MDU RESOURCES GROUP INC - Quarter Report: 2009 March (Form 10-Q)

form10q.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, 2009

	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 o 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, 2009: 183,960,963 shares.

DEFINITIONS

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

Abbreviation or Acronym

2008 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, 2008
ALJ	Administrative Law Judge
Anadarko	Anadarko Petroleum Corporation
APB	Accounting Principles Board
APB Opinion No. 28	Interim Financial Reporting
Bbl	Barrel of oil or other liquid hydrocarbons
Bcf	Billion cubic feet
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	Proposed coal-fired electric generating facility located near Big Stone City, South Dakota (the Company anticipates ownership of at least 116 MW)
Brazilian Transmission Lines	Centennial Resources’ 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 International	Centennial Energy Resources International, Inc., a direct wholly owned subsidiary of Centennial Resources
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
Colorado Federal District Court	U.S. District Court for the District of Colorado
Company	MDU Resources Group, Inc.
D.C. Appeals Court	U.S. Court of Appeals for the District of Columbia Circuit
dk	Decatherm
EBSR	Elk Basin Storage Reservoir, one of Williston Basin's natural gas storage reservoirs, which is located in Montana and Wyoming
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
FSP	FASB Staff Position
FSP FAS No. 107-1	Interim Disclosures about Fair Value of Financial Instruments
FSP FAS No. 115-2	Recognition and Presentation of Other-Than-Temporary Impairments
FSP FAS No. 132(R)-1	Employers’ Disclosures about Postretirement Benefit Plan Assets
FSP FAS No. 141(R)-1	Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies
FSP FAS No. 157-2	Effective Date of FASB Statement No. 157
FSP FAS No. 157-4	Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly
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
Howell	Howell Petroleum Corporation, a wholly owned subsidiary of Anadarko
Indenture	Indenture dated as of December 15, 2003, as supplemented, from the Company to The Bank of New York as Trustee
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital (effective October 1, 2008)
IPUC	Idaho Public Utilities Commission
Knife River	Knife River Corporation, a direct wholly owned subsidiary of Centennial
kWh	Kilowatt-hour
LWG	Lower Willamette Group
MBbls	Thousands of barrels of oil or other liquid hydrocarbons
MBI	Morse Bros., Inc., an indirect wholly owned subsidiary of Knife River
Mcf	Thousand cubic feet
MDU Brasil	MDU Brasil Ltda., an indirect wholly owned subsidiary of Centennial International
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
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 Federal District Court	U.S. District Court for the District of Montana
Montana State District Court	Montana Twenty-Second Judicial District Court, Big Horn County
Mortgage	Indenture of Mortgage dated May 1, 1939, as supplemented, amended and restated, from the Company to The Bank of New York and Douglas J. MacInnes, successor trustees
MPX	MPX Termoceara Ltda. (49 percent ownership, sold in June 2005)
MW	Megawatt
NDPSC	North Dakota Public Service Commission
Ninth Circuit	U.S. Ninth Circuit Court of Appeals
North Dakota District Court	North Dakota South Central Judicial District Court for Burleigh County
NPRC	Northern Plains Resource Council
NSPS	New Source Performance Standards
OPUC	Oregon Public Utilities Commission
Order on Rehearing	Order on Rehearing and Compliance and Remanding Certain Issues for Hearing
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
SEC	U.S. Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
SFAS	Statement of Financial Accounting Standards
SFAS No. 71	Accounting for the Effects of Certain Types of Regulation
SFAS No. 115	Accounting for Certain Investments in Debt and Equity Securities
SFAS No. 141 (revised)	Business Combinations (revised 2007)
SFAS No. 157	Fair Value Measurements
SFAS No. 159	The Fair Value Option for Financial Assets and Financial Liabilities
SFAS No. 160	Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51 (Consolidated Financial Statements)
SFAS No. 161	Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133
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
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 Washington and Oregon. 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, 2009 and 2008	8

Consolidated Balance Sheets --
March 31, 2009 and 2008, and December 31, 2008	9

Consolidated Statements of Cash Flows --
Three Months Ended March 31, 2009 and 2008	10

Notes to Consolidated Financial Statements	11

Management's Discussion and Analysis of Financial Condition and Results of Operations	34

Quantitative and Qualitative Disclosures About Market Risk	50

Controls and Procedures	52

Part II -- Other Information

Legal Proceedings	52

Risk Factors	52

Unregistered Sales of Equity Securities and Use of Proceeds	55

Submission of Matters to a Vote of Security Holders	56

Exhibits	57

Signatures	58

Exhibit Index	59

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	594,576		$	517,263
Construction services, natural gas and oil production, construction materials and contracting, and other		499,429			604,644
		1,094,005			1,121,907
Operating expenses:
Fuel and purchased power		18,731			18,778
Purchased natural gas sold		356,496			276,624
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services		71,351			59,563
Construction services, natural gas and oil production, construction materials and contracting, and other		422,149			497,617
Depreciation, depletion and amortization		93,245			87,231
Taxes, other than income		52,952			54,522
Write-down of natural gas and oil properties		620,000			---
		1,634,924			994,335

Operating income (loss)		(540,919	)		127,572

Earnings from equity method investments		1,787			1,825

Other income		1,719			1,565

Interest expense		20,997			18,656

Income (loss) before income taxes		(558,410	)		112,306

Income taxes		(214,607	)		41,255

Net income (loss)		(343,803	)		71,051

Dividends on preferred stocks		171			171

Earnings (loss) on common stock	$	(343,974	)	$	70,880
Earnings (loss) per common share -- basic	$	(1.87	)	$	.39
Earnings (loss) per common share -- diluted	$	(1.87	)	$	.39
Dividends per common share	$	.1550		$	.1450
Weighted average common shares outstanding -- basic		183,787			182,599
Weighted average common shares outstanding -- diluted		183,787			183,130

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2009			March 31, 2008			December 31, 2008
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	44,689		$	71,504		$	51,714
Receivables, net		580,700			697,079			707,109
Inventories		276,268			227,017			261,524
Deferred income taxes		---			27,897			---
Short-term investments		2,329			13,491			2,467
Commodity derivative instruments		92,577			31,604			78,164
Prepayments and other current assets		135,734			83,331			171,314
		1,132,297			1,151,923			1,272,292
Investments		114,058			113,286			114,290
Property, plant and equipment		6,550,825			6,303,570			7,062,237
Less accumulated depreciation, depletion and amortization		2,839,020			2,343,585			2,761,319
		3,711,805			3,959,985			4,300,918
Deferred charges and other assets:
Goodwill		621,566			430,309			615,735
Other intangible assets, net		26,573			25,562			28,392
Other		254,240			149,752			256,218
		902,379			605,623			900,345
	$	5,860,539		$	5,830,817		$	6,587,845

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	25,500		$	---		$	105,100
Long-term debt due within one year		28,621			211,669			78,666
Accounts payable		355,951			333,894			432,358
Taxes payable		71,238			85,366			49,784
Deferred income taxes		10,143			---			20,344
Dividends payable		28,685			26,677			28,640
Accrued compensation		35,543			40,470			55,646
Commodity derivative instruments		58,062			42,016			56,529
Other accrued liabilities		162,271			184,766			140,408
		776,014			924,858			967,475
Long-term debt		1,614,786			1,269,963			1,568,636
Deferred credits and other liabilities:
Deferred income taxes		516,965			677,982			727,857
Other liabilities		551,175			416,672			562,801
		1,068,140			1,094,654			1,290,658
Commitments and contingencies
Stockholders’ equity:
Preferred stocks		15,000			15,000			15,000
Common stockholders’ equity:
Common stock
Shares issued -- $1.00 par value, 184,499,434 at March 31, 2009; 183,336,872 at March 31, 2008 and 184,208,283 at December 31, 2008		184,499			183,337			184,208
Other paid-in capital		940,369			917,159			938,299
Retained earnings		1,244,248			1,478,327			1,616,830
Accumulated other comprehensive income (loss)		21,109			(48,855	)		10,365
Treasury stock at cost – 538,921 shares		(3,626	)		(3,626	)		(3,626	)
Total common stockholders’ equity		2,386,599			2,526,342			2,746,076
Total stockholders’ equity		2,401,599			2,541,342			2,761,076
	$	5,860,539		$	5,830,817		$	6,587,845

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,
	2009			2008
	(In thousands)
Operating activities:
Net income (loss)	$	(343,803	)	$	71,051
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		93,245			87,231
Earnings, net of distributions, from equity method investments		(1,531	)		(1,141	)
Deferred income taxes		(228,764	)		12,704
Write-down of natural gas and oil properties		620,000			---
Changes in current assets and liabilities, net of acquisitions:
Receivables		129,318			29,997
Inventories		(13,347	)		3,010
Other current assets		40,442			(60,689	)
Accounts payable		(59,863	)		(28,135	)
Other current liabilities		21,713			19,307
Other noncurrent changes		(9,586	)		9,223
Net cash provided by operating activities		247,824			142,558

Investing activities:
Capital expenditures		(145,355	)		(165,315	)
Acquisitions, net of cash acquired		(3,057	)		(248,677	)
Net proceeds from sale or disposition of property		4,213			7,713
Investments		1,229			80,551
Net cash used in investing activities		(142,970	)		(325,728	)

Financing activities:
Repayment of short-term borrowings		(79,600	)		(1,700	)
Issuance of long-term debt		59,091			178,159
Repayment of long-term debt		(62,884	)		(4,893	)
Proceeds from issuance of common stock		107			1,706
Dividends paid		(28,640	)		(26,619	)
Tax benefit on stock-based compensation		111			2,191
Net cash provided by (used in) financing activities		(111,815	)		148,844
Effect of exchange rate changes on cash and cash equivalents		(64	)		10
Decrease in cash and cash equivalents		(7,025	)		(34,316	)
Cash and cash equivalents -- beginning of year		51,714			105,820
Cash and cash equivalents -- end of period	$	44,689		$	71,504

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

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

March 31, 2009 and 2008

(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 2008 Annual Report, and the standards of accounting measurement set forth in APB Opinion No. 28 and any amendments thereto adopted by the FASB. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2008 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.

