Edgar Filing: MDU RESOURCES GROUP INC

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, 2008

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 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, 2008: 182,869,115 shares.

DEFINITIONS

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

Abbreviation or Acronym

	2007 Annual Report		Company's Annual Report on Form 10-K for the year ended December 31, 2007
	ALJ		Administrative Law Judge
	Anadarko		Anadarko Petroleum Corporation
	APB		Accounting Principles Board
	APB Opinion No. 28		Interim Financial Reporting
	Badger Hills Project		Tongue River-Badger Hills Project
	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)
	BLM		Bureau of Land Management
	Brazilian Transmission Lines		Company’s equity method investment in companies owning ECTE, ENTE and ERTE
	Btu		British thermal unit
	Carib Power		Carib Power Management LLC
	Cascade		Cascade Natural Gas Corporation
	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 Power		Centennial Power, Inc., a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
	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
	CMS		Cost Management Services, Inc.
	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
	DRC		Dakota Resource Council
	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 157-2		Effective Date of FASB Statement No. 157
	Great Plains		Great Plains Natural Gas Co., a public utility division of the Company
	Hartwell		Hartwell Energy Limited Partnership, a former equity method investment of the Company (sold in the third quarter of 2007)
	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
	Innovatum		Innovatum Inc., a former indirect wholly owned subsidiary of WBI Holdings (the stock and Innovatum’s assets have been sold)
	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
	MEPA		Montana Environmental Policy Act
	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 BOGC		Montana Board of Oil & Gas Conservation
	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)
	MTPSC		Montana Public Service Commission
	MW		Megawatt
	ND Health Department		North Dakota Department of Health
	NDPSC		North Dakota Public Service Commission
	NEPA		National Environmental Policy Act
	Ninth Circuit		U.S. Ninth Circuit Court of Appeals
	NPRC		Northern Plains Resource Council
	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
	PSD		Prevention of Significant Deterioration
	ROD		Record of Decision
	SEC		U.S. Securities and Exchange Commission
	SEIS		Supplemental Environmental Impact Statement
	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
	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
	Wyoming DEQ		Wyoming State Department of Environmental Quality
	Wyoming Federal District Court		U.S. District Court for the District of Wyoming

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. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. Cascade distributes natural gas in Washington and Oregon. 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

Consolidated Statements of Income --

Three Months Ended March 31, 2008 and 2007

Consolidated Balance Sheets --

March 31, 2008 and 2007, and December 31, 2007

Consolidated Statements of Cash Flows --

Three Months Ended March 31, 2008 and 2007

Notes to Consolidated Financial Statements

Management's Discussion and Analysis of Financial

Condition and Results of Operations

Quantitative and Qualitative Disclosures About Market Risk

Controls and Procedures

Part II -- Other Information

Legal Proceedings

Risk Factors

Unregistered Sales of Equity Securities and Use of Proceeds

Submission of Matters to a Vote of Security Holders

Exhibits

Signatures

Exhibit Index

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2008		2007
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	517,263	$	268,011
Construction services, natural gas and oil production, construction materials and contracting, and other		604,644		519,480
		1,121,907		787,491
Operating expenses:
Fuel and purchased power		18,778		17,118
Purchased natural gas sold		276,624		98,835
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services		59,563		44,654
Construction services, natural gas and oil production, construction materials and contracting, and other		497,617		445,851
Depreciation, depletion and amortization		87,231		69,802
Taxes, other than income		54,522		32,262
		994,335		708,522

Operating income		127,572		78,969

Earnings from equity method investments		1,825		2,054

Other income		1,565		1,332

Interest expense		18,656		17,376

Income before income taxes		112,306		64,979

Income taxes		41,255		23,572

Income from continuing operations		71,051		41,407

Income from discontinued operations, net of tax (Note 3)		---		5,255

Net income		71,051		46,662

Dividends on preferred stocks		171		171

Earnings on common stock	$	70,880	$	46,491
Earnings per common share -- basic
Earnings before discontinued operations	$	.39	$	.23
Discontinued operations, net of tax		---		.03
Earnings per common share -- basic	$	.39	$	.26
Earnings per common share -- diluted
Earnings before discontinued operations	$	.39	$	.23
Discontinued operations, net of tax		---		.02
Earnings per common share -- diluted	$	.39	$	.25
Dividends per common share	$	.1450	$	.1350
Weighted average common shares outstanding -- basic		182,599		181,341
Weighted average common shares outstanding -- diluted		183,130		182,337

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2008			March 31, 2007			December 31, 2007
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	71,504		$	51,574		$	105,820
Receivables, net		697,079			548,542			715,484
Inventories		227,017			206,250			229,255
Deferred income taxes		27,897			2,702			7,046
Short-term investments		13,491			15,600			91,550
Prepayments and other current assets		114,935			81,166			64,998
Current assets held for sale		---			23,871			179
		1,151,923			929,705			1,214,332
Investments		113,286			133,454			118,602
Property, plant and equipment		6,303,570			4,850,268			5,930,246
Less accumulated depreciation, depletion and amortization		2,343,585			1,799,770			2,270,691
		3,959,985			3,050,498			3,659,555
Deferred charges and other assets:
Goodwill		430,309			226,937			425,698
Other intangible assets, net		25,562			17,929			27,792
Other		149,752			107,639			146,455
Noncurrent assets held for sale		---			410,282			---
		605,623			762,787			599,945
	$	5,830,817		$	4,876,444		$	5,592,434
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	---		$	---		$	1,700
Long-term debt due within one year		211,669			83,446			161,682
Accounts payable		333,894			244,059			369,235
Taxes payable		85,366			67,223			60,407
Dividends payable		26,677			24,693			26,619
Accrued compensation		40,470			29,881			66,255
Other accrued liabilities		226,782			113,164			163,990
Current liabilities held for sale		---			19,150			---
		924,858			581,616			849,888
Long-term debt		1,269,963			1,155,117			1,146,781
Deferred credits and other liabilities:
Deferred income taxes		677,982			556,522			668,016
Other liabilities		416,672			357,353			396,430
Noncurrent liabilities held for sale		---			33,680			---
		1,094,654			947,555			1,064,446
Commitments and contingencies
Stockholders’ equity:
Preferred stocks		15,000			15,000			15,000
Common stockholders’ equity:
Common stock
Shares issued -- $1.00 par value 183,336,872 at March 31, 2008, 182,319,441 at March 31, 2007 and 182,946,528 at December 31, 2007		183,337			182,319			182,947
Other paid-in capital		917,159			891,990			912,806
Retained earnings		1,478,327			1,126,270			1,433,585
Accumulated other comprehensive loss		(48,855	)		(19,797	)		(9,393	)
Treasury stock at cost – 538,921 shares		(3,626	)		(3,626	)		(3,626	)
Total common stockholders’ equity		2,526,342			2,177,156			2,516,319
Total stockholders’ equity		2,541,342			2,192,156			2,531,319
	$	5,830,817		$	4,876,444		$	5,592,434

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,
	2008			2007
	(In thousands)
Operating activities:
Net income	$	71,051		$	46,662
Income from discontinued operations, net of tax		---			5,255
Income from continuing operations		71,051			41,407
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		87,231			69,802
Earnings, net of distributions, from equity method investments		(1,141	)		1,056
Deferred income taxes		12,704			13,686
Changes in current assets and liabilities, net of acquisitions:
Receivables		29,997			79,780
Inventories		3,010			(1,761	)
Other current assets		(60,689	)		(37,931	)
Accounts payable		(28,135	)		(48,729	)
Other current liabilities		19,307			(25,951	)
Other noncurrent changes		9,223			9,174
Net cash provided by continuing operations		142,558			100,533
Net cash provided by discontinued operations		---			5,596
Net cash provided by operating activities		142,558			106,129

Investing activities:
Capital expenditures		(165,315	)		(123,758	)
Acquisitions, net of cash acquired		(248,677	)		(320	)
Net proceeds from sale or disposition of property		7,713			3,202
Investments		80,551			17,113
Net cash used in continuing operations		(325,728	)		(103,763	)
Net cash used in discontinued operations		---			(839	)
Net cash used in investing activities		(325,728	)		(104,602	)

Financing activities:
Repayment of short-term debt		(1,700	)		---
Issuance of long-term debt		178,159			8,765
Repayment of long-term debt		(4,893	)		(24,692	)
Proceeds from issuance of common stock		1,706			13,933
Dividends paid		(26,619	)		(24,607	)
Tax benefit on stock-based compensation		2,191			3,566
Net cash provided by (used in) continuing operations		148,844			(23,035	)
Net cash provided by discontinued operations		---			---
Net cash provided by (used in) financing activities		148,844			(23,035	)
Effect of exchange rate changes on cash and cash equivalents		10			4
Decrease in cash and cash equivalents		(34,316	)		(21,504	)
Cash and cash equivalents -- beginning of year		105,820			73,078
Cash and cash equivalents -- end of period	$	71,504		$	51,574

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

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

March 31, 2008 and 2007

(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 2007 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 2007 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.

