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 March 31, 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 April 29, 2010: 188,130,501 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
ALJ	Administrative Law Judge
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
MNPUC	Minnesota Public Utilities Commission
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 Months Ended March 31, 2010 and 2009	7

Consolidated Balance Sheets --
March 31, 2010 and 2009, and December 31, 2009	8

Consolidated Statements of Cash Flows --
Three Months Ended March 31, 2010 and 2009	9

Notes to Consolidated Financial Statements	10

Management's Discussion and Analysis of Financial Condition and Results of Operations	32

Quantitative and Qualitative Disclosures About Market Risk	49

Controls and Procedures	51

Part II -- Other Information

Legal Proceedings	51

Risk Factors	51

Unregistered Sales of Equity Securities and Use of Proceeds	53

Exhibits	54

Signatures	55

Exhibit Index	56

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
	2010		2009
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	460,245	$	594,576
Construction services, natural gas and oil production, construction materials and contracting, and other		374,532		499,429
Total operating revenues		834,777		1,094,005
Operating expenses:
Fuel and purchased power		16,911		18,731
Purchased natural gas sold		233,691		356,496
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services		62,987		71,351
Construction services, natural gas and oil production, construction materials and contracting, and other		313,786		422,149
Depreciation, depletion and amortization		78,678		93,245
Taxes, other than income		45,795		52,952
Write-down of natural gas and oil properties		—		620,000
Total operating expenses		751,848		1,634,924

Operating income (loss)		82,929		(540,919	)

Earnings from equity method investments		2,183		1,787

Other income		2,502		1,719

Interest expense		20,516		20,997

Income (loss) before income taxes		67,098		(558,410	)

Income taxes		25,326		(214,607	)

Net income (loss)		41,772		(343,803	)

Dividends on preferred stocks		172		171

Earnings (loss) on common stock	$	41,600	$	(343,974	)

Earnings (loss) per common share -- basic	$	.22	$	(1.87	)

Earnings (loss) per common share -- diluted	$	.22	$	(1.87	)

Dividends per common share	$	.1575	$	.1550

Weighted average common shares outstanding -- basic		187,963		183,787

Weighted average common shares outstanding -- diluted		188,220		183,787

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2010			March 31, 2009			December 31, 2009
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	106,664		$	44,689		$	175,114
Receivables, net		467,790			580,700			531,980
Inventories		253,931			276,268			249,804
Deferred income taxes		18,543			—			28,145
Short-term investments		250			2,329			2,833
Commodity derivative instruments		38,146			92,577			7,761
Prepayments and other current assets		104,437			135,734			66,021
Total current assets		989,761			1,132,297			1,061,658
Investments		141,443			114,058			145,416
Property, plant and equipment		6,875,397			6,550,825			6,766,582
Less accumulated depreciation, depletion and amortization		2,935,453			2,839,020			2,872,465
Net property, plant and equipment		3,939,944			3,711,805			3,894,117
Deferred charges and other assets:
Goodwill		634,633			621,566			629,463
Other intangible assets, net		26,612			26,573			28,977
Other		249,454			254,240			231,321
Total deferred charges and other assets		910,699			902,379			889,761
Total assets	$	5,981,847		$	5,860,539		$	5,990,952

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	7,700		$	25,500		$	10,300
Long-term debt due within one year		72,572			28,621			12,629
Accounts payable		241,465			355,951			281,906
Taxes payable		69,077			71,238			55,540
Deferred income taxes		—			10,143			—
Dividends payable		29,796			28,685			29,749
Accrued compensation		22,607			35,543			47,425
Commodity derivative instruments		32,328			58,062			36,907
Other accrued liabilities		187,368			162,271			192,729
Total current liabilities		662,913			776,014			667,185
Long-term debt		1,426,146			1,614,786			1,486,677
Deferred credits and other liabilities:
Deferred income taxes		603,803			516,965			590,968
Other liabilities		680,965			551,175			674,475
Total deferred credits and other liabilities		1,284,768			1,068,140			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, 188,656,012 at March 31, 2010; 184,499,434 at March 31, 2009 and 188,389,265 at December 31, 2009		188,656			184,499			188,389
Other paid-in capital		1,018,441			940,369			1,015,678
Retained earnings		1,388,914			1,244,248			1,377,039
Accumulated other comprehensive income (loss)		635			21,109			(20,833	)
Treasury stock at cost – 538,921 shares		(3,626	)		(3,626	)		(3,626	)
Total common stockholders’ equity		2,593,020			2,386,599			2,556,647
Total stockholders’ equity		2,608,020			2,401,599			2,571,647
Total liabilities and stockholders’ equity	$	5,981,847		$	5,860,539		$	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)

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Operating activities:
Net income (loss)	$	41,772		$	(343,803	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		78,678			93,245
Earnings, net of distributions, from equity method investments		(1,443	)		(1,531	)
Deferred income taxes		8,226			(228,764	)
Write-down of natural gas and oil properties		—			620,000
Changes in current assets and liabilities, net of acquisitions:
Receivables		61,914			129,318
Inventories		(6,198	)		(13,347	)
Other current assets		(34,546	)		40,442
Accounts payable		(34,795	)		(59,863	)
Other current liabilities		(21,733	)		21,713
Other noncurrent changes		(6,759	)		(9,586	)
Net cash provided by operating activities		85,116			247,824

Investing activities:
Capital expenditures		(123,902	)		(145,355	)
Acquisitions, net of cash acquired		(1,725	)		(3,057	)
Net proceeds from sale or disposition of property		1,936			4,213
Investments		1,404			1,229
Net cash used in investing activities		(122,287	)		(142,970	)

Financing activities:
Repayment of short-term borrowings		(2,600	)		(79,600	)
Issuance of long-term debt		—			59,091
Repayment of long-term debt		(479	)		(62,884	)
Proceeds from issuance of common stock		1,214			107
Dividends paid		(29,749	)		(28,640	)
Tax benefit on stock-based compensation		452			111
Net cash used in financing activities		(31,162	)		(111,815	)
Effect of exchange rate changes on cash and cash equivalents		(117	)		(64	)
Decrease in cash and cash equivalents		(68,450	)		(7,025	)
Cash and cash equivalents -- beginning of year		175,114			51,714
Cash and cash equivalents -- end of period	$	106,664		$	44,689

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

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

March 31, 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 March 31, 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 March 31, 2010 and 2009, and December 31, 2009, was $17.1 million, $16.1 million and $16.6 million, respectively.

4. Natural gas in storage

Natural gas in storage for the Company's regulated operations is carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories and was $10.7 million, $9.5 million and $35.6 million at March 31, 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, $42.0 million, and $59.6 million at March 31, 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 $81.1 million, $92.0 million and $80.1 million; materials and supplies of $58.6 million, $73.0 million and $58.1 million; asphalt oil of $50.4 million, $50.0 million and $23.0 million; and other inventories of $53.1 million, $51.8 million and $53.0 million, as of March 31, 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 March 31, 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 March 31, 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 March 31, 2010, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the three months ended March 31, 2009, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Due to the loss on common stock for the three months ended March 31, 2009, the effect of outstanding stock options, restricted stock grants and performance share awards were excluded from the computation of diluted loss per common share as their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury.

8. Cash flow information

Cash expenditures for interest and income taxes were as follows:

	Three Months Ended March 31,
	2010		2009
	(In thousands)
Interest, net of amount capitalized	$	25,159	$	25,280
Income taxes paid (refunded), net	$	5,424	$	(21,914	)

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. The Company's other comprehensive income resulted from gains on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note 13.

Comprehensive income (loss), and the components of other comprehensive income and related tax effects, were as follows:

	Three Months Ended
	March 31,
	2010			2009
	(In thousands)
Net income (loss)	$	41,772		$	(343,803	)
Other comprehensive income:
Net unrealized gain on derivative instruments qualifying as hedges:
Net unrealized gain on derivative instruments arising during the period, net of tax of $13,159 and $13,895 in 2010 and 2009, respectively		21,471			22,671
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income (loss), net of tax of $(573) and $7,464 in 2010 and 2009, respectively		(934	)		12,178
Net unrealized gain on derivative instruments qualifying as hedges		22,405			10,493
Foreign currency translation adjustment, net of tax of $(621) and $164 in 2010 and 2009, respectively		(937	)		251
		21,468			10,744
Comprehensive income (loss)	$	63,240		$	(333,059	)

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 March 31, 2010, include the Brazilian Transmission Lines.

In August 2006, MDU Brasil acquired ownership interests in companies owning the Brazilian Transmission Lines. The interests involve the ENTE (13.3-percent ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent ownership interest) electric transmission lines, which are primarily in northeastern and southern Brazil.