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, 2009 and 2008, and December 31, 2008, was $16.1 million, $14.5 million and $13.7 million, respectively.

4. Natural gas in storage

Natural gas in storage for the Company's regulated operations is generally carried at cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories and was $9.5 million, $5.4 million and $27.6 million at March 31, 2009 and 2008, and December 31, 2008, respectively. The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $42.0 million, $43.0 million, and $43.4 million at March 31, 2009 and 2008, and December 31, 2008, respectively.

5. Inventories

Inventories, other than natural gas in storage for the Company’s regulated operations, consisted primarily of aggregates held for resale of $92.0 million, $108.6 million and $89.1 million; materials and supplies of $73.0 million, $39.0 million and $70.3 million; asphalt oil of $50.0 million, $35.9 million and $22.1 million; and other inventories of $51.8 million, $38.1 million and $52.4 million, as of March 31, 2009 and 2008, and December 31, 2008, 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 based on spot market prices that exist at the end of the period discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties less applicable income taxes. Future net revenue is estimated based on end-of-quarter spot market prices adjusted for contracted price changes. If capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter unless subsequent price changes eliminate or reduce an indicated write-down.

Due to low natural gas and oil prices that existed on March 31, 2009, the 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. Prices subsequent to March 31, 2009, remained low and therefore the noncash write-down was not reduced or eliminated. Sustained downward movements in natural gas and oil prices subsequent to March 31, 2009, could result in future write-downs of the Company’s natural gas and oil properties.

The Company hedges a portion of its natural gas and oil production and the effects of the cash flow hedges were used in determining the full-cost ceiling. The Company would have recognized an additional write-down of its natural gas and oil properties of $107.9 million ($66.9 million after tax) 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.

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, 2008, 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,
	2009			2008
	(In thousands)
Interest, net of amount capitalized	$	25,280		$	18,372
Income taxes paid (refunded), net	$	(21,914	)	$	10,813

9. New accounting standards

SFAS No. 157 In September 2006, the FASB issued SFAS No. 157. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The standard applies under other accounting pronouncements that require or permit fair value measurements with certain exceptions. SFAS No. 157 was effective for the Company on January 1, 2008. FSP FAS No. 157-2 delayed the effective date of SFAS No. 157 for certain nonfinancial assets and nonfinancial liabilities to January 1, 2009. The types of assets and liabilities that are recognized at fair value under the provisions of SFAS No. 157 effective January 1, 2009, due to the delayed effective date, include nonfinancial assets and nonfinancial liabilities initially measured at fair value in a business combination or new basis event, certain fair value measurements associated with goodwill impairment testing, indefinite-lived intangible assets and nonfinancial long-lived assets measured at fair value for impairment assessment, and asset retirement obligations initially measured at fair value. The adoption of SFAS No. 157, including the application to certain nonfinancial assets and nonfinancial liabilities with a delayed effective date of January 1, 2009, did not have a material effect on the Company's financial position or results of operations.

SFAS No. 141 (revised) In December 2007, the FASB issued SFAS No. 141 (revised). SFAS No. 141 (revised) requires an acquirer to recognize and measure the assets acquired, liabilities assumed and any noncontrolling interests in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exception. In addition, SFAS No. 141 (revised) requires that acquisition-related costs will be generally expensed as incurred. SFAS No. 141 (revised) also expands the disclosure requirements for business combinations. SFAS No. 141 (revised) was effective for the Company on January 1, 2009. The adoption of SFAS No. 141 (revised) did not have a material effect on the Company’s financial position or results of operations.

SFAS No. 160 In December 2007, the FASB issued SFAS No. 160. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 was effective for the Company on January 1, 2009. The adoption of SFAS No. 160 did not have a material effect on the Company’s financial position or results of operations.

SFAS No. 161 In March 2008, the FASB issued SFAS No. 161. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an

entity’s financial position, financial performance and cash flows. This Statement was effective for the Company on January 1, 2009. The adoption of SFAS No. 161 requires additional disclosures regarding the Company’s derivative instruments; however, it did not impact the Company’s financial position or results of operations.

FSP FAS No. 132(R)-1 In December 2008, the FASB issued FSP FAS No. 132(R)-1. FSP FAS No. 132(R)-1 provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan to provide users of financial statements with an understanding of how investment allocation decisions are made, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period and significant concentrations of risk within plan assets. This statement was effective for the Company on January 1, 2009. The adoption of FSP FAS No. 132(R)-1 will require additional disclosures regarding the Company's defined benefit pension and other postretirement plans in the annual financial statements; however, it will not impact the Company's financial position or results of operations.

Modernization of Oil and Gas Reporting In January 2009, the SEC adopted final rules amending its oil and gas reporting requirements. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. The final rules will be effective on December 31, 2009.

FSP FAS No. 107-1 In April 2009, the FASB issued FSP FAS No.107-1. FSP FAS No. 107-1 requires disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This statement will be effective for the Company in the second quarter of 2009. The adoption of FSP FAS No. 107-1 will not impact the Company's financial position or results of operations.

FSP FAS No. 115-2 In April 2009, the FASB issued FSP FAS No. 115-2. FSP FAS No. 115-2 amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This statement will be effective for the Company in the second quarter of 2009. The Company is evaluating the effects of the adoption of FSP FAS No. 115-2.

FSP FAS No. 157-4 In April 2009, the FASB issued FSP FAS No. 157-4. FSP FAS No. 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, when the volume and level of activity for the asset or liability have significantly decreased. This statement will be effective for the Company in the second quarter of 2009. The Company is evaluating the effects of the adoption of FSP FAS No. 157-4.

FSP FAS No. 141(R)-1 In April 2009, the FASB issued FSP FAS No. 141(R)-1. FSP FAS No. 141(R)-1 amends and clarifies SFAS No. 141 (revised), to address application issues raised in regard to initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This statement was effective for the Company on January 1, 2009. The

adoption of FSP FAS No. 141(R)-1 did not have a material effect on the Company's financial position or results of operations.

10. Comprehensive income (loss)

Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note 13.

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

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Net income (loss)	$	(343,803	)	$	71,051
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $13,895 and $(22,116) in 2009 and 2008, respectively		22,671			(36,197	)
Less: Reclassification adjustment for gain on derivative instruments included in net income (loss), net of tax of $7,464 and $2,083 in 2009 and 2008, respectively		12,178			3,345
Net unrealized gain (loss) on derivative instruments qualifying as hedges		10,493			(39,542	)
Foreign currency translation adjustment, net of tax of $164 and $336 in 2009 and 2008, respectively		251			485
		10,744			(39,057	)
Comprehensive income (loss)	$	(333,059	)	$	31,994

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, 2009, include the Brazilian Transmission Lines.

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

At March 31, 2009 and 2008, and December 31, 2008, the Company's equity method investments had total assets of $295.3 million, $395.7 million and $294.7 million, respectively, and long-term debt of $153.9 million, $207.3 million and $158.0 million, respectively. The Company's investment in its equity method investments was

approximately $45.4 million, $55.4 million and $44.4 million, including undistributed earnings of $8.4 million, $8.0 million and $6.8 million, at March 31, 2009 and 2008, and December 31, 2008, 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, 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
Three Months Ended	January 1,		During			March 31,
March 31, 2008	2008		the Year*			2008
	(In thousands)
Electric	$	---	$	---		$	---
Natural gas distribution		171,129		(11	)		171,118
Construction services		91,385		3,196			94,581
Pipeline and energy services		1,159		---			1,159
Natural gas and oil production		---		---			---
Construction materials and contracting		162,025		1,426			163,451
Other		---		---			---
Total	$	425,698	$	4,611		$	430,309
*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, 2008	2008		Year*		2008
	(In thousands)
Electric	$	---	$	---	$	---
Natural gas distribution		171,129		173,823		344,952
Construction services		91,385		4,234		95,619
Pipeline and energy services		1,159		---		1,159
Natural gas and oil production		---		---		---
Construction materials and contracting		162,025		11,980		174,005
Other		---		---		---
Total	$	425,698	$	190,037	$	615,735
*Includes purchase price adjustments that were not material related to acquisitions in a prior period.