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.	Discontinued operations

As described in Note 3 in the Company's Notes to Consolidated Financial Statements in the 2007 Annual Report, the Company's consolidated financial statements and accompanying notes for prior periods present the results of operations of Innovatum and the domestic independent power production assets as discontinued operations. In addition, the assets and liabilities of these operations were treated as held for sale from the time each of the assets was classified as held for sale.

During the fourth quarter of 2006, the stock and a portion of the assets of Innovatum were sold and the Company sold the remaining assets of Innovatum on January 23, 2008. The loss on disposal of Innovatum was not material.

In July 2007, Centennial Resources sold its domestic independent power production business consisting of Centennial Power and CEM. The gain on the sale of the assets, excluding the gain on the sale of Hartwell as discussed in Note 11, was approximately $85.4 million (after tax).

Operating results related to Innovatum were as follows:

	Three Months Ended March 31, 2007
	(In thousands)
Operating revenues	$	250
Loss from discontinued operations before income tax benefit		(75	)
Income tax benefit		(44	)
Loss from discontinued operations, net of tax	$	(31	)

Operating results related to the domestic independent power production assets were as follows:

	Three Months Ended March 31, 2007
	(In thousands)
Operating revenues	$	34,596
Income from discontinued operations before income tax expense		7,390
Income tax expense		2,104
Income from discontinued operations, net of tax	$	5,286

The carrying amounts of the major assets and liabilities related to the domestic independent power production assets held for sale, as well as the major assets and liabilities related to Innovatum, were as follows:

	March 31, 2007		December 31, 2007
	(In thousands)
Cash and cash equivalents	$	9,991	$	---
Receivables, net		6,697		---
Inventories		596		179
Prepayments and other current assets		6,587		---
Total current assets held for sale	$	23,871	$	179
Net property, plant and equipment	$	391,168	$	---
Goodwill		11,167		---
Other intangible assets, net		7,241		---
Other		706		---
Total noncurrent assets held for sale	$	410,282	$	---
Accounts payable	$	13,717	$	---
Other accrued liabilities		5,433		---
Total current liabilities held for sale	$	19,150	$	---
Deferred income taxes	$	29,664	$	---
Other liabilities		4,016		---
Total noncurrent liabilities held for sale	$	33,680	$	---

4.	Allowance for doubtful accounts

The Company's allowance for doubtful accounts as of March 31, 2008 and 2007, and December 31, 2007, was $14.5 million, $8.0 million and $14.6 million, respectively.

5.	Natural gas in underground storage

Natural gas in underground 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 underground storage expected to be used within one year was included in inventories and was $5.4 million, $3.5 million and $28.8 million at March 31, 2008 and 2007, and December 31, 2007, respectively. The remainder of natural gas in underground storage, which represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $43.0 million, $44.2 million and $43.0 million at March 31, 2008 and 2007, and December 31, 2007, respectively.

6.	Inventories

Inventories, other than natural gas in underground storage for the Company’s regulated operations, consisted primarily of aggregates held for resale of $108.6 million, $95.2 million and $102.2 million; materials and supplies of $74.9 million, $75.4 million and $56.0 million; and other inventories of $38.1 million, $32.1 million and $42.3 million, as of March 31, 2008 and 2007, and December 31, 2007, respectively. These inventories were stated at the lower of average cost or market value.

7.	Earnings per common share

Basic earnings per common share were computed by dividing earnings 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. 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,
	2008		2007
	(In thousands)
Interest, net of amount capitalized	$	18,372	$	17,367
Income taxes	$	10,813	$	3,150

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 157-2 delays 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 for which the Company has not applied the provisions of SFAS No. 157, 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, excluding 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. The Company is evaluating the effects of the adoption of the delayed provisions of SFAS No. 157.

SFAS No. 159 In February 2007, the FASB issued SFAS No. 159. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 was effective for the Company on January 1, 2008, and at adoption, 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 prior to January 1, 2008, were accounted for as available-for-sale investments and recorded at fair value with any unrealized gains or losses, net of income taxes, recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets until realized. Upon the adoption of SFAS No. 159, the unrealized gain on the available-for-sale investments of $405,000 (after tax) was recorded as an increase to the January 1, 2008, balance of retained earnings. The adoption of SFAS No. 159 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) will be effective for the Company on January 1, 2009. The Company is evaluating the effects of the adoption of SFAS No. 141 (revised).

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 will be effective for the Company on January 1, 2009. The Company is evaluating the effects of the adoption of SFAS No. 160.

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 will be effective for the Company on January 1, 2009. The Company is evaluating the effects of the adoption of SFAS No. 161.

10.	Comprehensive income

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

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

	Three Months Ended March 31,
	2008			2007
	(In thousands)
Net income	$	71,051		$	46,662
Other comprehensive loss:
Net unrealized loss on derivative instruments qualifying as hedges:
Net unrealized loss on derivative instruments arising during the period, net of tax of $(22,116) and $(6,383) in 2008 and 2007, respectively		(36,197	)		(10,196	)
Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $2,083 and $3,271 in 2008 and 2007, respectively		3,345			5,226
Net unrealized loss on derivative instruments qualifying as hedges		(39,542	)		(15,422	)
Foreign currency translation adjustment, net of tax of $336 in 2008		485			2,107
		(39,057	)		(13,315	)
Comprehensive income	$	31,994		$	33,347

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, 2008, include the Brazilian Transmission Lines.

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

In September 2004, Centennial Resources, through indirect wholly owned subsidiaries, acquired a 50-percent ownership interest in Hartwell, which owns a 310-MW natural gas-fired electric generating facility near Hartwell, Georgia. In July 2007, the Company sold its ownership interest in Hartwell, and realized a gain of $10.1 million ($6.1 million after tax) from the sale.

At March 31, 2008 and 2007, and December 31, 2007, the Company's equity method investments had total assets of $395.7 million, $457.6 million and $398.4 million, respectively, and long-term debt of $207.3 million, $275.5 million and $211.2 million, respectively. The Company's investment in its equity method investments was approximately $55.4 million, $79.6 million and $59.0 million, including undistributed earnings of $8.0 million, $5.2 million and $6.9 million, at March 31, 2008 and 2007, and December 31, 2007, respectively.

12.	Goodwill and other intangible assets

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

Three Months Ended March 31, 2008	Balance as of January 1, 2008		Goodwill Acquired During the Year*			Balance as of March 31, 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.

Three Months Ended March 31, 2007	Balance as of January 1, 2007		Goodwill Acquired During the Year*			Balance as of March 31, 2007
	(In thousands)
Electric	$	---	$	---		$	---
Natural gas distribution		---		---			---
Construction services		86,942		3,550			90,492
Pipeline and energy services		1,159		---			1,159
Natural gas and oil production		---		---			---
Construction materials and contracting		136,197		(911	)		135,286
Other		---		---			---
Total	$	224,298	$	2,639		$	226,937
* Includes purchase price adjustments that were not material related to acquisitions in a prior period.

Year Ended December 31, 2007	Balance as of January 1, 2007		Goodwill Acquired During the Year*		Balance as of December 31, 2007
	(In thousands)
Electric	$	---	$	---	$	---
Natural gas distribution		---		171,129		171,129
Construction services		86,942		4,443		91,385
Pipeline and energy services		1,159		---		1,159
Natural gas and oil production		---		---		---
Construction materials and contracting		136,197		25,828		162,025
Other		---		---		---
Total	$	224,298	$	201,400	$	425,698
*Includes purchase price adjustments that were not material related to acquisitions in a prior period.

Other amortizable intangible assets were as follows:

	March 31, 2008			March 31, 2007			December 31, 2007
	(In thousands)
Customer relationships	$	22,016		$	13,959		$	21,834
Accumulated amortization		(5,243	)		(2,628	)		(4,444	)
		16,773			11,331			17,390
Noncompete agreements		10,140			5,045			10,655
Accumulated amortization		(4,035	)		(1,873	)		(3,654	)
		6,105			3,172			7,001
Acquired contracts		328			1,186			2,539
Accumulated amortization		(208	)		(1,118	)		(1,615	)
		120			68			924
Other		3,865			4,842			3,404
Accumulated amortization		(1,301	)		(1,484	)		(927	)
		2,564			3,358			2,477
Total	$	25,562		$	17,929		$	27,792

Amortization expense for intangible assets for the three months ended March 31, 2008 and 2007, and for the year ended December 31, 2007, was $1.4 million, $1.0 million and $4.4 million, respectively. Estimated amortization expense for amortizable intangible assets is $5.1 million in 2008, $4.2 million in 2009, $3.3 million in 2010, $2.8 million in 2011, $2.5 million in 2012 and $9.1 million thereafter.