In the fourth quarter of 2009, multiple sales agreements were signed with three separate parties for the Company to sell its ownership interests in the Brazilian Transmission Lines. This sale is pending regulatory approvals. One of the parties will purchase 15.6 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 March 31, 2010 and 2009, and December 31, 2009, the Company's equity method investments had total assets of $374.8 million, $295.3 million and $387.0 million, respectively, and long-term debt of $166.4 million, $153.9 million and $176.7 million, respectively. The Company's investment in its equity method investments was approximately $56.0 million, $45.4 million and $62.4 million, including undistributed earnings of $10.8 million, $8.4 million and $9.3 million, at March 31, 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:

	Balance		Goodwill		Balance
	as of		Acquired		as of
Three Months Ended	January 1,		During		March 31,
March 31, 2010	2010		the Year*		2010
	(In thousands)
Electric	$	—	$	—	$	—
Natural gas distribution		345,736		—		345,736
Construction services		100,127		2,743		102,870
Pipeline and energy services		7,857		1,880		9,737
Natural gas and oil production		—		—		—
Construction materials and contracting		175,743		547		176,290
Other		—		—		—
Total	$	629,463	$	5,170	$	634,633
* Includes purchase price adjustments that were not material related to acquisitions in a prior period.

	Balance		Goodwill		Balance
	as of		Acquired		as of
Three Months Ended	January 1,		During		March 31,
March 31, 2009		2009	the Year*			2009
	(In thousands)
Electric	$	—	$	—	$	—
Natural gas distribution		344,952		296		345,248
Construction services		95,619		4,184		99,803
Pipeline and energy services		1,159		—		1,159
Natural gas and oil production		—		—		—
Construction materials and contracting		174,005		1,351		175,356
Other		—		—		—
Total	$	615,735	$	5,831	$	621,566
* Includes purchase price adjustments that were not material related to acquisitions in a prior period.

	Balance		Goodwill		Balance
	as of		Acquired		as of
Year Ended	January 1,		During the		December 31,
December 31, 2009	2009		Year*		2009
	(In thousands)
Electric	$	—	$	—	$	—
Natural gas distribution		344,952		784		345,736
Construction services		95,619		4,508		100,127
Pipeline and energy services		1,159		6,698		7,857
Natural gas and oil production		—		—		—
Construction materials and contracting		174,005		1,738		175,743
Other		—		—		—
Total	$	615,735	$	13,728	$	629,463
* Includes purchase price adjustments that were not material related to acquisitions in a prior period.

Other amortizable intangible assets were as follows:

	March 31, 2010			March 31, 2009			December 31, 2009
	(In thousands)
Customer relationships	$	24,942		$	21,688		$	24,942
Accumulated amortization		(10,093	)		(7,561	)		(9,500	)
		14,849			14,127			15,442
Noncompete agreements		9,405			9,792			12,377
Accumulated amortization		(5,755	)		(5,518	)		(6,675	)
		3,650			4,274			5,702
Other		11,368			10,668			10,859
Accumulated amortization		(3,255	)		(2,496	)		(3,026	)
		8,113			8,172			7,833
Total	$	26,612		$	26,573		$	28,977

Amortization expense for amortizable intangible assets for the three months ended March 31, 2010 and 2009, was $1.0 million and $1.4 million, respectively. Estimated amortization expense for amortizable intangible assets is $4.2 million in 2010, $3.8 million in 2011, $3.6 million in 2012, $3.2 million in 2013, $2.8 million in 2014 and $10.0 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 March 31, 2010, the Company had no outstanding foreign currency or interest rate hedges. The following information should be read in conjunction with Notes 1 and 7 in the Company's Notes to Consolidated Financial Statements in the 2009 Annual Report.

Cascade and Intermountain

At March 31, 2010, Cascade held natural gas swap agreements, with total forward notional volumes of 6.3 million MMBtu, which were not designated as hedges. Cascade utilizes, and

Intermountain periodically utilizes, natural gas swap agreements to manage a portion of their regulated natural gas supply portfolios in order to manage fluctuations in the price of natural gas related to core customers in accordance with authority granted by the IPUC, WUTC and OPUC. Core customers consist of residential, commercial and smaller industrial customers. The fair value of the derivative instrument must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability. Cascade and Intermountain record periodic changes in the fair market value of the derivative instruments on the Consolidated Balance Sheets as a regulatory asset or a regulatory liability, and settlements of these arrangements are expected to be recovered through the purchased gas cost adjustment mechanism. Gains and losses on the settlements of these derivative instruments are recorded as a component of purchased natural gas sold on the Consolidated Statements of Income as they are recovered through the purchased gas cost adjustment mechanism. Under the terms of these arrangements, Cascade and Intermountain will either pay or receive settlement payments based on the difference between the fixed strike price and the monthly index price applicable to each contract. For the three months ended March 31, 2010, Cascade and Intermountain recorded the change in the fair market value of the derivative instruments of $5.1 million as a decrease to regulatory assets.

Certain of Cascade's derivative instruments contain credit-risk-related contingent features that permit the counterparties to require collateralization if Cascade's derivative liability positions exceed certain dollar thresholds. The dollar thresholds in certain of Cascade's agreements are determined and may fluctuate based on Cascade's credit rating on its debt. In addition, Cascade's and Intermountain's derivative instruments contain cross-default provisions that state if the entity fails to make payment with respect to certain of its indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of such entity's derivative instruments in liability positions. The aggregate fair value of Cascade's derivative instruments with credit-risk-related contingent features that are in a liability position at March 31, 2010, was $22.8 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 March 31, 2010, was $22.8 million.

Fidelity

At March 31, 2010, Fidelity held natural gas swaps and collar agreements with total forward notional volumes of 30.8 million MMBtu, natural gas basis swaps with total forward notional volumes of 18.2 million MMBtu, and oil swaps and collar agreements with total forward notional volumes of 2.0 million Bbl, all of 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 months ended March 31, 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 March 31, 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 33 months. The Company estimates that over the next 12 months net gains of approximately $16.4 million (after tax) will be reclassified from accumulated other comprehensive income 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 March 31, 2010, was $12.4 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 March 31, 2010, was $12.4 million.

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

Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at March 31, 2010		Fair Value at March 31, 2009		Fair Value at December 31, 2009
		(In thousands)
Designated as hedges	Commodity derivative instruments	$	38,146	$	92,577	$	7,761
	Other assets – noncurrent		6,960		5,147		2,734
			45,106		97,724		10,495
Not designated as hedges	Commodity derivative instruments		—		—		—
	Other assets – noncurrent		—		—		—
			—		—		—
Total asset derivatives		$	45,106	$	97,724	$	10,495

Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at March 31, 2010		Fair Value at March 31, 2009		Fair Value at December 31, 2009
		(In thousands)
Designated as hedges	Commodity derivative instruments	$	11,616	$	788	$	13,763
	Other liabilities – noncurrent		759		—		114
			12,375		788		13,877
Not designated as hedges	Commodity derivative instruments		20,712		57,274		23,144
	Other liabilities – noncurrent		2,061		17,401		4,756
			22,773		74,675		27,900
Total liability derivatives		$	35,148	$	75,463	$	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 $22.0 million at March 31, 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 $36.5 million, $25.8 million and $34.8 million, as of March 31, 2010 and 2009, and December 31, 2009, respectively, are classified as Investments on the Consolidated Balance Sheets. The increase

in the fair value of these investments for the three months ended March 31, 2010, was $1.7 million (before tax). The decrease in the fair value of these investments for the three months ended March 31, 2009, was $1.9 million (before tax). The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income. The Company did not elect the fair value option for its remaining available-for-sale securities, which are auction rate securities. The Company’s auction rate securities, which totaled $11.4 million at March 31, 2010 and 2009, and December 31, 2009, are accounted for as available-for-sale and are recorded at fair value. The fair value of the auction rate securities approximate cost and, as a result, there are no accumulated unrealized gains or losses recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets related to these investments.

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

	Fair Value Measurements at March 31, 2010, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Collateral Provided to Counterparties		Balance at March 31, 2010
	(In thousands)
Assets:
Money market funds	$	10,977	$	65,000	$	—	$	—	$	75,977
Available-for-sale securities:
Fixed-income securities		2,785		11,400		—		—		14,185
Equity securities		6,689		—		—		—		6,689
Insurance contract*		—		27,000		—		—		27,000
Commodity derivative instruments - current		—		38,146		—		—		38,146
Commodity derivative instruments - noncurrent		—		6,960		—		—		6,960
Total assets measured at fair value	$	20,451	$	148,506	$	—	$	—	$	168,957
Liabilities:
Commodity derivative instruments - current	$	—	$	32,328	$	—	$	—	$	32,328
Commodity derivative instruments - noncurrent		—		2,820		—		—		2,820
Total liabilities measured at fair value	$	—	$	35,148	$	—	$	—	$	35,148
* Invested in mutual funds.

