MDU Resources (MDU) 10-Q 7 Aug 09 2009 Q2 Quarterly report Financial data

1000 - CONSOLIDATED STATEMENTS

1000 - CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Share data	3 Months Ended Jun. 30, 2009	3 Months Ended Jun. 30, 2008	6 Months Ended Jun. 30, 2009	6 Months Ended Jun. 30, 2008
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$263,617	$376,324	$858,191	$893,586
Construction services, natural gas and oil production, construction materials and contracting, and other	694,423	875,448	1,193,854	1,480,093
Total operating revenues	958,040	1,251,772	2,052,045	2,373,679
Operating expenses:
Fuel and purchased power	15,166	15,718	33,896	34,495
Purchased natural gas sold	106,401	145,060	462,897	421,684
Electric, natural gas distribution and pipeline and energy services	62,581	61,828	133,932	121,390
Construction services, natural gas and oil production, construction materials and contracting, and other	554,556	687,479	976,706	1,185,097
Depreciation, depletion and amortization	80,449	89,678	173,694	176,909
Taxes, other than income	38,822	53,518	91,774	108,041
Write-down of natural gas and oil properties	0	0	620,000	0
Total operating expense	857,975	1,053,281	2,492,899	2,047,616
Operating income (loss)	100,065	198,491	(440,854)	326,063
Earnings from equity method investments	2,078	2,039	3,864	3,864
Other income (expense)	2,435	(37)	4,154	1,528
Interest expense	20,759	19,186	41,755	37,842
Income (loss) before income taxes	83,819	181,307	(474,591)	293,613
Income taxes	28,508	65,800	(186,100)	107,055
Net income (loss)	55,311	115,507	(288,491)	186,558
Dividends on preferred stocks	171	171	343	343
Earnings (loss) on common stock	$55,140	$115,336	($288,834)	$186,215
Earnings (loss) per common share -- basic	0.3	0.63	-1.57	1.02
Earnings (loss) per common share -- diluted	0.3	0.63	-1.57	1.01
Dividends per common share	0.155	0.145	0.31	0.29
Weighted average common shares outstanding -- basic	183,964	182,972	183,876	182,785
Weighted average common shares outstanding -- diluted	184,398	183,727	183,876	183,513

2000 - CONSOLIDATED BALANCE SHE

2000 - CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands	Jun. 30, 2009	Dec. 31, 2008	Jun. 30, 2008
Current assets:
Cash and cash equivalents	$34,310	$51,714	$82,039
Receivables, net	559,842	707,109	769,379
Inventories	285,814	261,524	267,125
Deferred income taxes	2,490	0	47,442
Short-term investments	1,967	2,467	13,768
Commodity derivative instruments	62,048	78,164	64,193
Prepayments and other current assets	117,381	171,314	111,100
Total current assets	1,063,852	1,272,292	1,355,046
Investments	125,361	114,290	121,279
Property, plant and equipment	6,651,088	7,062,237	6,507,164
Less accumulated depreciation, depletion and amortization	2,906,824	2,761,319	2,408,093
Net property, plant and equipment	3,744,264	4,300,918	4,099,071
Deferred charges and other assets:
Goodwill	622,131	615,735	437,832
Other intangible assets, net	25,320	28,392	32,485
Other	242,436	256,218	166,019
Total deferred charges and other assets	889,887	900,345	636,336
Total assets	5,823,364	6,587,845	6,211,732
Current Liabilities:
Short-term borrowings	0	105,100	79,960
Long-term debt due within one year	27,879	78,666	87,366
Accounts payable	332,957	432,358	396,715
Taxes payable	42,151	49,784	46,200
Deferred income taxes	0	20,344	0
Dividends payable	28,686	28,640	26,723
Accrued compensation	44,141	55,646	55,631
Commodity derivative instruments	57,139	56,529	98,631
Other accrued liabilities	158,661	140,408	196,522
Total current liabilities	691,614	967,475	987,748
Long-term debt	1,636,592	1,568,636	1,474,908
Deferred credits and other liabilities:
Deferred income taxes	540,952	727,857	685,480
Other liabilities	544,104	562,801	472,989
Total deferred credits and other liabilities	1,085,056	1,290,658	1,158,469
Stockholders' equity
Preferred stocks	15,000	15,000	15,000
Common stockholders' equity:
Common stock	184,508	184,208	183,706
Other paid-in capital	941,773	938,299	925,784
Retained earnings	1,270,778	1,616,830	1,567,035
Accumulated other comprehensive income (loss)	1,669	10,365	(97,292)
Treasury stock at cost	(3,626)	(3,626)	(3,626)
Total common stockholders' equity	2,395,102	2,746,076	2,575,607
Total stockholders' equity	2,410,102	2,761,076	2,590,607
Total liabilities and stockholders' equity	$5,823,364	$6,587,845	$6,211,732

