MDU RESOURCES GROUP INC - Quarter Report: 2008 September (Form 10-Q)

form_10q.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 September 30, 2008

	OR

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

For the Transition Period from _____________ to ______________

Commission file number 1-3480

MDU Resources Group, Inc.

(Exact name of registrant as specified in its charter)

Delaware		41-0423660
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1200 West Century Avenue

P.O. Box 5650

Bismarck, North Dakota 58506-5650

(Address of principal executive offices)

(Zip Code)

(701) 530-1000

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o.

Indicate by check mark whether the registrant 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 October 29, 2008: 183,661,012 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	Centennial Resources’ equity method investment in companies owning ECTE, ENTE and ERTE
Btu	British thermal unit
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CBNG	Coalbed natural gas
CEM	Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
Centennial	Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital	Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial International	Centennial Energy Resources International, Inc., a direct wholly owned subsidiary of Centennial Resources
Centennial 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
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)
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital (effective October 1, 2008)
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)
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
North Dakota District Court	North Dakota South Central Judicial District Court for Burleigh County
NPRC	Northern Plains Resource Council
NSPS	New Source Performance Standards
OPUC	Oregon Public Utilities Commission
Order on Rehearing	Order on Rehearing and Compliance and Remanding Certain Issues for Hearing
Oregon DEQ	Oregon State Department of Environmental Quality
Prairielands	Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
PSD	Prevention of Significant Deterioration
ROD	Record of Decision
SEC	U.S. Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
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. 109	Accounting for Income Taxes
SFAS No. 115	Accounting for Certain Investments in Debt and Equity Securities
SFAS No. 141 (revised)	Business Combinations (revised 2007)
SFAS No. 157	Fair Value Measurements
SFAS No. 159	The Fair Value Option for Financial Assets and Financial Liabilities
SFAS No. 160	Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51 (Consolidated Financial Statements)
SFAS No. 161	Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133
South Dakota Federal District Court	U.S. District Court for the District of South Dakota

South Dakota SIP	South Dakota State Implementation Plan
TRWUA	Tongue River Water Users’ Association
WBI Holdings	WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
Williston Basin	Williston Basin Interstate Pipeline Company, an indirect wholly owned subsidiary of WBI Holdings
WUTC	Washington Utilities and Transportation Commission
WYPSC	Wyoming Public Service Commission

INTRODUCTION

The Company is a diversified natural resource company, which was incorporated under the laws of the state of Delaware in 1924. Its principal executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.

Montana-Dakota, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. 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.

On October 1, 2008, the Company acquired Intermountain. For further information, see Note 21.

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 16.

INDEX

Part I -- Financial Information	Page

Consolidated Statements of Income --
Three and Nine Months Ended September 30, 2008 and 2007	8

Consolidated Balance Sheets --
September 30, 2008 and 2007, and December 31, 2007	10

Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 2008 and 2007	11

Notes to Consolidated Financial Statements	12

Management's Discussion and Analysis of Financial Condition and Results of Operations	37

Quantitative and Qualitative Disclosures About Market Risk	59

Controls and Procedures	60

Part II -- Other Information

Legal Proceedings	61

Risk Factors	61

Exhibits	64

Signatures	65

Exhibit Index	66

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	268,882	$	235,562	$	1,162,468	$	699,063
Construction services, natural gas and oil production, construction materials and contracting, and other		1,064,952		1,009,748		2,545,045		2,316,103
		1,333,834		1,245,310		3,707,513		3,015,166
Operating expenses:
Fuel and purchased power		19,568		20,331		54,063		52,938
Purchased natural gas sold		65,626		60,887		487,310		200,016
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services		59,818		59,650		181,209		150,967
Construction services, natural gas and oil production, construction materials and contracting, and other		845,673		807,139		2,030,770		1,882,769
Depreciation, depletion and amortization		93,226		78,400		270,135		218,246
Taxes, other than income		46,626		39,747		154,666		109,320
		1,130,537		1,066,154		3,178,153		2,614,256