13.	Derivative instruments

From time to time, the Company utilizes 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, 2008, 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 2007 Annual Report.

Cascade core

At March 31, 2008, Cascade held natural gas swap agreements which were not designated as hedges.

Cascade utilizes natural gas swap agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas on its forecasted purchases of natural gas for core customers in accordance with authority granted by the 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 applies SFAS No. 71 and records 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. Under the terms of these arrangements, Cascade 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.

Fidelity and Cascade non-core

At March 31, 2008, Fidelity held natural gas and oil swap and collar derivative instruments designated as cash flow hedging instruments. Cascade held natural gas swap derivative instruments designated as cash flow hedging instruments.

Fidelity utilizes natural gas and oil price swap and collar agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on its forecasted sales of natural gas and oil production. Cascade utilizes natural gas swap agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas on its forecasted purchases for non-core customers. Cascade's non-core customers, who are not covered by the purchased gas cost adjustment mechanism, are generally large industrial, electric generation and institutional customers. Each of the swap and collar agreements was designated as a cash flow hedge of the forecasted sale of the related production or as a cash flow hedge of the forecasted purchase of the related commodity.

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

For the three months ended March 31, 2008 and 2007, the amount of hedge ineffectiveness was immaterial. For the three months ended March 31, 2008 and 2007, 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 the line item in which the hedged item is recorded. As of March 31, 2008, 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 45 months. The Company estimates that over the next 12 months net losses of approximately $25.9 million (after tax) will be reclassified from accumulated other comprehensive loss into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings.

14.	Fair value measurements

On January 1, 2008, the Company adopted SFAS No. 157 and SFAS No. 159, as discussed in Note 9.

Upon the adoption of SFAS No. 159, the Company elected to measure its investments in certain fixed-income and equity securities at fair value. 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 plan 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 $30.4 million as of March 31, 2008, 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, 2008, was $2.2 million (before tax), 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, as they are not intended for long-term investment. The Company’s auction rate securities, which totaled $11.4 million at March 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.

The Company’s assets and liabilities measured at fair value on a recurring basis are as follows:

			Fair Value Measurements at March 31, 2008, Using
	Balance at March 31, 2008		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In thousands)
Assets:
Available-for-sale securities	$	41,821	$	30,421	$	11,400	$	---
Commodity derivative agreements		38,170		---		38,170		---
Total assets measured at fair value	$	79,991	$	30,421	$	49,570	$	---
Liabilities:
Commodity derivative agreements	$	55,853	$	---	$	55,853	$	---
Total liabilities measured at fair value	$	55,853	$	---	$	55,853	$	---

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 derivative instruments, comprised of natural gas and oil swap and collar agreements, reflect the estimated amounts the Company would receive or pay to terminate the contracts at the reporting date based upon quoted market prices of comparable contracts.

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 the Company's 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 Minnesota, Oregon and Washington. These operations also supply related value-added products and services.

The construction services segment specializes in electric line construction, pipeline construction, utility excavation, inside electrical wiring, cabling and mechanical work, fire protection and the manufacture and distribution of 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. The pipeline and energy services 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 construction services. The construction materials and contracting 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 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 2007 Annual Report. Information on the Company’s businesses was as follows:

Three Months Ended March 31, 2008	External Operating Revenues			Inter- segment Operating Revenues	Earnings on Common 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

Three Months Ended March 31, 2007	External Operating Revenues		Inter- segment Operating Revenues	Earnings on Common Stock
	(In thousands)
Electric	$	47,104	$ ---	$ 3,784
Natural gas distribution		136,061	---	6,145
Pipeline and energy services		84,846	28,292	5,710
		268,011	28,292	15,639
Construction services		236,638	125	7,234
Natural gas and oil production		55,269	63,311	30,621
Construction materials and contracting		227,573	---	(9,796)
Other		---	2,440	2,793
		519,480	65,876	30,852
Intersegment eliminations		---	(94,168)	---
Total	$	787,491	$ ---	$ 46,491

The pipeline and energy services segment recognized a loss from discontinued operations, net of tax, of $31,000 for the three months ended March 31, 2007. The Other category reflects income from discontinued operations, net of tax, of $5.3 million for the three months ended March 31, 2007.

Excluding the loss from discontinued operations at pipeline and energy services, earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings (loss) from construction services, natural gas and oil production, construction materials and contracting, and other are all from nonregulated operations.

16. Acquisitions

During the first three months of 2008, the Company acquired natural gas properties in Texas and a construction materials and contracting business in Alaska neither of which were material. The total purchase consideration for these properties and purchase price adjustments with respect to certain other acquisitions made prior to 2008, consisting of the Company’s common stock and cash, was $249.5 million.

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

17.	Employee benefit plans

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

Three Months	Pension Benefits						Other Postretirement Benefits
Ended March 31,	2008			2007			2008			2007
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	2,629		$	2,250		$	490		$	533
Interest cost		5,124			4,141			1,185			938
Expected return on assets		(6,036	)		(5,070	)		(1,697	)		(1,093	)
Amortization of prior service cost (credit)		166			209			(689	)		11
Amortization of net actuarial (gain) loss		242			74			115			(313	)
Amortization of net transition obligation		---			---			531			531
Net periodic benefit cost, including amount capitalized		2,125			1,604			(65	)		607
Less amount capitalized		179			151			65			52
Net periodic benefit cost	$	1,946		$	1,453		$	(130	)	$	555

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 an 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, 2008 and 2007, was $2.0 million and $1.8 million, respectively.

18.	Regulatory matters and revenues subject to refund

In August 2006, CMS, a competing gas marketer, filed a complaint against Cascade before the WUTC alleging Cascade had entered into gas supply sales contracts with its non-core, transportation-only customers in violation of state law by not filing tariffs and copies of the gas supply contracts with the WUTC. CMS's complaint additionally raised claims of undue preference and discrimination. In January 2007, the WUTC entered an order allowing Cascade to continue to make gas supply sales to non-core, transportation-only customers but requiring Cascade to file its tariffs and sales contracts with the WUTC. In February 2007, Cascade filed revisions to its tariffs reflecting gas supply service options available to non-core, transportation-only customers; however, in March 2007, the WUTC suspended the tariff filing. Subsequently, in March 2007, due to the lack of approved tariffs, Cascade filed notice with the WUTC that it was reactivating a nonregulated affiliate to make retail gas sales to non-core, transportation-only customers. The WUTC consolidated the tariff proceeding with Cascade's filing to re-establish an affiliate to make non-core, transportation-only customer gas supply sales. In December 2007, the WUTC filed a complaint against Cascade alleging it is in violation of its most recent general rate case settlement by not sharing gas supply sales margins with core customers. Cascade filed an answer to the complaint in December 2007. On February 6, 2008, Cascade and the other participant parties entered into an agreement settling the issues in all of the above proceedings. Under the settlement, Cascade and its subsidiaries will discontinue the unbundled retail sale of gas supply to non-core, transportation-only customers by November 1, 2008. Fifty percent of the net gas supply sales margins realized from non-core, transportation-only customers by Cascade and its subsidiaries from April 1, 2007, through October 31, 2008, and fifty percent of the net gain, if any, from the sale of such business, will be credited to Cascade’s core customers. Cascade will also revise its gas procurement strategy for core customers to enhance its ability to acquire gas supply from the Rocky Mountain region. Cascade has reserved an amount for the crediting of the net gas supply sales margins generated from April 1, 2007, through March 31, 2008. The WUTC entered a final order on March 6, 2008, accepting the parties’ stipulation subject to the condition that Cascade hold core customers harmless in the event a replacement shipper defaults on payment under its award of pipeline capacity released under the settlement. Cascade does not consider the discontinuance of gas supply sales to non-core, transportation-only customers to have a material impact on its financial position or results of operations.

In July 2007, Montana-Dakota filed an application with the MTPSC for an electric rate increase. Montana-Dakota requested a total of $7.8 million annually or approximately 22 percent above current rates. Montana-Dakota requested a fuel and purchased power tracking adjustment and an off-system sales margin sharing adjustment. Montana-Dakota also requested an interim increase of $3.9 million annually, subject to refund. In December 2007, the MTPSC granted an interim increase of $3.4 million annually. On April 23, 2008, the MTPSC approved a settlement stipulation reached between Montana-Dakota and the interveners whereby the $3.4 million of interim rate relief became final and an additional annual rate increase of $730,000 will become effective January 1, 2009. As part of the settlement, Montana-Dakota will be allowed to implement a fuel and purchased power tracking mechanism on a shared basis, a margin sharing mechanism for off-system sales, and modify certain decommissioning and net negative salvage cost accruals. Also, Montana-Dakota will agree to not implement new rates from any subsequent general rate filings before January 1, 2010.

