ 0.45	$ 0.25	$ 0.30	$ (0.37)	$ (0.16)	$ 0.26	$ 0.19	$ 1.47		$ (0.08)		$ 1.19
Discontinued operations, net of tax	$ 0.00	$ 0.00	$ 0.00	$ 0.00	$ 0.05	$ 0.00	$ 0.03	$ 0.00	$ 0.00		$ 0.07		$ (0.07)
Earnings (loss) per common share - basic	$ 0.48	$ 0.45	$ 0.25	$ 0.30	$ (0.32)	$ (0.16)	$ 0.29	$ 0.19	$ 1.47		$ (0.01)		$ 1.12
Earnings per common share - diluted [Abstract]
Earnings before discontinued operations	$ 0.48	$ 0.44	$ 0.24	$ 0.30	$ (0.37)	$ (0.16)	$ 0.26	$ 0.19	$ 1.47		$ (0.08)		$ 1.19
Discontinued operations, net of tax	$ 0.00	$ 0.00	$ 0.00	$ 0.00	$ 0.05	$ 0.00	$ 0.03	$ 0.00	$ 0.00		$ 0.07		$ (0.07)
Earnings (loss) per common share - diluted	$ 0.48	$ 0.44	$ 0.24	$ 0.30	$ (0.32)	$ (0.16)	$ 0.29	$ 0.19	$ 1.47		$ (0.01)		$ 1.12
Weighted average common shares outstanding - basic	188,929	188,831	188,831	188,831	188,831	188,831	188,831	188,811	188,855		188,826		188,763
Weighted average common shares outstanding - diluted	189,766	189,638	189,463	189,222	188,831	188,831	189,107	189,182	189,693		188,826		188,905
Unrealized gain (loss) on commodity derivatives	(500,000)	(7,900,000)	8,200,000	(3,700,000)	(200,000)	(700,000)	3,000,000	(2,600,000)
Asset impairment charges			9,000,000				1,700,000		9,000,000		1,700,000
Reversal of an arbitration charge after tax	1,500,000				13,000,000		15,000,000		1,500,000		15,000,000
Noncash write-downs of oil and natural gas properties, after tax					$ 145,900,000	$ 100,900,000					$ 246,800,000

[1] Reflected in the Other category.

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Stock based compensation plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 Y	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation [Abstract]
Share-based compensation arrangement, number of shares available for grant	6.2
Share-based compensation expense	$ 3.9	$ 4.0	$ 3.5
Share based compensation nonvested awards total compensation cost not yet recognized	$ 7.0
Share-based compensation, nonvested awards, total compensation cost not yet recognized, period for recognition	1.6

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Discontinued operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Dec. 31, 2011
Discontinued Operations and Disposal Groups [Abstract]
Arbitration charge related to a guarantee	$ 21.0
Arbitration charge after tax	$ 13.0

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Health care rate assumptions and cost trend rate (Details 7) (Other Postretirement Benefits, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate assumed for next year (minimum)	6.00%	6.00%
Health care trend rate assumed for next year (maximum)	7.00%	8.00%
Health care cost trend rate - ultimate (minimum)	5.00%	5.00%
Health care cost trend rate - ultimate (maximum)	6.00%	6.00%
Year In which ultimate trend rate achieved, (maximum)	2017	2017
Percentage excess over the health care cost trend rate that retiree contributions will generally increase each year	6.00%
Effect on total of service and interest cost components, one percentage point increase	$ 159
Effect on total of service and interest cost components, one percentage point decrease	(135)
Effect on postretirement benefit obligations, one percentage point increase	3,352
Effect on postretirement benefit obligations, one percentage point decrease	$ (2,920)

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Comprehensive income (loss) (Details 15) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	$ (48,721)	$ (47,001)
Other comprehensive income (loss) before reclassifications	12,452
Amounts reclassified from accumulated other comprehensive loss	(1,936)
Net current-period other comprehensive income (loss)	10,516	(1,720)	(15,740)
Balance	(38,205)	(48,721)	(47,001)
Net unrealized gain (loss) on derivative instruments qualifying as hedges
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	6,018	6,275
Other comprehensive income (loss) before reclassifications	(5,594)
Amounts reclassified from accumulated other comprehensive loss	(4,189)
Net current-period other comprehensive income (loss)	(9,783)	(257)
Balance	(3,765)	6,018
Postretirement liability adjustment
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(54,347)	(53,320)
Other comprehensive income (loss) before reclassifications	18,539
Amounts reclassified from accumulated other comprehensive loss	2,001
Net current-period other comprehensive income (loss)	20,540	(1,027)
Balance	(33,807)	(54,347)
Foreign currency translation adjustment
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(511)	(38)
Other comprehensive income (loss) before reclassifications	(299)
Amounts reclassified from accumulated other comprehensive loss	143
Net current-period other comprehensive income (loss)	(156)	(473)
Balance	(667)	(511)
Net unrealized gains on available-for-sale investments
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	119	82
Other comprehensive income (loss) before reclassifications	(194)
Amounts reclassified from accumulated other comprehensive loss	109
Net current-period other comprehensive income (loss)	(85)	37
Balance	$ 34	$ 119

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Deferred tax reconciliation (Details 4) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in net deferred income tax liability from the preceding table	$ 102,002
Deferred taxes associated with other comprehensive loss	(7,277)
Other	(7,947)
Deferred income tax expense for the period	$ 86,778	$ (7,503)	$ 118,925

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Condensed Balance Sheets (Details 2) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 45,225		$ 49,042		$ 162,772		$ 222,074
Receivables, net	713,067		678,123
Inventories	282,391		317,415
Deferred income taxes	25,048		22,846
Prepayments and other current assets	49,510		42,351
Total current assets	1,116,688		1,128,081
Investments	112,939		103,243
Property, plant and equipment	8,803,866		8,107,751
Less accumulated depreciation, depletion and amortization	3,872,487		3,608,912		3,361,208
Net property, plant and equipment	4,931,379		4,498,839		4,285,014
Deferred charges and other assets:
Goodwill	636,039	[1]	636,039	[1]	634,931	[1]
Other	251,188		299,160
Total deferred charges and other assets	900,326		952,328
Total assets	7,061,332		6,682,491		6,556,125
Current liabilities:
Long-term debt due within one year	12,277		134,108
Accounts payable	404,961		388,015
Taxes payable	74,175		46,475
Dividends payable	33,737		171
Accrued compensation	69,661		48,448
Other accrued liabilities	171,106		204,698
Total current liabilities	784,900		850,115
Long-term debt	1,842,286		1,610,867
Deferred credits and other liabilities:
Deferred income taxes	859,306		755,102
Other liabilities	718,938		818,159
Total deferred credits and other liabilities	1,578,244		1,573,261
Equity:
Preferred stocks	15,000		15,000
Authorized - 500,000,000 shares, $1.00 par value
Issued - 189,868,780 shares in 2013 and 189,369,450 shares in 2012	189,869		189,369
Other paid-in capital	1,056,996		1,039,080
Retained earnings	1,603,130		1,457,146
Accumulated other comprehensive loss	(38,205)		(48,721)		(47,001)
Treasury stock at cost - 538,921 shares	(3,626)		(3,626)
Total common stockholders' equity	2,808,164		2,633,248
Total stockholders' equity	2,823,164		2,648,248
Total liabilities and stockholders' equity	7,061,332		6,682,491
Condensed Balance Sheet (Parenthetical)
Common stock, shares authorized	500,000,000		500,000,000
Common stock, par value	$ 1.00		$ 1.00
Common stock, shares issued	189,868,780		189,369,450
Treasury stock, shares	538,921		538,921
MDU Resources Group, Inc. [Member]
Current assets:
Cash and cash equivalents	5,051		3,596		6,900		6,275
Receivables, net	88,529		89,238
Accounts receivable from subsidiaries	31,372		2,957
Inventories	29,312		41,469
Deferred income taxes	3,196		3,685
Prepayments and other current assets	14,231		9,120
Total current assets	171,691		150,065
Investments	60,687		52,123
Investment in subsidiaries	2,380,829		2,253,294
Property, plant and equipment	1,785,861		1,581,776
Less accumulated depreciation, depletion and amortization	660,693		621,623
Net property, plant and equipment	1,125,168		960,153
Deferred charges and other assets:
Goodwill	4,812		4,812
Other	121,253		155,483
Total deferred charges and other assets	126,065		160,295
Total assets	3,864,440		3,575,930
Current liabilities:
Long-term debt due within one year	109		108
Accounts payable	45,282		42,149
Accounts payable to subsidiaries	4,839		6,423
Taxes payable	12,337		12,399
Dividends payable	33,737		171
Accrued compensation	16,076		10,282
Other accrued liabilities	28,042		29,490
Total current liabilities	140,422		101,022
Long-term debt	434,598		356,760
Deferred credits and other liabilities:
Deferred income taxes	205,639		172,769
Other liabilities	260,617		297,131
Total deferred credits and other liabilities	466,256		469,900
Equity:
Preferred stocks	15,000		15,000
Authorized - 500,000,000 shares, $1.00 par value
Issued - 189,868,780 shares in 2013 and 189,369,450 shares in 2012	189,869		189,369
Other paid-in capital	1,056,996		1,039,080
Retained earnings	1,603,130		1,457,146
Accumulated other comprehensive loss	(38,205)		(48,721)
Treasury stock at cost - 538,921 shares	(3,626)		(3,626)
Total common stockholders' equity	2,808,164		2,633,248
Total stockholders' equity	2,823,164		2,648,248
Total liabilities and stockholders' equity	$ 3,864,440		$ 3,575,930
Condensed Balance Sheet (Parenthetical)
Common stock, shares authorized	500,000,000		500,000,000
Common stock, par value	$ 1.00		$ 1.00
Common stock, shares issued	189,868,780		189,369,450
Treasury stock, shares	538,921		538,921

