MDU Resources (MDU) 10-Q 5 May 10 2010 Q1 Quarterly report Financial data

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)
In Thousands, except Share data	3 Months Ended Mar. 31, 2010	3 Months Ended Mar. 31, 2009
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$460,245	$594,576
Construction services, natural gas and oil production, construction materials and contracting, and other	374,532	499,429
Total operating revenues	834,777	1,094,005
Operating expenses:
Fuel and purchased power	16,911	18,731
Purchased natural gas sold	233,691	356,496
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services	62,987	71,351
Construction services, natural gas and oil production, construction materials and contracting, and other	313,786	422,149
Depreciation, depletion and amortization	78,678	93,245
Taxes, other than income	45,795	52,952
Write-down of natural gas and oil properties	0	620,000
Total operating expenses	751,848	1,634,924
Operating Income (loss)	82,929	(540,919)
Earnings from equity method investments	2,183	1,787
Other income	2,502	1,719
Interest expense	20,516	20,997
Income (loss) before income taxes	67,098	(558,410)
Income taxes	25,326	(214,607)
Net income (loss)	41,772	(343,803)
Dividends on preferred stocks	172	171
Earnings (loss) on common stock	$41,600	($343,974)
Earnings (loss) per common share - basic	0.22	-1.87
Earnings (loss) per common share - diluted	0.22	-1.87
Dividends per common share	0.1575	0.155
Weighted average common shares outstanding - basic	187,963	183,787
Weighted average common shares outstanding - diluted	188,220	183,787

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)
In Thousands	Mar. 31, 2010	Dec. 31, 2009	Mar. 31, 2009
Current assets:
Cash and cash equivalents	$106,664	$175,114	$44,689
Receivables, net	467,790	531,980	580,700
Inventories	253,931	249,804	276,268
Deferred income taxes	18,543	28,145	0
Short-term investments	250	2,833	2,329
Commodity derivative instruments	38,146	7,761	92,577
Prepayments and other current assets	104,437	66,021	135,734
Total current assets	989,761	1,061,658	1,132,297
Investments	141,443	145,416	114,058
Property, plant and equipment	6,875,397	6,766,582	6,550,825
Less accumulated depreciation, depletion and amortization	2,935,453	2,872,465	2,839,020
Net property, plant and equipment	3,939,944	3,894,117	3,711,805
Deferred charges and other assets:
Goodwill	634,633	629,463	621,566
Other intangible assets, net	26,612	28,977	26,573
Other	249,454	231,321	254,240
Total deferred charges and other assets	910,699	889,761	902,379
Total assets	5,981,847	5,990,952	5,860,539
Current liabilities:
Short-term borrowings	7,700	10,300	25,500
Long-term debt due within one year	72,572	12,629	28,621
Accounts payable	241,465	281,906	355,951
Taxes payable	69,077	55,540	71,238
Deferred income taxes	0	0	10,143
Dividends payable	29,796	29,749	28,685
Accrued compensation	22,607	47,425	35,543
Commodity derivative instruments	32,328	36,907	58,062
Other accrued liabilities	187,368	192,729	162,271
Total current liabilities	662,913	667,185	776,014
Long-term debt	1,426,146	1,486,677	1,614,786
Deferred credits and other liabilities:
Deferred income taxes	603,803	590,968	516,965
Other liabilities	680,965	674,475	551,175
Total deferred credits and other liabilities	1,284,768	1,265,443	1,068,140
Stockholders' equity:
Preferred stocks	15,000	15,000	15,000
Common stockholders' equity:
Common Stock Shares issued -- $1.00 par value, 188,656,012 at March 31, 2010; 184,499,434 at March 31, 2009 and 188,389,265 at December 31, 2009	188,656	188,389	184,499
Other paid-in capital	1,018,441	1,015,678	940,369
Retained earnings	1,388,914	1,377,039	1,244,248
Accumulated other comprehensive income (loss)	635	(20,833)	21,109
Treasury stock at cost - 538,921 shares	(3,626)	(3,626)	(3,626)
Total common stockholders' equity	2,593,020	2,556,647	2,386,599
Total stockholders' equity	2,608,020	2,571,647	2,401,599
Total liabilities and stockholders' equity	$5,981,847	$5,990,952	$5,860,539