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, that it was considering the impact of these withdrawals on the project and its options, and proposed that the NDPSC suspend the procedural schedule. In October 2007, Montana-Dakota proposed to supplement the record with additional resource planning analysis reflecting changes in plant configuration as a result of the participant withdrawals. Supplemental hearings before the NDPSC were held in late April 2008. The MNPUC is expected to rule on the issuance of the related transmission Certificate of Need and the NDPSC is expected to rule on the advance determination of prudence, both in June 2008.

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. On March 18, 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. The matter concerning the service restrictions is pending resolution by the FERC.

19.	Contingencies

Litigation

Coalbed Natural Gas Operations Fidelity is a party to and/or certain of its operations are or have been the subject of approximately a dozen lawsuits in Montana and Wyoming in connection with Fidelity’s CBNG development in the Powder River Basin. The lawsuits generally involve either challenges to regulatory agency decisions under the NEPA or the MEPA or to Fidelity’s management of water produced in association with its operations.

Challenges to State/Federal Regulatory Agency Decision Making Under NEPA/MEPA

In 1999 and 2000, the BLM, the Montana BOGC, and the Montana DEQ announced their respective decisions to prepare an EIS analyzing CBNG development in Montana. In 2003, the agencies each signed RODs approving a final EIS and allowing CBNG development throughout the State of Montana. The approval actions by the agencies resulted in numerous lawsuits initiated by environmental groups and the Northern Cheyenne Tribe related to the validity of the final EIS and associated environmental assessments. Fidelity has intervened in several of these lawsuits to protect its interests.

In lawsuits filed in Montana Federal District Court in May 2003, the NPRC and the Northern Cheyenne Tribe asserted that the BLM violated NEPA and other federal laws when approving the 2003 EIS. The Montana Federal District Court entered a ruling in February 2005 holding that the 2003 EIS was inadequate because it did not consider a phased-development alternative. The Montana Federal District Court later entered an order allowing limited CBNG development of up to 500 CBNG wells to be drilled annually on private, state, and federal lands in the Montana Powder River Basin pending the BLM's preparation of a SEIS. The plaintiffs appealed and in May 2005, the Ninth Circuit enjoined the BLM from approving any new CBNG development on federal lands in the Montana Powder River Basin pending further order from the Ninth Circuit. The Ninth Circuit also enjoined Fidelity from drilling additional federally permitted wells in its Montana Coal Creek Project and from constructing infrastructure to produce and transport CBNG from the Montana Coal Creek Project. In September 2007, the Ninth Circuit affirmed the Montana Federal District Court and ruled it had correctly issued an injunction allowing limited CBNG development in the Montana Powder River Basin. Plaintiffs’ petitioned the Ninth Circuit for a rehearing, which was denied. The deadline to seek review by the United States Supreme Court has passed. Fidelity is operating under the limited injunction.

In December 2006, the BLM issued a draft SEIS that endorses a phased-development approach to CBNG production in the Montana Powder River Basin, whereby future projects would be reviewed against four screens or filters (relating to water quality, wildlife, Native American concerns and air quality). Fidelity filed written comments on the draft SEIS asking the BLM to reconsider its proposed phased-development approach and to make numerous other changes to the draft SEIS. The final SEIS is scheduled for release in July 2008 with a ROD expected in December 2008. Fidelity cannot predict what the final terms of the SEIS will be.

In a related action filed in Montana Federal District Court in December 2003, the NPRC asserted, among other things, that the actions of the BLM in approving Fidelity's applications for permits and the plan of development for the Badger Hills Project in Montana did not comply with applicable federal laws, including the NEPA. In September 2005, the Montana Federal District Court entered an Order based on a stipulation between the parties that allowed production from existing wells in Fidelity’s Badger Hills Project to continue pending preparation of a revised environmental analysis. In December 2005, Fidelity and the BLM appealed the Montana Federal District Court’s decision to the Ninth Circuit insofar as it found the BLM’s approval of Fidelity’s applications did not comply with applicable law. In early February 2008, Fidelity and the BLM filed motions to dismiss their appeals following the Ninth Circuit’s decision in the NPRC and Northern Cheyenne Tribe cases that the 2003 EIS, upon which the environmental assessment for the Badger Hills project was prepared, was inadequate. The Ninth Circuit granted their motions on February 11, 2008.

Cases Involving Fidelity’s Management of Water Produced in Association with Its Operations

About half the CBNG cases Fidelity is involved in relate to administrative agency regulation of water produced in association with CBNG development in Montana and Wyoming. 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 have been granted leave to intervene in this proceeding. 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.

Industry members filed two lawsuits in April and September 2006, and the state of Wyoming filed a lawsuit in September 2006, in Wyoming Federal District Court. These lawsuits challenge the EPA’s failure to timely disapprove the BER’s 2006 rules, which amended the nondegradation policy as well as the BER’s 2003 rulemaking procedure which set numeric limits for certain parameters contained in water produced in connection with CBNG operations. The rules generally apply only to existing and proposed discharges in Montana and discharges in Wyoming if those discharges cause streams flowing into Montana to exceed the standards or cause degradation at the state line. All three Wyoming lawsuits were consolidated in September 2006. Although Fidelity has moved to intervene in these consolidated cases, Fidelity has determined that an adverse decision in these cases should not have a material adverse impact on its Wyoming operations because the water management tools it uses in Wyoming should not result in produced water reaching any of the streams or tributaries running from Wyoming into Montana.

The Wyoming Outdoor Council and Powder River Basin Resource Council filed a petition in May 2007, in the Wyoming State District Court seeking to invalidate the Environmental Quality Council’s approval of amendments to Chapter 1 of the Wyoming Water Quality Rules and Regulations that subject certain discharges of water produced in connection with CBNG development to stricter water quality standards. The plaintiffs contend that the Wyoming DEQ’s actions were arbitrary and capricious and that the rules are not in accordance with the Clean Water Act. Fidelity is partly funding the Petroleum Association of Wyoming’s intervention in these suits. Because the water management tools used by Fidelity in Wyoming do not result in discharges into streams and are therefore not subject to the stricter water quality standards, these rules should not materially impact Fidelity’s CBNG operations in Wyoming.

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 would mandate that the state 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 Petroleum Association of Wyoming has conditionally been granted intervention in this lawsuit and Fidelity is partly funding the intervention. Fidelity’s CBNG operations in Wyoming could be materially adversely affected if the plaintiffs are successful in this lawsuit.

Fidelity is involved in, or certain of its operations are the subject of, other legal proceedings that concern its CBNG operations. Although the outcomes of those proceedings can not be predicted, management believes that the outcomes of these proceedings will not have a material adverse affect upon the Company’s financial position or results of its operations.

Fidelity will continue to vigorously defend its interests in all CBNG-related lawsuits and related actions 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 Montana-Dakota joined with two electric generators in appealing a September 2003 finding by the ND Health Department that it may unilaterally revise operating permits previously issued to electric generating plants. Although it is doubtful that any revision of Montana-Dakota's operating permits by the ND Health Department would reduce the amount of electricity its plants could generate, the finding, if allowed to stand, could increase costs for sulfur dioxide removal and/or limit Montana-Dakota's ability to modify or expand operations at its North Dakota generation sites. Montana-Dakota and the other electric generators filed their appeal of the order in October 2003 in the Burleigh County District Court in Bismarck, North Dakota. Proceedings were stayed pending conclusion of the periodic review of sulfur dioxide emissions in the state.

In September 2005, the ND Health Department issued its final periodic review decision based on its August 2005 final air quality modeling report. The ND Health Department concluded there were no violations of the sulfur dioxide increment in North Dakota. In March 2006, the DRC filed a complaint in Colorado Federal District Court seeking to force the EPA to declare that the increment had been violated based on earlier modeling conducted by the EPA. The EPA defended against the DRC claim and filed a motion to dismiss the case. The Colorado Federal District Court has dismissed the case.

In June 2007, the EPA noticed for public comment a proposed rule that would, among other things, adopt PSD increment modeling refinements that, if adopted, would operate to formally ratify the modeling techniques and conclusions contained in the September 2005 ND Health Department decision and the August 2005 final report. The public comment period on the proposed rule closed in September 2007. The dismissal of the case in Burleigh County District Court referenced above is dependant upon the outcome of the proposed rule.

In November 2006, the Sierra Club sent a notice of intent to file a citizen suit in federal court under the Clean Air Act to the co-owners, including Montana-Dakota, of the Big Stone Station. The suit would seek injunctive relief and monetary penalties based on the Sierra Club’s claim that three projects conducted at the Big Stone Station between 1995 and 2005 were modifications of a major source and that the Big Stone Station failed to obtain a PSD permit, conduct best available control technology analyses, and comply with other regulatory requirements. The South Dakota Department of Environment and Natural Resources reviewed and approved the three projects and the co-owners of the Big Stone Station believe the Sierra Club’s claims are without merit. The Big Stone Station co-owners intend to vigorously defend their interests if suit is filed.

