Edgar Filing: MDU RESOURCES GROUP INC

mduform10-q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
	THE SECURITIES EXCHANGE ACT OF 1934

	For The Quarterly Period Ended June 30, 2010

	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)

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 x 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 x No 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 definition 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 Exchange Act). Yes o No x.

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of July 30, 2010: 188,167,816 shares.

DEFINITIONS

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

Abbreviation or Acronym

2009 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, 2009
ASC	FASB Accounting Standards Codification
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BER	Montana Board of Environmental Review
Big Stone Station	450-MW coal-fired electric generating facility located near Big Stone City, South Dakota (22.7 percent ownership)
Big Stone Station II	Formerly proposed coal-fired electric generating facility located near Big Stone City, South Dakota (the Company had anticipated ownership of at least 116 MW)
Brazilian Transmission Lines	Company’s equity method investment in companies owning ECTE, ENTE and ERTE
Btu	British thermal unit
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CBNG	Coalbed natural gas
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
Clean Air Act	Federal Clean Air Act
Clean Water Act	Federal Clean Water Act
Company	MDU Resources Group, Inc.
dk	Decatherm
ECTE	Empresa Catarinense de Transmissão de Energia S.A.
EIS	Environmental Impact Statement
ENTE	Empresa Norte de Transmissão de Energia S.A.
EPA	U.S. Environmental Protection Agency
ERTE	Empresa Regional de Transmissão de Energia S.A.
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
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
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
IPUC	Idaho Public Utilities Commission
Knife River	Knife River Corporation, a direct wholly owned subsidiary of Centennial
kWh	Kilowatt-hour
LTM	LTM, Inc., an indirect wholly owned subsidiary of Knife River
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
MBI	Morse Bros., Inc., an indirect wholly owned subsidiary of Knife River
MBOGC	Montana Board of Oil and Gas Conservation
Mcf	Thousand cubic feet
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
MEIC	Montana Environmental Information Center, Inc.
MMBtu	Million Btu
MMcf	Million cubic feet
MMdk	Million decatherms
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
Montana DEQ	Montana State Department of Environmental Quality
Montana First Judicial District Court	Montana First Judicial District Court, Lewis and Clark County
Montana Twenty-Second Judicial District Court	Montana Twenty-Second Judicial District Court, Big Horn County
MPX	MPX Termoceara Ltda. (49 percent ownership, sold in June 2005)
MTPSC	Montana Public Service Commission
MW	Megawatt
NDPSC	North Dakota Public Service Commission
North Dakota District Court	North Dakota South Central Judicial District Court for Burleigh County
NPRC	Northern Plains Resource Council
NSPS	New Source Performance Standards
Oil	Includes crude oil, condensate and natural gas liquids
OPUC	Oregon Public Utility Commission
Oregon DEQ	Oregon State Department of Environmental Quality

Prairielands	Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
PRP	Potentially Responsible Party
PSD	Prevention of Significant Deterioration
ROD	Record of Decision
SDPUC	South Dakota Public Utilities Commission
SEC	U.S. Securities and Exchange Commission
SEC Defined Prices	The average price of natural gas and oil 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
South Dakota Federal District Court	U.S. District Court for the District of South Dakota
South Dakota SIP	South Dakota State Implementation Plan
TRWUA	Tongue River Water Users’ Association
WBI Holdings	WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
Williston Basin	Williston Basin Interstate Pipeline Company, an indirect wholly owned subsidiary of WBI Holdings
WUTC	Washington Utilities and Transportation Commission
Wygen III	100-MW coal-fired electric generating facility located near Gillette, Wyoming (25 percent ownership)
WYPSC	Wyoming Public Service Commission

INTRODUCTION

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 products and services.

The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings (comprised of the pipeline and energy services and the natural gas and oil 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). For more information on the Company’s business segments, see Note 15.