2100 - PARENTHETICAL DATA TO TH

2100 - PARENTHETICAL DATA TO THE CONSOLIDATED BALANCE SHEETS (USD $)
	Jun. 30, 2009	Dec. 31, 2008	Jun. 30, 2008
Common stockholders' equity:
Par Value	1	1	1
Common stock shares issued	184,508,109	184,208,283	183,706,236
Treasury shares	538,921	538,921	538,921

3000 - CONSOLIDATED STATEMENTS

3000 - CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands	6 Months Ended Jun. 30, 2009	6 Months Ended Jun. 30, 2008
Operating activities:
Net income (loss)	($288,491)	$186,558
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	173,694	176,909
Earnings, net of distributions, from equity method investments	(1,685)	(1,844)
Deferred income taxes	(206,955)	34,870
Write-down of natural gas and oil properties	620,000	0
Changes in current assets and liabilities, net of acquisitions:
Receivables	149,782	(46,550)
Inventories	(26,574)	(36,482)
Other current assets	47,837	(111,199)
Accounts payable	(66,260)	18,953
Other current liabilities	2,218	11,209
Other noncurrent changes	(5,141)	6,381
Net cash provided by operating activities	398,425	238,805
Investing activities:
Capital expenditures	(272,867)	(386,014)
Acquisitions, net of cash acquired	(3,764)	(271,191)
Net proceeds from sale or disposition of property	7,494	26,379
Investments	(2,368)	80,389
Net cash used in investing activities	(271,505)	(550,437)
Financing activities:
Issuance of short-term borrowings	0	79,960
Repayment of short-term borrowings	(105,100)	(1,700)
Issuance of long-term debt	109,400	379,644
Repayment of long-term debt	(92,024)	(125,637)
Proceeds from issuance of common stock	284	4,945
Dividends paid	(57,325)	(53,296)
Tax benefit on stock-based compensation	144	3,737
Net cash provided by (used in) financing activities	(144,621)	287,653
Effect of exchange rate changes on cash and cash equivalents	297	198
Decrease in cash and cash equivalents	(17,404)	(23,781)
Cash and cash equivalents -- beginning of year	51,714	105,820
Cash and cash equivalents -- end of period	$34,310	$82,039

6000 - Basis of presentation

6000 - Basis of presentation
	6 Months Ended Jun. 30, 2009 USD / shares
Basis of presentation
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 2008 Annual Report, and the standards of accounting measurement set forth in APB Opinion No. 28 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 2008 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.

6010 - Seasonality of operation

6010 - Seasonality of operations
	6 Months Ended Jun. 30, 2009 USD / shares
Seasonality of operations
Nature 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.

6020 - Allowance for doubtfull

6020 - Allowance for doubtfull accounts
	6 Months Ended Jun. 30, 2009 USD / shares
Allowance for doubtful accounts
Allowance for doubtfull accounts	3.Allowance for doubtful accounts The Company's allowance for doubtful accounts as of June 30, 2009 and 2008, and December 31, 2008, was $16.5 million, $14.3 million and $13.7 million, respectively.

6030 - Natural gas in storage

6030 - Natural gas in storage
	6 Months Ended Jun. 30, 2009 USD / shares
Natural gas in storage
Natural gas in storage	4.Natural gas in storage Natural gas in storage for the Company's regulated operations is generally carried at 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 $19.1 million, $11.4 million and $27.6 million at June 30, 2009 and 2008, and December 31, 2008, 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 $40.3 million, $43.0 million, and $43.4 million at June 30, 2009 and 2008, and December 31, 2008, respectively.

6040 - Inventories

6040 - Inventories
	6 Months Ended Jun. 30, 2009 USD / shares
Inventories
Inventories	5.Inventories Inventories, other than natural gas in storage for the Companys regulated operations, consisted primarily of aggregates held for resale of $96.3 million, $110.2 million and $89.1 million; materials and supplies of $69.4 million, $60.5 million and $70.3 million; asphalt oil of $49.8 million, $41.2 million and $22.1 million; and other inventories of $51.2 million, $43.8 million and $52.4 million, as of June 30, 2009 and 2008, and December 31, 2008, respectively. These inventories were stated at the lower of average cost or market value.