PARENTHETICAL DATA TO THE CONSO

PARENTHETICAL DATA TO THE CONSOLIDATED BALANCE SHEETS
	Mar. 31, 2010	Dec. 31, 2009	Mar. 31, 2009
Common stockholders' equity:
Common stock par value	1	1	1
Common stock shares issued	188,656,012	188,389,265	184,499,434
Treasury shares	538,921	538,921	538,921

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)
In Thousands	3 Months Ended Mar. 31, 2010	3 Months Ended Mar. 31, 2009
Operating activities:
Net income (loss)	$41,772	($343,803)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	78,678	93,245
Earnings, net of distributions, from equity method investments	(1,443)	(1,531)
Deferred income taxes	8,226	(228,764)
Write-down of natural gas and oil properties	0	620,000
Changes in current assets and liabilities, net of acquisitions:
Receivables	61,914	129,318
Inventories	(6,198)	(13,347)
Other current assets	(34,546)	40,442
Accounts payable	(34,795)	(59,863)
Other current liabilities	(21,733)	21,713
Other noncurrent changes	(6,759)	(9,586)
Net cash provided by operating activities	85,116	247,824
Investing activities:
Capital expenditures	(123,902)	(145,355)
Acquisitions, net of cash acquired	(1,725)	(3,057)
Net proceeds from sale or disposition of property	1,936	4,213
Investments	1,404	1,229
Net cash used in investing activities	(122,287)	(142,970)
Financing activities:
Repayment of short-term borrowings	(2,600)	(79,600)
Issuance of long-term debt	0	59,091
Repayment of long-term debt	(479)	(62,884)
Proceeds from issuance of common stock	1,214	107
Dividends paid	(29,749)	(28,640)
Tax benefit on stock-based compensation	452	111
Net cash used in financing activities	(31,162)	(111,815)
Effect of exchange rate changes on cash and cash equivalents	(117)	(64)
Decrease in cash and cash equivalents	(68,450)	(7,025)
Cash and cash equivalents -- beginning of year	175,114	51,714
Cash and cash equivalents -- end of period	$106,664	$44,689

Basis of presentation

Basis of presentation
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Basis of presentation	1.Basis of presentation The accompanying consolidated interim financial statements were prepared in conformity with the basis of presentation reflected in the consolidated financial statements included in the Company's 2009 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the FASB. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2009 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. 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 March31, 2010, up to the date of issuance of these consolidated interim financial statements.

Seasonality of operations

Seasonality of operations
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Seasonality of operations	2.Seasonality of operations Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year.

Allowance for doubtful accounts

Allowance for doubtful accounts
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Allowance for doubtful accounts	3.Allowance for doubtful accounts The Company's allowance for doubtful accounts as of March 31, 2010 and 2009, and December 31, 2009, was $17.1 million, $16.1 million and $16.6 million, respectively.

Natural gas in storage

Natural gas in storage
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Natural gas in storage	4.Natural gas in storage Natural gas in storage for the Company's regulated operations is 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 and was $10.7million, $9.5million and $35.6million at March31, 2010 and 2009, and December31, 2009, respectively. 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 $59.3million, $42.0million, and $59.6million at March31, 2010 and 2009, and December31, 2009, respectively.

Inventories

Inventories
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Inventories	5.Inventories Inventories, other than natural gas in storage for the Companys regulated operations, consisted primarily of aggregates held for resale of $81.1million, $92.0million and $80.1million; materials and supplies of $58.6million, $73.0million and $58.1million; asphalt oil of $50.4million, $50.0million and $23.0million; and other inventories of $53.1million, $51.8million and $53.0million, as of March31, 2010 and 2009, and December31, 2009, respectively. These inventories were stated at the lower of average cost or market value.