Other amortizable intangible assets were as follows:

	March 31, 2009			March 31, 2008			December 31, 2008
	(In thousands)
Customer relationships	$	21,688		$	22,016		$	21,842
Accumulated amortization		(7,561	)		(5,243	)		(6,985	)
		14,127			16,773			14,857
Noncompete agreements		9,792			10,140			10,080
Accumulated amortization		(5,518	)		(4,035	)		(5,126	)
		4,274			6,105			4,954
Other		10,668			4,193			10,949
Accumulated amortization		(2,496	)		(1,509	)		(2,368	)
		8,172			2,684			8,581
Total	$	26,573		$	25,562		$	28,392

Amortization expense for amortizable intangible assets for the three months ended March 31, 2009 and 2008, was $1.4 million. Estimated amortization expense for amortizable intangible assets is $4.9 million in 2009, $3.9 million in 2010, $3.1 million in 2011, $3.0 million in 2012, $2.6 million in 2013 and $10.5 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, 2009, the Company had no outstanding foreign currency or interest rate hedges. The following information should be read in conjunction with Notes 1 and 7 in the Company's Notes to Consolidated Financial Statements in the 2008 Annual Report.

Cascade and Intermountain

At March 31, 2009, Cascade and Intermountain held natural gas swap agreements, with total forward notional volumes of 40.4 million MMBtu, which were not designated as hedges.

Cascade and Intermountain utilize natural gas swap agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas on their forecasted purchases of natural gas for core customers in accordance with authority granted by the IPUC, WUTC and OPUC. Core customers consist of residential, commercial and smaller industrial customers. The fair value of the derivative instrument must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability. Cascade and Intermountain apply SFAS No. 71 and record periodic changes in the fair market value of the derivative instruments on the Consolidated Balance Sheets as a regulatory asset or a regulatory liability, and settlements of these arrangements are expected to be recovered through the purchased gas cost adjustment mechanism. Gains and losses on the settlements of these derivative instruments are recorded as a component of purchased natural gas sold on the Consolidated Statements of Income as they are recovered through the purchased gas cost adjustment mechanism. Under the terms of these arrangements, Cascade and Intermountain will either pay or receive settlement payments based on the difference between the fixed strike price and the monthly index price applicable to each contract. For the three months ended March 31, 2009, Cascade and Intermountain recorded the changes in the fair market value of the derivative instruments of $6.8 million as regulatory assets.

Certain of Cascade's derivative instruments contain credit-risk-related contingent features that permit the counterparties to require collateralization if Cascade's derivative liability positions exceed certain dollar thresholds. The dollar thresholds in certain of Cascade's agreements are determined and may fluctuate based on Cascade's credit rating on its debt. In addition, Cascade's and Intermountain's derivative instruments contain cross-default provisions that state if the entity fails to make payment with respect to certain of its indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of such entity's derivative instruments in liability positions. The aggregate fair value of Cascade and Intermountain's derivative instruments with credit-risk-related contingent features that are in a liability position at March 31, 2009, was $96.7 million. Cascade has posted collateral of $22.0 million associated with certain of these contracts. The aggregate fair value of additional assets that would have been required to be posted as collateral and the 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, 2009, was $74.7 million.

Fidelity

At March 31, 2009, Fidelity held natural gas swaps, a basis swap and collar agreements, all of which were designated as cash flow hedging instruments with total forward notional volumes of 22.3 million MMBtu. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas on its forecasted sales of natural gas production.

The fair value of the hedging 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 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 production is generally based on market prices.

For the three months ended March 31, 2009 and 2008, 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 and the gains and losses reclassified from accumulated other comprehensive income into earnings, see Note 10.

As of March 31, 2009, 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 $56.9 million (after tax) will be reclassified from accumulated other comprehensive income into earnings, subject to changes in natural gas 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, 2009, was $788,000. 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, 2009, was $788,000.

The location and fair value of all of the Company’s derivative instruments in the Consolidated Balance Sheets as of March 31, 2009, were as follows:

	Asset Derivatives			Liability Derivatives
	Location on Consolidated Balance Sheets	Fair Value		Location on Consolidated Balance Sheets	Fair Value
	(in thousands)
Commodity derivatives designated as hedges:
	Commodity derivative instruments	$	92,577	Commodity derivative instruments	$	788
	Other assets - noncurrent		5,147	Other liabilities – noncurrent		---
Total derivatives designated as hedges			97,724			788

Commodity derivatives not designated as hedges:
	Commodity derivative instruments		---	Commodity derivative instruments		57,274
	Other assets - noncurrent		---	Other liabilities – noncurrent		17,401
Total derivatives not designated as hedges			---			74,675
Total derivatives		$	97,724		$	75,463
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.

14. Fair value measurements

The Company elected to measure its investments in certain fixed-income and equity securities at fair value in accordance with SFAS No. 159. These investments had previously been accounted for as available-for-sale investments in accordance with SFAS No. 115. The Company anticipates using these investments to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $25.8 million, $30.4 million and $27.7 million, as of March 31, 2009 and 2008, and December 31, 2008, respectively, are classified as Investments on the Consolidated Balance Sheets. The decrease in the fair value of these investments for the three months ended March 31, 2009 and 2008, was $1.9 million (before tax) and $2.2 million (before tax), respectively, which is considered part of the cost of the plan, and 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, 2009 and 2008, and December 31, 2008, are accounted for as available-for-sale in accordance with SFAS No. 115 and are recorded at fair value. The fair value of the auction rate securities approximate cost and, as a result, there are no accumulated unrealized gains or losses recorded in accumulated other comprehensive income on the Consolidated Balance Sheets related to these investments.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The Company’s assets and liabilities measured at fair value on a recurring basis are as follows:

	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 March 31, 2008, 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, 2008
	(In thousands)
Assets:
Available-for-sale securities	$	30,421	$	11,400	$	---	$	---	$	41,821
Commodity derivative instruments - current		---		31,604		---		---		31,604
Commodity derivative instruments - noncurrent		---		6,566		---		---		6,566
Total assets measured at fair value	$	30,421	$	49,570	$	---	$	---	$	79,991
Liabilities:
Commodity derivative instruments - current	$	---	$	42,016	$	---	$	---	$	42,016
Commodity derivative instruments - noncurrent		---		13,837		---		---		13,837
Total liabilities measured at fair value	$	---	$	55,853	$	---	$	---	$	55,853

	Fair Value Measurements at December 31, 2008, 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, 2008
	(In thousands)
Assets:
Available-for-sale securities	$	27,725	$	11,400	$	---	$	---	$	39,125
Commodity derivative instruments - current		---		78,164		---		---		78,164
Commodity derivative instruments - noncurrent		---		3,222		---		---		3,222
Total assets measured at fair value	$	27,725	$	92,786	$	---	$	---	$	120,511
Liabilities:
Commodity derivative instruments - current	$	---	$	67,629	$	---	$	11,100	$	56,529
Commodity derivative instruments - noncurrent		---		23,534		---		---		23,534
Total liabilities measured at fair value	$	---	$	91,163	$	---	$	11,100	$	80,063

The estimated fair value of the Company’s Level 1 available-for-sale securities 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 available-for-sale securities is based on comparable market transactions. The estimated fair value of the Company’s commodity

derivative instruments reflects the estimated amounts the Company would receive or pay to terminate the contracts at the reporting date. These values are based upon, among other things, futures prices, volatility and time to maturity.

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 protection systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment.

The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides energy-related management services.

The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent regions of the United States and in and around the Gulf of Mexico.

The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services. This segment operates in the central, southern and western United States and Alaska and Hawaii.

The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the 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 2008 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, 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	)


			Inter-
	External		segment			Earnings
Three Months	Operating		Operating			on Common
Ended March 31, 2008	Revenues		Revenues			Stock
	(In thousands)
Electric	$	52,256	$	---		$	5,480
Natural gas distribution		362,146		---			16,386
Pipeline and energy services		102,861		30,932			7,154
		517,263		30,932			29,020
Construction services		307,386		44			10,814
Natural gas and oil production		95,981		73,606			50,646
Construction materials and contracting		201,277		---			(21,097	)
Other		---		2,636			1,497
		604,644		76,286			41,860
Intersegment eliminations		---		(107,218	)		---
Total	$	1,121,907	$	---		$	70,880

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,	2009			2008			2009			2008
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	2,097		$	2,629		$	440		$	490
Interest cost		5,529			5,124			1,195			1,185
Expected return on assets		(6,857	)		(6,036	)		(1,273	)		(1,697	)
Amortization of prior service cost (credit)		151			166			(568	)		(689	)
Amortization net actuarial loss		174			242			185			115
Amortization of net transition obligation		---			---			438			531
Net periodic benefit cost, including amount capitalized		1,094			2,125			417			(65	)
Less amount capitalized		281			179			46			65
Net periodic benefit cost	$	813		$	1,946		$	371		$	(130	)

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, 2009 and 2008, was $2.1 million and $2.0 million, respectively.