[1] Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

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Goodwill and other intangible assets (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill [Line Items]

Changes in the carrying amount of goodwill

The changes in the carrying amount of goodwill for the year ended December 31, 2013, were as follows:

	Balance at January 1, 2013		*	Goodwill Acquired During the Year		Balance at December 31, 2013		*
	(In thousands)
Natural gas distribution	$	345,736		$	—	$	345,736
Pipeline and energy services	9,737			—		9,737
Construction materials and contracting	176,290			—		176,290
Construction services	104,276			—		104,276
Total	$	636,039		$	—	$	636,039

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

The changes in the carrying amount of goodwill for the year ended December 31, 2012, were as follows:

	Balance at January 1, 2012		*	Goodwill Acquired During the Year		**	Balance at December 31, 2012		*
	(In thousands)
Natural gas distribution	$	345,736		$	—		$	345,736
Pipeline and energy services	9,737			—			9,737
Construction materials and contracting	176,290			—			176,290
Construction services	103,168			1,108			104,276
Total	$	634,931		$	1,108		$	636,039

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.

** Includes contingent consideration that was not material related to an acquisition in a prior period.

Other amortizable intangible assets

Other amortizable intangible assets at December 31 were as follows:

	2013			2012
	(In thousands)
Customer relationships	$	21,310		$	21,310
Accumulated amortization	(13,726		)	(11,701		)
	7,584			9,609
Noncompete agreements	6,186			7,236
Accumulated amortization	(4,840		)	(5,326		)
	1,346			1,910
Other	10,995			10,979
Accumulated amortization	(6,826		)	(5,369		)
	4,169			5,610
Total	$	13,099		$	17,129

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Property, plant and equipment (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Property, plant and equipment [Line Items]
Interest capitalized	$ 6,033		$ 8,659		$ 10,821
AFUDC - borrowed	2,767		2,483		1,666
AFUDC - equity	3,322		4,530		2,587
Property, plant and equipment	8,803,866		8,107,751
Less accumulated depreciation, depletion and amortization	3,872,487		3,608,912		3,361,208
Net property, plant and equipment	4,931,379		4,498,839		4,285,014
BOE average rate for amortization under units-of-production method (in dollars per BOE)	17.41		15.28		12.25
Oil and natural gas properties not subject to amortization	124,869		191,794		232,462
Electric:
Property, plant and equipment [Line Items]
Property, plant and equipment	1,315,822	[1]	1,150,584	[1]	1,068,524	[1]
Natural gas distribution:
Property, plant and equipment [Line Items]
Property, plant and equipment	1,776,901	[1]	1,689,950	[1]	1,568,866	[1]
Pipeline and energy services:
Property, plant and equipment [Line Items]
Property, plant and equipment	962,172		816,533		719,291
Exploration and production:
Property, plant and equipment [Line Items]
Property, plant and equipment	3,060,848		2,764,560		2,615,146
Construction materials and contracting:
Property, plant and equipment [Line Items]
Property, plant and equipment	1,510,355		1,504,981		1,499,852
Construction services:
Property, plant and equipment [Line Items]
Property, plant and equipment	134,948		130,624		124,796
Other:
Property, plant and equipment [Line Items]
Property, plant and equipment	49,997		50,519		49,747
Regulated: | Electric: | Generation
Property, plant and equipment [Line Items]
Property, plant and equipment	570,394		546,011
Weighted average depreciable life in years	42 years
Regulated: | Electric: | Distribution
Property, plant and equipment [Line Items]
Property, plant and equipment	308,202		276,446
Weighted average depreciable life in years	39 years
Regulated: | Electric: | Transmission
Property, plant and equipment [Line Items]
Property, plant and equipment	196,824		180,543
Weighted average depreciable life in years	48 years
Regulated: | Electric: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	141,365		62,123
Regulated: | Electric: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	99,037		85,461
Weighted average depreciable life in years	14 years
Regulated: | Natural gas distribution: | Distribution
Property, plant and equipment [Line Items]
Property, plant and equipment	1,384,587		1,308,314
Weighted average depreciable life in years	40 years
Regulated: | Natural gas distribution: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	46,763		71,679
Regulated: | Natural gas distribution: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	345,551		309,957
Weighted average depreciable life in years	25 years
Regulated: | Pipeline and energy services: | Transmission
Property, plant and equipment [Line Items]
Property, plant and equipment	418,594		403,126
Weighted average depreciable life in years	52 years
Regulated: | Pipeline and energy services: | Gathering
Property, plant and equipment [Line Items]
Property, plant and equipment	39,597		42,420
Weighted average depreciable life in years	19 years
Regulated: | Pipeline and energy services: | Storage
Property, plant and equipment [Line Items]
Property, plant and equipment	42,939		42,058
Weighted average depreciable life in years	51 years
Regulated: | Pipeline and energy services: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	6,937		13,667
Regulated: | Pipeline and energy services: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	39,504		38,386
Weighted average depreciable life in years	29 years
Nonregulated: | Eliminations
Property, plant and equipment [Line Items]
Property, plant and equipment	(7,177)		0
Nonregulated: | Pipeline and energy services: | Midstream
Property, plant and equipment [Line Items]
Property, plant and equipment	213,063		233,840
Weighted average depreciable life in years	17 years
Nonregulated: | Pipeline and energy services: | Construction in progress
Property, plant and equipment [Line Items]
Property, plant and equipment	188,641		29,657
Nonregulated: | Pipeline and energy services: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	12,897		13,379
Weighted average depreciable life in years	11 years
Nonregulated: | Exploration and production: | Oil and natural gas properties
Property, plant and equipment [Line Items]
Property, plant and equipment	3,017,879	[2]	2,723,356	[2]
Nonregulated: | Exploration and production: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	42,969		41,204
Weighted average depreciable life in years	8 years
Nonregulated: | Construction materials and contracting: | Land
Property, plant and equipment [Line Items]
Property, plant and equipment	125,551		126,788
Nonregulated: | Construction materials and contracting: | Buildings and improvements
Property, plant and equipment [Line Items]
Property, plant and equipment	70,000		73,884
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	906,774		899,592
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	13,315		11,165
Nonregulated: | Construction materials and contracting: | Aggregate reserves
Property, plant and equipment [Line Items]
Property, plant and equipment	394,715	[3]	393,552	[3]
Nonregulated: | Construction services: | Land
Property, plant and equipment [Line Items]
Property, plant and equipment	4,821		4,723
Nonregulated: | Construction services: | Buildings and improvements
Property, plant and equipment [Line Items]
Property, plant and equipment	16,628		16,563
Weighted average depreciable life in years	20 years
Nonregulated: | Construction services: | Machinery, vehicles and equipment
Property, plant and equipment [Line Items]
Property, plant and equipment	105,991		100,445
Weighted average depreciable life in years	6 years
Nonregulated: | Construction services: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	7,508		8,893
Weighted average depreciable life in years	4 years
Nonregulated: | Other: | Land
Property, plant and equipment [Line Items]
Property, plant and equipment	2,837		2,837
Nonregulated: | Other: | Other
Property, plant and equipment [Line Items]
Property, plant and equipment	$ 47,160		$ 47,682
Weighted average depreciable life in years	23 years

[1] Includes allocations of common utility property.