Natural gas and oil properties

Natural gas and oil properties
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Natural gas and oil properties	6.Natural gas and oil properties The Company uses the full-cost method of accounting for its natural gas and oil production activities. Under this method, all costs incurred in the acquisition, exploration and development of natural gas and oil 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 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 less applicable income taxes. Future net revenue was estimated based on end-of-quarter spot market prices adjusted for contracted price changes prior to the fourth quarter of 2009. Effective December 31, 2009, the Modernization of Oil and Gas Reporting rules issued by the SEC changed the pricing used to estimate reserves and associated future cash flows to SEC Defined Prices. Prior to that date, if capitalized costs exceeded the full-cost ceiling at the end of any quarter, a permanent noncash write-down was required to be charged to earnings in that quarter unless subsequent price changes eliminated or reduced an indicated write-down. Effective December 31, 2009, if capitalized costs 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. Due to low natural gas and oil prices that existed on March31, 2009, the Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at March31, 2009. Accordingly, the Company was required to write down its natural gas and oil producing properties. The noncash write-down amounted to $620.0million ($384.4million after tax) for the three months ended March31, 2009. The Company hedges a portion of its natural gas and oil production and the effects of the cash flow hedges were used in determining the full-cost ceiling. The Company would have recognized an additional write-down of its natural gas and oil properties of $107.9 million ($66.9 million after tax) at March 31, 2009, 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 Note13. At March 31, 2010, the Companys full-cost ceiling exceeded the Companys capitalized cost. However, sustained downward movements in natural gas and oil prices subsequent to March 31, 2010, could result in a future write-down of the Companys natural gas and oil properties.

Earnings

Earnings (loss) per common share
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Earnings (loss) per common share	7.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 applicable period. 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 applicable period, plus the effect of outstanding stock options, restricted stock grants and performance share awards. For the three months ended March 31, 2010, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the three months ended March 31, 2009, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Due to the loss on common stock for the three months ended March 31, 2009, the effect of outstanding stock options, restricted stock grants and performance share awards were 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.

Cash flow information

Cash flow information
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Cash flow information	8.Cash flow information Cash expenditures for interest and income taxes were as follows: Three Months Ended March 31, 2010 2009 (In thousands) Interest, net of amount capitalized $ 25,159 $ 25,280 Income taxes paid (refunded), net $ 5,424 $ (21,914 )

New accounting standards

New accounting standards
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
New accounting standards	9.New accounting standards Variable Interest Entities In June2009, the FASB issued guidance related to variable interest entities which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting rights should be consolidated and modifies the approach for determining the primary beneficiary of a variable interest entity. This guidance requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. The guidance related to variable interest entities was effective for the Company on January1, 2010. The adoption of this guidance did not have a material effect on the Companys financial position or results of operations. Improving Disclosure About Fair Value Measurements In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods and were effective for the Company on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January1, 2011. The guidance requires additional disclosures but does not impact the Companys financial position or results of operations. Subsequent Events In February2010, the FASB issued guidance amending certain recognition and disclosure requirements related to subsequent events. The guidance requires an entity that is an SEC filer to evaluate subsequent events through the date that the financial statements are issued. The guidance also removes the requirement to disclose the date through which subsequent events were evaluated. The guidance related to subsequent events was effective for the Company in the first quarter of 2010. The adoption of this guidance did not impact the Companys financial position or results of operations.

Comprehensive income

Comprehensive income (loss)
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Comprehensive income (loss)	10.Comprehensive income (loss) Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income. The Company's other comprehensive income resulted from gains on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note 13. Comprehensive income (loss), and the components of other comprehensive income and related tax effects, were as follows: Three Months Ended March 31, 2010 2009 (In thousands) Net income (loss) $ 41,772 $ (343,803 ) Other comprehensive income: Net unrealized gain on derivative instruments qualifying as hedges: Net unrealized gain on derivative instruments arising during the period, net of tax of $13,159 and $13,895 in 2010 and 2009, respectively 21,471 22,671 Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income (loss), net of tax of $(573) and $7,464 in 2010 and 2009, respectively (934 ) 12,178 Net unrealized gain on derivative instruments qualifying as hedges 22,405 10,493 Foreign currency translation adjustment, net of tax of $(621) and $164 in 2010 and 2009, respectively (937 ) 251 21,468 10,744 Comprehensive income (loss) $ 63,240 $ (333,059 )