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, 2008, Williston Basin estimated that between 9.75 and 10.25 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 to the Ninth Circuit in July 2006. Oral argument was held on February 5, 2008.

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. On March 17, 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. On April 28, 2008, the parties filed objections to the recommendations with the Wyoming State District Court. The Wyoming State District Court has scheduled the case for trial beginning March 16, 2009.

As noted above, Williston Basin estimates that as of March 31, 2008, Howell and Anadarko had diverted between 9.75 and 10.25 Bcf from the EBSR. Williston Basin believes Howell and Anadarko continue to divert gas from the EBSR and 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.

In expert reports filed with the Wyoming State District Court in January 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 estimate that the replacement cost of the gas produced by Howell and Anadarko through October 2007 is approximately $106 million if injection is completed by the end of the 2010 injection season. Williston Basin's experts also estimate that Williston Basin will expend $8.7 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. 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 continues to evaluate the Howell and Anadarko reports. The parties will be given an opportunity to file rebuttal reports with the Wyoming State District Court.

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 heating season to supplement its cushion gas. While installation of the additional compression and leased working gas during the 2007 - 2008 heating season both provided temporary relief, Williston Basin believes that the adverse physical and operational effects occasioned by the continued loss of storage gas, if left unchecked, 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.

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 Potentially Responsible Party 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. Sixty-eight other parties were also named in this administrative action. 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. Although the LWG originally estimated the overall remedial investigation and feasibility study would cost approximately $10 million, it is now anticipated, on the basis of costs incurred to date and delays attributable to an additional round of sampling and potential further investigative work, that such cost could increase to a total in excess of $60 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 record of decision has been published. It is also not possible to estimate the costs of natural resource damages until investigation and allocations are undertaken. While the remedial investigation and feasibility study for the harbor site has commenced, it is expected to take several more years to complete. The development of a proposed plan and record of decision on the harbor site is not anticipated to occur until 2010, after which a cleanup plan will be undertaken. 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.

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 any and all 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.

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 two 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 potentially responsible parties in addition to Cascade that are potentially liable for cleanup of the contamination. Some of these other parties have shared in the investigation costs. It is expected that these and other potentially responsible parties 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. In November 2007, the Oregon DEQ provided notice that additional ecological risk assessment of the site was necessary. Completion of the assessment is anticipated by the end of 2008.

The second claim is for contamination at a site in Washington and was received in 1997. Although a preliminary investigation has concluded the site is contaminated, it appears that other property owners may have contributed to the contamination. There is currently not enough information available to estimate the potential liability associated with this claim and no formal investigation plan has been communicated to Cascade.

The Company believes that both these claims are covered by insurance. To the extent not covered by insurance, Cascade will seek recovery of contamination remediation costs through its rates.

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 continues to guarantee CEM's obligations under a construction contract for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. As described in Note 3, Centennial Resources sold CEM in July 2007 to Bicent Power LLC, which has provided a $10 million bank letter of credit to Centennial in support of that guarantee obligation. The guarantee, which has no fixed maximum, expires when CEM has completed its obligations under the construction contract. Construction is expected to be completed in mid- to late 2008, and the warranty period associated with this project will expire one year after the date of substantial completion of the construction.

In addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas and oil price swap and collar agreement obligations. There is no fixed maximum amount guaranteed in relation to the natural gas and oil price swap and collar agreements, as the amount of the obligation is dependent upon natural gas and oil commodity prices. The amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the natural gas and oil price swap and collar agreements at March 31, 2008, expire in the years ranging from 2008 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. The amount outstanding by Fidelity was $26.1 million and was reflected on the Consolidated Balance Sheets at March 31, 2008. 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, 2008, the fixed maximum amounts guaranteed under these agreements aggregated $413.4 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $9.6 million in 2008; $370.0 million in 2009; $500,000 in 2010; $24.7 million in 2011; $2.4 million in 2012; $1.2 million in 2018; $1.0 million, which is subject to expiration 30 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 $700,000 and was reflected on the Consolidated Balance Sheet at March 31, 2008. 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, 2008, the fixed maximum amounts guaranteed under these letters of credit, aggregated $44.0 million. In 2008 and 2009, $37.6 million and $6.4 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at March 31, 2008.

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, 2008, the fixed maximum amounts guaranteed under these agreements aggregated $22.9 million. Scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $20.0 million in 2009 and $2.9 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 $1.8 million, which was not reflected on the Consolidated Balance Sheet at March 31, 2008, 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, 2008.

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, 2008, approximately $450 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. 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. The natural gas distribution segment also continues to pursue growth by expanding its level of energy-related services.

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, as to the electric business, the ability of this segment to grow its service territory and customer base is affected by significant competition from other energy providers, including rural electric cooperatives.

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 down turns in the economy are ongoing challenges.

Pipeline and Energy Services

Strategy Leverage 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 Energy price volatility; natural gas basis differentials; regulatory requirements; ongoing litigation; recruitment and retention of a skilled workforce; and increased competition from other natural gas pipeline and gathering companies.

Natural Gas and Oil Production

Strategy Apply technology and leverage 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 Fluctuations 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, auxiliary equipment and industry-related field services; inflationary pressure on development and operating costs; and increased competition from other natural gas and oil companies.

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 slow-down 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. The Company is experiencing price volatility in petroleum products such as diesel, gasoline and liquid asphalt. Increased competition in certain markets has lowered margins. Recruitment and retention of a skilled workforce is also an ongoing challenge.

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 2007 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,
	2008			2007
(Dollars in millions, where applicable)
Electric	$	5.5		$	3.8
Natural gas distribution		16.4			6.2
Construction services		10.8			7.2
Pipeline and energy services		7.2			5.7
Natural gas and oil production		50.6			30.6
Construction materials and contracting		(21.1	)		(9.8	)
Other		1.5			(2.5	)
Earnings before discontinued operations		70.9			41.2
Income from discontinued operations, net of tax		---			5.3
Earnings on common stock	$	70.9		$	46.5
Earnings per common share – basic:
Earnings before discontinued operations	$	.39		$	.23
Discontinued operations, net of tax		---			.03
Earnings per common share – basic	$	.39		$	.26
Earnings per common share – diluted:
Earnings before discontinued operations	$	.39		$	.23
Discontinued operations, net of tax		---			.02
Earnings per common share – diluted	$	.39		$	.25
Return on average common equity for the 12 months ended		18.9	%		14.8	%

Three Months Ended March 31, 2008 and 2007 Consolidated earnings for the quarter ended March 31, 2008, increased $24.4 million from the comparable prior period largely due to:

·	Higher average realized oil and natural gas prices of 89 and 17 percent, respectively, and increased natural gas and oil production of 7 percent and 12 percent, respectively, partially offset by higher depreciation, depletion and amortization expense at the natural gas and oil production business

·	Increased earnings at the natural gas distribution business largely due to the acquisition of Cascade

·	Increased workloads and equipment sales and rentals at the construction services business

Partially offsetting the increase was a higher seasonal loss at the construction materials and contracting business, primarily related to construction workloads and margins as well as product volumes which were significantly lower as a result of the economic slowdown.

FINANCIAL AND OPERATING DATA

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

Electric

	Three Months Ended March 31,
	2008		2007
(Dollars in millions, where applicable)
Operating revenues	$	52.3	$	47.1
Operating expenses:
Fuel and purchased power		18.8		17.1
Operation and maintenance		15.0		15.1
Depreciation, depletion and amortization		6.0		5.6
Taxes, other than income		2.3		2.2
		42.1		40.0
Operating income		10.2		7.1
Earnings	$	5.5	$	3.8
Retail sales (million kWh)		707.8		645.8
Sales for resale (million kWh)		48.4		44.1
Average cost of fuel and purchased power per kWh	$	.023	$	.024

Three Months Ended March 31, 2008 and 2007 Electric earnings increased $1.7 million, primarily due to higher retail sales volumes and margins, partially offset by increased depreciation, depletion and amortization expense of $300,000 (after tax) related to higher asset balances.

Natural Gas Distribution

	Three Months Ended March 31,
	2008			2007
(Dollars in millions, where applicable)
Operating revenues	$	362.1		$	136.0
Operating expenses:
Purchased natural gas sold		282.6			106.2
Operation and maintenance		27.0			15.5
Depreciation, depletion and amortization		7.2			2.5
Taxes, other than income		14.5			1.7
		331.3			125.9
Operating income		30.8			10.1
Earnings	$	16.4		$	6.2
Volumes (MMdk):
Sales		31.1			15.9
Transportation		26.6			3.4
Total throughput		57.7			19.3
Degree days (% of normal)*
Montana-Dakota		101	%		94	%
Cascade		107	%		---
Average cost of natural gas, including transportation, per dk**
Montana-Dakota	$	7.70		$	6.70
Cascade	$	7.74			---
* Degree days are a measure of the daily temperature-related demand for energy for heating. ** Regulated natural gas sales only. Note: Cascade was acquired on July 2, 2007.