[2] Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $17.41, $15.28 and $12.25 for the years ended December 31, 2013, 2012 and 2011, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $124.9 million and $191.8 million were excluded from amortization at December 31, 2013 and 2012, respectively.

[3] Depleted on the units-of-production method.

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The components of income (loss) before income taxes from continuing operations for each of the years ended December 31 were as follows:

	2013		2012			2011
	(In thousands)
United States	$	415,202	$	(47,175	)	$	333,486
Foreign	416		1,708			2,740
Income (loss) before income taxes from continuing operations	$	415,618	$	(45,467	)	$	336,226

Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:

	2013			2012			2011
	(In thousands)
Current:
Federal	$	45,518		$	(26,858	)	$	(7,188	)
State	4,311			858			778
Foreign	(29		)	(75		)	127
	49,800			(26,075		)	(6,283		)
Deferred:
Income taxes:
Federal	78,953			(1,224		)	105,528
State	8,031			(6,323		)	13,157
Investment tax credit - net	(206		)	44			240
	86,778			(7,503		)	118,925
Change in uncertain tax positions	—			1,974			(1,048		)
Change in accrued interest	158			458			(1,320		)
Total income tax expense (benefit)	$	136,736		$	(31,146	)	$	110,274

Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:

	2013			2012
	(In thousands)
Deferred tax assets:
Regulatory matters	$	125,607		$	121,781
Accrued pension costs	74,320			85,037
Alternative minimum tax credit carryforward	33,304			—
Compensation-related	31,550			23,441
Asset retirement obligations	29,578			26,748
Legal and environmental contingencies	10,710			8,046
Other	45,101			39,792
Total deferred tax assets	350,170			304,845
Deferred tax liabilities:
Depreciation and basis differences on property, plant and equipment	813,597			755,392
Basis differences on oil and natural gas producing properties	266,168			167,113
Regulatory matters	64,914			82,077
Intangible asset amortization	13,579			14,078
Other	26,170			18,441
Total deferred tax liabilities	1,184,428			1,037,101
Net deferred income tax liability	$	(834,258	)	$	(732,256	)

As of December 31, 2013 and 2012, no valuation allowance has been recorded associated with the previously identified deferred tax assets. The alternative minimum tax credit carryforwards do not expire.

The following table reconciles the change in the net deferred income tax liability from December 31, 2012, to December 31, 2013, to deferred income tax expense:

	2013
(In thousands)
Change in net deferred income tax liability from the preceding table	$	102,002
Deferred taxes associated with other comprehensive loss	(7,277		)
Other	(7,947		)
Deferred income tax expense for the period	$	86,778

Total income tax expense (benefit) differs from the amount computed by applying the statutory federal income tax rate to income (loss) before taxes. The reasons for this difference were as follows:

Years ended December 31,	2013					2012					2011
	Amount			%		Amount			%		Amount			%
	(Dollars in thousands)
Computed tax at federal statutory rate	$	145,466		35.0		$	(15,914	)	35.0		$	117,679		35.0
Increases (reductions) resulting from:
State income taxes, net of federal income tax	10,524			2.5		2,469			(5.4	)	10,653			3.2
Nonqualified benefit plans	(5,173		)	(1.2	)	(2,359		)	5.2		(2,918		)	(.9	)
Depletion allowance	(3,764		)	(.9	)	(3,728		)	8.2		(3,266		)	(1.0	)
Federal renewable energy credit	(3,404		)	(.8	)	(3,401		)	7.5		(3,485		)	(1.0	)
Deductible K-Plan dividends	(1,593		)	(.4	)	(2,829		)	6.2		(2,282		)	(.7	)
AFUDC equity	(1,074		)	(.3	)	(1,500		)	3.3		(873		)	(.3	)
Resolution of tax matters and uncertain tax positions	(859		)	(.2	)	2,559			(5.6	)	(3,906		)	(1.2	)
Deferred tax rate changes	741			.2		(3,083		)	6.8		(417		)	(.1	)
Other	(4,128		)	(1.0	)	(3,360		)	7.3		(911		)	(.2	)
Total income tax expense (benefit)	$	136,736		32.9		$	(31,146	)	68.5		$	110,274		32.8

The income tax benefit in 2012 resulted largely from the Company's write-downs of oil and natural gas properties, as discussed in Note 1.

Deferred income taxes have been accrued with respect to temporary differences related to the Company's foreign operations. The amount of cumulative undistributed earnings for which there are temporary differences is approximately $7.0 million at December 31, 2013. The amount of deferred tax liability, net of allowable foreign tax credits, associated with the undistributed earnings at December 31, 2013, was approximately $2.2 million.

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state, local and foreign jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years ending prior to 2007. The 2007 through 2009 tax years are currently under audit.

A reconciliation of the unrecognized tax benefits (excluding interest) for the years ended December 31 was as follows:

	2013		2012		2011
	(In thousands)
Balance at beginning of year	$	14,914	$	11,206	$	9,378
Additions for tax positions of prior years	—		3,708		4,172
Settlements	—		—		(2,344		)
Balance at end of year	$	14,914	$	14,914	$	11,206

Included in the balance of unrecognized tax benefits at December 31, 2013 and 2012, were $8.4 million and $8.4 million, respectively, of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate was $9.0 million, including approximately $2.5 million for the payment of interest and penalties at December 31, 2013, and was $8.5 million, including approximately $2.0 million for the payment of interest and penalties at December 31, 2012.

It is likely that substantially all of the unrecognized tax benefits, as well as interest, at December 31, 2013, will be settled in the next twelve months due to the anticipated settlement of federal and state audits.

For the years ended December 31, 2013, 2012 and 2011, the Company recognized approximately $1.2 million, $740,000 and $780,000, respectively, in interest expense. Penalties were not material in 2013, 2012 and 2011. The Company recognized interest income of approximately $660,000, $290,000 and $1.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. The Company had accrued liabilities of approximately $2.8 million and $1.4 million at December 31, 2013 and 2012, respectively, for the payment of interest.

In September 2013, the Internal Revenue Service released final regulations relating to the capitalization of tangible personal property which are effective for tax years beginning on or after January 1, 2014. The Company does not expect these new regulations to have a material effect on its results of operations, financial position or cash flows.

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Operating leases (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Leases, Annual minimum lease payments due [Abstract]
2014	$ 32.8
2015	26.6
2016	22.2
2017	17.8
2018	13.5
Thereafter	45.7
Rent expense
Rent expense	$ 48.1	$ 42.9	$ 40.7

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

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 $29.5 million and $22.5 million for contingencies, including litigation, production taxes, royalty claims and environmental matters as of December 31, 2013 and 2012, respectively, which include amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note.