	Fair Value Measurements at March 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 March 31, 2009
	(In thousands)
Assets:
Available-for-sale securities	$	25,822	$	11,400	$	—	$	—	$	37,222
Commodity derivative instruments - current		—		92,577		—		—		92,577
Commodity derivative instruments - noncurrent		—		5,147		—		—		5,147
Total assets measured at fair value	$	25,822	$	109,124	$	—	$	—	$	134,946
Liabilities:
Commodity derivative instruments - current	$	—	$	80,017	$	—	$	21,955	$	58,062
Commodity derivative instruments - noncurrent		—		17,401		—		—		17,401
Total liabilities measured at fair value	$	—	$	97,418	$	—	$	21,955	$	75,463

	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		Fair
	Amount		Value
	(In thousands)
Long-term debt at March 31, 2010	$	1,498,718	$	1,586,765
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:

	External		Inter- segment			Earnings (Loss)
Three Months	Operating		Operating			on Common
Ended March 31, 2010	Revenues		Revenues			Stock
	(In thousands)
Electric	$	49,696	$	—		$	5,884
Natural gas distribution		349,026		—			23,344
Pipeline and energy services		61,523		27,086			8,791
		460,245		27,086			38,019
Construction services		153,066		23			127
Natural gas and oil production		71,659		35,927			22,211
Construction materials and contracting		149,807		—			(20,137	)
Other		—		2,238			1,380
		374,532		38,188			3,581
Intersegment eliminations		—		(65,274	)		—
Total	$	834,777	$	—		$	41,600


			Inter-
	External		segment			Earnings
Three Months	Operating		Operating			on Common
Ended March 31, 2009	Revenues		Revenues			Stock
	(In thousands)
Electric	$	51,248	$	—		$	5,066
Natural gas distribution		483,156		—			23,881
Pipeline and energy services		60,172		24,927			6,385
		594,576		24,927			35,332
Construction services		244,798		31			8,634
Natural gas and oil production		71,158		34,964			(373,317	)
Construction materials and contracting		183,473		—			(15,654	)
Other		—		2,699			1,031
		499,429		37,694			(379,306	)
Intersegment eliminations		—		(62,621	)		—
Total	$	1,094,005	$	—		$	(343,974	)

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.	Employee benefit plans

The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans were as follows:

							Other
							Postretirement
Three Months	Pension Benefits						Benefits
Ended March 31,	2010			2009			2010			2009
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	804		$	2,097		$	357		$	440
Interest cost		4,926			5,529			1,277			1,195
Expected return on assets		(5,692	)		(6,857	)		(1,392	)		(1,273	)
Amortization of prior service cost (credit)		38			151			(864	)		(568	)
Recognized net actuarial loss		972			174			388			185
Amortization of net transition obligation		—			—			532			438
Net periodic benefit cost, including amount capitalized		1,048			1,094			298			417
Less amount capitalized		276			281			47			46
Net periodic benefit cost	$	772		$	813		$	251		$	371

In 2009, the Company evaluated several provisions of its employee defined benefit plans for nonunion and certain union employees. As a result of this evaluation, the Company determined that, effective January 1, 2010, all benefit and service accruals of these plans were frozen. These employees are eligible to receive additional defined contribution plan benefits.

Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company’s businesses. Current employees who attain age 55 with 10 years of continuous service by December 31, 2010, will be provided the current retiree medical insurance benefits or can elect the new benefit, if desired, regardless of when they retire. All other current employees must meet the new eligibility criteria of age 60 and 10 years of continuous service at the time they retire. These employees will be eligible for a specified company funded Retiree Reimbursement Account. Employees hired after December 31, 2009, are not eligible for retiree medical benefits.

In addition to the qualified plan defined pension benefits reflected in the table, the Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that generally provides for defined benefit payments at age 65 following the employee’s retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for this plan for the three months ended March 31, 2010 and 2009, was $2.1 million.

17. Regulatory matters and revenues subject to refund

In November 2006, Montana-Dakota filed an application with the NDPSC requesting an advance determination of prudence of Montana-Dakota's ownership interest in Big Stone Station II. In August 2008, the NDPSC approved Montana-Dakota’s 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. The intervenors in the proceeding appealed the NDPSC order to the North Dakota District Court which affirmed the order of the NDPSC. The intervenors then appealed the North Dakota District Court order to the North Dakota Supreme Court. The Big Stone Station II participants subsequently decided not to proceed with the project and in December 2009, Montana-Dakota filed an application with the NDPSC for a determination that Montana-Dakota’s continued participation in the Big Stone Station II is no longer prudent. The parties have stipulated that the intervenors will move to dismiss their appeal to the North Dakota Supreme Court if the NDPSC grants Montana-Dakota’s pending application for a determination that its participation in the Big Stone Station II is no longer prudent. In December 2009, Montana-Dakota filed applications with the NDPSC, SDPUC, and MTPSC for authority to defer the costs incurred for securing new electric generation, primarily Big Stone Station II, until the next general rate case. The SDPUC and the MTPSC approved Montana-Dakota’s applications on February 11, 2010, and April 6, 2010, respectively. On April 14, 2010, Montana-Dakota and the NDPSC Advocacy Staff filed a settlement agreement with the NDPSC. The settlement agreement provides for the recovery of approximately $10.2 million, including carrying charges, of the North Dakota allocated costs associated with the Big Stone Station II over a three-year period beginning June 1, 2010. A hearing on the settlement agreement before the NDPSC is scheduled for May 5, 2010.

In August 2009, Montana-Dakota filed an application with the WYPSC for an electric rate increase. Montana-Dakota requested a total increase of $6.2 million annually or approximately 31 percent above current rates. The rate increase request was necessitated by Montana-Dakota’s purchase of an ownership interest in Wygen III. On January 14, 2010, Montana-Dakota filed a supplement to the application to reflect the inclusion of bonus tax depreciation on Wygen III, reducing its request to a $5.1 million annual increase or approximately 25 percent above current rates. A hearing was held February 23 through February 25, 2010. A stipulation and agreement between Montana-Dakota and the Wyoming Office of Consumer Advocate was filed with the WYPSC on March 5, 2010, that provides a $3.3 million annual increase to be phased-in over a three-year period beginning May 1, 2010. The WYPSC held a hearing on the stipulation on March 22, 2010, and held additional deliberations on April 14, 2010, wherein the WYPSC decided on each issue in the case and Montana-Dakota was directed to file a compliance filing. Montana-Dakota submitted the compliance filing on April 23, 2010, reflecting an increase of $2.7 million annually or approximately 13.1 percent. On April 27, 2010, the WYPSC approved the compliance filing with rates effective May 1, 2010.

On April 19, 2010, Montana-Dakota filed an application with the NDPSC for an electric rate increase. Montana-Dakota requested a total increase of $15.4 million annually or approximately 14 percent above current rates. The requested increase includes the investment in infrastructure upgrades, recovery of the investment in renewable generation and the costs associated with Big Stone Station II. If resolution of a proposed alternate recovery mechanism pending before the NDPSC is approved for the Big Stone Station II plant costs, those costs will be withdrawn from the proceeding. Montana-Dakota requested an interim increase of $7.6 million annually to be effective within sixty days.

18. Contingencies

Litigation

Coalbed Natural Gas Operations Fidelity’s CBNG operations are and have been the subject of numerous lawsuits in Montana and Wyoming. The current cases involve the permitting and use of water produced in connection with Fidelity’s CBNG development in the Powder River Basin. Some of these cases challenge the issuance of discharge permits by the Montana DEQ and approval of other water management tools by the MBOGC.

In April 2006, the Northern Cheyenne Tribe filed a complaint in Montana Twenty-Second Judicial District Court against the Montana DEQ seeking to set aside Fidelity’s 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 Constitution’s guarantee of a clean and healthful environment, that the Montana DEQ’s related environmental assessment was invalid, that the Montana DEQ was required, but failed, to prepare an EIS and that the Montana DEQ failed to consider other alternatives to the issuance of the permits. Fidelity, the NPRC, and the TRWUA were granted leave to intervene in this proceeding. In January 2009, the Montana Twenty-Second Judicial District Court decided the case in favor of Fidelity and the Montana DEQ in all respects, denying the motions of the Northern Cheyenne Tribe, TRWUA, and NPRC, and granting the cross-motions of the Montana DEQ and Fidelity in their entirety. As a result, Fidelity may continue to utilize its direct discharge and treatment permits. The NPRC, the TRWUA and the Northern Cheyenne Tribe appealed the decision to the Montana Supreme Court in March 2009.

Fidelity’s 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, Fidelity’s CBNG operations in Montana could be significantly and adversely affected.

In October 2003, Tongue & Yellowstone Irrigation District, NPRC and MEIC filed a lawsuit in Montana First Judicial District Court challenging the MBOGC’s ROD adopting the 2003 Final EIS which analyzed CBNG development in the State of Montana. The primary legal issue before the court was whether the ROD authorized the “wasting” of ground water in violation of the Montana State Constitution and the public trust doctrine. Specifically, the plaintiffs contended that various water management tools, including Fidelity’s direct discharge permits, allowed for the waste of water. On March 5, 2010, the Montana First Judicial District Court issued an order holding that Fidelity’s direct discharge permits did not violate the Montana State Constitution. On March 15, 2010, the NPRC filed a motion to amend the order with respect to the court’s conclusion that the disposal of CBNG water by evaporation is not a beneficial use of water and, to the extent the ROD authorized evaporation pits, the ROD is unconstitutional. Fidelity does not use evaporation pits as a tool to dispose of CBNG water. On April 26, 2010, the court issued a revised order stating that the authorization of evaporation pits in the ROD violates the Montana State Constitution. Once judgment is entered, the parties will have 60 days to appeal to the Montana Supreme Court. Should the Montana Supreme Court determine the permits violate

the Montana State Constitution, Fidelity’s Montana CBNG operations could be significantly and adversely affected.

Fidelity will continue to vigorously defend its interests in all CBNG-related litigation in which it is involved. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could adversely impact Fidelity’s existing CBNG operations and/or the future development of this resource in the affected regions.