17. Regulatory matters and revenues subject to refund

In August 2008, Montana-Dakota filed an application with the WYPSC for an electric rate increase. Montana-Dakota requested a total increase of $757,000 annually or approximately 4 percent above current rates. On April 6, 2009, Montana-Dakota and the Office of Consumer Advocate filed a Stipulation with the WYPSC, agreeing to an increase of $425,000 annually or 2.3 percent with rates to be effective May 1, 2009. On April 15, 2009, the WYPSC approved the Stipulation with rates to be effective May 1, 2009.

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. Hearings on the application were held in June 2007. In September 2007, Montana-Dakota informed the NDPSC that certain of the other participants in the project had withdrawn and it was considering the impact of these withdrawals on the project and its options. Supplemental hearings before the NDPSC were held in late April 2008 regarding possible plant configuration changes as a result of the participant withdrawals and updated supporting modeling. 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. In September 2008, the intervenors in the

proceeding appealed the NDPSC order to the North Dakota District Court. The intervenors brief was filed January 21, 2009, and Montana-Dakota filed its response brief on February 17, 2009.

In December 1999, Williston Basin filed a general natural gas rate change application with the FERC. Williston Basin began collecting such rates effective June 1, 2000, subject to refund. Currently, the only remaining issue outstanding related to this rate change application is in regard to certain service restrictions. In May 2004, the FERC remanded this issue to an ALJ for resolution. In November 2005, the FERC issued an Order on Initial Decision affirming the ALJ's Initial Decision regarding certain service and annual demand quantity restrictions. In April 2006, the FERC issued an Order on Rehearing denying Williston Basin's Request for Rehearing of the FERC's Order on Initial Decision. In April 2006, Williston Basin appealed to the D.C. Appeals Court certain issues addressed by the FERC's Order on Initial Decision and its Order on Rehearing. In March 2008, the D.C. Appeals Court issued its opinion in this matter concerning the service restrictions. The D.C. Appeals Court found that the FERC was correct to decide the case under the “just and reasonable” standard of section 5(a) of the Natural Gas Act; however, it remanded the case back to the FERC as flaws in the FERC’s reasoning render its orders arbitrary and capricious. In December 2008, the FERC issued its Order Requesting Data and Comment on this matter. Williston Basin and Northern States Power Company provided responses to FERC’s requests in January 2009. In addition, initial comments addressing specific issues identified by the FERC were filed on February 17, 2009, and reply comments were filed on March 9, 2009. The initial and reply comments should contain all the arguments and supporting evidence the parties determine they need to provide to update the record with regard to the issue under remand.

18. Contingencies

Litigation

Coalbed Natural Gas Operations Fidelity is a party to and/or certain of its operations are or have been the subject of more than a half dozen lawsuits in Montana and Wyoming related to administrative regulation of water produced in connection with Fidelity’s CBNG development in the Powder River Basin. These cases involve legal challenges to the issuance of discharge permits, as well as challenges to the State of Wyoming’s CBNG water permitting procedures.

In April 2006, the Northern Cheyenne Tribe filed a complaint in Montana State District Court against the Montana DEQ seeking to set aside 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. On January 12, 2009, the Montana State District Court decided the case in favor of Fidelity and the

Montana DEQ in all respects, denying the motions of the Northern Cheyenne Tribe, TRWUA, and NPRC, and granting the cross-motions of the Montana DEQ and Fidelity in their entirety. As a result, Fidelity may continue to utilize its direct discharge and treatment permits. The NPRC, the TRWUA and the Northern Cheyenne Tribe appealed the decision to the Montana Supreme Court on March 9, 11, and 13, 2009, respectively.

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.

The Powder River Basin Resource Council is funding litigation, filed in Wyoming State District Court in June 2007, on behalf of two surface owners against the Wyoming State Engineer and the Wyoming Board of Control. The plaintiffs seek a declaratory judgment that current ground water permitting practices are unlawful; that the state is required to adopt rules and procedures to ensure that coalbed groundwater is managed in accordance with the Wyoming Constitution and other laws; and that would prohibit the Wyoming State Engineer from issuing permits to produce coalbed groundwater and permits to store coalbed groundwater in reservoirs until the Wyoming State Engineer adopts such rules. The Wyoming State District Court granted the Petroleum Association of Wyoming’s motion to intervene provided that the defendants motion to dismiss was denied. Fidelity is partly funding the intervention. In May 2008, the Wyoming State District Court dismissed the case. The plaintiffs appealed to the Wyoming Supreme Court in June 2008. Fidelity’s CBNG operations in Wyoming could be materially adversely affected if the plaintiffs are successful in this lawsuit.

Fidelity will continue to vigorously defend its interests in all CBNG-related litigation in which it is involved, including the proceedings challenging its water permits. In those cases where damage claims have been asserted, Fidelity is unable to quantify the damages sought and will be unable to do so until after the completion of discovery. 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. On March 31, 2009, the District Court granted the motion of the co-owners to dismiss the complaint. The Sierra Club has filed a motion requesting the District Court to reconsider its ruling on a section of the order dismissing the complaint.

Natural Gas Storage Based on reservoir and well pressure data and other information, Williston Basin believes that reservoir pressure (and therefore the amount of gas) in the EBSR, one of its natural gas storage reservoirs, has decreased as a result of Howell and Anadarko’s drilling and production activities in areas within and near the boundaries of the EBSR. As of March 31, 2009, Williston Basin estimated that between 11.0 and 11.5 Bcf of storage gas had been diverted from the EBSR as a result of Howell and Anadarko’s drilling and production.

Williston Basin filed suit in Montana Federal District Court in January 2006, seeking to recover unspecified damages from Howell and Anadarko, and to enjoin Howell and Anadarko’s present and future production from specified wells in and near the EBSR. The Montana Federal District Court entered an Order in July 2006, dismissing the case for lack of subject matter jurisdiction. Williston Basin appealed and in May 2008, the Ninth Circuit affirmed the Montana Federal District Court’s decision.

In related litigation, Howell filed suit in Wyoming State District Court against Williston Basin in February 2006 asserting that it is entitled to produce any gas that might escape from the EBSR. In August 2006, Williston Basin moved for a preliminary injunction to halt Howell and Anadarko’s production in and near the EBSR. The Wyoming State District Court denied Williston Basin’s motion in July 2007. In December 2007, motions were argued to a court appointed special master concerning the application of certain legal principles to the production of Williston Basin’s storage gas, including gas residing outside the certificated boundaries of the EBSR, by Howell and Anadarko. In March 2008, the special master issued recommendations to the Wyoming State District Court. The special master recommended that the Wyoming State District Court adopt a ruling that gas injected into an underground reservoir belongs to the injector and the injector does not lose title to that gas unless the gas escapes or migrates from the reservoir because it was not well defined or well maintained or if the injector is unable to identify such injected gas because it has been commingled with native gas. The special master also recommended that the Wyoming State District Court adopt a ruling that generally would allow Howell and Anadarko to produce native gas residing inside or outside the certificated boundaries of the EBSR from its wells completed outside the certificated boundaries. The special master recognized that there are other issues yet to be developed that may be determinative of whether Howell and Anadarko may produce native or injected gas, or both. In July 2008, the Wyoming State District Court adopted the special master’s report. In July 2008, Williston Basin filed a petition requesting the Wyoming Supreme Court to review a ruling by the Wyoming State District Court that the Natural Gas Act does not preempt the state law that permits an oil and gas producer to take gas that has been dedicated for use in a federally certificated gas storage reservoir. In August 2008, the Wyoming Supreme Court denied the petition. The Wyoming State District Court has scheduled the case for trial beginning January 19, 2010.

In a related proceeding, the FERC issued an order in July 2008, in response to a petition filed by Williston Basin in April 2008, declaring that the certification of a storage facility under the Natural Gas Act conveys to the certificate holder the right to acquire native gas within the certificated boundaries of the storage facility. The FERC also concurred that state law precluding the certificate holder from acquiring the right to native gas would be preempted by federal law.

As previously noted, Williston Basin estimates that as of March 31, 2009, Howell and Anadarko had diverted between 11.0 and 11.5 Bcf from the EBSR. Although all of Howell’s wells are shut in and no longer producing gas, Williston Basin believes that its gas losses from the EBSR will continue until pressures in the various interconnected geologic formations equalize. Williston Basin continues to monitor and analyze the situation. At trial, Williston Basin will seek recovery based on the amount of gas that has been and continues to be diverted as well as on the amount of gas that must be recovered as a result of the equalization of the pressures of various interconnected geological formations.

Expert reports were filed with the Wyoming State District Court in January 2008. Supplemental and rebuttal expert reports were filed in September 2008. Williston Basin’s experts are of the opinion that all of the gas produced by Howell and Anadarko is Williston Basin's gas and will have to be replaced. Williston Basin’s experts estimated that the replacement cost of the gas produced by Howell and Anadarko through July 2008 would be approximately $103 million if injection was completed by the end of the 2010 injection season. Williston Basin's experts also estimated that Williston Basin will have expended $6.3 million to mitigate the damages that Williston Basin suffered during the period of Howell and Anadarko’s production if the replacement gas is injected by the end of the 2010 injection season. Williston Basin believes that its experts’ opinions are based on sound law, economics, reservoir engineering, geology and geochemistry. Changes in natural gas prices may affect the replacement cost of the gas produced by Howell and Anadarko.