INDEX

Part I -- Financial Information	Page

Consolidated Statements of Income --
Three and Six Months Ended June 30, 2010 and 2009	7

Consolidated Balance Sheets --
June 30, 2010 and 2009, and December 31, 2009	8

Consolidated Statements of Cash Flows --
Six Months Ended June 30, 2010 and 2009	9

Notes to Consolidated Financial Statements	10

Management's Discussion and Analysis of Financial Condition and Results of Operations	35

Quantitative and Qualitative Disclosures About Market Risk	55

Controls and Procedures	57

Part II -- Other Information

Legal Proceedings	57

Risk Factors	58

Unregistered Sales of Equity Securities and Use of Proceeds	60

Exhibits	60

Signatures	61

Exhibit Index	62

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	272,177	$	263,617	$	732,422	$	858,191
Construction services, natural gas and oil production, construction materials and contracting, and other		634,267		694,423		1,008,799		1,193,854
Total operating revenues		906,444		958,040		1,741,221		2,052,045
Operating expenses:
Fuel and purchased power		13,106		15,166		30,017		33,896
Purchased natural gas sold		97,441		106,401		331,133		462,897
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services		68,437		62,581		131,421		133,932
Construction services, natural gas and oil production, construction materials and contracting, and other		516,854		554,556		830,642		976,706
Depreciation, depletion and amortization		81,547		80,449		160,225		173,694
Taxes, other than income		40,397		38,822		86,192		91,774
Write-down of natural gas and oil properties		—		—		—		620,000
Total operating expenses		817,782		857,975		1,569,630		2,492,899

Operating income (loss)		88,662		100,065		171,591		(440,854	)

Earnings from equity method investments		2,260		2,078		4,443		3,864

Other income		2,686		2,435		5,188		4,154

Interest expense		20,490		20,759		41,006		41,755

Income (loss) before income taxes		73,118		83,819		140,216		(474,591	)

Income taxes		24,180		28,508		49,506		(186,100	)

Net income (loss)		48,938		55,311		90,710		(288,491	)

Dividends on preferred stocks		171		171		343		343

Earnings (loss) on common stock	$	48,767	$	55,140	$	90,367	$	(288,834	)

Earnings (loss) per common share -- basic	$	.26	$	.30	$	.48	$	(1.57	)

Earnings (loss) per common share -- diluted	$	.26	$	.30	$	.48	$	(1.57	)

Dividends per common share	$	.1575	$	.1550	$	.3150	$	.3100

Weighted average common shares outstanding -- basic		188,129		183,964		188,047		183,876

Weighted average common shares outstanding -- diluted		188,267		184,398		188,198		183,876

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2010			June 30, 2009			December 31, 2009
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	65,792		$	34,310		$	175,114
Receivables, net		502,454			559,842			531,980
Inventories		260,163			285,814			249,804
Deferred income taxes		17,755			2,490			28,145
Short-term investments		250			1,967			2,833
Commodity derivative instruments		24,932			62,048			7,761
Prepayments and other current assets		97,953			117,381			66,021
Total current assets		969,299			1,063,852			1,061,658
Investments		142,212			125,361			145,416
Property, plant and equipment		7,085,632			6,651,088			6,766,582
Less accumulated depreciation, depletion and amortization		3,000,663			2,906,824			2,872,465
Net property, plant and equipment		4,084,969			3,744,264			3,894,117
Deferred charges and other assets:
Goodwill		634,654			622,131			629,463
Other intangible assets, net		26,199			25,320			28,977
Other		255,473			242,436			231,321
Total deferred charges and other assets		916,326			889,887			889,761
Total assets	$	6,112,806		$	5,823,364		$	5,990,952