Electric Operations In June 2008, the Sierra Club filed a complaint in the South Dakota Federal District Court against Montana-Dakota and the two other co-owners of the Big Stone Station. The complaint alleged certain violations of the PSD and NSPS provisions of the Clean Air Act and certain violation of the South Dakota SIP. The action further alleged that the Big Stone Station was modified and operated without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. The Sierra Club alleged that these actions contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. The Sierra Club sought declaratory and injunctive relief to bring the co-owners of the Big Stone Station into compliance with the Clean Air Act and the South Dakota SIP and to require them to remedy the alleged violations. The Sierra Club also sought unspecified civil penalties, including a beneficial mitigation project. The Company believes the claims are without merit and that Big Stone Station has been and is being operated in compliance with the Clean Air Act and the South Dakota SIP. In March 2009, the District Court granted the motion of the co-owners to dismiss the complaint. The Sierra Club filed a motion requesting the District Court to reconsider its ruling on a portion of the order dismissing the complaint which was denied on July 22, 2009. On July 30, 2009, the Sierra Club appealed from the orders dismissing the case and denying the motion for reconsideration to the United States Court of Appeals for the Eighth Circuit. The United States has filed a brief as amicus curiae supporting the Sierra Club’s position in the appeal and the State of South Dakota filed a brief as amicus curiae supporting the Big Stone Station owners’ position in the appeal. Oral argument on the appeal is scheduled for May 11, 2010.

Construction Materials LTM is a third-party defendant in litigation pending in Oregon Circuit Court regarding the concrete floors in an industrial food processing facility located in Jackson County, Oregon. The complaint against the facility construction contractor alleges the concrete floors of the facility are defective and must be removed and replaced for suitable repair. Damages, including disruption of the food processing operations, have been estimated by the plaintiff to be approximately $26.5 million. The construction contractor’s answer and third-party complaint alleges the owner and third-party defendants, including LTM which supplied the concrete, are primarily responsible for any defects in the concrete surfaces. Discovery is currently being conducted by the parties. A trial date has not been set.

The Company also is involved in other legal actions in the ordinary course of its business. Although the outcomes of any such legal actions cannot be predicted, management believes that the outcomes with respect to these other legal proceedings will not have a material adverse effect upon the Company’s financial position or results of operations.

Environmental matters

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

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

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

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

The first claim is for soil and groundwater contamination at a site in Oregon and was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. An ecological risk assessment draft report was submitted to the Oregon DEQ in June 2009. The assessment showed no unacceptable risk to the aquatic ecological receptors present in the shoreline along the site and concluded that no further ecological investigation is necessary. The report is being reviewed by the Oregon DEQ. It is anticipated the Oregon DEQ will recommend a cleanup alternative for the site after it

completes its review of the report. It is not known at this time what share of the cleanup costs will actually be borne by Cascade.

The second claim is for contamination at a site in Washington and was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to $6.4 million. Data developed through the assessment and previous investigations indicates the contamination likely derived from multiple, different sources and multiple current and former owners of properties and businesses in the vicinity of the site may be responsible for the contamination. Cascade received notice in April 2010, that the Washington Department of Ecology has determined that Cascade is a PRP for release of hazardous substances at the manufactured gas plant site. Cascade has reserved $6.4 million for remediation of this site. On April 9, 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case.

The third claim is also for contamination at a site in Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade’s predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim.

To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers.

Guarantees

In connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent of any losses that Petrobras may incur from certain contingent liabilities specified in the purchase agreement. Centennial has agreed to unconditionally guarantee payment of the indemnity obligations to Petrobras for periods ranging up to five and a half years from the date of sale. The guarantee was required by Petrobras as a condition to closing the sale of MPX.

Centennial guaranteed CEM's obligations under a construction contract with LPP for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. Centennial Resources sold CEM in July 2007 to Bicent Power LLC, which provided a $10 million bank letter of credit to Centennial in support of the guarantee obligation. In February 2009, Centennial received a Notice and Demand from LPP under the guaranty agreement alleging that CEM did not meet certain of its obligations under the construction contract and demanding that Centennial indemnify LPP against all losses, damages, claims, costs, charges and expenses arising from CEM’s alleged failures. In December 2009, LPP submitted a demand for arbitration of its dispute with CEM to the American Arbitration Association. The demand seeks compensatory damages of $146 million plus damages for increased operating, capital and construction costs related to a water treatment facility for

the generating facility. LPP’s notice of demand for arbitration also demanded performance of the guarantee by Centennial. The Company believes the indemnification claims against Centennial are without merit and intends to vigorously defend against such claims.

In connection with the pending sale of the Brazilian Transmission Lines, as discussed in Note 11, Centennial has agreed to guarantee the performance of certain of the Company’s indirect wholly owned subsidiaries in three purchase and sale agreements. Centennial has agreed to unconditionally guarantee payment of the indemnity obligations of the wholly owned subsidiary sellers for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines.

In addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas and oil swap and collar agreement obligations. There is no fixed maximum amount guaranteed in relation to the natural gas and oil swap and collar agreements as the amount of the obligation is dependent upon natural gas and oil commodity prices. The amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the natural gas and oil swap and collar agreements at March 31, 2010, expire in the years ranging from 2010 to 2011; however, Fidelity continues to enter into additional hedging activities and, as a result, WBI Holdings from time to time may issue additional guarantees on these hedging obligations. Fidelity had $700,000 outstanding under these agreements, which was reflected on the Consolidated Balance Sheet, at March 31, 2010. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees.

Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts, a conditional purchase agreement and certain other guarantees. At March 31, 2010, the fixed maximum amounts guaranteed under these agreements aggregated $235.1 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $9.7 million in 2010; $197.9 million in 2011; $17.6 million in 2012; $1.2 million in 2013; $200,000 in 2014; $1.0 million in 2018; $300,000 in 2019; $3.2 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $500,000 and was reflected on the Consolidated Balance Sheet at March 31, 2010. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.

Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies, materials obligations, natural gas transportation agreements and other agreements that guarantee the performance of other subsidiaries of the Company. At March 31, 2010, the fixed maximum amounts guaranteed under these letters of credit, aggregated $33.0 million. In 2010 and 2011, $26.0 million and $7.0 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at March 31, 2010.

WBI Holdings has an outstanding guarantee to Williston Basin. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of

Prairielands. At March 31, 2010, the fixed maximum amount guaranteed under this agreement aggregated $5.0 million and is scheduled to expire in 2011. In the event of Prairielands’ default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $1.5 million. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at March 31, 2010, because this intercompany transaction was eliminated in consolidation.

In addition, Centennial and Knife River have issued guarantees to third parties related to the Company’s routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under its obligation in relation to the purchase of certain maintenance items, materials or lease obligations, Centennial or Knife River would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these maintenance items and materials were reflected on the Consolidated Balance Sheet at March 31, 2010.

In the normal course of business, Centennial has purchased surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. As of March 31, 2010, approximately $605 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

19. Subsequent events

On April 29, 2010, Fidelity completed the acquisition of 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 63 Bcfe of proven reserves. The purchase price for these properties was approximately $113 million, subject to accounting and purchase price adjustments customary with acquisitions of this type.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

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

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

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

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

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities and the issuance from time to time of debt and equity securities. In the event that access to the commercial paper markets were to become unavailable, the Company may need to borrow under its credit agreements. For more information on the Company’s net capital expenditures, see Liquidity and Capital Commitments.

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

Key Strategies and Challenges

Electric and Natural Gas Distribution

Strategy Provide competitively priced energy to customers while working with them to ensure efficient usage. Both the electric and natural gas distribution segments continually seek opportunities for growth and expansion of their customer base through extensions of existing operations, including electric generation with a diverse resource mix including wind, and transmission build-out, and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity for the Company to earn a competitive return on investment.

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

Construction Services

Strategy Provide a competitive return on investment while operating in a competitive industry by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; focusing business development efforts on project areas that will permit higher margins; and properly managing risk. This segment continuously seeks opportunities to expand through strategic acquisitions.

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

Pipeline and Energy Services

Strategy Utilize the segment’s existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new sources of natural gas for storage, gathering and transportation services; expansion of existing gathering, transmission and storage facilities; expansion of related energy services; and incremental expansion of pipeline capacity to allow customers access to more liquid and higher-priced markets.

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

Natural Gas and Oil Production

Strategy Apply technology and utilize existing exploration and production expertise, with a focus on operated properties, to increase production and reserves from existing leaseholds, and to seek additional reserves and production opportunities both in new and existing areas to further expand the segment’s asset base. By optimizing existing operations and taking advantage of new and incremental growth opportunities, this segment’s goal is to increase both production and reserves over the long term so as to generate competitive returns on investment.

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

Construction Materials and Contracting

Strategy Focus on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthen long-term, strategic aggregate reserve position through purchase and/or lease opportunities; enhance profitability through cost containment, margin discipline and vertical integration of the segment’s operations; and continue growth through organic and acquisition opportunities. Ongoing efforts to increase margin are being pursued through the implementation of a variety of continuous improvement programs, including corporate purchasing of equipment, parts and commodities (liquid asphalt, diesel fuel, cement and other materials), and negotiation of contract price escalation provisions. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to adequate quantities of permitted aggregate reserves being significant. A key element of the

Company’s long-term strategy for this business is to further expand its presence, through acquisition, in the higher-margin materials business (rock, sand, gravel, liquid asphalt, ready-mixed concrete and related products), complementing and expanding on the Company’s expertise.