The expert reports filed by Howell and Anadarko claim that storage gas owned by Williston Basin has migrated outside the EBSR into areas in which Howell and Anadarko have oil and gas rights. They theorize that Williston Basin is accountable to Howell and Anadarko for the migration of such gas. Although Howell and Anadarko have not specified the amount of damages they seek to recover, Williston Basin believes Howell and Anadarko’s proposed methodology for valuing their alleged injury, if any, is flawed, inconsistent and lacking in factual and legal support. Williston Basin intends to vigorously defend its rights and interests in these proceedings, to assess further avenues for recovery through the regulatory process at the FERC, and to pursue the recovery of any and all economic losses it may have suffered. Williston Basin cannot predict the ultimate outcome of these proceedings.

In light of the actions of Howell and Anadarko, Williston Basin installed temporary compression at the site in 2006 in order to maintain deliverability into the transmission system. Williston Basin leased working gas for the 2007 – 2008 and 2008 – 2009 heating seasons to supplement its cushion gas. While installation of the additional compression and leasing working gas provide temporary relief, Williston Basin believes that the adverse physical and operational effects occasioned by the past and potential future loss of storage gas could threaten the operation and viability of the EBSR, impair Williston Basin’s ability to comply with the EBSR certificated operating requirements mandated by the FERC and

adversely affect Williston Basin’s ability to meet its contractual storage and transportation service commitments to customers. In another effort to protect the viability of the EBSR, Williston Basin, in April 2008, filed an application with the FERC to expand the boundaries of the EBSR. The proposed expansion includes the areas from which Howell and Anadarko were producing. On April 16, 2009, the FERC approved Williston Basin’s application.

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 limitation in connection with the LWG’s potential claim for contribution to the costs of the remedial investigation and feasibility study. By letter of March 2, 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. It is not known at this time what share of the cleanup costs will actually be borne by Cascade. Additional ecological risk assessment conducted by Cascade and other PRPs is expected to be completed in 2009. The results of the assessment may affect the selection and implementation of a cleanup alternative.

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 that will require further investigation and cleanup. A supplemental investigation is currently being conducted to better characterize the extent of the contamination. The supplemental investigation is expected to be completed in 2009. The data from the preliminary investigation indicates other current and former owners of properties and businesses in the vicinity of the site may also be responsible for the contamination. There is currently not enough information to estimate the potential liability associated with this claim.

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. The guarantee, which has no fixed maximum, expires when CEM has completed its obligations under the construction contract. The warranty period associated with this project will expire one year after the date of substantial completion of construction. CEM declared substantial

completion of the plant on February 16, 2009, and on February 27, 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. LPP did not quantify the amount of indemnification being sought, which could be material. The Company believes the indemnification claims are without merit and intends to vigorously defend against such claims.

In addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas price swap and collar agreement obligations. There is no fixed maximum amount guaranteed in relation to the natural gas price swap and collar agreements as the amount of the obligation is dependent upon natural gas commodity prices. The amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the natural gas price swap and collar agreements at March 31, 2009, expire in the years ranging from 2009 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. There was no amount outstanding by Fidelity at March 31, 2009. 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, 2009, the fixed maximum amounts guaranteed under these agreements aggregated $179.6 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $125.1 million in 2009; $20.5 million in 2010; $24.5 million in 2011; $2.3 million in 2012; $800,000 in 2013; $1.2 million in 2018; $1.2 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 $1.1 million and was reflected on the Consolidated Balance Sheet at March 31, 2009. 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, 2009, the fixed maximum amounts guaranteed under these letters of credit, aggregated $37.0 million. In 2009 and 2010, $30.0 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, 2009.

Fidelity and WBI Holdings have outstanding guarantees to Williston Basin. These guarantees are related to natural gas transportation and storage agreements that guarantee the performance of Prairielands. At March 31, 2009, the fixed maximum amounts guaranteed under these agreements aggregated $24.0 million. Scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $20.0 million in 2009 and

$4.0 million in 2011. In the event of Prairielands’ default in its payment obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee. The amount outstanding by Prairielands under the above guarantees was $1.7 million, which was not reflected on the Consolidated Balance Sheet at March 31, 2009, because these intercompany transactions are 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, 2009.

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, 2009, approximately $592 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

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 securities and the Company’s equity securities. Although volatility and disruptions in the capital markets have increased significantly, the Company continues to issue commercial paper to meet its current needs. If access to the commercial paper markets were to become unavailable, the Company may need to borrow under its credit agreements. At that time, accessing the long-term debt market may be more challenging and result in significantly higher interest rates, which have resulted in an increased focus on the use of operating cash flows for capital expenditure purposes. 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 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 significant competition from other energy providers, including rural electric cooperatives. The construction of electric generating facilities and transmission lines are subject to increasing cost and lead time, as well as extensive permitting procedures.

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 and managing through downturns in the economy 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 and transmission facilities; 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; ongoing litigation; 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 in new areas to further diversify 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 and auxiliary equipment, and industry-related field services, all primarily in a higher price environment; inflationary pressure on development and operating costs; 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 2008 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,
	2009			2008
(Dollars in millions, where applicable)
Electric	$	5.1		$	5.5
Natural gas distribution		23.9			16.4
Construction services		8.6			10.8
Pipeline and energy services		6.4			7.2
Natural gas and oil production		(373.3	)		50.6
Construction materials and contracting		(15.7	)		(21.1	)
Other		1.0			1.5
Earnings (loss) on common stock	$	(344.0	)	$	70.9
Earnings (loss) per common share – basic	$	(1.87	)	$	.39
Earnings (loss) per common share – diluted	$	(1.87	)	$	.39
Return on average common equity for the 12 months ended		(4.5	)%		18.9	%

Three Months Ended March 31, 2009 and 2008 Consolidated earnings for the quarter ended March 31, 2009, decreased $414.9 million from the comparable prior period largely due to:

A $384.4 million after-tax noncash write-down of natural gas and oil properties as well as lower average realized natural gas and oil prices and decreased natural gas production

Lower construction workloads at the construction services business

Partially offsetting these decreases were increased earnings at the natural gas distribution business largely due to the October 1, 2008, acquisition of Intermountain and 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,
	2009		2008
(Dollars in millions, where applicable)
Operating revenues	$	51.2	$	52.3
Operating expenses:
Fuel and purchased power		18.7		18.8
Operation and maintenance		15.6		15.0
Depreciation, depletion and amortization		6.1		6.0
Taxes, other than income		2.4		2.3
		42.8		42.1
Operating income		8.4		10.2
Earnings	$	5.1	$	5.5
Retail sales (million kWh)		724.9		707.8
Sales for resale (million kWh)		9.6		48.4
Average cost of fuel and purchased power per kWh	$	.024	$	.023

Three Months Ended March 31, 2009 and 2008 Electric earnings decreased $400,000 (8 percent) due to:

Decreased sales for resale margins due to lower average rates of 42 percent and decreased volumes of 80 percent due to decreased plant generation, the result of lower rates

Higher operation and maintenance expense of $300,000 (after-tax), largely payroll-related costs

Partially offsetting these decreases were higher electric retail sales margins due to increased retail sales volumes of 2 percent.

Natural Gas Distribution

	Three Months Ended
	March 31,
	2009			2008
(Dollars in millions, where applicable)
Operating revenues	$	483.2		$	362.1
Operating expenses:
Purchased natural gas sold		365.9			282.6
Operation and maintenance		38.1			27.0
Depreciation, depletion and amortization		10.7			7.2
Taxes, other than income		22.9			14.5
		437.6			331.3
Operating income		45.6			30.8
Earnings	$	23.9		$	16.4
Volumes (MMdk):
Sales		43.6			31.1
Transportation		34.0			26.6
Total throughput		77.6			57.7
Degree days (% of normal)*
Montana-Dakota		103	%		101	%
Cascade		107	%		107	%
Intermountain		106	%		---
Average cost of natural gas, including transportation, per dk**	$	8.39		$	7.72
* Degree days are a measure of the daily temperature-related demand for energy for heating.
** Regulated natural gas sales only.
Note: Intermountain was acquired on October 1, 2008

Three Months Ended March 31, 2009 and 2008 Earnings at the natural gas distribution business increased $7.5 million (46 percent) due to earnings from Intermountain, which was acquired on October 1, 2008.

Construction Services

	Three Months Ended
	March 31,
	2009		2008
	(In millions)
Operating revenues	$	244.8	$	307.4
Operating expenses:
Operation and maintenance		217.3		274.0
Depreciation, depletion and amortization		3.4		3.4
Taxes, other than income		9.5		11.8
		230.2		289.2
Operating income		14.6		18.2
Earnings	$	8.6	$	10.8

Three Months Ended March 31, 2009 and 2008 Construction services earnings decreased $2.2 million (20 percent) due to lower construction workloads, largely in the Southwest region. Partially offsetting this decrease were higher construction margins in certain regions, as well as lower general and administrative expense of $700,000 (after tax), largely payroll-related.