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	3,700		$	—		$	10,300
Long-term debt due within one year		72,551			27,879			12,629
Accounts payable		266,069			332,957			281,906
Taxes payable		39,976			42,151			55,540
Dividends payable		29,802			28,686			29,749
Accrued compensation		35,989			44,141			47,425
Commodity derivative instruments		20,160			57,139			36,907
Other accrued liabilities		172,446			158,661			192,729
Total current liabilities		640,693			691,614			667,185
Long-term debt		1,508,714			1,636,592			1,486,677
Deferred credits and other liabilities:
Deferred income taxes		627,256			540,952			590,968
Other liabilities		708,403			544,104			674,475
Total deferred credits and other liabilities		1,335,659			1,085,056			1,265,443
Commitments and contingencies
Stockholders’ equity:
Preferred stocks		15,000			15,000			15,000
Common stockholders’ equity:
Common stock
Shares issued -- $1.00 par value, 188,672,532 at June 30, 2010, 184,508,109 at June 30, 2009 and 188,389,265 at December 31, 2009		188,673			184,508			188,389
Other paid-in capital		1,020,206			941,773			1,015,678
Retained earnings		1,407,950			1,270,778			1,377,039
Accumulated other comprehensive income (loss)		(463	)		1,669			(20,833	)
Treasury stock at cost – 538,921 shares		(3,626	)		(3,626	)		(3,626	)
Total common stockholders’ equity		2,612,740			2,395,102			2,556,647
Total stockholders’ equity		2,627,740			2,410,102			2,571,647
Total liabilities and stockholders’ equity	$	6,112,806		$	5,823,364		$	5,990,952

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2010			2009
	(In thousands)
Operating activities:
Net income (loss)	$	90,710		$	(288,491	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		160,225			173,694
Earnings, net of distributions, from equity method investments		(1,899	)		(1,685	)
Deferred income taxes		35,758			(206,955	)
Write-down of natural gas and oil properties		—			620,000
Changes in current assets and liabilities, net of acquisitions:
Receivables		27,149			149,782
Inventories		(12,442	)		(26,574	)
Other current assets		(32,471	)		47,837
Accounts payable		(13,164	)		(66,260	)
Other current liabilities		(45,613	)		2,218
Other noncurrent changes		(4,882	)		(5,141	)
Net cash provided by operating activities		203,371			398,425

Investing activities:
Capital expenditures		(237,535	)		(272,867	)
Acquisitions, net of cash acquired		(106,548	)		(3,764	)
Net proceeds from sale or disposition of property		11,972			7,494
Investments		1,228			(2,368	)
Net cash used in investing activities		(330,883	)		(271,505	)

Financing activities:
Repayment of short-term borrowings		(6,600	)		(105,100	)
Issuance of long-term debt		82,992			109,400
Repayment of long-term debt		(814	)		(92,024	)
Proceeds from issuance of common stock		1,739			284
Dividends paid		(59,545	)		(57,325	)
Tax benefit on stock-based compensation		548			144
Net cash provided by (used in) financing activities		18,320			(144,621	)
Effect of exchange rate changes on cash and cash equivalents		(130	)		297
Decrease in cash and cash equivalents		(109,322	)		(17,404	)
Cash and cash equivalents -- beginning of year		175,114			51,714
Cash and cash equivalents -- end of period	$	65,792		$	34,310

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

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

June 30, 2010 and 2009

(Unaudited)

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 June 30, 2010, up to the date of issuance of these consolidated interim financial statements.

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.

3.	Allowance for doubtful accounts

The Company's allowance for doubtful accounts as of June 30, 2010 and 2009, and December 31, 2009, was $14.9 million, $16.5 million and $16.6 million, respectively.

4.	Natural gas in storage

Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories and was $14.3 million, $19.1 million and $35.6 million at June 30, 2010 and 2009, and December 31, 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 $59.3 million, $40.3 million, and $59.6 million at June 30, 2010 and 2009, and December 31, 2009, respectively.

5.	Inventories

Inventories, other than natural gas in storage for the Company’s regulated operations, consisted primarily of aggregates held for resale of $83.5 million, $96.3 million and $80.1 million; materials and supplies of $62.1 million, $69.4 million and $58.1 million; asphalt oil of $52.0 million, $49.8 million and $23.0 million; and other inventories of $48.3 million, $51.2 million and $53.0 million, as of June 30, 2010 and 2009, and December 31, 2009, respectively. These inventories were stated at the lower of average cost or market value.

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 March 31, 2009, the Company's 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.

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 Note 13.

At June 30, 2010, the Company’s full-cost ceiling exceeded the Company’s capitalized cost. However, sustained downward movements in natural gas and oil prices subsequent to June 30, 2010, could result in a future write-down of the Company’s natural gas and oil properties.

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, 2010 and 2009, and the six months ended June 30, 2010, 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.