Equity method investments

Equity method investments
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Equity Method Investments	11.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. The Company's equity method investments at March31, 2010, include the Brazilian Transmission Lines. In August 2006, MDU Brasil acquired ownership interests in companies owning the Brazilian Transmission Lines. The interests involve the ENTE (13.3-percent ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent ownership interest) electric transmission lines, which are primarily in northeastern and southern Brazil. In the fourth quarter of 2009, multiple sales agreements were signed with three separate parties for the Company to sell its ownership interests in the Brazilian Transmission Lines. This sale is pending regulatory approvals. One of the parties will purchase 15.6percent of the Companys ownership interests over a four-year period. The other parties will purchase 84.4 percent of the Companys ownership interests at the financial close of the transaction. At March31, 2010 and 2009, and December31, 2009, the Company's equity method investments had total assets of $374.8million, $295.3million and $387.0million, respectively, and long-term debt of $166.4million, $153.9million and $176.7million, respectively. The Company's investment in its equity method investments was approximately $56.0million, $45.4million and $62.4million, including undistributed earnings of $10.8million, $8.4million and $9.3million, at March31, 2010 and 2009, and December31, 2009, respectively.

Goodwill and other intangible a

Goodwill and other intangible assets
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Goodwill And Other Intangible Assets	12.Goodwill and other intangible assets The changes in the carrying amount of goodwill were as follows: Balance Goodwill Balance as of Acquired as of Three Months Ended January1, During March 31, March 31, 2010 2010 the Year* 2010 (In thousands) Electric $ $ $ Natural gas distribution 345,736 345,736 Construction services 100,127 2,743 102,870 Pipeline and energy services 7,857 1,880 9,737 Natural gas and oil production Construction materials and contracting 175,743 547 176,290 Other Total $ 629,463 $ 5,170 $ 634,633 * Includes purchase price adjustments that were not material related to acquisitions in a prior period. Balance Goodwill Balance as of Acquired as of Three Months Ended January1, During March31, March 31, 2009 2009 the Year* 2009 (In thousands) Electric $ $ $ Natural gas distribution 344,952 296 345,248 Construction services 95,619 4,184 99,803 Pipeline and energy services 1,159 1,159 Natural gas and oil production Construction materials and contracting 174,005 1,351 175,356 Other Total $ 615,735 $ 5,831 $ 621,566 * Includes purchase price adjustments that were not material related to acquisitions in a prior period. Balance Goodwill Balance as of Acquired as of Year Ended January1, During the December 31, December 31, 2009 2009 Year* 2009 (In thousands) Electric $ $ $ Natural gas distribution 344,952 784 345,736 Construction services 95,619 4,508 100,127 Pipeline and energy services 1,159 6,698 7,857 Natural gas and oil production Construction materials and contracting 174,005 1,738 175,743 Other Total $ 615,735 $ 13,728 $ 629,463 * Includes purchase price adjustments that were not material related to acquisitions in a prior period. Other amortizable intangible assets were as follows: March 31, 2010 March 31, 2009 December31, 2009 (In thousands) Customer relationships $ 24,942 $ 21,688 $ 24,942 Accumulated amortization (10,093 ) (7,561 ) (9,500 ) 14,849 14,127 15,442 Noncompete agreements 9,405 9,792 12,377 Accumulated amortization (5,755 ) (5,518 ) (6,675 ) 3,650 4,274 5,702 Other 11,368 10,668 10,859 Accumulated amortization (3,255 ) (2,496 ) (3,026 ) 8,113 8,172 7,833 Total $ 26,612 $ 26,573 $ 28,977 Amortizatio