Pipeline and Energy Services

	Three Months Ended
	March 31,
	2009		2008
	(Dollars in millions)
Operating revenues	$	85.1	$	133.8
Operating expenses:
Purchased natural gas sold		46.1		94.1
Operation and maintenance		17.6		17.6
Depreciation, depletion and amortization		6.2		5.6
Taxes, other than income		2.9		2.8
		72.8		120.1
Operating income		12.3		13.7
Earnings	$	6.4	$	7.2
Transportation volumes (MMdk):
Montana-Dakota		8.3		8.3
Other		28.8		21.4
		37.1		29.7
Gathering volumes (MMdk)		24.2		24.0

Three Months Ended March 31, 2009 and 2008 Pipeline and energy services earnings decreased $800,000 (11 percent) due to:

Lower storage services revenues of $1.6 million (after tax), resulting from lower storage balances and withdrawals as well as lower rates

Higher operation and maintenance expense largely related to the natural gas storage litigation and payroll-related costs. For further information regarding natural gas storage litigation, see Note 18. The above table also reflects lower operation and maintenance expense and revenues related to energy-related service projects.

Partially offsetting the earnings decrease were:

Increased transportation volumes of $1.4 million (after tax), largely transportation to storage and off-system transportation volumes

Higher gathering rates of $500,000 (after tax)

Results also reflect lower operating revenues, as well as lower purchased natural gas sold related to lower natural gas prices.

Natural Gas and Oil Production

	Three Months Ended
	March 31,
	2009			2008
(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	81.7		$	117.5
Oil		24.4			52.1
		106.1			169.6
Operating expenses:
Operation and maintenance:
Lease operating costs		20.0			18.3
Gathering and transportation		6.1			5.7
Other		10.3			8.8
Depreciation, depletion and amortization		42.6			39.3
Taxes, other than income:
Production and property taxes		7.5			13.7
Other		.2			.2
Write-down of natural gas and oil properties		620.0			---
		706.7			86.0
Operating income (loss)		(600.6	)		83.6
Earnings (loss)	$	(373.3	)	$	50.6
Production:
Natural gas (MMcf)		15,401			16,561
Oil (MBbls)		742			621
Total Production (MMcf equivalent)		19,852			20,288
Average realized prices (including hedges):
Natural gas (per Mcf)	$	5.31		$	7.10
Oil (per Bbl)	$	32.86		$	83.79
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	3.63		$	6.91
Oil (per Bbl)	$	32.86		$	84.35
Average depreciation, depletion and amortization rate, per equivalent Mcf	$	2.07		$	1.88
Production costs, including taxes, per net equivalent Mcf:
Lease operating costs	$	1.00		$	.90
Gathering and transportation		.31			.28
Production and property taxes		.38			.67
	$	1.69		$	1.85

Three Months Ended March 31, 2009 and 2008 Natural gas and oil production experienced a decrease in earnings of $423.9 million due to:

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

Lower average realized oil prices of 61 percent and lower average realized natural gas prices of 25 percent

Decreased natural gas production of 7 percent, largely related to normal production declines at certain properties

Higher depreciation, depletion and amortization expense of $2.0 million (after tax), due to higher depletion rates, partially offset by decreased combined production

Increased lease operating costs of $1.0 million (after tax)

Partially offsetting these decreases were:

Lower production taxes of $3.8 million (after tax) associated largely with lower average prices

Increased oil production of 19 percent, largely related to drilling activity in the Bakken area as well as higher production from the East Texas properties

Construction Materials and Contracting

	Three Months Ended
	March 31,
	2009			2008
	(Dollars in millions)
Operating revenues	$	183.5		$	201.3
Operating expenses:
Operation and maintenance		172.4			195.2
Depreciation, depletion and amortization		23.9			25.4
Taxes, other than income		7.5			9.1
		203.8			229.7
Operating loss		(20.3	)		(28.4	)
Loss	$	(15.7	)	$	(21.1	)
Sales (000's):
Aggregates (tons)		3,185			4,241
Asphalt (tons)		188			196
Ready-mixed concrete (cubic yards)		509			611

Three Months Ended March 31, 2009 and 2008 Construction materials and contracting experienced a seasonal first quarter loss of $15.7 million. The loss decreased by $5.4 million (26 percent) from the $21.1 million loss in 2008. The decreased loss was due to:

Lower selling, general and administrative expense (largely lower payroll and benefit-related costs) as well as lower maintenance costs, totaling $5.7 million (after tax)

Higher construction workloads and margins

Lower depreciation, depletion and amortization expense of $900,000 (after tax), largely the result of lower property, plant and equipment balances

Partially offsetting the decreased loss were lower product volumes as a result of the continuing economic downturn.

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,
	2009		2008
	(In millions)
Other:
Operating revenues	$	2.7	$	2.6
Operation and maintenance		3.2		2.7
Depreciation, depletion and amortization		.3		.3
Taxes, other than income		.1		.1
Intersegment transactions:
Operating revenues	$	62.6	$	107.2
Purchased natural gas sold		55.5		100.1
Operation and maintenance		7.1		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 2008 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 2009, diluted, are projected in the range of $1.05 to $1.30 excluding a $384.4 million, or $2.09 per common share after-tax noncash charge related to low natural gas and oil prices. (Including the noncash charge, guidance for 2009 is a loss of $.79 to $1.04 per common share.)

·	The Company expects the percentage of 2009 earnings per common share by quarter, excluding the noncash charge, to be in the following approximate ranges:

Second quarter – 15 percent to 20 percent

Third quarter – 35 percent to 40 percent

Fourth quarter – 20 percent to 25 percent

·	While 2009 earnings per share are projected to decline compared to 2008 earnings, long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent.

Electric

In April 2009, the Company purchased a 25 MW ownership interest in the Wygen III power generation facility which is under construction near Gillette, Wyoming. This rate-based generation will replace a portion of the purchased power for the Wyoming system. The plant is expected to be online June 2010.

·	The Company plans to develop 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 third quarter 2010.

The Company is analyzing potential projects for accommodating load growth and replacing an expired purchased power contract with company-owned generation, which will add to base-load capacity. The Company is a participant in the Big Stone Station II project. The MNPUC unanimously voted to grant a transmission certificate of need and a route permit for the project with conditions. The Company anticipates owning at least 116 MW of this plant, which is projected to be completed in 2015. In the event the participants decide not to proceed with construction, the Company is reviewing alternatives, including the construction of certain natural gas-fired combustion generation.

Construction services

·	The Company anticipates margins in 2009 to be comparable to 2008.

·	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, 2009, was approximately $557 million, compared to $752 million at March 31, 2008 and $604 million at December 31, 2008.

·	This business continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.

Pipeline and energy services

An incremental expansion to the Grasslands Pipeline of 75,000 Mcf per day is in process with a projected in-service date of August 2009. Through additional compression, the firm capacity of the Grasslands Pipeline will reach ultimate full capacity of 213,000 Mcf per day, an increase from the current firm capacity of 138,000 Mcf per day.

·	In 2009, total gathering and transportation throughput is expected to be slightly higher than 2008 record levels.

·	The Company continues to pursue expansion of facilities and services offered to customers.

Natural gas and oil production

·	As the result of lower natural gas and oil prices, the Company has reduced its 2009 capital expenditures for this segment to approximately $170 million. At this level of investment, the Company expects its combined natural gas and oil production to be 7 percent to 10 percent lower than 2008 levels.

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

	Index*	Price Per Mcf
	Ventura	$3.50 to $4.00
	NYMEX	$3.75 to $4.25
	CIG	$2.50 to $3.00
	* 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 $48 to $53 per barrel.


·	For the last nine months of 2009, the Company has hedged approximately 40 percent to 45 percent of its estimated natural gas production and 25 percent to 30 percent of its estimated oil production. For 2010 and 2011, the Company has hedged less than 5 percent of its estimated natural gas production. The hedges that are in place as of April 30, 2009, are summarized in the following chart:

Commodity	Type	Index*	Period Outstanding	Forward Notional Volume (MMBtu/Bbl)	Price (Per MMBtu/Bbl)
Natural Gas	Swap	HSC	4/09 - 12/09	1,870,000	$8.16
Natural Gas	Collar	Ventura	4/09 - 12/09	1,100,000	$7.90-$8.54
Natural Gas	Collar	Ventura	4/09 - 12/09	3,300,000	$8.25-$8.92
Natural Gas	Swap	Ventura	4/09 - 12/09	2,750,000	$9.02
Natural Gas	Collar	CIG	4/09 - 12/09	2,750,000	$6.50-$7.20
Natural Gas	Swap	CIG	4/09 - 12/09	687,500	$7.27
Natural Gas	Collar	NYMEX	4/09 - 12/09	1,375,000	$8.75-$10.15
Natural Gas	Swap	Ventura	4/09 - 12/09	2,750,000	$9.20
Natural Gas	Collar	NYMEX	4/09 - 12/09	2,750,000	$11.00-$12.78
Natural Gas	Basis	NYMEX to Ventura	4/09 - 12/09	2,750,000	$0.61
Natural Gas	Swap	HSC	1/10 - 12/10	1,606,000	$8.08
Natural Gas	Swap	HSC	1/11 - 12/11	1,350,500	$8.00
Crude Oil	Swap	NYMEX	5/09 - 12/09	367,500	$57.02
Crude Oil	Collar	NYMEX	5/09 - 12/09	245,000	$54.00-$60.00
* 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.