Challenges The economic downturn has adversely impacted operations, particularly in the private market. This business unit expects to continue cost containment efforts and a greater emphasis on industrial, energy and public works projects. Significant volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and steel continue to be a concern. Increased competition in certain construction markets has also lowered margins.

For further information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company’s financial condition, see Part II, Item 1A – Risk Factors, as well as Part I, Item 1A – Risk Factors in the 2009 Annual Report. For further information on each segment’s key growth strategies, projections and certain assumptions, see Prospective Information. For information pertinent to various commitments and contingencies, see Notes to Consolidated Financial Statements.

Earnings Overview

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

	Three Months Ended
	March 31,
	2010			2009
(Dollars in millions, where applicable)
Electric	$	5.9		$	5.1
Natural gas distribution		23.3			23.9
Construction services		.1			8.6
Pipeline and energy services		8.8			6.4
Natural gas and oil production		22.2			(373.3	)
Construction materials and contracting		(20.1	)		(15.7	)
Other		1.4			1.0
Earnings (loss) on common stock	$	41.6		$	(344.0	)
Earnings (loss) per common share – basic	$	.22		$	(1.87	)
Earnings (loss) per common share – diluted	$	.22		$	(1.87	)
Return on average common equity for the 12 months ended		10.5	%		(4.5	)%

Three Months Ended March 31, 2010 and 2009 Consolidated earnings for the quarter ended March 31, 2010, increased $385.6 million from the comparable prior period largely due to:

Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), higher average realized oil prices, as well as lower depreciation, depletion and amortization expense, partially offset by decreased natural gas production and lower average realized natural gas prices at the natural gas and oil production business

·	Higher storage services revenue and lower operation and maintenance expense, partially offset by lower gathering volumes at the pipeline and energy services business

Partially offsetting these increases were:

·	Lower construction workloads and margins, partially offset by lower general and administrative expense at the construction services business

·	Lower product volumes and margins, partially offset by lower selling, general and administrative expense at the construction materials and contracting business

FINANCIAL AND OPERATING DATA

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

Electric

	Three Months Ended
	March 31,
	2010		2009
(Dollars in millions, where applicable)
Operating revenues	$	49.7	$	51.2
Operating expenses:
Fuel and purchased power		16.9		18.7
Operation and maintenance		15.2		15.6
Depreciation, depletion and amortization		5.7		6.1
Taxes, other than income		2.7		2.4
		40.5		42.8
Operating income		9.2		8.4
Earnings	$	5.9	$	5.1
Retail sales (million kWh)		749.8		724.9
Sales for resale (million kWh)		29.8		9.6
Average cost of fuel and purchased power per kWh	$	.021	$	.024

Three Months Ended March 31, 2010 and 2009 Electric earnings increased $800,000 (16 percent) due to:

·	Higher other income, primarily allowance for funds used during construction of $700,000 (after tax)

·	Lower operation and maintenance expense of $400,000 (after tax), largely payroll and benefit-related costs

Partially offsetting these increases was higher interest expense, resulting from higher average borrowings.

Natural Gas Distribution

	Three Months Ended
	March 31,
	2010			2009
(Dollars in millions, where applicable)
Operating revenues	$	349.0		$	483.2
Operating expenses:
Purchased natural gas sold		245.2			365.9
Operation and maintenance		32.7			38.1
Depreciation, depletion and amortization		10.6			10.7
Taxes, other than income		16.5			22.9
		305.0			437.6
Operating income		44.0			45.6
Earnings	$	23.3		$	23.9
Volumes (MMdk):
Sales		38.1			43.6
Transportation		34.5			34.0
Total throughput		72.6			77.6
Degree days (% of normal)*
Montana-Dakota		99	%		103	%
Cascade		86	%		107	%
Intermountain		95	%		106	%
Average cost of natural gas, including transportation, per dk	$	6.44		$	8.39
* Degree days are a measure of the daily temperature-related demand for energy for heating.

Three Months Ended March 31, 2010 and 2009 Earnings at the natural gas distribution business decreased $600,000 (2 percent) due to decreased retail sales margins, largely lower volumes resulting from warmer weather than last year. Partially offsetting this decrease was lower operation and maintenance expense of $1.9 million (after tax), largely lower payroll. The pass-through of lower natural gas prices is reflected in the decrease in both sales revenue and purchased natural gas sold.

Construction Services

	Three Months Ended
	March 31,
	2010		2009
	(In millions)
Operating revenues	$	153.1	$	244.8
Operating expenses:
Operation and maintenance		141.8		217.3
Depreciation, depletion and amortization		3.3		3.4
Taxes, other than income		6.5		9.5
		151.6		230.2
Operating income		1.5		14.6
Earnings	$	.1	$	8.6

Three Months Ended March 31, 2010 and 2009 Construction services earnings decreased $8.5 million due to lower construction workloads and margins, largely in the Southwest region, partially offset by lower general and administrative expense of $3.1 million (after tax), largely payroll-related.

Pipeline and Energy Services

	Three Months Ended
	March 31,
	2010		2009
	(Dollars in millions)
Operating revenues	$	88.6	$	85.1
Operating expenses:
Purchased natural gas sold		47.5		46.1
Operation and maintenance		15.2		17.6
Depreciation, depletion and amortization		6.4		6.2
Taxes, other than income		3.0		2.9
		72.1		72.8
Operating income		16.5		12.3
Earnings	$	8.8	$	6.4
Transportation volumes (MMdk):
Montana-Dakota		7.6		8.3
Other		22.9		28.8
		30.5		37.1
Gathering volumes (MMdk)		19.1		24.2

Three Months Ended March 31, 2010 and 2009 Pipeline and energy services earnings increased $2.4 million (38 percent) due to:

·	Higher storage services revenue of $2.4 million (after tax), largely higher storage balances

·	Lower operation and maintenance expense of $2.1 million (after tax), including lower costs associated with the natural gas storage litigation, which was settled in July 2009

Partially offsetting the earnings increase were lower gathering volumes of $1.5 million (after tax), as well as lower volumes transported to storage.

Natural Gas and Oil Production

	Three Months Ended
	March 31,
	2010		2009
(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	57.5	$	81.7
Oil		50.1		24.4
		107.6		106.1
Operating expenses:
Operation and maintenance:
Lease operating costs		15.8		20.0
Gathering and transportation		5.8		6.1
Other		8.7		10.3
Depreciation, depletion and amortization		29.7		42.6
Taxes, other than income:
Production and property taxes		9.5		7.5
Other		.3		.2
Write-down of natural gas and oil properties		—		620.0
		69.8		706.7
Operating income (loss)		37.8		(600.6	)
Earnings (loss)	$	22.2	$	(373.3	)
Production:
Natural gas (MMcf)		12,243		15,401
Oil (MBbls)		761		742
Total Production (MMcf equivalent)		16,808		19,852
Average realized prices (including hedges):
Natural gas (per Mcf)	$	4.70	$	5.31
Oil (per Bbl)	$	65.79	$	32.86
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	4.56	$	3.63
Oil (per Bbl)	$	66.40	$	32.86
Average depreciation, depletion and amortization rate, per equivalent Mcf	$	1.67	$	2.07
Production costs, including taxes, per net equivalent Mcf:
Lease operating costs	$	.94	$	1.00
Gathering and transportation		.35		.31
Production and property taxes		.56		.38
	$	1.85	$	1.69

Three Months Ended March 31, 2010 and 2009 Natural gas and oil production earnings increased $395.5 million due to:

·	Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), as discussed in Note 6

·	Average realized oil prices that doubled

·	Lower depreciation, depletion and amortization expense of $8.0 million (after tax), due to lower depletion rates and decreased combined production. The lower depletion rates are largely the result of the write-down of natural gas and oil properties in March 2009.

·	Decreased lease operating expenses of $2.6 million (after tax)

Partially offsetting these increases were:

·	Decreased natural gas production of 21 percent, largely related to normal production declines

·	Lower average realized natural gas prices of 11 percent

Construction Materials and Contracting

	Three Months Ended
	March 31,
	2010			2009
	(Dollars in millions)
Operating revenues	$	149.8		$	183.5
Operating expenses:
Operation and maintenance		146.0			172.4
Depreciation, depletion and amortization		22.6			23.9
Taxes, other than income		7.2			7.5
		175.8			203.8
Operating loss		(26.0	)		(20.3	)
Loss	$	(20.1	)	$	(15.7	)
Sales (000's):
Aggregates (tons)		2,963			3,185
Asphalt (tons)		154			188
Ready-mixed concrete (cubic yards)		476			509

Three Months Ended March 31, 2010 and 2009 Construction materials and contracting experienced a seasonal first quarter loss of $20.1 million. The loss increased by $4.4 million (29 percent) from the $15.7 million loss in 2009. The increased loss was largely due to lower product volumes and margins, which include the effects of weather-related delays. Partially offsetting the increased loss was lower selling, general and administrative expense of $2.1 million (after tax), largely the result of cost reduction measures.

Other and Intersegment Transactions

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

	Three Months Ended
	March 31,
	2010		2009
	(In millions)
Other:
Operating revenues	$	2.3	$	2.7
Operation and maintenance		1.9		3.2
Depreciation, depletion and amortization		.4		.3
Taxes, other than income		.1		.1
Intersegment transactions:
Operating revenues	$	65.3	$	62.6
Purchased natural gas sold		59.0		55.5
Operation and maintenance		6.3		7.1

For further information on intersegment eliminations, see Note 15.