Operating income		203,297		179,156		529,360		400,910

Earnings from equity method investments		1,867		11,782		5,731		17,867

Other income		395		3,456		1,922		5,670

Interest expense		19,921		19,074		57,762		53,928

Income before income taxes		185,638		175,320		479,251		370,519

Income taxes		67,256		70,823		174,311		142,580

Income from continuing operations		118,382		104,497		304,940		227,939

Income from discontinued operations, net of tax (Note 3)		---		96,765		---		109,459

Net income		118,382		201,262		304,940		337,398

Dividends on preferred stocks		171		172		514		513

Earnings on common stock	$	118,211	$	201,090	$	304,426	$	336,885

(continued on next page)

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME (continued)

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In thousands, except per share amounts)

Earnings per common share -- basic
Earnings before discontinued operations	$	.65	$	.57	$	1.66	$	1.25
Discontinued operations, net of tax		---		.53		---		.60
Earnings per common share -- basic	$	.65	$	1.10	$	1.66	$	1.85
Earnings per common share -- diluted
Earnings before discontinued operations	$	.64	$	.57	$	1.66	$	1.24
Discontinued operations, net of tax		---		.53		---		.60
Earnings per common share -- diluted	$	.64	$	1.10	$	1.66	$	1.84
Dividends per common share	$	.1550	$	.1450	$	.4450	$	.4150
Weighted average common shares outstanding -- basic		183,219		182,192		182,931		181,796
Weighted average common shares outstanding -- diluted		184,081		183,171		183,774		182,780

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2008			September 30, 2007			December 31, 2007
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	57,126		$	94,528		$	105,820
Receivables, net		784,351			748,858			715,484
Inventories		276,138			254,710			229,255
Deferred income taxes		---			---			7,046
Short-term investments		13,271			24,700			91,550
Prepayments and other current assets		189,224			104,721			64,998
Current assets held for sale		---			594			179
		1,320,110			1,228,111			1,214,332
Investments		118,865			112,283			118,602
Property, plant and equipment		6,665,008			5,740,966			5,930,246
Less accumulated depreciation, depletion and amortization		2,483,697			2,203,218			2,270,691
		4,181,311			3,537,748			3,659,555
Deferred charges and other assets:
Goodwill		442,702			430,644			425,698
Other intangible assets, net		30,730			29,115			27,792
Other		161,770			152,607			146,455
Noncurrent assets held for sale		---			140			---
		635,202			612,506			599,945
	$	6,255,488		$	5,490,648		$	5,592,434
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	89,030		$	---		$	1,700
Long-term debt due within one year		87,394			131,971			161,682
Accounts payable		391,188			310,509			369,235
Taxes payable		62,657			114,427			60,407
Deferred income taxes		8,225			3,069			---
Dividends payable		28,572			26,616			26,619
Accrued compensation		62,380			67,225			66,255
Other accrued liabilities		165,072			198,924			163,990
		894,518			852,741			849,888
Long-term debt		1,418,330			1,146,708			1,146,781
Deferred credits and other liabilities:
Deferred income taxes		722,413			629,582			668,016
Other liabilities		430,613			398,353			396,430
		1,153,026			1,027,935			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, 183,770,147 at September 30, 2008, 182,914,769 at September 30, 2007 and 182,946,528 at December 31, 2007		183,770			182,915			182,947
Other paid-in capital		928,415			909,805			912,806
Retained earnings		1,656,767			1,365,497			1,433,585
Accumulated other comprehensive income (loss)		9,288			(6,327	)		(9,393	)
Treasury stock at cost – 538,921 shares		(3,626	)		(3,626	)		(3,626	)
Total common stockholders’ equity		2,774,614			2,448,264			2,516,319
Total stockholders’ equity		2,789,614			2,463,264			2,531,319
	$	6,255,488		$	5,490,648		$	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)