Construction materials and contracting

The economic slowdown and substantially higher energy prices adversely impacted operations in 2008. Although the Company predicts that this economic slowdown will continue in 2009, it is expected that earnings will be higher than 2008 primarily the result of cost reduction measures put in place during 2008 and substantially lower diesel costs expected in 2009 compared to 2008.

·	The Company continues its strong emphasis on cost containment throughout the organization. In addition, the Company has strong market share in its markets and is well positioned to take advantage of government stimulus spending on transportation infrastructure.

Work backlog as of March 31, 2009, was approximately $574 million, compared to $577 million at March 31, 2008 and $453 million at December 31, 2008. The backlog includes several public works projects. Although public project margins tend to be somewhat lower than private construction-related work, the Company anticipates significant contributions to revenue from an increase in public works volume.

·	As the country’s 8th largest aggregate producer, the Company will continue to strategically manage its 1.1 billion tons of aggregate reserves in its markets.

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 2008 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2008 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 2009 increased $105.3 million from the comparable 2008 period. Lower working capital requirements of $154.8 million, including lower receivables and lower natural gas costs recoverable through rate adjustments, were partially offset by lower income before depreciation, depletion and amortization and before the after-tax noncash write-down of natural gas and oil properties.

Investing activities Cash flows used in investing activities in the first three months of 2009 decreased $182.8 million from the comparable period in 2008. The decrease in cash used in investing activities largely results from less cash used for acquisitions of $245.6 million, primarily at the natural gas and oil production business, and decreased cash provided from the sale of investments.

Financing activities Cash flows provided by financing activities in the first three months of 2009 decreased $260.7 million from the comparable period in 2008 due to lower issuance of long-term debt and higher repayment of long-term debt and short-term borrowings.

Defined benefit pension plans

There were no material changes to the Company’s qualified noncontributory defined benefit pension plans from those reported in the 2008 Annual Report. For further information, see Note 16 and Part II, Item 7 in the 2008 Annual Report.

Capital expenditures

Net capital expenditures for the first three months of 2009 were $129.5 million. Estimated capital expenditures for 2009 have been reduced to approximately $385 million, primarily as a result of low natural gas and oil prices. The decrease, as compared to estimated capital expenditures of $602 million, as reported in Part II, Item 7 of the Company’s 2008 Annual Report, is largely related to lower expenditures at the natural gas and oil production business and electric and natural gas distribution businesses. Estimated capital expenditures include:

System upgrades

Routine replacements

Service extensions

Routine equipment maintenance and replacements

Buildings, land and building improvements

Pipeline and gathering projects

Further enhancement of natural gas and oil production and reserve growth

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 2009 capital expenditures referred to previously. The Company has increased its focus on the use of operating cash flows to fund capital expenditures. In addition, the Company has capabilities to fund capital expenditures through various sources, including 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, all of which the Company and its subsidiaries were in compliance with at March 31, 2009. 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.

MDU Resources Group, Inc. The Company has a revolving credit agreement with various banks totaling $125 million (with provision for an increase, 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 at March 31, 2009. The credit agreement supports the Company’s $125 million commercial paper program. Although volatility in the capital markets has increased significantly, the Company continues to issue commercial paper to meet its current needs. Under the Company’s commercial paper program, $34.5 million was outstanding at March 31, 2009. 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 (supported by the credit agreement, which expires in June 2011).

The Company’s objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. A recent downgrade in the Company’s credit ratings by one of the credit rating agencies has not limited, nor is it currently expected to limit, the Company’s ability to access the capital markets, although it may experience an increase in overall interest rates with respect to its cost of borrowings. If the Company were to experience a further downgrade of its credit

ratings, it may need to borrow under its credit agreement.

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 became too expensive, which the Company does not currently anticipate, the Company would seek alternative funding.

In order to borrow under the Company’s credit agreement, the Company must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of the Company’s credit agreement, see Part II, Item 8 – Note 10, in the 2008 Annual Report.

In connection with the funding of the Intermountain acquisition, on September 26, 2008, the Company entered into a term loan agreement providing for a commitment amount of $175 million. On October 1, 2008, the Company borrowed $170 million under this agreement. The Company repaid the remaining outstanding amount under the term loan agreement in the first quarter of 2009 and the agreement expired on March 24, 2009.

There are no credit facilities that contain cross-default provisions between the Company and any of its subsidiaries.

The Company's issuance of first mortgage debt is subject to certain restrictions imposed under the terms and conditions of its Mortgage. Generally, those restrictions require the Company to fund $1.43 of unfunded property or use $1.00 of refunded bonds for each dollar of indebtedness incurred under the Mortgage and, in some cases, to certify to the trustee that annual earnings (pretax and before interest charges), as defined in the Mortgage, equal at least two times its annualized first mortgage bond interest costs. Under the more restrictive of the tests, as of March 31, 2009, the Company could have issued approximately $627 million of additional first mortgage bonds.

The Company's coverage of fixed charges including preferred dividends was 5.3 times for the 12 months ended December 31, 2008. Due to the $84.2 million and $384.4 million after-tax noncash write-downs of natural gas and oil properties in the fourth quarter of 2008 and the first quarter of 2009, respectively, earnings were insufficient by $235.0 million to cover fixed charges for the 12 months ended March 31, 2009. If the $84.2 million and $384.4 million after-tax noncash write-downs are excluded, the coverage of fixed charges including preferred dividends would have been 5.9 times for the 12 months ended March 31, 2009. Common stockholders' equity as a percent of total capitalization was 59 percent and 61 percent at March 31, 2009 and December 31, 2008, respectively.

The coverage of fixed charges including preferred dividends that excludes the effect of the after-tax noncash write-downs 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-downs excluded are not indicative of the Company’s cash flows available to meet its fixed charges obligations. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.

The Company has repurchased, and may from time to time seek to repurchase, outstanding first mortgage bonds through open market purchases or privately negotiated transactions. The Company will evaluate any such transactions in light of then existing market conditions, taking into account its liquidity and prospects for future access to capital. As of March 31, 2009, the Company had $35.5

million of first mortgage bonds outstanding, $30.0 million of which were held by the Indenture trustee for the benefit of the senior note holders. The aggregate principal amount of the Company’s outstanding first mortgage bonds, other than those held by the Indenture trustee, is $5.5 million and satisfies the lien release requirements under the Indenture. As a result, the Company may at any time, subject to satisfying certain specified conditions, require that any debt issued under its Indenture become unsecured and rank equally with all of the Company’s other unsecured and unsubordinated debt (as of March 31, 2009, the only such debt outstanding under the Indenture was $30.0 million in aggregate principal amount of the Company’s 5.98% Senior Notes due in 2033).

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 5,000,000 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 are expected to be used for corporate development purposes and other general corporate purposes. The Company has not issued any stock under the Sales Agency Financing Agreement through March 31, 2009.

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.

MDU Energy Capital, LLC MDU Energy Capital has a master shelf agreement that allows for borrowings up to $175 million. Under the terms of the master shelf agreement, $165.0 million was outstanding at March 31, 2009. MDU Energy Capital may incur additional indebtedness under the master shelf agreement until the earlier of August 14, 2010, or such time as the agreement is terminated by either of the parties thereto.

In order to borrow under its master shelf agreement, MDU Energy Capital must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of the MDU Energy Capital master shelf agreement, see Part II, Item 8 – Note 10, in the 2008 Annual Report.

Cascade Natural Gas Corporation Cascade has a revolving credit agreement with various banks totaling $50 million with certain provisions allowing for increased borrowings, up to a maximum of $75 million. The credit agreement expires on December 28, 2012, with provisions allowing for an extension of up to two years upon consent of the banks. Under the terms of the credit agreement, $25.5 million was outstanding at March 31, 2009. As of March 31, 2009, there were outstanding letters of credit, as discussed in Note 18, of which $1.9 million reduced amounts available under the credit agreement.

In order to borrow under Cascade's credit agreement, Cascade must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of Cascade's credit agreement, see Part II, Item 8 – Note 9, in the 2008 Annual Report.

Cascade's credit agreement contains cross-default provisions. For information on the cross-default provisions of this agreement, see Part II, Item 8 – Note 9, in the 2008 Annual Report.

Intermountain Gas Company Intermountain has a revolving credit agreement with various banks totaling $65 million with certain provisions allowing for increased borrowings, up to a maximum of $70 million. The credit agreement expires on August 31, 2010. Under the terms of the credit agreement, $24.0 million was outstanding at March 31, 2009.