Derivative instruments

Derivative instruments
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Derivative Instruments	13. 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. As of March 31, 2010, the Company had no outstanding foreign currency or interest rate hedges. The following information should be read in conjunction with Notes 1 and 7 in the Company's Notes to Consolidated Financial Statements in the 2009 Annual Report. Cascade and Intermountain At March31, 2010, Cascade held natural gas swap agreements, with total forward notional volumes of 6.3million MMBtu, which were not designated as hedges. Cascade utilizes, and Intermountain periodically utilizes, natural gas swap agreements to manage a portion of their regulated natural gas supply portfolios in order to manage fluctuations in the price of natural gas related to core customers in accordance with authority granted by the IPUC, WUTC and OPUC. Core customers consist of residential, commercial and smaller industrial customers. The fair value of the derivative instrument must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability. Cascade and Intermountain record periodic changes in the fair market value of the derivative instruments on the Consolidated Balance Sheets as a regulatory asset or a regulatory liability, and settlements of these arrangements are expected to be recovered through the purchased gas cost adjustment mechanism. Gains and losses on the settlements of these derivative instruments are recorded as a component of purchased natural gas sold on the Consolidated Statements of Income as they are recovered through the purchased gas cost adjustment mechanism. Under the terms of these arrangements, Cascade and Intermountain will either pay or receive settlement payments based on the difference between the fixed strike price and the monthly index price applicable to each contract. For the three months ended March31, 2010, Cascade and Intermountain recorded the change in the fair market value of the derivative instruments of $5.1million as a decrease to regulatory assets. Certain of Cascade's derivative instruments contain credit-risk-related contingent features that permit the counterparties to require collateralization if Cascade's derivative liability positions exceed certain dollar thresholds. The dollar thresholds in certain of Cascade's agreements are determined and may fluctuate based on Cascade's credit rating on its debt. In addition, Cascade's and Intermountain's derivative instruments contain cross-default provisions that state if the entity fails to make payment with respect to certain of its indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of such entity's derivative instruments in liability positions. The aggregate fair value of Cascade's derivative instruments with credit-risk-related contingent features that are in a liability position at March31, 2010, was $22.8million. The aggregate fair va

Fair value measurements

Fair value measurements
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Fair Value Measurements	14.Fair value measurements The Company elected to measure 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 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 $36.5 million, $25.8 million and $34.8 million, as of March31, 2010 and 2009, and December 31, 2009, respectively, are classified as Investments on the Consolidated Balance Sheets. The increase in the fair value of these investments for the three months ended March31, 2010, was $1.7million (before tax). The decrease in the fair value of these investments for the three months ended March31, 2009, was $1.9 million (before tax). 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 for its remaining available-for-sale securities, which are auction rate securities. The Companys auction rate securities, which totaled $11.4 million at March 31, 2010 and 2009, and December 31, 2009, are accounted for as available-for-sale and are recorded at fair value. The fair value of the auction rate securities approximate cost and, as a result, there are no accumulated unrealized gains or losses recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets related to these investments. 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 Companys assets and liabilities measured at fair value on a recurring basis are as follows: Fair Value Measurements at March 31, 2010, Using Quoted Prices in Active Markets for Identical Assets (Level1) Significant Other Observable Inputs (Level2) Significant Unobservable Inputs (Level3) Collateral Provided to Counterparties Balance at March31, 2010 (In thousands) Assets: Money market funds $ 10,977 $ 65,000 $ $ $ 75,977 Available-for-sale securities: Fixed-income securities 2,785 11,400 14,185 Equity securities 6,689 6,689 Insurance contract* 27,000 27,000 Commodity derivative instruments - current 38,146 38,146 Commodity derivative instruments - noncurrent 6,960 6,960 Total assets measured at fair value $ 20,451 $ 148,506 $ $ $ 168,957 Liabilities: Commodity derivative instruments

Business segment data

Business segment data
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Business Segment Data	15.Business segment data The Companys reportable segments are those that are based on the Companys method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The vast majority of the Companys operations are located within the United States. The Company also has investments in foreign countries, which largely consist of Centennial Resources equity method investment in the Brazilian Transmission Lines. 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 products and services. 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 pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides cathodic protection and other energy-related services. The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent regions of the United States and in and around the Gulf of Mexico. 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 Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Companys subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies general liability and automobile liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' equity method investment in the Brazilian Transmission Lines. The information below follows the same accounting policies as described in Note 1 of the Companys Notes to Consolidated Financial Statements in the 2009 Annual Report. Information on the Company's businesses was as follows: External Inter- segment Earnings (Loss) Three Months Operating Operating on Common Ended March 31, 2010 Revenues Revenues Stock (I