8.	Cash flow information

Cash expenditures for interest and income taxes were as follows:

	Six Months Ended June 30,
	2010		2009
	(In thousands)
Interest, net of amount capitalized	$	39,652	$	40,588
Income taxes	$	36,011	$	13,343

9.	New accounting standards

Variable Interest Entities In June 2009, 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 January 1, 2010. The adoption of this guidance did not have a material effect on the Company’s 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 January 1, 2011. The guidance requires additional disclosures but does not impact the Company’s financial position or results of operations.

Subsequent Events In February 2010, 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 Company’s financial position or results of operations.

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 income (loss) resulted from gains (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 income (loss) and related tax effects, were as follows:

	Three Months Ended June 30,
	2010			2009
	(In thousands)
Net income	$	48,938		$	55,311
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 $2,588 and $(4,028) in 2010 and 2009, respectively		4,637			(6,571	)
Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $3,191 and $11,415 in 2010 and 2009, respectively		5,259			18,625
Net unrealized loss on derivative instruments qualifying as hedges		(622	)		(25,196	)
Foreign currency translation adjustment, net of tax of $307 and $3,711 in 2010 and 2009, respectively		(476	)		5,756
		(1,098	)		(19,440	)
Comprehensive income	$	47,840		$	35,871

	Six Months Ended June 30,
		2010			2009
	(In thousands)
Net income (loss)	$	90,710		$	(288,491	)
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain on derivative instruments arising during the period, net of tax of $11,962 and $5,634 in 2010 and 2009, respectively		19,932			9,193
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income (loss), net of tax of $(1,166) and $14,646 in 2010 and 2009, respectively		(1,850	)		23,896
Net unrealized gain (loss) on derivative instruments qualifying as hedges		21,782			(14,703	)
Foreign currency translation adjustment, net of tax of $(929) and $3,875 in 2010 and 2009, respectively		(1,412	)		6,007
		20,370			(8,696	)
Comprehensive income (loss)	$	111,080		$	(297,187	)

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, 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. Regulatory approval for the sale has been received. The financial closing of the sale is anticipated to occur later this year. One of the parties will purchase 15.6 percent of the Company’s ownership interests over a four-year period. The other parties will purchase 84.4 percent of the Company’s ownership interests at the financial close of the transaction.

At June 30, 2010 and 2009, and December 31, 2009, the Company's equity method investments had total assets of $369.9 million, $348.3 million and $387.0 million, respectively, and long-term debt of $157.1 million, $171.7 million and $176.7 million, respectively. The Company's investment in its equity method investments was approximately $57.9 million, $52.6 million and $62.4 million, including undistributed earnings of $11.1 million, $8.4 million and $9.3 million, at June 30, 2010 and 2009, and December 31, 2009, respectively.

12.	Goodwill and other intangible assets

The changes in the carrying amount of goodwill were as follows:

Six Months Ended June 30, 2010	Balance as of January 1, 2010		Goodwill Acquired During the Year*		Balance as of June 30, 2010
	(In thousands)
Electric	$	—	$	—	$	—
Natural gas distribution		345,736		—		345,736
Construction services		100,127		2,764		102,891
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	$	5,191	$	634,654
* Includes purchase price adjustments that were not material related to acquisitions in a prior period.

Six Months Ended June 30, 2009	Balance as of January 1, 2009		Goodwill Acquired During the Year*		Balance as of June 30, 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.

Year Ended December 31, 2009	Balance as of January 1, 2009		Goodwill Acquired During the Year*		Balance as of December 31, 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 intangible assets were as follows:

	June 30, 2010			June 30, 2009			December 31, 2009
	(In thousands)
Customer relationships	$	24,942		$	21,688		$	24,942
Accumulated amortization		(10,688	)		(8,142	)		(9,500	)
		14,254			13,546			15,442
Noncompete agreements		9,405			9,792			12,377
Accumulated amortization		(6,033	)		(5,942	)		(6,675	)
		3,372			3,850			5,702
Other		12,063			10,679			10,859
Accumulated amortization		(3,490	)		(2,755	)		(3,026	)
		8,573			7,924			7,833
Total	$	26,199		$	25,320		$	28,977

Amortization expense for amortizable intangible assets for the three and six months ended June 30, 2010, was $1.1 million and $2.1 million, respectively. Amortization expense for the three and six months ended June 30, 2009, was $1.2 million and $2.6 million, respectively. Estimated amortization expense for amortizable intangible assets is $4.2 million in 2010, $3.9 million in 2011, $3.8 million in 2012, $3.3 million in 2013, $2.9 million in 2014 and $10.2 million thereafter.