PROSPECTIVE INFORMATION

The following information highlights the key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters for certain of the Company’s businesses. Many of these highlighted points are “forward-looking statements.” There is no assurance that the Company’s projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer to assumptions contained in this section, as well as the various important factors listed in Part II, Item 1A – Risk Factors, as well as Part I, Item 1A – Risk Factors in the 2009 Annual Report. Changes in such assumptions and factors could cause actual future results to differ materially from the Company’s growth and earnings projections.

MDU Resources Group, Inc.

·	Earnings per common share for 2010, diluted, are projected in the range of $1.10 to $1.35. The Company expects the percentage of 2010 earnings per common share by quarter to be in the following approximate ranges:

o	Second quarter – 20 percent to 25 percent

o	Third quarter – 30 percent to 35 percent

o	Fourth quarter – 25 percent to 30 percent

·	Long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent.

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

Electric and natural gas distribution

·	The Company continues to realize efficiencies and enhanced service levels through its efforts to standardize operations, share services and consolidate back-office functions among its four utility companies.

·	The Company is pursuing expansion opportunities.

In April 2009, the Company purchased a 25 MW ownership interest in Wygen III, which commenced commercial operation on April 1, 2010. This rate-based generation replaces a portion of power purchased for the Wyoming system. In August 2009, Montana-Dakota filed an application with the WYPSC for an electric rate increase, as discussed in Note 17.

o	The Company is developing additional wind generation including a 19.5 MW wind generation facility in southwest North Dakota and a 10.5 MW expansion of the Diamond Willow wind facility near Baker, Montana. Both projects are expected to be commercial mid-year.

o	In April 2010, the Company filed an application with the NDPSC for an electric rate increase, as discussed in Note 17.

o	The Company is developing a landfill methane gas recovery project in Billings, Montana to supplement the Company’s gas supply portfolio. The project is expected to begin production in the third quarter of 2010, and upon total phase-in to recover up to 2,500 dk per day.

o	The Company is analyzing potential projects for accommodating load growth and replacing purchased power contracts with company-owned generation. The Company is reviewing the construction of natural gas-fired combustion and wind generation.

·	The Company is pursuing opportunities associated with the potential development of high voltage transmission lines and system enhancements targeted towards delivery of renewable energy from the wind rich regions that lie within its traditional electric service territory to major metropolitan areas.

Construction services

·	The Company anticipates margins in 2010 to be lower than 2009 levels.

The Company is aggressively pursuing expansion in high voltage transmission construction, renewable resource construction and military installation services. In late 2009, the Company was awarded the engineering, procurement and construction contract to build the 214-mile Montana Alberta Tie Line between Lethbridge, Alberta and Great Falls, Montana.

·	The Company continues to focus on costs and efficiencies to enhance margins. With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure.

Work backlog as of March 31, 2010, was approximately $400 million, compared to $557 million at March 31, 2009, which included backlog related to the Fontainebleau project of $197 million. The Fontainebleau project was removed from backlog in the third quarter of 2009. Absent the Fontainebleau-related backlog, levels are $40 million higher than one year ago. Backlog at December 31, 2009, was $383 million.

Pipeline and energy services

·	An incremental expansion to the Grasslands Pipeline of 75,000 Mcf per day went into service August 31, 2009. The firm capacity of the Grasslands Pipeline is at its ultimate full capacity of 213,000 Mcf per day.

The Company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Wyoming, Montana and North Dakota, is expanding, most notably the Bakken Shale of North Dakota and eastern Montana. Ongoing energy development is expected to have many direct and indirect benefits to its business.

The Company has three natural gas storage fields, including the largest storage field in North America located near Baker, Montana. Total working gas storage capacity is 193 Bcf for its storage fields. The Company is pursuing a project to increase its firm deliverability and related transportation capacity from the Baker Storage field. A binding open season was held during the first quarter of 2010. Results of the open season continue to be reviewed and a phased development of the project is being planned.

Natural gas and oil production

The Company expects to spend approximately $375 million in capital expenditures for 2010, approximately double the level of capital invested in 2009. This reflects further exploitation of existing properties, leasehold acquisitions in the Bakken and Niobrara oil shale plays and the acquisition of producing natural gas properties located in the Green River Basin in southwest Wyoming. The capital expenditures forecast reflects a shift from certain natural gas development activities to oil shale leasehold acquisitions, which will affect short-term production growth.

The leasehold acquisitions in the Bakken and Niobrara plays broaden the Company’s long-term growth potential. The recent Bakken leasehold purchase of an additional 40,000 net acres increased the Company’s acreage position to more than 56,000 net acres. In the Niobrara play, the Company has signed agreements in place to acquire over 80,000 net acres. The Company is also continuing to actively pursue additional leasehold and reserve acquisitions, which are not included in the current forecast.

Because of reduced capital spending in 2009 and the redirecting of forecasted 2010 capital expenditures, along with delays in obtaining well completion/frac services, primarily in Texas, the Company expects its 2010 combined natural gas and oil production to be approximately 3 percent to 6 percent below 2009 levels.

·	Earnings guidance reflects estimated natural gas prices for May through December as follows:

	Index*	Price Per Mcf
	Ventura	$4.25 to $4.75
	NYMEX	$4.50 to $5.00
	CIG	$4.00 to $4.50
	* Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system.

·	Earnings guidance reflects estimated NYMEX crude oil prices for May through December in the range of $78 to $83 per barrel.

For the last nine months of 2010, the Company has hedged approximately 50 percent of both its estimated natural gas and oil production. For 2011, the Company has hedged 10 percent to 15 percent of its estimated natural gas production and 20 percent to 25 percent of its estimated oil production. For 2012, the Company has hedged 5 percent to 10 percent of its estimated natural gas production. The hedges that are in place as of April 29, 2010, are summarized in the following chart:

Commodity	Type	Index	Period Outstanding	Forward Notional Volume (MMBtu/Bbl)	Price (Per MMBtu/Bbl)
Natural Gas	Swap	HSC	4/10 - 12/10	1,210,000	$8.08
Natural Gas	Swap	NYMEX	4/10 - 12/10	2,750,000	$6.18
Natural Gas	Swap	NYMEX	4/10 - 12/10	1,375,000	$6.40
Natural Gas	Collar	NYMEX	4/10 - 12/10	1,375,000	$5.63-$6.00
Natural Gas	Swap	NYMEX	4/10 - 12/10	1,375,000	$5.855
Natural Gas	Swap	NYMEX	4/10 - 12/10	1,375,000	$6.045
Natural Gas	Swap	NYMEX	4/10 - 12/10	1,375,000	$6.045
Natural Gas	Swap	CIG	4/10 - 12/10	2,750,000	$5.03
Natural Gas	Swap	HSC	4/10 - 10/10	428,000	$5.57
Natural Gas	Swap	NYMEX	4/10 - 10/10	1,712,000	$5.645
Natural Gas	Swap	Ventura	4/10 - 12/10	1,375,000	$5.95
Natural Gas	Swap	NYMEX	4/10 - 12/10	3,025,000	$5.54
Natural Gas	Collar	NYMEX	4/10 - 3/11	1,825,000	$5.62-$6.50
Natural Gas	Swap	HSC	1/11 - 12/11	1,350,500	$8.00
Natural Gas	Swap	NYMEX	1/11 - 12/11	4,015,000	$6.1027
Natural Gas	Swap	NYMEX	1/12 - 12/12	3,477,000	$6.27
Crude Oil	Collar	NYMEX	4/10 - 12/10	275,000	$60.00-$75.00
Crude Oil	Swap	NYMEX	4/10 - 12/10	275,000	$73.20
Crude Oil	Collar	NYMEX	4/10 - 12/10	275,000	$70.00-$86.00
Crude Oil	Swap	NYMEX	4/10 - 12/10	275,000	$83.05
Crude Oil	Collar	NYMEX	1/11 - 12/11	547,500	$80.00-$94.00
Crude Oil	Collar	NYMEX	1/11 - 12/11	365,000	$80.00-$89.00
Natural Gas	Basis Swap	Ventura	4/10 - 12/10	2,750,000	$0.25
Natural Gas	Basis Swap	Ventura	4/10 - 12/10	687,500	$0.245
Natural Gas	Basis Swap	Ventura	4/10 - 12/10	3,437,500	$0.25
Natural Gas	Basis Swap	Ventura	4/10 - 12/10	1,375,000	$0.225
Natural Gas	Basis Swap	Ventura	4/10 - 12/10	687,500	$0.23
Natural Gas	Basis Swap	Ventura	4/10 - 12/10	2,062,500	$0.23
Natural Gas	Basis Swap	CIG	5/10 - 12/10	2,695,000	$0.385
Natural Gas	Basis Swap	Ventura	1/11 - 3/11	450,000	$0.135
Natural Gas	Basis Swap	CIG	1/11 - 12/11	4,015,000	$0.395
Natural Gas	Basis Swap	CIG	1/12 - 12/12	2,745,000	$0.405
Natural Gas	Basis Swap	CIG	1/12 - 12/12	732,000	$0.41
Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column.