Three Months Ended March 31, 2008 and 2007 Earnings at the natural gas distribution business increased $10.2 million due to:

·	Earnings of $9.9 million at Cascade, which was acquired on July 2, 2007

·	Increased retail sales volumes resulting from 9 percent colder weather than last year and higher retail sales margins, both excluding Cascade

Partially offsetting these increases was increased operation and maintenance expense (excluding Cascade) of $600,000 (after tax), primarily payroll and benefit related costs.

Construction Services

	Three Months Ended March 31,
	2008		2007
	(In millions)
Operating revenues	$	307.4	$	236.8
Operating expenses:
Operation and maintenance		274.0		211.7
Depreciation, depletion and amortization		3.4		3.5
Taxes, other than income		11.8		8.8
		289.2		224.0
Operating income		18.2		12.8
Earnings	$	10.8	$	7.2

Three Months Ended March 31, 2008 and 2007 Construction services earnings increased $3.6 million due to:

·	Higher construction workloads of $3.2 million (after tax), largely in the Southwest region

·	Increased equipment sales and rentals

Pipeline and Energy Services

	Three Months Ended March 31,
	2008		2007
	(Dollars in millions)
Operating revenues	$	133.8	$	113.1
Operating expenses:
Purchased natural gas sold		94.1		79.6
Operation and maintenance		17.6		14.1
Depreciation, depletion and amortization		5.6		5.4
Taxes, other than income		2.8		2.7
		120.1		101.8
Operating income		13.7		11.3
Earnings	$	7.2	$	5.7
Transportation volumes (MMdk):
Montana-Dakota		8.3		8.0
Other		21.4		20.6
		29.7		28.6
Gathering volumes (MMdk)		24.0		22.1

Three Months Ended March 31, 2008 and 2007 Pipeline and energy services experienced an increase in earnings of $1.5 million due to:

·	Increased transportation (largely the result of an expansion to the Grasslands system) and gathering volumes totaling $1.6 million (after tax)

·	Higher storage services revenue of $500,000 (after tax)

·	Higher gathering rates of $300,000 (after tax)

Partially offsetting this increase was higher operation and maintenance expense related to the natural gas storage litigation and higher material costs and rentals. For more information regarding the natural gas storage litigation, see Note 19.

Natural Gas and Oil Production

	Three Months Ended March 31,
	2008		2007
(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	117.5	$	94.0
Oil		52.1		24.6
		169.6		118.6
Operating expenses:
Purchased natural gas sold		---		.3
Operation and maintenance:
Lease operating costs		18.3		15.5
Gathering and transportation		5.7		4.5
Other		8.8		8.4
Depreciation, depletion and amortization		39.3		29.8
Taxes, other than income:
Production and property taxes		13.7		8.9
Other		.2		.2
		86.0		67.6
Operating income		83.6		51.0
Earnings	$	50.6	$	30.6
Production:
Natural gas (MMcf)		16,561		15,440
Oil (MBbls)		621		556
Total production (MMcf equivalent)		20,288		18,773
Average realized prices (including hedges):
Natural gas (per Mcf)	$	7.10	$	6.08
Oil (per Bbl)	$	83.79	$	44.34
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	6.91	$	5.74
Oil (per Bbl)	$	84.35	$	44.34
Average depreciation, depletion and amortization rate, per equivalent Mcf	$	1.88	$	1.52
Production costs, including taxes, per equivalent Mcf:
Lease operating costs	$	.90	$	.83
Gathering and transportation		.28		.24
Production and property taxes		.67		.47
	$	1.85	$	1.54

Three Months Ended March 31, 2008 and 2007 The natural gas and oil production business earnings increased $20.0 million due to:

·	Higher average realized oil prices of 89 percent and higher average realized natural gas prices of 17 percent

·	Increased natural gas and oil production of 7 percent and 12 percent, respectively, largely the result of the East Texas property acquisition in January 2008 and additional drilling activity

Partially offsetting these increases were:

·	Higher depreciation, depletion and amortization expense of $5.9 million (after tax) due to higher depletion rates and increased production

·	Higher production taxes of $3.0 million (after tax) associated with higher revenue

·	Higher lease operating expense of $1.7 million (after tax)

Construction Materials and Contracting

	Three Months Ended March 31,
	2008			2007
	(Dollars in millions)
Operating revenues	$	201.3		$	227.6
Operating expenses:
Operation and maintenance		195.2			208.9
Depreciation, depletion and amortization		25.4			22.6
Taxes, other than income		9.1			7.7
		229.7			239.2
Operating loss		(28.4	)		(11.6	)
Loss	$	(21.1	)	$	(9.8	)
Sales (000's):
Aggregates (tons)		4,241			5,557
Asphalt (tons)		196			336
Ready-mixed concrete (cubic yards)		611			626

Three Months Ended March 31, 2008 and 2007 Construction materials and contracting experienced a seasonal first quarter loss of $21.1 million. The loss increased by $11.3 million from $9.8 million in 2007. The increased loss was due to:

·	Lower margins from existing operations of $9.7 million, largely

o	Construction workloads and margins as well as product volumes which were significantly lower as a result of the economic slowdown

o	Significantly higher diesel fuel costs

·	Higher depreciation, depletion and amortization expense, largely the result of higher property, plant and equipment balances from ongoing operations and acquisitions

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,
	2008		2007
	(In millions)
Other:
Operating revenues	$	2.6	$	2.4
Operation and maintenance		2.7		3.6
Depreciation, depletion and amortization		.3		.4
Taxes, other than income		.1		.1
Intersegment transactions:
Operating revenues	$	107.2	$	94.1
Purchased natural gas sold		100.1		87.3
Operation and maintenance		7.1		6.8

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 each 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 and revenues, 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 2007 Annual Report. Changes in such assumptions and factors could cause actual future results to differ materially from the Company’s growth, earnings and revenue projections.

MDU Resources Group, Inc.

·	Earnings per common share for 2008 are projected in the range of $1.85 to $2.10. The Company expects the percentage of 2008 earnings per common share by quarter to be in the following approximate ranges:

o	Second quarter – 25 percent to 30 percent

o	Third quarter – 30 percent to 35 percent

o	Fourth quarter – 25 percent to 30 percent

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

Electric

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 and rate base. A final decision on the Big Stone Station II project will be made when conclusions are reached on the issuance of major permits and certain regulatory approvals, which is expected by mid- to late 2008. If the decision is to proceed with construction of the plant, it is projected to be completed in 2013. The Company anticipates it would own at least 116 MW of this plant or other generation sources. For further information, see Note 18.

·	This business continues to pursue expansion of energy-related services.

Natural gas distribution

·	This business continues to pursue expansion of energy-related services and expects continued strong customer growth in Washington and Oregon.

Construction services

·	The Company anticipates margins in 2008 to be slightly lower than 2007.

·	The Company continues to focus on costs and efficiencies to enhance margins.

·	Work backlog as of March 31, 2008, was approximately $752 million, compared to $747 million at March 31, 2007.

·	This business continuously seeks opportunities to expand through strategic acquisitions.

Pipeline and energy services

·	Based on anticipated demand, incremental expansions to the Grasslands Pipeline are forecasted over the next few years. Through additional compression, the pipeline firm capacity could ultimately reach 200,000 Mcf per day, an increase from the current firm capacity of 138,000 Mcf per day.

·	In 2008, total gathering and transportation throughput is expected to be slightly higher than 2007 record levels.

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

·	The labor contract that Williston Basin was negotiating, as reported in Items 1 and 2 – Business and Properties – General in the 2007 Annual Report, has been ratified.

Natural gas and oil production

The Company expects a combined natural gas and oil production increase in 2008 in the range of 12 percent to 16 percent over 2007 levels, including the effects of the acquisition of natural gas production assets in East Texas. Meeting these targets will depend on the success of exploration activities and the timely receipt of regulatory approvals.

The Company expects to participate in approximately 350 to 375 wells in 2008 with varying working interests. The decrease in well counts from the previous estimate is largely the result of the strategic redeployment of certain capital from some of the originally planned drilling activities to the Bakken area where drilling costs per well are considerably higher than many of the areas in which the Company participates.

·	Currently, this segment's net combined natural gas and oil production is approximately 225,000 Mcf equivalents to 240,000 Mcf equivalents per day.

The Company’s combined proved natural gas and oil reserves as of December 31, 2007, were 707 Bcf equivalent. The East Texas property acquisition included an additional 97 Bcf equivalent of proved reserves. The Company is pursuing continued reserve growth through the further exploitation of its existing properties, exploratory drilling and property acquisitions.