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, 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 June 30, 2010, Cascade and Intermountain held natural gas swap agreements, with total forward notional volumes of 9.2 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 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 and six months ended June 30, 2010, Cascade and Intermountain recorded the change in the fair market value of the derivative instruments of $3.9 million and $9.0 million, respectively, 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 and Intermountain's derivative instruments with credit-risk-related contingent features that are in a liability position at June 30, 2010, was $18.9 million. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on June 30, 2010, was $18.9 million.

Fidelity

At June 30, 2010, Fidelity held natural gas swaps and collar agreements with total forward notional volumes of 27.1 million MMBtu, natural gas basis swaps with total forward notional volumes of 17.3 million MMBtu, and oil swap and collar agreements with total forward notional volumes of 2.0 million Bbl, which were designated as cash flow hedging instruments. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil and basis differentials on its forecasted sales of natural gas and oil production.

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. 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). At the date the natural gas and oil quantities are settled, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. The proceeds received for natural gas and oil production are generally based on market prices.

For the three and six months ended June 30, 2010, and 2009, the amount of hedge ineffectiveness was immaterial, and 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. There were no such reclassifications into earnings as a result of the discontinuance of hedges.

Gains and losses on derivative instruments that are reclassified from accumulated other comprehensive income (loss) to current-period earnings are included in operating revenues on the Consolidated Statements of Income. For further information regarding the gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in other comprehensive income (loss) and the gains and losses reclassified from accumulated other comprehensive income (loss) into earnings, see Note 10.

As of June 30, 2010, the maximum term of the swap and collar agreements, in which the exposure to the variability in future cash flows for forecasted transactions is being hedged, is 30 months. The Company estimates that over the next 12 months net gains of approximately $14.3 million (after tax) will be reclassified from accumulated other comprehensive income (loss) into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings.

Certain of Fidelity's derivative instruments contain cross-default provisions that state if Fidelity 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 derivative instruments with credit-risk-related contingent features that are in a liability position at June 30, 2010, was $2.0 million. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on June 30, 2010, was $2.0 million.

The location and fair value of all of the Company’s derivative instruments in the Consolidated Balance Sheets were as follows:

Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at June 30, 2010		Fair Value at June 30, 2009		Fair Value at December 31, 2009
		(In thousands)
Designated as hedges	Commodity derivative instruments	$	24,932	$	62,047	$	7,761
	Other assets – noncurrent		8,524		4,217		2,734
			33,456		66,264		10,495
Not designated as hedges	Commodity derivative instruments		—		1		—
	Other assets – noncurrent		—		1		—
			—		2		—
Total asset derivatives		$	33,456	$	66,266	$	10,495

Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at June 30, 2010		Fair Value at June 30, 2009		Fair Value at December 31, 2009
		(In thousands)
Designated as hedges	Commodity derivative instruments	$	1,961	$	8,440	$	13,763
	Other liabilities – noncurrent		—		1,538		114
			1,961		9,978		13,877
Not designated as hedges	Commodity derivative instruments		18,199		48,699		23,144
	Other liabilities – noncurrent		698		10,786		4,756
			18,897		59,485		27,900
Total liability derivatives		$	20,858	$	69,463	$	41,777
Note: The fair value of the commodity derivative instruments not designated as hedges is presented net of collateral provided to the counterparties by Cascade of $8.5 million at June 30, 2009.