6050 - Natural gas and oil prop

6050 - Natural gas and oil properties
	6 Months Ended Jun. 30, 2009 USD / shares
Natural gas and oil properties
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 based on spot market prices that exist at the end of the period 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 is estimated based on end-of-quarter spot market prices adjusted for contracted price changes. 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 unless subsequent price changes eliminate or reduce an indicated write-down. Due to low natural gas and oil prices that existed on March 31, 2009, the Companys capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 2009. Accordingly, the Company was required to write down its natural gas and oil producing properties. The noncash write-down amounted to $620.0 million ($384.4 million after tax) for the three months ended March 31, 2009. At June 30, 2009, the Companys full-cost ceiling exceeded the Companys capitalized cost. However, sustained downward movements in natural gas and oil prices subsequent to June 30, 2009, could result in future write-downs of the Companys natural gas and oil properties. 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) as of 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 Companys cash flow hedges, see Note 13.

6060 - Earnings

6060 - Earnings (loss) per common share
	6 Months Ended Jun. 30, 2009 USD / shares
Earnings (loss) per common share
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 June 30, 2009 and 2008, and the six months ended June 30, 2008, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the six months ended June 30, 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 six months ended June 30, 2009, the effect of outstanding stock options, restricted stock grants and 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.

6070 - Cash flow information

6070 - Cash flow information
	6 Months Ended Jun. 30, 2009 USD / shares
Cash flow information
Cash flow information	8.Cash flow information Cash expenditures for interest and income taxes were as follows: Six Months Ended June 30, 2009 2008 (In thousands) Interest, net of amount capitalized $ 40,588 $ 37,504 Income taxes $ 13,343 $ 91,398

6080 - New accounting standards

6080 - New accounting standards
	6 Months Ended Jun. 30, 2009 USD / shares
New accounting standards
New accounting standards	9.New accounting standards SFAS No. 157 In September 2006, the FASB issued SFAS No. 157. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The standard applies under other accounting pronouncements that require or permit fair value measurements with certain exceptions. SFAS No. 157 was effective for the Company on January 1, 2008. FSP FAS No. 157-2 delayed the effective date of SFAS No. 157 for certain nonfinancial assets and nonfinancial liabilities to January 1, 2009. The types of assets and liabilities that are recognized at fair value under the provisions of SFAS No. 157 effective January 1, 2009, due to the delayed effective date, include nonfinancial assets and nonfinancial liabilities initially measured at fair value in a business combination or new basis event, certain fair value measurements associated with goodwill impairment testing, indefinite-lived intangible assets and nonfinancial long-lived assets measured at fair value for impairment assessment, and asset retirement obligations initially measured at fair value. The adoption of SFAS No. 157, including the application to certain nonfinancial assets and nonfinancial liabilities with a delayed effective date of January 1, 2009, did not have a material effect on the Company's financial position or results of operations. SFAS No. 141 (revised)In December 2007, the FASB issued SFAS No. 141 (revised). SFAS No. 141 (revised) requires an acquirer to recognize and measure the assets acquired, liabilities assumed and any noncontrolling interests in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exception. In addition, SFAS No. 141 (revised) requires that acquisition-related costs will be generally expensed as incurred. SFAS No. 141 (revised) also expands the disclosure requirements for business combinations. SFAS No. 141 (revised) was effective for the Company on January 1, 2009. The adoption of SFAS No. 141 (revised) did not have a material effect on the Companys financial position or results of operations. SFAS No. 160 In December 2007, the FASB issued SFAS No. 160. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 was effective for the Company on January 1, 2009. The adoption of SFAS No. 160 did not have a material effect on the Companys financial position or results of operations. SFAS No. 161 In March 2008, the FASB issued SFAS No. 161. SFAS No. 161 requires enhanced disclosures about an entitys derivative and hedging activities including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entitys financial position, financial performance and cash flows. This Statement was effective for the Company on January 1, 2009. The adoption of SFAS No. 161 requires additional disclosures regarding the Companys derivative instruments; however, it did not impact the Companys financial position or r