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

Index*	Price Per Mcf
Ventura		$7.50 to $8.00
NYMEX		$8.00 to $8.50
CIG		$6.50 to $7.00
* 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.

During 2007, more than three-fourths of natural gas production was priced at non-NYMEX prices, the majority of which was at Ventura pricing.

·	Earnings guidance reflects estimated NYMEX crude oil prices for May through December in the range of $85 to $90 per barrel.

For the last nine months of 2008, the Company has hedged approximately 45 percent to 50 percent of its estimated natural gas production and less than 5 percent of its estimated oil production. Of its estimated 2009 natural gas production, the Company has hedged approximately 25 percent to 30 percent and less than 5 percent for 2010 and 2011. The hedges that are in place as of May 1, 2008, are summarized in the following chart:

Commodity	Index*	Period Outstanding	Forward Notional Volume (MMBtu/Bbl)		Price Swap or Costless Collar Floor-Ceiling (Per MMBtu/Bbl)
Natural Gas	Ventura	4/08 - 10/08		1,070,000		$7.00-$8.05
Natural Gas	Ventura	4/08 - 10/08		1,070,000		$7.00-$8.06
Natural Gas	Ventura	4/08 - 10/08		1,070,000		$7.45
Natural Gas	Ventura	4/08 - 10/08		1,070,000		$7.50-$8.70
Natural Gas	Ventura	4/08 - 10/08		1,070,000		$8.005
Natural Gas	Ventura	4/08 - 10/08		749,000		$7.25-$8.02
Natural Gas	CIG	4/08 - 10/08		749,000		$5.75-$7.40
Natural Gas	Ventura	4/08 - 12/08		1,375,000		$7.00-$8.45
Natural Gas	Ventura	4/08 - 12/08		1,375,000		$7.50-$8.34
Natural Gas	Ventura	4/08 - 12/08		2,475,000		$8.55
Natural Gas	NYMEX	4/08 - 12/08		1,375,000		$7.50-$10.15
Natural Gas	HSC	4/08 - 12/08		1,870,000		$7.91
Natural Gas	CIG	4/08 - 12/08		1,375,000		$6.75-$7.04
Natural Gas	CIG	4/08 - 12/08		1,375,000		$6.35
Natural Gas	CIG	4/08 - 12/08		1,375,000		$6.41
Natural Gas	Ventura	4/08 - 12/08		3,850,000		$9.10
Natural Gas	NYMEX	4/08 - 12/08		1,375,000		$9.00-$10.50
Natural Gas	Ventura	11/08 - 12/08		427,000		$9.25
Natural Gas	Ventura	11/08 - 12/08		610,000		$8.85
Natural Gas	CIG	1/09 - 3/09		225,000		$8.45
Natural Gas	HSC	1/09 - 12/09		2,482,000		$8.16
Natural Gas	Ventura	1/09 - 12/09		1,460,000		$7.90-$8.54
Natural Gas	Ventura	1/09 - 12/09		4,380,000		$8.25-$8.92
Natural Gas	Ventura	1/09 - 12/09		3,650,000		$9.02
Natural Gas	CIG	1/09 - 12/09		3,650,000		$6.50-$7.20
Natural Gas	CIG	1/09 - 12/09		912,500		$7.27
Natural Gas	NYMEX	1/09 - 12/09		1,825,000		$8.75-$10.15
Natural Gas	Ventura	1/09 - 12/09		3,650,000		$9.20
Natural Gas	HSC	1/10 - 12/10		1,606,000		$8.08
Natural Gas	HSC	1/11 - 12/11		1,350,500		$8.00
Crude Oil	NYMEX	4/08 - 12/08		55,000		$67.50-$78.70

* 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 has adversely impacted operations and it is expected that 2008 revenues and earnings will be lower than 2007.

·	The Company continues its strong emphasis on industrial, energy and public works projects and cost containment.

·	Work backlog as of March 31, 2008, was approximately $577 million, compared to $586 million at March 31, 2007. Margins on the backlog have declined as a result of increased competition and a shift of volume to the public sector.

·	A key long-term strategy for the Company is its investment in 1.2 billion tons of strategically located aggregate reserves. The Company remains optimistic about the continued expansion of business through acquisition opportunities.

·	Of the six labor contracts that Knife River was negotiating, as reported in Items 1 and 2 – Business and Properties – General in the 2007 Annual Report, four have been ratified. The two remaining contracts are still in negotiations.

NEW ACCOUNTING STANDARDS

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

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

The Company’s critical accounting policies involving significant estimates include impairment testing of long-lived assets and intangibles, impairment testing of natural gas and oil production properties, revenue recognition, purchase accounting, asset retirement obligations, pension and other postretirement benefits, and income taxes. There were no material changes in the Company’s critical accounting policies involving significant estimates from those reported in the 2007 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2007 Annual Report.

LIQUIDITY AND CAPITAL COMMITMENTS

Cash flows

Operating activities Net income before depreciation, depletion and amortization is a significant contributor to cash flows from 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 2008 increased $36.4 million from the comparable 2007 period, the result of:

·	Higher income from continuing operations of $29.6 million, reflecting increases at all segments except construction materials and contracting which experienced a higher seasonal loss

·	Higher depreciation, depletion and amortization expense of $17.4 million, largely at the natural gas and oil production business

Partially offsetting the increase was the absence in 2008 of the 2007 cash provided by discontinued operations of $5.6 million.

Investing activities Cash flows used in investing activities in the first three months of 2008 increased $221.1 million from the comparable period in 2007, primarily the result of:

·	Increased cash used for acquisitions of $248.4 million, primarily at the natural gas and oil production business

·	Higher ongoing capital expenditures of $41.6 million

Partially offsetting this increase was an increase in cash flows provided by investments of $63.4 million, primarily due to the sale of auction rate securities, partially offset by the proceeds received from the sale of Carib Power in 2007.

Financing activities Cash flows provided by financing activities in the first three months of 2008 increased $171.9 million from the comparable period in 2007, primarily the result of an increase in the issuance of long-term debt of $169.4 million and a decrease in the repayment of long-term debt of $19.8 million. Partially offsetting this increase was a decrease in the issuance of common stock of $12.2 million.

Defined benefit pension plans

There were no material changes to the Company’s qualified noncontributory defined benefit pension plans from those reported in the 2007 Annual Report. For further information, see Note 17 and Part II, Item 7 in the 2007 Annual Report.

Capital expenditures

Net capital expenditures for the first three months of 2008 were $391.9 million and are estimated to be approximately $1.0 billion for 2008. The estimated 2008 capital expenditures exclude proceeds related to the disposal of unidentified assets. Estimated capital expenditures include those for:

·	Completed acquisitions

·	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

Approximately 25 percent of estimated 2008 net capital expenditures referred to previously are associated with completed acquisitions. 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 2008 capital expenditures referred to previously. It is anticipated that all of the funds required for capital expenditures will be met from various sources, including internally generated funds; the Company's credit facilities, as described below; and through the issuance of long-term debt and the Company’s equity securities.

Capital resources

Certain debt instruments of the Company and its subsidiaries, including those discussed below, contain restrictive covenants, all of which the Company and its subsidiaries were in compliance with at March 31, 2008.

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, 2008. The credit agreement supports the Company’s $100 million commercial paper program. Under the Company’s commercial paper program, $56.4 million was outstanding at March 31, 2008. 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. Minor fluctuations in the Company’s credit ratings have not limited, nor would they be expected to limit, the Company’s ability to access the capital markets. In the event of a minor downgrade, the Company may experience a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If the Company were to experience a significant 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 2007 Annual Report. The Company was in compliance with these covenants and met the required conditions at March 31, 2008. In the event the Company does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.

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, 2008, the Company could have issued approximately $555 million of additional first mortgage bonds.

The Company's coverage of fixed charges including preferred dividends was 6.8 times and 6.4 times for the 12 months ended March 31, 2008 and December 31, 2007, respectively. Common stockholders' equity as a percent of total capitalization was 63 percent and 66 percent at March 31, 2008 and December 31, 2007, respectively.

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, 2008, the Company had $50.5 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 $20.5 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, 2008, 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).

The Company has entered into a Sales Agency Financing Agreement, as amended June 25, 2007, with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 3,000,000 shares of the Company’s common stock, par value $1.00 per share, together with preference share purchase rights appurtenant thereto. 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 December 1, 2008. 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 offering would be made pursuant to the Company’s shelf registration statement on Form S-3, as amended, which became effective on September 26, 2003, as supplemented by a prospectus supplement, dated June 28, 2007, filed with the SEC pursuant to Rule 424(b) under the Securities Act of 1933, as amended. The Company has not issued any stock under the Sales Agency Financing Agreement through March 31, 2008.