	Nine Months Ended September 30,
	2008			2007
	(In thousands)
Operating activities:
Net income	$	304,940		$	337,398
Income from discontinued operations, net of tax		---			109,459
Income from continuing operations		304,940			227,939
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		270,135			218,246
Earnings, net of distributions, from equity method investments		(1,717	)		(12,448	)
Deferred income taxes		65,698			41,387
Changes in current assets and liabilities, net of acquisitions:
Receivables		(56,931	)		(67,602	)
Inventories		(45,420	)		(35,181	)
Other current assets		(64,568	)		(39,563	)
Accounts payable		651			(19,962	)
Other current liabilities		(23,610	)		40,182
Other noncurrent changes		(341	)		7,230
Net cash provided by continuing operations		448,837			360,228
Net cash used in discontinued operations		---			(46,750	)
Net cash provided by operating activities		448,837			313,478

Investing activities:
Capital expenditures		(558,225	)		(380,087	)
Acquisitions, net of cash acquired		(276,335	)		(341,790	)
Net proceeds from sale or disposition of property		39,531			16,264
Investments		82,507			3,275
Proceeds from sale of equity method investments		---			56,150
Net cash used in continuing operations		(712,522	)		(646,188	)
Net cash provided by discontinued operations		---			548,216
Net cash used in investing activities		(712,522	)		(97,972	)

Financing activities:
Issuance of short-term borrowings		87,330			310,000
Repayment of short-term borrowings		---			(310,000	)
Issuance of long-term debt		351,984			85,000
Repayment of long-term debt		(154,428	)		(226,791	)
Proceeds from issuance of common stock		5,851			16,580
Dividends paid		(80,019	)		(74,025	)
Tax benefit on stock-based compensation		4,349			4,883
Net cash provided by (used in) continuing operations		215,067			(194,353	)
Net cash provided by discontinued operations		---			---
Net cash provided by (used in) financing activities		215,067			(194,353	)
Effect of exchange rate changes on cash and cash equivalents		(76	)		297
Increase (decrease) in cash and cash equivalents		(48,694	)		21,450
Cash and cash equivalents -- beginning of year		105,820			73,078
Cash and cash equivalents -- end of period	$	57,126		$	94,528

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

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

September 30, 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 and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.

2. Seasonality of operations

Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year.

3. 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		Nine Months Ended
	September 30,		September 30,
	2007		2007
	(In thousands)
Operating revenues	$	593	$	1,283
Income from discontinued operations before income tax expense		218		246
Income tax expense		29		--
Income from discontinued operations, net of tax	$	189	$	246

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2007		2007
	(In thousands)
Operating revenues	$	26,980	$	125,867
Income from discontinued operations (including gain on disposal of $142.4 million) before income tax expense		160,612		177,535
Income tax expense		64,036		68,322
Income from discontinued operations, net of tax	$	96,576	$	109,213

The carrying amounts of the assets and liabilities related to Innovatum at September 30, 2007, and December 31, 2007, were not material.

4. Allowance for doubtful accounts

The Company's allowance for doubtful accounts as of September 30, 2008 and 2007, and December 31, 2007, was $13.0 million, $12.2 million and $14.6 million, respectively.

5. Natural gas in storage

Natural gas in storage for the Company's regulated operations is generally carried at cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories and was $41.1 million, $49.1 million and $28.8 million at September 30, 2008 and 2007, and December 31, 2007, respectively. The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $43.0 million, $44.2 million, and $43.0 million at September 30, 2008 and 2007, and December 31, 2007, respectively.

6. Inventories

Inventories, other than natural gas in storage for the Company’s regulated operations, consisted primarily of aggregates held for resale of $101.1 million, $102.4 million and $102.2 million; materials and supplies of $91.4 million, $68.2 million and $56.0 million; and other inventories of $42.5 million, $35.0 million and $42.3 million, as of September 30, 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:

	Nine Months Ended September 30,
	2008		2007
	(In thousands)
Interest, net of amount capitalized	$	59,638	$	55,139
Income taxes	$	117,506	$	153,030

Income taxes paid for the nine months ended September 30, 2008, decreased from the amount paid for the nine months ended September 30, 2007, primarily due to estimated quarterly income tax payments paid in 2007 on the estimated gain on the sale of the domestic independent power production assets as discussed in Note 3.