6090 - Comprehensive income

6090 - Comprehensive income (loss)
	6 Months Ended Jun. 30, 2009 USD / shares
Comprehensive income (loss)
Comprehensive income	10.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 loss resulted from losses 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 loss and related tax effects, were as follows: Three Months Ended June 30, 2009 2008 (In thousands) Net income $ 55,311 $ 115,507 Other comprehensive loss: Net unrealized loss on derivative instruments qualifying as hedges: Net unrealized loss on derivative instruments arising during the period, net of tax of $(4,028) and $(37,169) in 2009 and 2008, respectively (6,571 ) (60,644 ) Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $11,415 and $(5,045) in 2009 and 2008, respectively 18,625 (8,230 ) Net unrealized loss on derivative instruments qualifying as hedges (25,196 ) (52,414 ) Foreign currency translation adjustment, net of tax of $3,711 and $2,570 in 2009 and 2008, respectively 5,756 3,977 (19,440 ) (48,437 ) Comprehensive income $ 35,871 $ 67,070 Six Months Ended June 30, 2009 2008 (In thousands) Net income (loss) $ (288,491 ) $ 186,558 Other comprehensive loss: Net unrealized loss on derivative instruments qualifying as hedges: Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $5,634 and $(53,537) in 2009 and 2008, respectively 9,193 (87,433 ) Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $14,646 and $2,786 in 2009 and 2008, respectively 23,896 4,522 Net unrealized loss on derivative instruments qualifying as hedges (14,703 ) (91,955 ) Foreign currency translation adjustment, net of tax of $3,875 and $2,876 in 2009 and 2008, respectively 6,007 4,461 (8,696 ) (87,494 ) Comprehensive income (loss) $ (297,187 ) $ 99,064

6100 - Equity method investment

6100 - Equity method investments
	6 Months Ended Jun. 30, 2009 USD / shares
Equity method investments
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 June 30, 2009, 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. At June 30, 2009 and 2008, and December 31, 2008, the Company's equity method investments had total assets of $348.3 million, $431.1 million and $294.7 million, respectively, and long-term debt of $171.7 million, $218.8 million and $158.0 million, respectively. The Company's investment in its equity method investments was approximately $52.6 million, $63.0 million and $44.4 million, including undistributed earnings of $8.4 million, $8.7 million and $6.8 million, at June 30, 2009 and 2008, and December 31, 2008, respectively.

6110 - Goodwill and other intan

6110 - Goodwill and other intangible assets
	6 Months Ended Jun. 30, 2009 USD / shares
Goodwill and other intangible assets
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 Six Months Ended January1, During June30, June 30, 2009 2009 the Year* 2009 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution 344,952 296 345,248 Construction services 95,619 4,398 100,017 Pipeline and energy services 1,159 --- 1,159 Natural gas and oil production --- --- --- Construction materials and contracting 174,005 1,702 175,707 Other --- --- --- Total $ 615,735 $ 6,396 $ 622,131 * Includes purchase price adjustments that were not material related to acquisitions in a prior period. Balance Goodwill Balance as of Acquired as of Six Months Ended January1, During June30, June 30, 2008 2008 the Year* 2008 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution 171,129 (11 ) 171,118 Construction services 91,385 3,937 95,322 Pipeline and energy services 1,159 --- 1,159 Natural gas and oil production --- --- --- Construction materials and contracting 162,025 8,208 170,233 Other --- --- --- Total $ 425,698 $ 12,134 $ 437,832 * 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, 2008 2008 Year* 2008 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution 171,129 173,823 344,952 Construction services 91,385 4,234 95,619 Pipeline and energy services 1,159 --- 1,159 Natural gas and oil production --- --- --- Construction materials and contracting 162,025 11,980 174,005 Other --- --- --- Total $ 425,698 $ 190,037 $ 615,735 *Includes purchase price adjustments that were not material related to acquisitions in a prior period. Other intangible assets were as follows: June30, 2009 June30, 2008 December31, 2008 (In thousands) Customer relationships $ 21,688 $ 25,262 $ 21,842 Accumulated amortization (8,142 ) (5,979 ) (6,985 ) 13,546 19,283 14,857 Noncompete agreements 9,792 10,823 10,080 Accumulated amortization (5,942 ) (4,493 ) (5,126 ) 3,850 6,330 4,954 Other 10,679 8,370 10,949 Accumulated amortization (2,755 ) (1,498 ) (2,368 ) 7,924 6,872 8,581 Total $ 25,320 $ 32,485 $ 28,392 Amortization expense for amo