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 $20.2 million, $29.5 million and $34.8 million, as of June 30, 2010 and 2009, and December 31, 2009, respectively, are classified as Investments on the Consolidated Balance Sheets. The decrease in the fair value of these investments for the three and six months ended June 30, 2010, was $1.8 million (before tax) and $970,000 (before tax), respectively. 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 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 Company’s auction rate securities, which totaled $11.4 million at June 30, 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 Company’s assets and liabilities measured at fair value on a recurring basis are as follows:

	Fair Value Measurements at June 30, 2010, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Collateral Provided to Counterparties		Balance at June 30, 2010
	(In thousands)
Assets:
Money market funds	$	8,251	$	—	$	—	$	—	$	8,251
Available-for-sale securities:
Fixed-income securities		—		11,400		—		—		11,400
Insurance contract*		—		20,236		—		—		20,236
Commodity derivative instruments - current		—		24,932		—		—		24,932
Commodity derivative instruments - noncurrent		—		8,524		—		—		8,524
Total assets measured at fair value	$	8,251	$	65,092	$	—	$	—	$	73,343
Liabilities:
Commodity derivative instruments - current	$	—	$	20,160	$	—	$	—	$	20,160
Commodity derivative instruments - noncurrent		—		698		—		—		698
Total liabilities measured at fair value	$	—	$	20,858	$	—	$	—	$	20,858
* Invested in mutual funds.

	Fair Value Measurements at June 30, 2009, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Collateral Provided to Counterparties		Balance at June 30, 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:
Commodity derivative instruments - current	$	—	$	65,604	$	—	$	8,465	$	57,139
Commodity derivative instruments - noncurrent		—		12,324		—		—		12,324
Total liabilities measured at fair value	$	—	$	77,928	$	—	$	8,465	$	69,463

	Fair Value Measurements at December 31, 2009, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Collateral Provided to Counterparties		Balance at December 31, 2009
	(In thousands)
Assets:
Money market funds	$	9,124	$	151,000	$	—	$	—	$	160,124
Available-for-sale securities		9,078		37,141		—		—		46,219
Commodity derivative instruments - current		—		7,761		—		—		7,761
Commodity derivative instruments - noncurrent		—		2,734		—		—		2,734
Total assets measured at fair value	$	18,202	$	198,636	$	—	$	—	$	216,838
Liabilities:
Commodity derivative instruments - current	$	—	$	36,907	$	—	$	—	$	36,907
Commodity derivative instruments - noncurrent		—		4,870		—		—		4,870
Total liabilities measured at fair value	$	—	$	41,777	$	—	$	—	$	41,777

The estimated fair value of the Company’s Level 1 money market funds is determined using the market approach and is valued at the net asset value of shares held by the Company, based on published market quotations in active markets.

The estimated fair value of the Company’s Level 1 available-for-sale securities is determined using the market approach and is based on quoted market prices in active markets for identical equity and fixed-income securities.

The estimated fair value of the Company’s Level 2 money market funds and available-for-sale securities is determined using the market approach. The 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 available for-sale securities is based on comparable market transactions.

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 nonperformance risk of the counterparties in addition to the Company’s nonperformance risk is also evaluated.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.

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 estimated fair value of the Company’s long-term debt was based on quoted market prices of the same or similar issues. The estimated fair value of the Company's long-term debt was as follows:

	Carrying Amount		Fair Value
	(In thousands)
Long-term debt at June 30, 2010	$	1,581,265	$	1,718,477
Long-term debt at June 30, 2009	$	1,664,471	$	1,538,693
Long-term debt at December 31, 2009	$	1,499,306	$	1,566,331

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

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 vast majority of the Company’s 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 Company’s 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 Company’s Notes to Consolidated Financial Statements in the 2009 Annual Report. Information on the Company's businesses was as follows:

Three Months Ended June 30, 2010	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	45,683	$	—		$	4,947
Natural gas distribution		160,138		—			74
Pipeline and energy services		66,356		14,143			9,541
		272,177		14,143			14,562
Construction services		188,182		8			2,923
Natural gas and oil production		84,406		26,400			24,035
Construction materials and contracting		361,625		—			5,659
Other		54		2,213			1,588
		634,267		28,621			34,205
Intersegment eliminations		—		(42,764	)		—
Total	$	906,444	$	—		$	48,767