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Employee Benefit Plans	16. Employee benefit plans The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans were as follows: Other Postretirement Three Months Pension Benefits Benefits Ended March 31, 2010 2009 2010 2009 (In thousands) Components of net periodic benefit cost: Service cost $ 804 $ 2,097 $ 357 $ 440 Interest cost 4,926 5,529 1,277 1,195 Expected return on assets (5,692 ) (6,857 ) (1,392 ) (1,273 ) Amortization of prior service cost (credit) 38 151 (864 ) (568 ) Recognized net actuarial loss 972 174 388 185 Amortization of net transition obligation 532 438 Net periodic benefit cost, including amount capitalized 1,048 1,094 298 417 Less amount capitalized 276 281 47 46 Net periodic benefit cost $ 772 $ 813 $ 251 $ 371 In 2009, the Company evaluated several provisions of its employee defined benefit plans for nonunion and certain union employees. As a result of this evaluation, the Company determined that, effective January 1, 2010, all benefit and service accruals of these plans were frozen. These employees are eligible to receive additional defined contribution plan benefits. Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Companys businesses. Current 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, are not eligible for retiree medical benefits. In addition to the qualified plan defined pension benefits reflected in the table, the Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that generally provides for defined benefit payments at age 65 following the employees retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for this plan for the three months ended March31, 2010 and 2009, was $2.1 million.

REGULATORY MATTERS AND REVENUES

REGULATORY MATTERS AND REVENUES SUBJECT TO REFUND
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Regulatory Matters And Revenues Subject To Refund	17.Regulatory matters and revenues subject to refund In November 2006, Montana-Dakota filed an application with the NDPSC requesting an advance determination of prudence of Montana-Dakota's ownership interest in Big Stone StationII. In August 2008, the NDPSC approved Montana-Dakotas request for advance determination of prudence for ownership in the proposed Big Stone Station II for a minimum of 121.8MW up to a maximum of 133MW and a proportionate ownership share of the associated transmission electric resources. The intervenors in the proceeding appealed the NDPSC order to the North Dakota District Court which affirmed the order of the NDPSC. The intervenors then appealed the North Dakota District Court order to the North Dakota Supreme Court. The Big Stone Station II participants subsequently decided not to proceed with the project and in December2009, Montana-Dakota filed an application with the NDPSC for a determination that Montana-Dakotas continued participation in the Big Stone Station II is no longer prudent. The parties have stipulated that the intervenors will move to dismiss their appeal to the North Dakota Supreme Court if the NDPSC grants Montana-Dakotas pending application for a determination that its participation in the Big Stone Station II is no longer prudent. In December2009, Montana-Dakota filed applications with the NDPSC, SDPUC, and MTPSC for authority to defer the costs incurred for securing new electric generation, primarily Big Stone Station II, until the next general rate case. The SDPUC and the MTPSC approved Montana-Dakotas applications on February11, 2010, and April6, 2010, respectively. On April14, 2010, Montana-Dakota and the NDPSC Advocacy Staff filed a settlement agreement with the NDPSC. The settlement agreement provides for the recovery of approximately $10.2million, including carrying charges, of the North Dakota allocated costs associated with the Big Stone Station II over a three-year period beginning June1, 2010. A hearing on the settlement agreement before the NDPSC is scheduled for May5, 2010. In August 2009, Montana-Dakota filed an application with the WYPSC for an electric rate increase. Montana-Dakota requested a total increase of $6.2million annually or approximately 31percent above current rates. The rate increase request was necessitated by Montana-Dakotas purchase of an ownership interest in Wygen III. On January14, 2010, Montana-Dakota filed a supplement to the application to reflect the inclusion of bonus tax depreciation on Wygen III, reducing its request to a $5.1million annual increase or approximately 25 percent above current rates. A hearing was held February23 through February 25, 2010. A stipulation and agreement between Montana-Dakota and the Wyoming Office of Consumer Advocate was filed with the WYPSC on March5, 2010, that provides a $3.3million annual increase to be phased-in over a three-year period beginning May1, 2010. The WYPSC held a hearing on the stipulation on March 22, 2010, and held additional deliberations on April14, 2010, wherein the WYPSC decided on each issue in the case and Montana-Dakota was directed to file a compliance filing. Montana-Dakota submitted th