In order to borrow under Intermountain’s credit agreement, Intermountain must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of Intermountain’s credit agreement, see Part II, Item 8 – Note 10, in the 2008 Annual Report.

Intermountain’s credit agreement contains cross-default provisions. For information on the cross-default provisions of this agreement, see Part II, Item 8 – Note 10, in the 2008 Annual Report.

Centennial Energy Holdings, Inc. Centennial has a revolving credit agreement with various banks and institutions totaling $400 million with certain provisions allowing for increased borrowings. The credit agreement supports Centennial’s $400 million commercial paper program. Although volatility in the capital markets has increased significantly, the Company continues to issue commercial paper to meet its current needs. There were no outstanding borrowings under the Centennial credit agreement at March 31, 2009. Under the Centennial commercial paper program, $197.0 million was outstanding at March 31, 2009. 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 (supported by the credit agreement). The revolving credit agreement includes a provision for an increase, at the option of Centennial on stated conditions, up to a maximum of $450 million and expires on December 13, 2012. As of March 31, 2009, Centennial had letters of credit outstanding, as discussed in Note 18, of which $27.4 million reduced amounts available under the agreement.

Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $550 million. Under the terms of the master shelf agreement, $459.0 million was outstanding at March 31, 2009. On April 15, 2009, Centennial borrowed $65.0 million under this agreement. The ability to request additional borrowings under this master shelf agreement expires on May 8, 2009. To meet potential future financing needs, Centennial may pursue other financing arrangements, including private and/or public financing.

Centennial’s objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Given its recent ratings downgrade and depending on future credit market conditions, Centennial may experience an increase in overall interest rates with respect to its cost of borrowings and may need to borrow under its committed bank lines.

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 was 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.

In order to borrow under Centennial’s credit agreement and the Centennial uncommitted long-term master shelf agreement, Centennial and certain of its subsidiaries must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of the credit agreement and the uncommitted long-term master shelf agreement, see Part II,

Item 8 – Note 10, in the 2008 Annual Report.

Certain of Centennial’s financing agreements contain cross-default provisions. For information on the cross-default provisions of these agreements, see Part II, Item 8 – Note 10, in the 2008 Annual Report.

Williston Basin Interstate Pipeline Company Williston Basin has an uncommitted long-term private shelf agreement that allows for borrowings up to $125 million. Under the terms of the private shelf agreement, $72.5 million was outstanding at March 31, 2009. The $72.5 million outstanding consists of $20.0 million of notes issued under the private shelf agreement and $52.5 million of notes issued under a master shelf agreement that expired in December 2008. The ability to request additional borrowings under this private shelf agreement expires on December 23, 2010, with certain provisions allowing for an extension to December 23, 2011.

In order to borrow under its uncommitted long-term private shelf agreement, Williston Basin must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions for the uncommitted long-term private shelf agreement, see Part II, Item 8 – Note 10, in the 2008 Annual Report.

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 2008 Annual Report.

For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2008 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 on forecasted sales of natural gas and oil production. Cascade and Intermountain utilize derivative instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas on forecasted purchases of natural gas. For more information on derivative instruments and commodity price risk, see Part II, Item 7A in the 2008 Annual Report, and Notes 10 and 13.

The following table summarizes derivative agreements entered into by Fidelity, Cascade and Intermountain as of March 31, 2009. These agreements call for Fidelity to receive fixed prices and pay variable prices, and for Cascade and Intermountain to receive variable prices and pay fixed prices.

(Forward notional volume and fair value in thousands)

	Weighted		Forward
	Average		Notional
	Fixed Price		Volume
	(Per MMBtu)		(MMBtu)		Fair Value
Fidelity
Natural gas swap agreements maturing in 2009		$8.73		8,058	$	38,873
Natural gas swap agreements maturing in 2010		$8.08		1,606	$	3,970
Natural gas swap agreements maturing in 2011		$8.00		1,351	$	2,156
Natural gas basis swap agreement maturing in 2009		$ .61		2,750	$	(788	)

Cascade
Natural gas swap agreements maturing in 2009		$7.95		11,543	$	(29,507	)
Natural gas swap agreements maturing in 2010		$8.03		8,922	$	(27,700	)
Natural gas swap agreements maturing in 2011		$8.10		2,270	$	(5,366	)

Intermountain
Natural gas swap agreements maturing in 2009		$3.43		17,683	$	(12,102	)

	Weighted
	Average		Forward
	Floor/Ceiling		Notional
	Price (Per		Volume
	MMBtu)		(MMBtu)		Fair Value
Fidelity
Natural gas collar agreements maturing in 2009		$8.52/$9.56		11,275	$	52,725
Note: The fair value of Cascade’s natural gas swap agreements is presented net of the collateral provided to the counterparties of $22.0 million.

Interest rate risk

There were no material changes to interest rate risk faced by the Company from those reported in the 2008 Annual Report. For more information, see Part II, Item 7A in the 2008 Annual Report.

At March 31, 2009 and 2008, and December 31, 2008, 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 2008 Annual Report.

At March 31, 2009 and 2008, and December 31, 2008, 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, 2009, 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 2008 Annual Report other than the risk related to economic volatility; the risk of exposure to credit risk; the risk associated with electric generation operation 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.

Economic Risks

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

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

A severe prolonged economic downturn

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

Further deterioration in capital market conditions

Turmoil in the financial services industry

Volatility in commodity prices

Terrorist attacks

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

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 issuance of a substantial amount of the Company’s common stock, whether sold pursuant to the registration statement, issued in connection with an acquisition or otherwise issued, or the perception that such an issuance could occur, may adversely affect the market price of the Company’s common stock.

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

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

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 federal and state legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions. 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 more than 70 percent of Montana-Dakota’s generating capacity. More than 90 percent of the electricity generated by Montana-Dakota is from coal-fired plants and Montana-Dakota has acquired a 25 MW ownership interest in the Wygen III coal-fired generation facility which is under construction near Gillette, Wyoming and is a participant in the coal-fired Big Stone Station II project. Montana-Dakota also owns approximately 100 MW of natural gas- and oil-fired peaking plants. Implementation of 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. 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 has been named as a defendant in, and/or certain of its operations are or have been the subject of, more than a half dozen lawsuits filed in connection with its CBNG development in the Powder River Basin in Montana and Wyoming. If the plaintiffs are successful in these 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. 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, 2009 and March 31, 2009, the Company issued 176,851 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, 2009	---
February 1 through February 28, 2009	45,017	$18.61
March 1 through March 31, 2009	181	$16.66
Total	45,198

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

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The Company’s Annual Meeting of Stockholders was held on April 28, 2009. Two proposals were submitted to stockholders as described in the Company’s Proxy Statement dated March 10, 2009, and were voted upon and approved by stockholders at the meeting. The table below briefly describes the proposals and the results of the stockholder votes.

	Shares	Shares		Broker
	For	Against	Abstentions	Non-Votes
Proposal to elect eight directors: For terms expiring in 2010 --
Thomas Everist	157,173,205	4,806,213	1,159,707	---
Karen B. Fagg	157,328,455	4,794,747	1,015,923	---
A. Bart Holaday	159,996,954	2,022,352	1,119,819	---
Thomas C. Knudson	158,946,733	3,025,168	1,167,224	---
Richard H. Lewis	157,282,130	4,780,836	1,076,159	---
Patricia L. Moss	154,609,345	7,415,316	1,114,464	---
Harry J. Pearce	157,537,967	4,514,189	1,086,969	---
Sister Thomas Welder, O.S.B.	145,234,720	16,862,279	1,042,126	---

Proposal to ratify the appointment of Deloitte & Touche LLP as the Company’s independent auditors for 2009	160,798,072	1,491,358	849,695	---

Directors whose terms of office continued were Terry D. Hildestad, Dennis W. Johnson, John L. Olson and John K. Wilson.

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 6, 2009	BY:	/s/ Vernon A. Raile
		Vernon A. Raile
		Executive Vice President, Treasurer
		and Chief Financial Officer


	BY:	/s/ Doran N. Schwartz
		Doran N. Schwartz
		Vice President and Chief Accounting Officer

EXHIBIT INDEX

Exhibit No.

+10(a)	MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended November 15, 2007, and Rules and Regulations, as amended February 11, 2009

+10(b)	Montana-Dakota Utilities Co. Executive Incentive Compensation Plan, as amended November 15, 2007, and Rules and Regulations, as amended February 11, 2009

+10(c)	MDU Construction Services Group, Inc. Executive Incentive Compensation Plan, as amended January 31, 2008, and Rules and Regulations, as amended February 16, 2009

+10(d)	Knife River Corporation Executive Incentive Compensation Plan, as amended January 31, 2008, and Rules and Regulations, as amended February 16, 2009

+10(e)	WBI Holdings, Inc. Executive Incentive Compensation Plan, as amended January 31, 2008, and Rules and Regulations, as amended February 16, 2009

+10(f)	John G. Harp 2009 additional incentive opportunity

+10(g)	Form of 2009 Annual Incentive Award Agreement under the Long-Term Performance-Based Incentive Plan

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

+ 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.