Construction materials and contracting

·	Most of the markets served by construction materials are seeing positive impacts related to the federal stimulus spending.

The Company is well positioned to take advantage of government stimulus spending on transportation infrastructure particularly in the asphalt paving and liquid asphalt oil product lines. Federal transportation stimulus of $7.9 billion was directed to states where the Company operates. Of that amount, 26 percent was spent as of late March 2010, with the remaining $5.8 billion to be spent during 2010 and 2011.

The Company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets.

·	The Company has a strong emphasis on operational efficiencies and cost reduction.

·	Liquid asphalt margins are expected to be lower in 2010 than the record levels experienced in 2009. However, this product line continues to perform well. The Company has planned green field expansions for this business beginning in 2010.

Work backlog as of March 31, 2010, was approximately $568 million, $109 million higher than the December 31, 2009, backlog of $459 million. Backlog a year ago was comparable at $574 million. Private project backlog has decreased, however public work has increased over prior year levels. Although public project margins tend to be somewhat lower than private construction-related work, the Company anticipates significant contributions to revenue from public works volume.

·	As the country’s 9th largest aggregate producer, the Company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.

·	Of the five labor contracts that Knife River was negotiating, as reported in Items 1 and 2 – Business and Properties – General in the 2009 Annual Report, three have been ratified. The two remaining contracts are still in negotiations.

NEW ACCOUNTING STANDARDS

For information regarding new accounting standards, see Note 9, which is incorporated by reference.

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

The Company’s critical accounting policies involving significant estimates include impairment testing of long-lived assets and intangibles, impairment testing of natural gas and oil production properties, revenue recognition, purchase accounting, asset retirement obligations, pension and other postretirement benefits, and income taxes. There were no material changes in the Company’s critical accounting policies involving significant estimates from those reported in the 2009 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2009 Annual Report.

LIQUIDITY AND CAPITAL COMMITMENTS

Cash flows

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

Cash flows provided by operating activities in the first three months of 2010 decreased $162.7 million from the comparable 2009 period. The decrease in cash provided by operating activities was largely due to higher working capital requirements of $153.6 million, including higher net natural gas costs recoverable through rate adjustments at the natural gas distribution business, decreased cash provided from receivables at the construction businesses, as well as at the natural gas and oil production business.

Investing activities Cash flows used in investing activities in the first three months of 2010 decreased $20.7 million from the comparable period in 2009. The decrease in cash used in investing activities largely results from decreased capital expenditures of $21.5 million, primarily at the natural gas and oil production business, partially offset by increased capital expenditures at the electric business.

Financing activities Cash flows used in financing activities in the first three months of 2010 decreased $80.7 million from the comparable period in 2009. The decrease in cash used in financing activities was largely due to lower repayment of short-term borrowings and long-term debt, partially offset by lower issuance of long-term debt.

Defined benefit pension plans

There were no material changes to the Company’s qualified noncontributory defined benefit pension plans from those reported in the 2009 Annual Report. For further information, see Note 16 and Part II, Item 7 in the 2009 Annual Report.

Capital expenditures

Net capital expenditures for the first three months of 2010 were $122.5 million and are estimated to be approximately $618 million for 2010. Estimated capital expenditures include:

·	The acquisition of producing natural gas properties located in the Green River Basin in southwest Wyoming

·	System upgrades

·	Routine replacements

·	Service extensions

·	Routine equipment maintenance and replacements

·	Buildings, land and building improvements

·	Pipeline and gathering projects

·	Further development of existing properties and leasehold acquisitions at the natural gas and oil production segment

·	Power generation opportunities, including certain costs for additional electric generating capacity

·	Other growth opportunities

The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimated 2010 capital expenditures referred to previously. It is anticipated that all of the funds required for capital expenditures will be met from various sources, including internally generated funds; the Company's credit facilities, as described

below; and through the issuance of long-term debt and the Company's equity securities.

Capital resources

Certain debt instruments of the Company and its subsidiaries, including those discussed below, contain restrictive covenants and cross-default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions, all of which the Company and its subsidiaries, as applicable, were in compliance with at March 31, 2010. In the event the Company and its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. For additional information on the covenants, certain other conditions and cross-default provisions, see Part II, Item 8 – Note 9, in the 2009 Annual Report.

The following table summarizes the outstanding credit facilities of the Company and its subsidiaries at March 31, 2010:

Company	Facility		Facility Limit			Amount Outstanding			Letters of Credit			Expiration Date
(Dollars in millions)
MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement	(a)	$	125.0		$	—	(b)	$	—		6/21/11
MDU Energy Capital, LLC	Master shelf agreement		$	175.0		$	165.0		$	—		8/14/10	(c)
Cascade Natural Gas Corporation	Revolving credit agreement		$	50.0	(d)	$	—		$	1.9	(e)	12/28/12	(f)
Intermountain Gas Company	Revolving credit agreement		$	65.0	(g)	$	7.7		$	—		8/31/10
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement	(h)	$	400.0		$	—	(b)	$	25.8	(e)	12/13/12
Williston Basin Interstate Pipeline Company	Uncommitted long-term private shelf agreement		$	125.0		$	87.5		$	—		12/23/11

(a)	The $125 million commercial paper program is supported by a revolving credit agreement with various banks totaling $125 million (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $150 million). There were no amounts outstanding under the credit agreement.
(b)	Amount outstanding under commercial paper program.
(c)	Or such time as the agreement is terminated by either of the parties thereto.
(d)	Certain provisions allow for increased borrowings, up to a maximum of $75 million.
(e)	The outstanding letters of credit, as discussed in Note 18, reduce amounts available under the credit agreement.
(f)	Provisions allow for an extension of up to two years upon consent of the banks.
(g)	Certain provisions allow for increased borrowings, up to a maximum of $70 million.
(h)	The $400 million commercial paper program is supported by a revolving credit agreement with various banks totaling $400 million (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $450 million). There were no amounts outstanding under the credit agreement.

In order to maintain the Company’s and Centennial’s respective commercial paper programs in the amounts indicated above, both the Company and Centennial must have revolving credit agreements in place at least equal to the amount of their commercial paper programs. While the amount of commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, the Company and Centennial do not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreements.

The following includes information related to the above table.

MDU Resources Group, Inc. The Company’s revolving credit agreement supports its commercial paper program. The commercial paper borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings. The

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

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

The Company's coverage of fixed charges including preferred stock dividends was 4.6 times for the 12 months ended March 31, 2010. Due to the $384.4 million after-tax noncash write-down of natural gas and oil properties in the first quarter of 2009, earnings were insufficient by $228.7 million to cover fixed charges for the 12 months ended December 31, 2009. If the $384.4 million after-tax noncash write-down is excluded, the coverage of fixed charges including preferred stock dividends would have been 4.6 times for the 12 months ended December 31, 2009. Common stockholders' equity as a percent of total capitalization was 63 percent at March 31, 2010 and December 31, 2009.

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

In September 2008, the Company entered into a Sales Agency Financing Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 5 million shares of the Company’s common stock. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement, which terminates on May 28, 2011. Proceeds from the sale of shares of common stock under the agreement have been and are expected to be used for corporate development purposes and other general corporate purposes. The Company did not issue any shares of stock during the first quarter of 2010 under the Sales Agency Financing Agreement. The Company has issued a total of approximately 3.2 million shares of stock under the Sales Agency Financing Agreement through March 31, 2010, resulting in total net proceeds of $63.1 million.

The Company currently has authorization to issue and sell up to $1.0 billion of securities pursuant to a registration statement on file with the SEC. The Company may sell all or a portion of such securities if warranted by market conditions and the Company's capital requirements. Any offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder.

Centennial Energy Holdings, Inc. Centennial’s revolving credit agreement supports its commercial paper program. The Centennial commercial paper borrowings are classified as long-term debt as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings. Centennial’s objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in Centennial’s credit ratings have not limited, nor are currently expected to limit, Centennial’s ability to access the capital markets. If Centennial were to experience a further downgrade of its credit ratings, it may need

to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.

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

Off balance sheet arrangements

Centennial continues to guarantee CEM's obligations under a construction contract for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. For further information, see Note 18.

Contractual obligations and commercial commitments

There are no material changes in the Company’s contractual obligations relating to long-term debt, estimated interest payments, operating leases, purchase commitments and uncertain tax positions from those reported in the 2009 Annual Report.

For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2009 Annual Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity price risk

Fidelity utilizes 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 forecasted sales of natural gas and oil production. Cascade utilizes and Intermountain periodically utilizes derivative instruments to manage a portion of their regulated natural gas supply portfolio in order to manage fluctuations in the price of natural gas. For more information on derivative instruments and commodity price risk, see Part II, Item 7A in the 2009 Annual Report, and Notes 10 and 13.

The following table summarizes derivative agreements entered into by Fidelity and Cascade as of March 31, 2010. These agreements call for Fidelity to receive fixed prices and pay variable prices, and for Cascade to receive variable prices and pay fixed prices.