Litigation

Guarantee Obligation Under a Construction Contract Centennial guaranteed CEM's obligations under a construction contract with LPP for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. Centennial Resources sold CEM in July 2007 to Bicent. In February 2009, Centennial received a Notice and Demand from LPP under the guarantee agreement alleging that CEM did not meet certain of its obligations under the construction contract and demanding that Centennial indemnify LPP against all losses, damages, claims, costs, charges and expenses arising from CEM's alleged failures. In December 2009, LPP submitted a demand for arbitration of its dispute with CEM to the American Arbitration Association seeking compensatory damages of $149.7 million. An arbitration award was issued January 13, 2012, awarding LPP $22.0 million. Centennial subsequently received a demand from LPP for payment of the arbitration award plus interest and attorneys' fees. An accrual related to the guarantee as a result of the arbitration award was recorded in discontinued operations on the Consolidated Statement of Income in the fourth quarter of 2011. CEM filed a petition with the New York Supreme Court to vacate the arbitration award in favor of LPP. On October 19, 2012, Centennial moved to intervene in the New York Supreme Court action to vacate the arbitration award and also filed a complaint with the New York Supreme Court seeking a declaration that LPP is not entitled to indemnification from Centennial under the guaranty for the arbitration award. The New York Supreme Court granted CEM's petition to vacate the arbitration award on November 20, 2012, and entered an order and judgment to that effect on June 5, 2013. LPP appealed the order and judgment and on February 20, 2014, the New York Supreme Court Appellate Division ruled the arbitration award was properly vacated. Due to the vacation of the arbitration award, the Company no longer believes the loss related to this matter to be probable and thus the liability that was previously recorded in 2011 was reversed in the fourth quarter of 2012. The effect of this was recorded in discontinued operations on the Consolidated Statement of Income. For more information regarding discontinued operations, see Note 3.

Construction MaterialsUntil the fall of 2011 when it discontinued active mining operations at the pit, JTL operated the Target Range Gravel Pit in Missoula County, Montana under a 1975 reclamation contract pursuant to the Montana Opencut Mining Act. In September 2009, the Montana DEQ sent a letter asserting JTL was in violation of the Montana Opencut Mining Act by conducting mining operations outside a permitted area. JTL filed a complaint in Montana First Judicial District Court in June 2010, seeking a declaratory order that the reclamation contract is a valid permit under the Montana Opencut Mining Act. The Montana DEQ filed an answer and counterclaim to the complaint in August 2011, alleging JTL was in violation of the Montana Opencut Mining Act and requesting imposition of penalties of not more than $3.7 million plus not more than $5,000 per day from the date of the counterclaim. The Company believes the operation of the Target Range Gravel Pit was conducted under a valid permit; however, the imposition of civil penalties is reasonably possible. The Company filed an application for amendment of its opencut mining permit and intends to resolve this matter through settlement or continuation of the Montana First Judicial District Court litigation.

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. An arbitration hearing was held in August 2010. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. As a result, WBI Energy Midstream, which is included in the pipeline and energy services segment, recorded a $26.6 million charge ($16.5 million after tax) in the third quarter of 2010. On April 20, 2011, the Colorado State District Court confirmed the arbitration award as a court judgment. WBI Energy Midstream filed an appeal from the Colorado State District Court's order and judgment to the Colorado Court of Appeals. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. As a result of the Colorado Court of Appeals decision, in the second quarter of 2012, WBI Energy Midstream changed its estimated loss related to this matter. This resulted in a reduction of expense of $24.1 million ($15.0 million after tax), which was largely reflected in operation and maintenance expense on the Consolidated Statements of Income. On August 2, 2012, SourceGas filed a petition for writ of certiorari with the Colorado Supreme Court for review of the Colorado Court of Appeals decision which was denied on July 22, 2013. On remand of the matter to the Colorado State District Court, SourceGas may assert claims similar to those asserted in the arbitration proceeding.

In a related matter, Omimex filed a complaint against WBI Energy Midstream in Montana Seventeenth Judicial District Court in July 2010 alleging WBI Energy Midstream breached a separate gathering contract with Omimex as a result of the increased operating pressures demanded by SourceGas on the same natural gas gathering system. In December 2011, Omimex filed an amended complaint alleging WBI Energy Midstream breached obligations to operate its gathering system as a common carrier under United States and Montana law. WBI Energy Midstream removed the action to the United States District Court for the District of Montana. The parties subsequently settled the breach of contract claim and, subject to final determination on liability, stipulated to the damages on the common carrier claim, for amounts that are not material. A trial on the common carrier claim was held during July 2013, but a decision has not been issued.

Exploration and Production During the ordinary course of its business, Fidelity is subject to audit for various production related taxes by certain state and federal tax authorities for varying periods as well as claims for royalty obligations under lease agreements for oil and gas production. Disputes may exist regarding facts and questions of law relating to the tax and royalty obligations.

On May 15, 2013, Austin Holdings, LLC filed an action against Fidelity in Wyoming State District Court alleging Fidelity violated the Wyoming Royalty Payment Act and implied lease covenants by deducting production costs from and by failing to properly report and pay royalties for coalbed methane gas production in Wyoming. The plaintiff, in addition to declaratory and injunctive relief, seeks class certification for similarly situated persons and an unspecified amount of monetary damages on behalf of the class for unpaid royalties, interest, reporting violations and attorney fees. Fidelity believes it has meritorious defenses against class certification and the claims.

The Company also is subject to other litigation, and actual and potential claims in the ordinary course of its business which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. Accruals are based on the best information available but actual losses in future periods are affected by various factors making them uncertain. After taking into account liabilities accrued for the foregoing matters, management believes that the outcomes with respect to the above issues and other probable and reasonably possible losses in excess of the amounts accrued, while uncertain, will not have a material effect upon the Company's financial position, results of operations or cash flows.

Environmental matters

Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include Knife River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. Knife River - Northwest also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Portland Harbor Natural Resource Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.

Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, Knife River - Northwest does not believe it is a Responsible Party. In addition, Knife River - Northwest has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement. Knife River - Northwest has entered into an agreement tolling the statute of limitations in connection with the LWG's potential claim for contribution to the costs of the remedial investigation and feasibility study. By letter in March 2009, LWG stated its intent to file suit against Knife River - Northwest and others to recover LWG's investigation costs to the extent Knife River - Northwest cannot demonstrate its non-liability for the contamination or is unwilling to participate in an alternative dispute resolution process that has been established to address the matter. At this time, Knife River - Northwest has agreed to participate in the alternative dispute resolution process.

The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced administrative action.

Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade's predecessors.

The first claim is for contamination at a site in Eugene, Oregon which was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. The Oregon DEQ is preparing a staff report which will recommend a cleanup alternative for the site. 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 $1.3 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 an order reauthorizing the deferred accounting for the 12 months starting November 30, 2013.

The second claim is for contamination at a site in Bremerton, Washington which was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to $6.4 million. Data developed through the assessment and previous investigations indicates the contamination likely derived from multiple, different sources and multiple current and former owners of properties and businesses in the vicinity of the site may be responsible for the contamination. In April 2010, the Washington Department of Ecology issued notice it considered Cascade a PRP for hazardous substances at the site. In May 2012, the EPA added the site to the National Priorities List of Superfund sites. Cascade has entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. Cascade has accrued $12.0 million for the remedial investigation, feasibility study and remediation of this site. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.

The third claim is for contamination at a site in Bellingham, Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade and its predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. Other PRPs have reached an agreed order and work plan with the Washington Department of Ecology for completion of a remedial investigation and feasibility study for the site. A report documenting the initial phase of the remedial investigation was completed in June 2011. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim although Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, it converted the plant to a propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas.

Cascade has received notices from and entered into agreement with certain of its insurance carriers that they will participate in defense of Cascade for these contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers. The accruals related to these matters are reflected in regulatory assets. For more information, see Note 6.

Operating leases

The Company leases certain equipment, facilities and land under operating lease agreements. The amounts of annual minimum lease payments due under these leases as of December 31, 2013, were $32.8 million in 2014, $26.6 million in 2015, $22.2 million in 2016, $17.8 million in 2017, $13.5 million in 2018 and $45.7 million thereafter. Rent expense was $48.1 million, $42.9 million and $40.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Purchase commitments

The Company has entered into various commitments, largely construction, natural gas and coal supply, purchased power, natural gas transportation and storage, service, shipping and construction materials supply contracts, some of which are subject to variability in volume and price. These commitments range from one to 47 years. The commitments under these contracts as of December 31, 2013, were $635.8 million in 2014, $281.6 million in 2015, $170.7 million in 2016, $100.3 million in 2017, $73.4 million in 2018 and $910.8 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, 2013, 2012 and 2011, were $861.8 million, $718.4 million and $626.3 million, respectively.