6120 - Derivative instruments

6120 - Derivative instruments
	6 Months Ended Jun. 30, 2009 USD / shares
Derivative instruments
Derivatives 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 June 30, 2009, 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 2008 Annual Report. Cascade and Intermountain At June 30, 2009, Cascade and Intermountain held natural gas swap agreements, with total forward notional volumes of 33.8 million MMBtu, which were not designated as hedges. Cascade and Intermountain utilize natural gas swap agreements to manage a portion of their regulated natural gas supply portfolio 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 apply SFAS No. 71 and 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 and six months ended June 30, 2009, Cascade and Intermountain recorded the decrease in the fair market value of the derivative instruments of $28.8 million and $22.0 million, respectively, in 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 and Intermountain's derivative instruments with credit-risk-related contingent features that are in a liability position at June

6130 - Fair value measurements

6130 - Fair value measurements
	6 Months Ended Jun. 30, 2009 USD / shares
Fair value measurements
Fair value measurements	14.Fair value measurements The Company elected to measure its investments in certain fixed-income and equity securities at fair value in accordance with SFAS No. 159. These investments had previously been accounted for as available-for-sale investments in accordance with SFAS No. 115. 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 $29.5 million, $34.0 million and $27.7 million, as of June 30, 2009 and 2008, and December 31, 2008, respectively, are classified as Investments on the Consolidated Balance Sheets. The increase in the fair value of these investments for the three and six months ended June 30, 2009, was $3.7 million (before tax) and $1.8 million (before tax), respectively. The decrease in the fair value of these investments for the three and six months ended June 30, 2008, was $184,000 (before tax) and $2.3 million (before tax), respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income. The Company did not elect the fair value option for its remaining available-for-sale securities, which are auction rate securities. The Companys auction rate securities, which totaled $11.4 million at June 30, 2009 and 2008, and December 31, 2008, are accounted for as available-for-sale in accordance with SFAS No. 115 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. SFAS No. 157 defines fair value 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 statement 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 June 30, 2009, 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 June30, 2009 (In thousands) Assets: Available-for-sale securities $ 29,532 $ 11,400 $ --- $ --- $ 40,932 Commodity derivative instruments - current --- 62,048 --- --- 62,048 Commodity derivative instruments - noncurrent --- 4,218 --- --- 4,218 Total assets measured at fair value $ 29,532 $ 77,666 $ --- $ --- $ 107,198 Liabilities: Commo

6140 - Business segment data

6140 - Business segment data
	6 Months Ended Jun. 30, 2009 USD / shares
Business segment data
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 protection 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 energy-related management 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 2008 Annual Report. Information on the Companys businesses was as follows: Inter- External segment Earnings Three Months Operating Operating on Common Ended June 30, 2009 Revenues Revenues Stock (In thousands) Electric $ 44,508 $ ---

6150 - Employee benefit plans

6150 - Employee benefit plans
	6 Months Ended Jun. 30, 2009 USD / shares
Employee benefit plans
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 June 30, 2009 2008 2009 2008 (In thousands) Components of net periodic benefit cost: Service cost $ 1,966 $ 2,191 $ 651 $ 660 Interest cost 5,430 6,505 1,530 1,797 Expected return on assets (5,673 ) (8,458 ) (1,544 ) (1,691 ) Amortization of prior service cost (credit) 151 198 (810 ) (988 ) Amortization net actuarial loss 643 332 170 246 Amortization of net transition obligation --- --- 625 763 Net periodic benefit cost, including amount capitalized 2,517 768 622 787 Less amount capitalized 484 217 (23 ) 124 Net periodic benefit cost $ 2,033 $ 551 $ 645 $ 663 Other Postretirement Six Months Pension Benefits Benefits Ended June 30, 2009 2008 2009 2008 (In thousands) Components of net periodic benefit cost: Service cost $ 4,063 $ 4,820 $ 1,091 $ 1,150 Interest cost 10,959 11,629 2,725 2,982 Expected return on assets (12,530 ) (14,494 ) (2,817 ) (3,388 ) Amortization of prior service cost (credit) 302 364 (1,378 ) (1,677 ) Amortization net actuarial loss 817 574 355 361 Amortization of net transition obligation --- --- 1,063 1,294 Net periodic benefit cost, including amount capitalized 3,611 2,893 1,039 722 Less amount capitalized 765 396 23 189 Net periodic benefit cost $ 2,846 $ 2,497 $ 1,016 $ 533 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 and six months ended June 30, 2009, was $2.2 million and $4.3 million, respectively. The Companys net periodic benefit cost for this plan for the three and six months ended June 30, 2008, was $2.4 million and $4.4 million, respectively.