(Forward notional volume and fair value in thousands)

	Weighted Average Fixed Price (Per MMBtu/Bbl)		Forward Notional Volume (MMBtu/Bbl)		Fair Value
Fidelity
Natural gas swap agreements maturing in 2010	$	5.92		18,750	$	32,293
Natural gas swap agreements maturing in 2011	$	6.58		5,366	$	6,702
Natural gas swap agreement maturing in 2012	$	6.27		3,477	$	1,630
Natural gas basis swap agreements maturing in 2010	$	.27		13,695	$	(3,230	)
Natural gas basis swap agreements maturing in 2011	$	.37		4,465	$	(365	)
Oil swap agreements maturing in 2010	$	78.13		550	$	(3,756	)


Cascade
Natural gas swap agreements maturing in 2010	$	7.79		4,071	$	(15,533	)
Natural gas swap agreements maturing in 2011	$	8.10		2,270	$	(7,240	)

	Weighted Average Floor/Ceiling Price (Per MMBtu/Bbl)		Forward Notional Volume (MMBtu/Bbl)		Fair Value
Fidelity
Natural gas collar agreements maturing in 2010		$5.63/$6.25		2,750	$	3,568
Natural gas collar agreement maturing in 2011		$5.62/$6.50		450	$	540
Oil collar agreements maturing in 2010		$65.00/$80.50		550	$	(4,304	)
Oil collar agreements maturing in 2011		$80.00/$92.00		913	$	(347	)

Interest rate risk

There were no material changes to interest rate risk faced by the Company from those reported in the 2009 Annual Report. For more information, see Part II, Item 7A in the 2009 Annual Report.

At March 31, 2010 and 2009, and December 31, 2009, the Company had no outstanding interest rate hedges.

Foreign currency risk

MDU Brasil’s equity method investments in the Brazilian Transmission Lines are exposed to market risks from changes in foreign currency exchange rates between the U.S. dollar and the Brazilian Real. For further information, see Part II, Item 8 – Note 4 in the 2009 Annual Report.

At March 31, 2010 and 2009, and December 31, 2009, the Company had no outstanding foreign currency hedges.

ITEM 4. CONTROLS AND PROCEDURES

The following information includes the evaluation of disclosure controls and procedures by the Company’s chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company.

Evaluation of disclosure controls and procedures

The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. The Company’s controls and other procedures are designed to provide reasonable assurance that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Company’s disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed is accumulated and communicated to management, including the Company’s chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company’s chief executive officer and chief financial officer have evaluated the effectiveness of the Company’s disclosure controls and procedures and they have concluded that, as of the end of the period covered by this report, such controls and procedures were effective at a reasonable assurance level.

Changes in internal controls

The Company maintains a system of internal accounting controls that is designed to provide reasonable assurance that the Company’s transactions are properly authorized, the Company’s assets are safeguarded against unauthorized or improper use, and the Company’s transactions are properly recorded and reported to permit preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America. There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2010, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 18, which is incorporated by reference.

ITEM 1A. RISK FACTORS

This Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions.

The Company is including the following factors and cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature,

including statements contained within Prospective Information. All these subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these factors and cautionary statements.

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

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

There are no material changes in the Company’s risk factors from those reported in Part I, Item 1A – Risk Factors in the 2009 Annual Report other than the risk associated with electric generation operations that could be adversely impacted by global climate change initiatives to reduce GHG emissions and the risk related to litigation and administrative proceedings in connection with CBNG development activities. These factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

Environmental and Regulatory Risks

The Company's electric generation operations could be adversely impacted by global climate change initiatives to reduce GHG emissions.

Concern that GHG emissions are contributing to global climate change has led to international, federal and state legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions including the EPA’s proposed endangerment finding for GHGs which could lead to regulation of GHG under the Clean Air Act. The primary GHG emitted from the Company's operations is carbon dioxide from combustion of fossil fuels at Montana-Dakota's electric generating facilities, particularly its coal-fired electric generating facilities which comprise approximately 70 percent of Montana-Dakota’s generating capacity. More than 90 percent of the electricity generated by Montana-Dakota is from coal-fired plants. Montana-Dakota also owns approximately 100 MW of natural gas- and oil-fired peaking plants. While there are many uncertainties regarding the future of GHG regulation, Montana-Dakota’s electric generating facilities may be subject to regulation under climate change laws or regulations within the next few years. Implementation of treaties, legislation or regulations to reduce GHG emissions could affect Montana-Dakota's electric utility operations by requiring the expansion of energy conservation efforts and/or the increased development of renewable energy sources, as well as instituting other mandates that could significantly increase the capital expenditures and operating costs at its fossil fuel-fired generating facilities. The most prominent federal legislative proposals are based on “cap and trade” programs which place a limit on GHG emissions from major emission sources such as the electric generating industry. The impact of a cap and trade program on Montana-Dakota would be determined by considerations such as the overall GHG emissions cap level, the scope and timeframe by which the cap level is decreased, the extent to which GHG offsets are allowed, whether allowances are given to new and existing emission sources, and the indirect

impact on natural gas, coal and other fuel prices. Montana-Dakota’s ability to recover costs incurred to comply with new regulations and programs will also be important in determining the financial impact on the Company.

Due to the uncertainty of technologies available to control GHG emissions and the unknown nature of compliance obligations with potential GHG emission legislation or regulations, the Company cannot determine the financial impact on its operations. If Montana-Dakota does not receive timely and full recovery of the costs of complying with GHG emission legislation and regulations from its customers, then such requirements could have an adverse impact on the results of its operations.

One of the Company's subsidiaries is subject to ongoing litigation and administrative proceedings in connection with its CBNG development activities. These proceedings have caused delays in CBNG drilling activity, and the ultimate outcome of the actions could have a material negative effect on existing CBNG operations and/or the future development of its CBNG properties.

Fidelity’s operations are and have been the subject of numerous lawsuits filed in connection with its CBNG development in the Montana and Wyoming Powder River Basin. If the plaintiffs are successful in the current lawsuits, the ultimate outcome of the actions could have a material negative effect on Fidelity's existing CBNG operations and/or the future development of its CBNG properties.

The BER in March 2006 issued a decision in a rulemaking proceeding, initiated by the NPRC, that amends the non-degradation policy applicable to water discharged in connection with CBNG operations. The amended policy includes additional limitations on factors deemed harmful, thereby restricting water discharges even further than under previous standards. Due in part to this amended policy, in May 2006, the Northern Cheyenne Tribe commenced litigation in Montana state court challenging two five-year water discharge permits that the Montana DEQ granted to Fidelity in February 2006 and which are critical to Fidelity's ability to manage water produced under present and future CBNG operations. Although the Montana state court decided the case in favor of Fidelity and the Montana DEQ in January 2009, the case was appealed to the Montana Supreme Court in March 2009. In a separate proceeding in Montana state court, plaintiffs challenged the ROD adopted by the MBOGC in 2003 and alleged that various water management tools, including Fidelity’s water discharge permits, allow for the “wasting” of water in violation of the Montana State Constitution. On March 5, 2010, the Montana First Judicial District Court determined that the water management tools used by Fidelity did not waste water in violation of the constitution. On March 15, 2010, the NPRC filed a motion to amend the order. On April 26, 2010, the court issued a revised order stating that the authorization of evaporation pits in the ROD violates the Montana State Constitution. Fidelity does not use evaporation pits as a tool to dispose of CBNG water. Once judgment is entered, the parties will have 60 days to appeal to the Montana Supreme Court. If these permits are set aside, Fidelity's CBNG operations in Montana could be significantly and adversely affected.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Between January 1, 2010 and March 31, 2010, the Company issued 85,504 shares of common stock, $1.00 par value, as part of the consideration paid by the Company in the acquisition of businesses acquired by the Company in a prior period. The common stock issued by the Company in these transactions was issued in a private transaction exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof, Rule 506 promulgated thereunder, or both. The classes of persons to whom these securities were sold were either accredited investors or other persons to whom such securities were permitted to be offered under the applicable exemption.

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

ISSUER PURCHASES OF EQUITY SECURITIES

Period	(a) Total Number of Shares (or Units) Purchased (1)		(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2)
January 1 through January 31, 2010		—
February 1 through February 28, 2010		59,025		$19.97
March 1 through March 31, 2010		—
Total		59,025

(1) Represents shares of common stock withheld by the Company to pay taxes in connection with the vesting of shares granted pursuant to the Long-Term Performance-Based Incentive Plan.

(2) Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.

ITEM 6. EXHIBITS

See the index to exhibits immediately preceding the exhibits filed with this report.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	MDU RESOURCES GROUP, INC.



DATE: May 5, 2010	BY:	/s/ Doran N. Schwartz
		Doran N. Schwartz
		Vice President and Chief Financial Officer


	BY:	/s/ Nicole A. Kivisto
		Nicole A. Kivisto
		Vice President, Controller and
		Chief Accounting Officer

EXHIBIT INDEX

Exhibit No.

3	Certificate of Amendment, dated April 27, 2010, to Restated Certificate of Incorporation of the Company, as filed with the Secretary of State of Delaware on April 27, 2010

+10(a)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated January 5, 2010

+10(b)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated March 30, 2010

12	Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends

31(a)	Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b)	Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32	Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101	The following materials from MDU Resources Group, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows and (iv) the Notes to Consolidated Financial Statements, tagged as blocks of text

+ Management contract, compensatory plan or arrangement.

MDU Resources Group, Inc. agrees to furnish to the SEC upon request any instrument with respect to long-term debt that MDU Resources Group, Inc. has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.