Guarantees

Centennial guaranteed CEM's obligations under a construction contract. For more information, see Litigation in this note.

In connection with the sale of the Brazilian Transmission Lines, as discussed in Note 4, Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines.

WBI Holdings has guaranteed certain of Fidelity's oil and natural gas swap agreement obligations. There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices. The amount of derivative activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap agreements at December 31, 2013, expire in the years ranging from 2014 to 2015; however, Fidelity continues to enter into additional derivative instruments and, as a result, WBI Holdings from time to time may issue additional guarantees on these derivative instruments. The amount outstanding by Fidelity was $4.8 million and was reflected on the Consolidated Balance Sheet at December 31, 2013. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees.

Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts and certain other guarantees. At December 31, 2013, the fixed maximum amounts guaranteed under these agreements aggregated $54.4 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $32.5 million in 2014; $2.1 million in 2015; $700,000 in 2016; $600,000 in 2017; $500,000 in 2018; $500,000 in 2019; $13.5 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $200,000 and was reflected on the Consolidated Balance Sheet at December 31, 2013. 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, 2013, the fixed maximum amounts guaranteed under these letters of credit, aggregated $36.0 million and are scheduled to expire in 2014. There were no amounts outstanding under the above letters of credit at December 31, 2013.

WBI Holdings has an outstanding guarantee to WBI Energy Transmission. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of Prairielands. At December 31, 2013, the fixed maximum amount guaranteed under this agreement was $5.0 million and is scheduled to expire in 2014. In the event of Prairielands' default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $800,000. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at December 31, 2013, because this intercompany transaction was eliminated in consolidation.

In addition, Centennial, Knife River and MDU Construction Services have issued guarantees to third parties related to the routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under these obligations, Centennial, Knife River and MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these guarantees were reflected on the Consolidated Balance Sheet at December 31, 2013.

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, 2013, approximately $516 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, LLCOn February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate Dakota Prairie Refinery in southwestern North Dakota. WBI Energy and Calumet each have a 50 percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments, based on a total project cost of $300 million, under the agreement are $150 million and $75 million, respectively. Capital commitments in excess of $300 million are expected to be shared equally between WBI Energy and Calumet. The total project cost is currently estimated at $350 million. Dakota Prairie Refining entered into a term loan for project debt financing of $75 million on April 22, 2013. The operating agreement provides for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt will be allocated to Calumet. Calumet's future cash distributions from Dakota Prairie Refining will be decreased by the principal and interest to be paid on the project debt, while the cash distributions to WBI Energy will not be decreased. Pursuant to the operating agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan.

Dakota Prairie Refining has been determined to be a VIE, and the Company has determined that it is the primary beneficiary as it has an obligation to absorb losses that could be potentially significant to the VIE through WBI Energy's equity investment and Centennial's guarantee of the third-party term loan. Accordingly, the Company consolidates Dakota Prairie Refining in its financial statements and records a noncontrolling interest for Calumet's ownership interest.

Construction of Dakota Prairie Refinery began in early 2013 and the plant is not yet operational. Therefore, the results of operations of Dakota Prairie Refining did not have a material effect on the Company's Consolidated Statements of Income. The assets of Dakota Prairie Refining shall be used solely for the benefit of Dakota Prairie Refining. The total assets and liabilities of Dakota Prairie Refining reflected on the Company's Consolidated Balance Sheets at December 31 were as follows:

	2013
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	4,774
Other current assets	26
Total current assets	4,800
Net property, plant and equipment	172,073
Total assets	$	176,873
Liabilities
Current liabilities:
Long-term debt due within one year	$	3,000
Accounts payable	8,904
Taxes payable	5
Accrued compensation	26
Other accrued liabilities	461
Total current liabilities	12,396
Long-term debt	72,000
Total liabilities	$	84,396

Fuel Contract On October 10, 2012, the Coyote Station entered into a new coal supply agreement with Coyote Creek that will replace a coal supply agreement expiring in May 2016. The new agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for the period May 2016 through December 2040.

The new coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal will cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station, with no primary beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements.

At December 31, 2013, 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, 2013, was $7.7 million.