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Contingencies	18.Contingencies Litigation Coalbed Natural Gas Operations Fidelitys CBNG operations are and have been the subject of numerous lawsuits in Montana and Wyoming. The current cases involve the permitting and use of water produced in connection with Fidelitys CBNG development in the Powder River Basin. Some of these cases challenge the issuance of discharge permits by the Montana DEQ and approval of other water management tools by the MBOGC. In April 2006, the Northern Cheyenne Tribe filed a complaint in Montana Twenty-Second Judicial District Court against the Montana DEQ seeking to set aside Fidelitys renewed direct discharge and treatment permits. The Northern Cheyenne Tribe claimed the Montana DEQ violated the Clean Water Act and the Montana Water Quality Act by failing to include in the permits conditions requiring application of the best practicable control technology currently available and by failing to impose a nondegradation policy like the one the BER adopted soon after the permit was issued. In addition, the Northern Cheyenne Tribe claimed that the actions of the Montana DEQ violated the Montana State Constitutions guarantee of a clean and healthful environment, that the Montana DEQs related environmental assessment was invalid, that the Montana DEQ was required, but failed, to prepare an EIS and that the Montana DEQ failed to consider other alternatives to the issuance of the permits. Fidelity, the NPRC, and the TRWUA were granted leave to intervene in this proceeding. In January 2009, the Montana Twenty-Second Judicial District Court decided the case in favor of Fidelity and the Montana DEQ in all respects, denying the motions of the Northern Cheyenne Tribe, TRWUA, and NPRC, and granting the cross-motions of the Montana DEQ and Fidelity in their entirety. As a result, Fidelity may continue to utilize its direct discharge and treatment permits. The NPRC, the TRWUA and the Northern Cheyenne Tribe appealed the decision to the Montana Supreme Court in March 2009. Fidelitys discharge of water pursuant to its two permits is its primary means for managing CBNG-produced water. Fidelity believes that its discharge permits should, assuming normal operating conditions, allow Fidelity to continue its existing CBNG operations through the expiration of the permits in March 2011. If its permits are set aside, Fidelitys CBNG operations in Montana could be significantly and adversely affected. In October 2003, Tongue Yellowstone Irrigation District, NPRC and MEIC filed a lawsuit in Montana First Judicial District Court challenging the MBOGCs ROD adopting the 2003 Final EIS which analyzed CBNG development in the State of Montana. The primary legal issue before the court was whether the ROD authorized the wasting of ground water in violation of the Montana State Constitution and the public trust doctrine. Specifically, the plaintiffs contended that various water management tools, including Fidelitys direct discharge permits, allowed for the waste of water. On March5, 2010, the Montana First Judicial District Court issued an order holding that Fidelitys direct discharge permits did not violate the Montana State Constitution. On

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS
	3 Months Ended Mar. 31, 2010
Notes To Financial Statements [Abstract]
Subsequent Events	19.Subsequent events On April29, 2010, Fidelity completed the acquisition of natural gas properties located in the Green River Basin in southwest Wyoming, with an October1, 2009, effective date. The acquisition includes the purchase of 63Bcfe of proven reserves. The purchase price for these properties was approximately $113million, subject to accounting and purchase price adjustments customary with acquisitions of this type.

Document Information

Document Information
	3 Months Ended Mar. 31, 2010
Document Information [Text Block]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	2010-03-31

Entity Information

Entity Information (USD $)
	3 Months Ended Mar. 31, 2010	Apr. 29, 2010	Jun. 30, 2009
Entity [Text Block]
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	Yes
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$3,489,895,496
Entity Common Stock Shares Outstanding		188,130,501
Document Fiscal Year Focus	2,010
Document Fiscal Period Focus	Q1