MDU Energy Capital, LLC MDU Energy Capital has a master shelf agreement that allows for borrowings up to $125 million. Under the terms of the master shelf agreement, $85 million was outstanding at March 31, 2008. 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 2007 Annual Report. MDU Energy Capital was in compliance with these covenants and met the required conditions at March 31, 2008.

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 $50 million credit agreement expires on December 28, 2012, with provisions allowing for an extension of up to two years upon consent of the banks. Cascade also has a $20 million uncommitted line of credit which may be terminated by the bank or Cascade at any time. There were no amounts outstanding under the Cascade credit agreements at March 31, 2008. As of March 31, 2008, there were outstanding letters of credit, as discussed in Note 19, of which $1.9 million reduced amounts available under the $50 million credit agreement.

In order to borrow under Cascade's $50 million 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 $50 million credit agreement, see Part II, Item 8 – Note 9, in the 2007 Annual Report. Cascade was in compliance with these covenants and met the required conditions at March 31, 2008.

Cascade's $50 million credit agreement contains cross-default provisions. These provisions state that if Cascade fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the agreement will be in default. Certain of Cascade's financing agreements and Cascade's practices limit the amount of subsidiary indebtedness.

Centennial Energy Holdings, Inc. Centennial has a revolving credit agreement and an uncommitted line of credit with various banks and institutions totaling $425 million with certain provisions allowing for increased borrowings. These credit agreements support Centennial’s $400 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at March 31, 2008. Under the Centennial commercial paper program, $178.2 million was outstanding at March 31, 2008. 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 Centennial credit agreements). The revolving credit agreement is for $400 million, which 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. The uncommitted line of credit for $25 million may be terminated by the bank at any time. As of March 31, 2008, $42.2 million of letters of credit were outstanding, as discussed in Note 19, of which $24.3 million reduced amounts available under these agreements.

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, $417.5 million was outstanding at March 31, 2008. 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. Minor fluctuations in Centennial’s credit ratings have not limited, nor would they be expected to limit, Centennial’s ability to access the capital markets. In the event of a minor downgrade, Centennial may experience a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If Centennial were to experience a significant downgrade of its credit ratings, it may need to borrow under its committed bank lines.

Prior to the maturity of the Centennial credit agreements, Centennial expects that it will negotiate the extension or replacement of these agreements, which provide credit support to access the capital markets. In the event Centennial was unable to successfully negotiate these agreements, or in the event the fees on such facilities became too expensive, which Centennial does not currently anticipate, it would seek alternative funding.

In order to borrow under Centennial’s credit agreements 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 more information on the covenants and certain other conditions for the $400 million credit agreement and the master shelf agreement, see Part II, Item 8 – Note 10, in the 2007 Annual Report. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at March 31, 2008. In the event Centennial or such subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.

Certain of Centennial’s financing agreements contain cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the applicable agreements will be in default. Certain of Centennial’s financing agreements and Centennial’s practices limit the amount of subsidiary indebtedness.

Williston Basin Interstate Pipeline Company Williston Basin has an uncommitted long-term master shelf agreement that allows for borrowings of up to $100 million. Under the terms of the master shelf agreement, $80.0 million was outstanding at March 31, 2008. The ability to request additional borrowings under this master shelf agreement expires on December 20, 2008.

In order to borrow under its uncommitted long-term master shelf agreement, Williston Basin must be in compliance with the applicable covenants and certain other conditions. For more information on the covenants and certain other conditions for the uncommitted long-term master shelf agreement, see Part II, Item 8 – Note 10, in the 2007 Annual Report. Williston Basin was in compliance with these covenants and met the required conditions at March 31, 2008. In the event Williston Basin does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.

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 19.

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 2007 Annual Report.

For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2007 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 its forecasted sales of natural gas and oil production. Cascade utilizes derivative instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas on its forecasted purchases of natural gas. For more information on derivative instruments and commodity price risk, see Part II, Item 7A in the 2007 Annual Report, and Notes 10 and 13.

The following table summarizes hedge agreements entered into by Fidelity and Cascade as of March 31, 2008. These agreements call for Fidelity to receive fixed prices and pay variable prices, and for Cascade to receive variable prices and pay fixed prices.

(Forward notional volume and fair value in thousands)

Fidelity	Weighted Average Fixed Price (Per MMBtu)	Forward Notional Volume (MMBtu)	Fair Value
Natural gas swap agreements maturing in 2008	$8.10	14,122	$	(21,644	)
Natural gas swap agreements maturing in 2009	$8.49	7,270	$	(5,124	)
Natural gas swap agreements maturing in 2010	$8.08	1,606	$	(1,072	)
Natural gas swap agreements maturing in 2011	$8.00	1,351	$	(668	)

Cascade core
Natural gas swap agreements maturing in 2008	$7.53	12,294	$	22,436
Natural gas swap agreements maturing in 2009	$7.79	13,410	$	12,194
Natural gas swap agreements maturing in 2010	$7.72	5,902	$	1,140

Cascade non-core
Natural gas swap agreements maturing in 2008	$7.91	266	$	298

Fidelity

Weighted

Average

Floor/Ceiling

Price (Per MMBtu/Bbl)

Forward

Notional

Volume

(MMBtu/Bbl)

Fair Value

Natural gas collar agreements maturing in 2008

$7.31/$8.57

11,583

$(15,644)

Natural gas collar agreements maturing in 2009

$7.72/$8.52

11,315

$(8,427)

Oil collar agreement maturing in 2008

$67.50/$78.70

$(1,172)

Interest rate risk

There were no material changes to interest rate risk faced by the Company from those reported in the 2007 Annual Report. For more information on interest rate risk, see Part II, Item 7A in the 2007 Annual Report.

At March 31, 2008 and 2007, and December 31, 2007, 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 on foreign currency risk, see Part II, Item 8 – Note 4 in the 2007 Annual Report.

At March 31, 2008 and 2007, and December 31, 2007, 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. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. 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.

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, 2008, 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 19, 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 2007 Annual Report other than the risk associated with the regulatory approval, permitting, construction, startup and operation of power generation facilities, and the risk related to changes in environmental laws and regulations, as discussed below. 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 regulatory approval, permitting, construction, startup and operation of power generation facilities may involve unanticipated changes or delays that could negatively impact the Company's business, its results of operations and cash flows.

The construction, startup and operation of power generation facilities involves many risks, including: delays; breakdown or failure of equipment; competition; inability to obtain required governmental permits and approvals; inability to negotiate acceptable acquisition, construction, fuel supply, off-take, transmission or other material agreements; changes in market price for power; cost increases; as well as the risk of performance below expected levels of output or efficiency. Such unanticipated events could negatively impact the Company's business, its results of operations and cash flows.

The Company is analyzing potential projects for accommodating load growth and replacing an expired purchased power contract with company-owned generation, which will add base-load capacity and rate base. A potential project is the planned participation in Big Stone Station II. Should regulatory approvals and permits not be received on a timely basis, the project could be at risk and the Company would need to pursue other generation sources.

Environmental and Regulatory Risks

Some of the Company's operations are subject to extensive environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.

The Company is subject to extensive environmental laws and regulations affecting many aspects of its present and future operations including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, and delays as a result of ongoing litigation and administrative proceedings and compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions and CBNG development. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Public officials and entities, as well as private individuals and organizations, may seek injunctive relief or other remedies to enforce applicable environmental laws and regulations. The Company cannot predict the outcome (financial or operational) of any related litigation or administrative proceedings that may arise.

Existing environmental regulations may be revised and new regulations seeking to protect the environment may be adopted or become applicable to the Company. Various proposals related to the emission of greenhouse gases, such as carbon dioxide, are being considered at both the federal and state level. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on the Company's results of operations and cash flows.

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

Between January 1, 2008 and March 31, 2008, the Company issued 73,760 shares of common stock, $1.00 par value, and the preference share purchase rights appurtenant thereto, 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 and preference share purchase rights issued by the Company in these transactions were 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, 2008
February 1 through February 29, 2008
March 1 through March 31, 2008	94,958	$26.66
Total	94,958

(1) Represents shares of common stock withheld by the Company to pay taxes in connection with the vesting of shares granted pursuant to a compensation 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 22, 2008. Two proposals were submitted to stockholders as described in the Company’s Proxy Statement dated March 7, 2008, 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	Against or		Broker
	For	Withheld	Abstentions	Non-Votes
Proposal to elect three directors: For terms expiring in 2009 --
Thomas Everist	162,533,345	2,931,135	---	---
Karen B. Fagg	163,278,794	2,185,686	---	---
Patricia L. Moss	163,030,403	2,434,077	---	---

Proposal to ratify the appointment of Deloitte & Touche LLP as the Company’s independent auditors for 2008	163,200,984	997,719	1,265,777	---

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, 2008	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)	WBI Holdings, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as amended January 31, 2008

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

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

+10(d)	John G. Harp 2008 additional incentive opportunity

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.