XML

Business segment data (Details) (USD $)	3 Months Ended										12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012		Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Business segment data [Line Items]
External operating revenues	$ 1,184,423,000		$ 1,285,782,000	$ 1,060,595,000	$ 931,604,000	$ 1,081,144,000		$ 1,173,518,000	$ 967,962,000	$ 852,807,000	$ 4,462,404,000		$ 4,075,431,000		$ 4,050,492,000
Intersegment operating revenues											0		0		0
Depreciation, depletion and amortization											386,856,000		359,205,000		343,395,000
Interest expense											83,917,000		76,699,000		81,354,000
Income taxes											136,736,000		(31,146,000)		110,274,000
Earnings (loss) on common stock before income (loss) from discontinued operations											278,560,000		(15,006,000)		225,267,000
Income (loss) from discontinued operations, net of tax	(58,000)		(118,000)	(59,000)	(77,000)	8,700,000		(139,000)	5,106,000	(100,000)	(312,000)	[1]	13,567,000	[1]	(12,926,000)	[1]
Total earnings (loss) on common stock											278,248,000		(1,439,000)		212,341,000
Net proceeds from sale or disposition of property and other											(112,131,000)		(57,460,000)		(40,857,000)
Total net capital expenditures											728,070,000		933,777,000		481,023,000
Total assets	7,061,332,000					6,682,491,000					7,061,332,000		6,682,491,000		6,556,125,000
Property, plant and equipment	8,803,866,000					8,107,751,000					8,803,866,000		8,107,751,000
Less accumulated depreciation, depletion and amortization	3,872,487,000					3,608,912,000					3,872,487,000		3,608,912,000		3,361,208,000
Net property, plant and equipment	4,931,379,000					4,498,839,000					4,931,379,000		4,498,839,000		4,285,014,000
Additional information [Abstract]
Write-downs of oil and natural gas properties						231,700,000		160,100,000			0		391,800,000		0
Noncash write-down of natural gas and oil properties, after tax						145,900,000		100,900,000					246,800,000
Asset impairment charges				9,000,000					1,700,000		9,000,000		1,700,000
Reversal of an arbitration charge after tax	1,500,000					13,000,000			15,000,000		1,500,000		15,000,000
Net noncash inclusion of acct pay and NCI exclusion of capital expenditures											(56,800,000)		33,700,000		24,000,000
Regulated:
Business segment data [Line Items]
External operating revenues											1,264,574,000		1,131,626,000		1,343,714,000
Nonregulated:
Business segment data [Line Items]
External operating revenues											3,197,830,000		2,943,805,000		2,706,778,000
Electric:
Business segment data [Line Items]
External operating revenues											257,260,000		236,895,000		225,468,000
Intersegment operating revenues											0		0		0
Depreciation, depletion and amortization											32,789,000		32,509,000		32,177,000
Interest expense											12,590,000		12,421,000		13,745,000
Income taxes											9,683,000		8,975,000		7,242,000
Earnings (loss) on common stock before income (loss) from discontinued operations											34,837,000		30,634,000		29,258,000
Capital expenditures											168,557,000		112,035,000		52,072,000
Total assets	884,283,000	[2]				760,324,000	[2]				884,283,000	[2]	760,324,000	[2]	672,940,000	[2]
Property, plant and equipment	1,315,822,000	[2]				1,150,584,000	[2]				1,315,822,000	[2]	1,150,584,000	[2]	1,068,524,000	[2]
Natural gas distribution:
Business segment data [Line Items]
External operating revenues											851,945,000		754,848,000		907,400,000
Intersegment operating revenues											0		0		0
Depreciation, depletion and amortization											50,031,000		45,731,000		44,641,000
Interest expense											25,123,000		28,726,000		29,444,000
Income taxes											16,633,000		12,005,000		16,931,000
Earnings (loss) on common stock before income (loss) from discontinued operations											37,656,000		29,409,000		38,398,000
Capital expenditures											101,279,000		130,178,000		70,624,000
Total assets	1,786,068,000	[2]				1,703,459,000	[2]				1,786,068,000	[2]	1,703,459,000	[2]	1,679,091,000	[2]
Property, plant and equipment	1,776,901,000	[2]				1,689,950,000	[2]				1,776,901,000	[2]	1,689,950,000	[2]	1,568,866,000	[2]
Pipeline and energy services:
Business segment data [Line Items]
External operating revenues											155,369,000		139,883,000		210,846,000
Intersegment operating revenues											46,699,000		53,274,000		67,497,000
Depreciation, depletion and amortization											29,119,000		27,684,000		25,502,000
Interest expense											10,330,000		7,742,000		10,516,000
Income taxes											3,390,000		15,291,000		12,912,000
Earnings (loss) on common stock before income (loss) from discontinued operations											7,629,000		26,588,000		23,082,000
Capital expenditures											127,092,000		133,787,000		45,556,000
Total assets	798,701,000					622,470,000					798,701,000		622,470,000		526,797,000
Property, plant and equipment	962,172,000					816,533,000					962,172,000		816,533,000		719,291,000
Exploration and production:
Business segment data [Line Items]
External operating revenues											490,924,000		412,651,000		359,873,000
Intersegment operating revenues											45,099,000		35,966,000		93,713,000
Depreciation, depletion and amortization											186,458,000		160,681,000		142,645,000
Interest expense											14,315,000		9,018,000		7,445,000
Income taxes											53,197,000		(108,264,000)		46,298,000
Earnings (loss) on common stock before income (loss) from discontinued operations											94,450,000		(177,283,000)		80,282,000
Capital expenditures											391,315,000		554,528,000		272,855,000
Total assets	1,616,131,000					1,539,017,000					1,616,131,000		1,539,017,000		1,481,556,000
Property, plant and equipment	3,060,848,000					2,764,560,000					3,060,848,000		2,764,560,000		2,615,146,000
Construction materials and contracting:
Business segment data [Line Items]
External operating revenues											1,675,444,000		1,597,257,000		1,509,538,000
Intersegment operating revenues											36,693,000		20,168,000		472,000
Depreciation, depletion and amortization											74,470,000		79,527,000		85,459,000
Interest expense											17,394,000		15,211,000		16,241,000
Income taxes											24,765,000		14,099,000		11,227,000
Earnings (loss) on common stock before income (loss) from discontinued operations											50,946,000		32,420,000		26,430,000
Capital expenditures											34,607,000		45,083,000		52,303,000
Total assets	1,305,808,000					1,371,252,000					1,305,808,000		1,371,252,000		1,374,026,000
Property, plant and equipment	1,510,355,000					1,504,981,000					1,510,355,000		1,504,981,000		1,499,852,000
Construction services:
Business segment data [Line Items]
External operating revenues											1,029,909,000		932,013,000		834,918,000
Intersegment operating revenues											9,930,000		6,545,000		19,471,000
Depreciation, depletion and amortization											11,939,000		11,063,000		11,399,000
Interest expense											4,306,000		4,435,000		4,473,000
Income taxes											29,504,000		24,128,000		13,426,000
Earnings (loss) on common stock before income (loss) from discontinued operations											52,213,000		38,429,000		21,627,000
Capital expenditures											15,102,000		14,835,000		9,711,000
Total assets	450,614,000					429,547,000					450,614,000		429,547,000		418,519,000
Property, plant and equipment	134,948,000					130,624,000					134,948,000		130,624,000		124,796,000
Other
Business segment data [Line Items]
External operating revenues											1,553,000		1,884,000		2,449,000
Intersegment operating revenues											8,067,000		8,486,000		8,997,000
Depreciation, depletion and amortization											2,050,000		2,010,000		1,572,000
Interest expense											15,000		13,000		0
Income taxes											2,433,000		2,620,000		2,238,000
Earnings (loss) on common stock before income (loss) from discontinued operations											5,136,000		4,797,000		6,190,000
Capital expenditures											2,249,000		791,000		18,759,000
Total assets	219,727,000	[3]				256,422,000	[3]				219,727,000	[3]	256,422,000	[3]	403,196,000	[3]
Property, plant and equipment	49,997,000					50,519,000					49,997,000		50,519,000		49,747,000
Eliminations
Business segment data [Line Items]
Intersegment operating revenues											(146,488,000)		(124,439,000)		(190,150,000)
Interest expense											(156,000)		(867,000)		(510,000)
Income taxes											(2,869,000)		0		0
Earnings (loss) on common stock before income (loss) from discontinued operations											(4,307,000)		0		0
Property, plant and equipment	$ (7,177,000)					$ 0					$ (7,177,000)		$ 0		$ 0

[1] Reflected in the Other category.

[2] Includes allocations of common utility property.

[3] Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

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Accounts receivable and allowance for doubtful accounts (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Balance of receivables past due 90 days or more	$ 36.4	$ 34.3
Allowance for doubtful accounts	$ 10.1	$ 10.8

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Fair value - pension level 3 (Details 10) (Corporate debt securities [Member], Fair value, measurements using significant unobservable inputs (Level 3), Pension Benefits, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Corporate debt securities [Member] | Fair value, measurements using significant unobservable inputs (Level 3) | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Balance at beginning of year	$ 289
Total realized/unrealized losses	(47)
Purchases, issuances and settlements (net)	(242)
Balance at end of year	$ 0

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

Share-based Compensation [Abstract]

Target grants performance share

Target grants of performance shares outstanding at December 31, 2013, were as follows:

Grant Date	Performance Period	Target Grant of Shares
February 2011	2011-2013	254,514
February 2012	2012-2014	251,196
March 2013	2013-2015	244,281

Schedule of share-based payment award, performance shares, valuation assumptions

Assumptions used for grants of performance shares issued in 2013, 2012 and 2011 were:

				2013						2012						2011
Grant-date fair value					$29.01						$17.18						$19.99
Blended volatility range	16.10	%	-	19.39		%	24.29	%	-	25.81		%	23.20	%	-	32.18		%
Risk-free interest rate range	.09	%	-	.40		%	.10	%	-	.35		%	.09	%	-	1.34		%
Discounted dividends per share					$2.12						$1.19						$1.23

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, 2013, was as follows:

	Number of Shares		Weighted Average Grant-Date Fair Value
Nonvested at beginning of period	786,136		$	18.17
Granted	264,614		29.01
Vested	—		—
Forfeited	(300,759	)	18.20
Nonvested at end of period	749,991		$	21.99

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Nonqualified benefit plans (Details 12) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental employee retirement plan, defined benefit [Member]
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Net periodic benefit cost	$ 7,300,000	$ 8,100,000	$ 8,100,000
Projected benefit obligation	106,900,000	113,000,000
Accumulated benefit obligation	99,700,000	107,500,000
Discount rate	4.32%	3.44%
Rate of compensation increase	4.00%	3.00%
Discount rate	3.44%	4.00%
Rate of compensation increase	3.00%	4.00%
Expected future benefit payments, next twelve months	5,700,000
Expected future benefit payments, year two	6,700,000
Expected future benefit payments, year three	6,500,000
Expected future benefit payments, year four	6,700,000
Expected future benefit payments, year five	7,200,000
Expected future benefit payments, five fiscal years thereafter	37,500,000
Supplemental employee retirement plan, defined contribution [Member]
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Plan, cost recognized	304,000	84,000
Supplemental employee retirement plans, defined contribution and defined benefit plans [Member]
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Investments in nonqualified benefit plans	98,100,000	84,400,000
Supplemental employee retirement plans, defined contribution and defined benefit plans [Member] | Equity securities [Member]
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Investments in nonqualified benefit plans	53,500,000	41,900,000
Supplemental employee retirement plans, defined contribution and defined benefit plans [Member] | Life insurance carried on plan participants [Member]
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Investments in nonqualified benefit plans	31,400,000	32,700,000
Supplemental employee retirement plans, defined contribution and defined benefit plans [Member] | Other investments [Member]
Defined Benefit and Defined Contribution Plans Disclosure [Line Items]
Investments in nonqualified benefit plans	$ 13,200,000	$ 9,800,000