6160 - Regulatory matters and r

6160 - Regulatory matters and revenues subject to refund
	6 Months Ended Jun. 30, 2009 USD / shares
Regulatory matters and revenues subject to refund
Regulatory matters and revenues subject to refund	17.Regulatory matters and revenues subject to refund In August 2008, Montana-Dakota filed an application with the WYPSC for an electric rate increase. Montana-Dakota requested a total increase of $757,000 annually or approximately 4 percent above current rates. On April 6, 2009, Montana-Dakota and the Office of Consumer Advocate filed a Stipulation with the WYPSC, agreeing to an increase of $425,000 annually or 2.3 percent with rates effective May 1, 2009. On April 15, 2009, the WYPSC approved the Stipulation. 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 Station II. 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 121.8 MW up to a maximum of 133 MW and a proportionate ownership share of the associated transmission electric resources. In September 2008, the intervenors in the proceeding appealed the NDPSC order to the North Dakota District Court. The intervenors brief was filed January 21, 2009, and Montana-Dakota filed its response brief on February 17, 2009. In December 1999, Williston Basin filed a general natural gas rate change application with the FERC. Williston Basin began collecting such rates effective June 1, 2000, subject to refund. Currently, the only remaining issue outstanding related to this rate change application is in regard to certain service restrictions. In May 2004, the FERC remanded this issue to an ALJ for resolution. In November 2005, the FERC issued an Order on Initial Decision affirming the ALJ's Initial Decision regarding certain service and annual demand quantity restrictions. In April 2006, the FERC issued an Order on Rehearing denying Williston Basin's Request for Rehearing of the FERC's Order on Initial Decision. In April 2006, Williston Basin appealed to the D.C. Appeals Court certain issues addressed by the FERC's Order on Initial Decision and its Order on Rehearing. In March 2008, the D.C. Appeals Court issued its opinion in this matter concerning the service restrictions. The D.C. Appeals Court found that the FERC was correct to decide the case under the just and reasonable standard of section 5(a) of the Natural Gas Act; however, it remanded the case back to the FERC as flaws in the FERCs reasoning render its orders arbitrary and capricious. In December 2008, the FERC issued its Order Requesting Data and Comment on this matter. Williston Basin and Northern States Power Company provided responses to FERCs requests in January 2009. In addition, initial comments addressing specific issues identified by the FERC were filed on February 17, 2009, and reply comments were filed on March 9, 2009. The initial and reply comments should contain all the arguments and supporting evidence the parties determine they need to provide to update the record with regard to the issue under remand.

6170 - Contingencies

6170 - Contingencies
	6 Months Ended Jun. 30, 2009 USD / shares
Contingencies
Contingencies	18.Contingencies Litigation Coalbed Natural Gas Operations Fidelity is a party to and/or certain of its operations are or have been the subject of more than a half dozen lawsuits in Montana and Wyoming related to administrative regulation of water produced in connection with Fidelitys CBNG development in the Powder River Basin. These cases involve legal challenges to the issuance of discharge permits, as well as challenges to the State of Wyomings CBNG water permitting procedures. In April 2006, the Northern Cheyenne Tribe filed a complaint in Montana State 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. On January 12, 2009, the Montana State 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 on March 9, 11, and 13, 2009, respectively. 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. The Powder River Basin Resource Council funded litigation, filed in Wyoming State District Court in June 2007, on behalf of two surface owners against the Wyoming State Engineer and the Wyoming Board of Control. The plaintiffs sought a declaratory judgment that current ground water permitting practices were unlawful; that the state was required to adopt rules and procedures to ensure that coalbed groundwater was managed in accordance with the Wyoming Constitution and other laws; and that would prohibit the Wyoming State Engineer from issuing permits to produce coalbed groundwater and permits to store coalbed groundwater in reservoirs until the Wyoming State Engineer adopted such rules. The Wyoming Stat

6180 - Subsequent events

6180 - Subsequent events
	6 Months Ended Jun. 30, 2009 USD / shares
Subsequent events
Subsequent events	19.Subsequent events The Company evaluated for events or transactions between the balance sheet date and August 7, 2009, the date of the issuance of the financial statements, that would require recognition or disclosure in the financial statements.

Document Information

Document Information
	6 Months Ended Jun. 30, 2009 USD / shares
Document Information
Document Type	10-Q
Amendment Flag	false
Amendment Description	none
Document Period End Date	2009-06-30

Entity Information

Entity Information (USD $)
	6 Months Ended Jun. 30, 2009	Jul. 31, 2009	Jun. 30, 2008
Entity Information
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			$6,385,212,601
Entity Common Stock, Shares Outstanding		184,073,788