Three Months Ended June 30, 2009	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	44,508	$	—		$	3,263
Natural gas distribution		164,158		—			(4,765	)
Pipeline and energy services		54,951		13,046			10,876
		263,617		13,046			9,374
Construction services		220,697		10			6,931
Natural gas and oil production		84,291		20,488			20,779
Construction materials and contracting		389,435		—			15,983
Other		—		2,699			2,073
		694,423		23,197			45,766
Intersegment eliminations		—		(36,243	)		—
Total	$	958,040	$	—		$	55,140

Six Months Ended June 30, 2010	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	95,379	$	—		$	10,832
Natural gas distribution		509,162		—			23,416
Pipeline and energy services		127,881		41,228			18,332
		732,422		41,228			52,580
Construction services		341,247		32			3,051
Natural gas and oil production		156,066		62,327			46,246
Construction materials and contracting		511,432		—			(14,478	)
Other		54		4,451			2,968
		1,008,799		66,810			37,787
Intersegment eliminations		—		(108,038	)		—
Total	$	1,741,221	$	—		$	90,367

Six Months Ended June 30, 2009	External Operating Revenues		Inter- segment Operating Revenues			Earnings (Loss) on Common Stock
	(In thousands)
Electric	$	95,755	$	—		$	8,329
Natural gas distribution		647,313		—			19,114
Pipeline and energy services		115,123		37,973			17,261
		858,191		37,973			44,704
Construction services		465,495		41			15,565
Natural gas and oil production		155,450		55,451			(352,537	)
Construction materials and contracting		572,909		—			330
Other		—		5,398			3,104
		1,193,854		60,890			(333,538	)
Intersegment eliminations		—		(98,863	)		—
Total	$	2,052,045	$	—		$	(288,834	)

Earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from construction services, natural gas and oil production, construction materials and contracting, and other are all from nonregulated operations.

16.	Acquisitions

During the first six months of 2010, the Company acquired natural gas properties located in the Green River Basin in southwest Wyoming, with an October 1, 2009, effective date. The acquisition includes the purchase of over 60 Bcfe of proven reserves. The total purchase consideration for these properties and purchase price adjustments with respect to acquisitions made prior to 2010, consisting of the Company’s common stock and cash, was approximately $108.1 million.

The above acquisition was accounted for under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed have been preliminarily recorded at their respective fair values as of the date of acquisition. The final fair market values are pending the completion of the review of the relevant assets and liabilities identified as of the acquisition date. The results of operations of the acquired properties are included in the financial statements as of the date of acquisition. Pro forma financial amounts reflecting the effects of the above acquisition have not been presented, as the acquisition was not material to the Company’s financial position or results of operations.

17.	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:

Three Months	Pension Benefits						Other Postretirement Benefits
Ended June 30,	2010			2009			2010			2009
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	501		$	1,966		$	374		$	651
Interest cost		4,004			5,430			1,317			1,530
Expected return on assets		(4,992	)		(5,673	)		(1,577	)		(1,544	)
Amortization of prior service cost (credit)		31			151			(915	)		(810	)
Amortization of net actuarial loss		256			643			67			170
Amortization of net transition obligation		—			—			613			625
Net periodic benefit cost, including amount capitalized		(200	)		2,517			(121	)		622
Less amount capitalized		107			484			37			(23	)
Net periodic benefit cost	$	(307	)	$	2,033		$	(158	)	$	645

Six Months	Pension Benefits						Other Postretirement Benefits
Ended June 30,		2010			2009			2010			2009
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	1,305		$	4,063		$	731		$	1,091
Interest cost		8,930			10,959			2,594			2,725
Expected return on assets		(10,684	)		(12,530	)		(2,969	)		(2,817	)
Amortization of prior service cost (credit)		69			302			(1,779	)		(1,378	)
Amortization of net actuarial loss		1,228			817			455			355
Amortization of net transition obligation		—			—			1,145			1,063
Net periodic benefit cost, including amount capitalized		848			3,611			177			1,039
Less amount capitalized		383			765			84			23
Net periodic benefit cost	$	465		$	2,846		$	93