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Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Stockholders' equity:
Common stock, shares authorized	500,000,000	500,000,000
Common stock, par value	$ 1.00	$ 1.00
Common stock, shares issued	189,868,780	189,369,450
Treasury stock, shares	538,921	538,921

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Performance share awards (Details 4) (Performance shares [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	16.10%	24.29%	23.20%
Expected volatility rate, maximum	19.39%	25.81%	32.18%
Risk-free interest rate, minimum	0.09%	0.10%	0.09%
Risk-free interest rate, maximum	0.40%	0.35%	1.34%
Discounted dividends, per share	$ 2.12	$ 1.19	$ 1.23
Grant-date fair value	$ 29.01	$ 17.18	$ 19.99
Grant date February 2011 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	254,514
Grant date February 2012 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	251,196
Grant date March 2013 [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Target grant of shares under performance awards	244,281
Number of shares [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Nonvested at beginning of period	786,136
Granted	264,614
Vested	0
Forfeited	(300,759)
Nonvested at end of period	749,991
Weighted average grant-date fair value [Member]
Share-based compensation arrangement by share-based payment award [Line Items]
Nonvested at beginning of period	$ 18.17
Grant-date fair value	$ 29.01
Vested	$ 0.00
Forfeited	$ 18.20
Nonvested at end of period	$ 21.99

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Discontinued operations

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Discontinued operations

Discontinued Operations

In 2007, Centennial Resources sold CEM to Bicent. In connection with the sale, Centennial Resources had 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 incurs legal expenses and has accrued liabilities related to this matter. In the fourth quarter of 2011, the Company accrued $21.0 million ($13.0 million after tax) related to the guarantee as a result of an arbitration award against CEM. In 2011, the Company also incurred legal expenses related to this matter and in the first quarter had an income tax benefit related to favorable resolution of certain tax matters. In the second quarter of 2012, discontinued operations reflected the settlement of certain liabilities and estimated insurance recoveries resulting in a net benefit related to this matter. In the fourth quarter of 2012, the Company reversed its previously recorded accrual for the arbitration charge due to a favorable court ruling, which was partially offset by the reversal of estimated insurance recoveries. These items are reflected as discontinued operations in the consolidated financial statements and accompanying notes. Discontinued operations are included in the Other category. For more information, see Note 19.

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Natural gas costs recoverable or refundable through rate adjustments (Details 10) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Minimum period over which natural gas costs greater or less than amounts being recovered become recoverable or refundable through rate adjustments	12 months
Maximum period over which natural gas costs greater or less than amounts being recovered become recoverable or refundable through rate adjustments	28 months
Natural gas costs refundable	$ 16.9	$ 35.3
Natural gas costs recoverable	$ 12.1	$ 3.0

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Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset retirement obligation [Roll Forward]
Balance, beginning of period	$ 102,545,000	$ 98,151,000
Liabilities incurred	5,610,000	6,523,000
Liabilities acquired	0	0
Asset retirement obligation, liabilities settled	(22,257,000)	(10,472,000)
Accretion expense	4,574,000	4,266,000
Revisions in estimates	7,671,000	3,655,000
Other	386,000	422,000
Balance, end of period	98,529,000	102,545,000
Fair value of assets legally restricted for purposes of settling asset retirement obligations	$ 4,100,000	$ 5,000,000

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Estimated future benefit payments and subsidies (Details 11) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments, next twelve months	$ 5,596
Prescription drug subsidy receipts, next twelve months	237
Expected future benefit payments, year two	5,584
Prescription drug subsidy receipts, year two	230
Expected future benefit payments, year three	5,583
Prescription drug subsidy receipts, year three	221
Expected future benefit payments, year four	5,543
Prescription drug subsidy receipts, Year Four	211
Expected future benefit payments, year five	5,483
Prescription drug subsidy receipts, year five	200
Expected future benefit payments, five fiscal years thereafter	26,038
Prescription drug subsidy receipts, after year five	823
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments, next twelve months	23,391
Expected future benefit payments, year two	23,645
Expected future benefit payments, year three	23,911
Expected future benefit payments, year four	24,439
Expected future benefit payments, year five	24,814
Expected future benefit payments, five fiscal years thereafter	$ 130,026

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Goodwill and other intangible assets (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Finite-lived intangible assets [Line Items]
Intangible assets, net (excluding goodwill)	$ 13,099,000	$ 17,129,000
Amortization of intangible assets	4,000,000	3,800,000	3,700,000
Estimated amortization expense for amortizable intangible assets
2014	3,200,000
2015	2,500,000
2016	2,200,000
2017	2,000,000
2018	1,000,000
Thereafter	2,200,000
Customer relationships [Member]
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	21,310,000	21,310,000
Accumulated amortization	(13,726,000)	(11,701,000)
Intangible assets, net (excluding goodwill)	7,584,000	9,609,000
Noncompete agreements [Member]
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	6,186,000	7,236,000
Accumulated amortization	(4,840,000)	(5,326,000)
Intangible assets, net (excluding goodwill)	1,346,000	1,910,000
Other [Member}
Finite-lived intangible assets [Line Items]
Other amortizable intangible assets	10,995,000	10,979,000
Accumulated amortization	(6,826,000)	(5,369,000)
Intangible assets, net (excluding goodwill)	$ 4,169,000	$ 5,610,000

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Subsequent Events

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Subsequent Event

On January 28, 2014, the Company entered into a note purchase agreement. The Company contracted to issue $50.0 million and $100.0 million of Senior Notes under the agreement on April 15, 2014 and July 15, 2014, respectively, with due dates ranging from July 2024 to April 2044 at a weighted average interest rate of 4.6 percent.

On December 12, 2013, MDU Energy Capital entered into a note purchase agreement. MDU Energy Capital contracted to issue $30.0 million of Senior Notes under the agreement on January 27, 2014, with due dates ranging from January 2029 to January 2044 at a weighted average interest rate of 5.3 percent.

On February 10, 2014, the Company entered into an agreement to purchase working interests and leasehold positions in oil and natural gas production assets in the southern Powder River Basin of Wyoming for approximately $183.0 million, subject to accounting and purchase price adjustments customary with acquisitions of this type. The effective date of the acquisition is October 1, 2013, with the expected closing date to occur on or before April 1, 2014, conditioned upon completing a due diligence process, including environmental reviews, and satisfying other standard closing conditions.

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Guarantees (Details 5) (USD $)	Dec. 31, 2013
Guarantor Obligations [Line Items]
Amount of hedging obligations guaranteed reflected on balance sheet	$ 4,800,000
Guarantor obligations, maximum exposure, undiscounted	54,400,000
Fixed maximum amounts guaranteed by year 2014	32,500,000
Fixed maximum amounts guaranteed by year 2015	2,100,000
Fixed maximum amounts guaranteed by year 2016	700,000
Fixed maximum amounts guaranteed by year 2017	600,000
Fixed maximum amounts guaranteed by year 2018	500,000
Fixed maximum amounts guaranteed by year 2019	500,000
Expires on a specified number of days after the receipt of written notice	13,500,000
Fixed maximum amounts guaranteed by year no maturity date	4,000,000
Amount outstanding under guarantees that are reflected on balance sheet	200,000
Letters of credit	36,000,000
Outstanding letters of credit	0
Natural gas transportation and storage agreement fixed maximum amount of performance guarantee of a related party	5,000,000
The amount outstanding by a related party under the guarantee	800,000
Amount of surety bonds outstanding	$ 516,000,000

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Condensed Statements of Cash Flows (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 742,193	$ 584,740	$ 626,648
Capital expenditures	(909,400)	(872,920)	(497,000)
Net proceeds from sale or disposition of property and other	124,541	40,110	40,107
Investments	302	9,725	(10,302)
Net cash used in investing activities	(782,661)	(887,952)	(464,545)
Issuance of short-term borrowings	9,500	20,100	0
Repayment of short-term borrowings	0	0	(20,000)
Issuance of long-term debt	507,924	467,957	300
Repayment of long-term debt	(423,707)	(138,775)	(85,151)
Proceeds from issuance of common stock	14,554	88	5,744
Dividends paid	(98,405)	(159,768)	(123,323)
Excess tax benefit on stock-based compensation	0	26	1,239
Net cash used in financing activities	36,866	189,628	(221,191)
Increase (decrease) in cash and cash equivalents	(3,817)	(113,730)	(59,302)
Cash and cash equivalents - beginning of year	49,042	162,772	222,074
Cash and cash equivalents - end of year	45,225	49,042	162,772
MDU Resources Group, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	188,259	225,968	217,514
Capital expenditures	(211,013)	(150,337)	(74,580)
Net proceeds from sale or disposition of property and other	20,624	1,120	720
Investments in and advances to subsidiaries	(1,016)	(1,387)	(5,701)
Investments from and advances from subsidiaries	10,000	5,000	0
Investments	613	12	0
Net cash used in investing activities	(180,792)	(145,592)	(79,561)
Repayment of short-term borrowings	0	0	(20,000)
Issuance of long-term debt	77,924	76,000	0
Repayment of long-term debt	(85)	(21)	(107)
Proceeds from issuance of common stock	14,554	88	5,744
Dividends paid	(98,405)	(159,768)	(123,323)
Excess tax benefit on stock-based compensation	0	21	358
Net cash used in financing activities	(6,012)	(83,680)	(137,328)
Increase (decrease) in cash and cash equivalents	1,455	(3,304)	625
Cash and cash equivalents - beginning of year	3,596	6,900	6,275
Cash and cash equivalents - end of year	$ 5,051	$ 3,596	$ 6,900

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Estimated discounted future cash flows of total proved reserves (Details 6) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 4,507,000	$ 3,696,200	$ 4,188,000
Future production costs	1,734,800	1,536,500	1,560,300
Future development costs	403,000	301,600	285,300
Future net cash flows before income taxes	2,369,200	1,858,100	2,342,400
Future income tax expense	545,200	304,900	531,100
Future net cash flows	1,824,000	1,553,200	1,811,300
10% annual discount for estimated timing of cash flows	810,000	669,800	832,500
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$ 1,014,000	$ 883,400	$ 978,800

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Derivative Instruments Subject to master netting agreements (Details 4) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	$ 1,950	$ 18,304
Derivative liability, fair value, gross liability	7,483	6,255
Commodity derivative instruments assets [Member]
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	1,950	18,304
Gross amount not offset	(1,950)	0
Derivative asset, fair value, net	0	18,304
Total assets [Member]
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	1,950	18,304
Gross amount not offset	(1,950)	0
Derivative asset, fair value, net	0	18,304
Commodity derivatives - liabilities [Member]
Derivative instruments [Line Items]
Derivative liability, fair value, gross liability	7,483
Gross amount not offset	(1,950)
Derivative liability, fair value, net	5,533
Interest rate derivatives - liabilities [Member]
Derivative instruments [Line Items]
Derivative liability, fair value, gross liability		6,255
Gross amount not offset		0
Derivative liability, fair value, net		6,255
Total liabilities [Member]
Derivative instruments [Line Items]
Derivative liability, fair value, gross liability	7,483	6,255
Gross amount not offset	(1,950)	0
Derivative liability, fair value, net	$ 5,533	$ 6,255

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Debt (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013			Amount Outstanding at December 31, 2012			Letters of Credit at December 31, 2013			Expiration Date
			(In millions)
MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement	(a)	$	125.0		$	78.9	(b)	$	76.0	(b)	$	—		10/4/17
Cascade Natural Gas Corporation	Revolving credit agreement		$	50.0	(c)	$	11.5		$	2.0		$	2.2	(d)	7/9/18
Intermountain Gas Company	Revolving credit agreement		$	65.0	(e)	$	3.0		$	26.2		$	—		7/13/18
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	75.0	(b)	$	217.0	(b)	$	—		6/8/17

(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 $150 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 million.

(d) The outstanding letter of credit, as discussed in Note 19, reduces the amount available under the credit agreement.

(e) Certain provisions allow for increased borrowings, up to a maximum of $90 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 $650 million). There were no amounts outstanding under the credit agreement.

Long term debt outstanding

Long-term debt outstanding at December 31 was as follows:

	2013			2012
	(In thousands)
Senior Notes at a weighted average rate of 5.52%, due on dates ranging from June 19, 2015 to April 15, 2044	$	1,545,078		$	1,349,160
Commercial paper at a weighted average rate of .40%, supported by revolving credit agreements	153,924			293,000
Term Loan Agreements at a weighted average rate of 2.08%, due on dates ranging from April 22, 2014 to April 22, 2023	75,000			—
Medium-Term Notes at a weighted average rate of 7.32%, due on dates ranging from September 15, 2027 to March 16, 2029	35,000			59,000
Other notes at a weighted average rate of 5.23%, due on dates ranging from September 1, 2020 to February 1, 2035	39,863			40,090
Credit agreements at a weighted average rate of 4.11%, due on dates ranging from February 28, 2014 to November 30, 2038	5,701			3,768
Discount	(3		)	(43		)
Total long-term debt	1,854,563			1,744,975
Less current maturities	12,277			134,108
Net long-term debt	$	1,842,286		$	1,610,867

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2013

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, 2013, there are 6.2 million remaining shares available to grant under these plans. The Company generally issues new shares of common stock to satisfy restricted stock, stock and performance share awards.

Total stock-based compensation expense (after tax) was $3.9 million, $4.0 million and $3.5 million in 2013, 2012 and 2011, respectively.

As of December 31, 2013, total remaining unrecognized compensation expense related to stock-based compensation was approximately $7.0 million (before income taxes) which will be amortized over a weighted average period of 1.6 years.

Stock options

The Company had granted stock options to directors, key employees and employees. The Company has not granted stock options since 2003 and as of December 31, 2013 and 2012, there were no stock options outstanding.

The Company received cash of $88,000 and $5.7 million from the exercise of stock options for the years ended December 31, 2012 and 2011, respectively. The aggregate intrinsic value of options exercised during the years ended December 31, 2012 and 2011, was $60,000 and $3.3 million, respectively.

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 36,713 shares with a fair value of $1.1 million, 53,888 shares with a fair value of $1.1 million and 55,141 shares with a fair value of $1.1 million issued under this plan during the years ended December 31, 2013, 2012 and 2011, respectively.

A key employee of the Company received an award of 43,103 shares of common stock under a long-term incentive plan with a fair value of $930,000 during the year ended December 31, 2012.

Performance share awards

Since 2003, key employees of the Company have been awarded performance share awards each year. Entitlement to performance shares is based on the Company's total shareholder return over designated performance periods as measured against a selected peer group.

Target grants of performance shares outstanding at December 31, 2013, were as follows:

Grant Date	Performance Period	Target Grant of Shares
February 2011	2011-2013	254,514
February 2012	2012-2014	251,196
March 2013	2013-2015	244,281

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 2013, 2012 and 2011 were:

				2013						2012						2011
Grant-date fair value					$29.01						$17.18						$19.99
Blended volatility range	16.10	%	-	19.39		%	24.29	%	-	25.81		%	23.20	%	-	32.18		%
Risk-free interest rate range	.09	%	-	.40		%	.10	%	-	.35		%	.09	%	-	1.34		%
Discounted dividends per share					$2.12						$1.19						$1.23

There were no performance shares that vested in 2013, 2012 or 2011.

A summary of the status of the performance share awards for the year ended December 31, 2013, was as follows:

	Number of Shares		Weighted Average Grant-Date Fair Value
Nonvested at beginning of period	786,136		$	18.17
Granted	264,614		29.01
Vested	—		—
Forfeited	(300,759	)	18.20
Nonvested at end of period	749,991		$	21.99

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Expected rate of return (Details 6)	12 Months Ended
	Dec. 31, 2013
Equity securities [Member] | Pension 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%
Equity securities [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target plan asset allocations range maximum	75.00%
Defined benefit plan, target plan asset allocations range minimum	65.00%
Fixed Income Securities [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target plan asset allocations range maximum	40.00%
Defined benefit plan, target plan asset allocations range minimum	30.00%
Fixed Income Securities [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target plan asset allocations range maximum	35.00%
Defined benefit plan, target plan asset allocations range minimum	25.00%