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 does not expect the adoption of SFAS No. 160 to have a material effect on the Company’s financial position or results of operations.

SFAS No. 161 In March 2008, the FASB issued SFAS No. 161. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This Statement will be effective for the Company on January 1, 2009.

10. Comprehensive income

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

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

	Three Months Ended
	September 30,
	2008			2007
	(In thousands)
Net income	$	118,382		$	201,262
Other comprehensive income:
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain on derivative instruments arising during the period, net of tax of $56,940 and $3,075 in 2008 and 2007, respectively		92,903			4,958
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $(12,955) and $3,247 in 2008 and 2007, respectively		(21,137	)		5,187
Net unrealized gain (loss) on derivative instruments qualifying as hedges		114,040			(229	)
Foreign currency translation adjustment, net of tax of $(4,805) in 2008		(7,461	)		2,795
		106,579			2,566
Comprehensive income	$	224,961		$	203,828

	Nine Months Ended
	September 30,
	2008			2007
	(In thousands)
Net income	$	304,940		$	337,398
Other comprehensive income:
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain on derivative instruments arising during the period, net of tax of $16,811 and $4,066 in 2008 and 2007, respectively		27,462			6,541
Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $3,310 and $9,305 in 2008 and 2007, respectively		5,377			14,864
Net unrealized gain (loss) on derivative instruments qualifying as hedges		22,085			(8,323	)
Foreign currency translation adjustment, net of tax of $(1,928) in 2008		(3,000	)		8,478
		19,085			155
Comprehensive income	$	324,025		$	337,553

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 September 30, 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, which is recorded in earnings from equity method investments on the Consolidated Statements of Income.

At September 30, 2008 and 2007, and December 31, 2007, the Company's equity method investments had total assets of $358.6 million, $380.5 million and $398.4 million, respectively, and long-term debt of $179.0 million, $210.3 million and $211.2 million, respectively. The Company's investment in its equity method investments was approximately $53.7 million, $55.2 million and $59.0 million, including undistributed earnings of $8.6 million, $5.2 million and $6.9 million, at September 30, 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:

	Balance		Goodwill			Balance
	as of		Acquired			as of
Nine Months Ended	January 1,		During			September 30,
September 30, 2008	2008		the Year*			2008
	(In thousands)
Electric	$	---	$	---		$	---
Natural gas distribution		171,129		(11	)		171,118
Construction services		91,385		3,937			95,322
Pipeline and energy services		1,159		---			1,159
Natural gas and oil production		---		---			---
Construction materials and contracting		162,025		13,078			175,103
Other		---		---			---
Total	$	425,698	$	17,004		$	442,702
*Includes purchase price adjustments that were not material related to acquisitions in a prior period.

	Balance		Goodwill		Balance
	as of		Acquired		as of
Nine Months Ended	January 1,		During		September 30,
September 30, 2007	2007		the Year*		2007
	(In thousands)
Electric	$	---	$	---	$	---
Natural gas distribution		---		177,167		177,167
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		24,736		160,933
Other		---		---		---
Total	$	224,298	$	206,346	$	430,644
*Includes purchase price adjustments that were not material related to acquisitions in a prior period.

	Balance		Goodwill		Balance
	as of		Acquired		as of
Year Ended	January 1,		During the		December 31,
December 31, 2007	2007		Year*		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 intangible assets were as follows:

	September 30, 2008			September 30, 2007			December 31, 2007
	(In thousands)
Customer relationships	$	22,719		$	21,518		$	21,834
Accumulated amortization		(6,362	)		(3,609	)		(4,444	)
		16,357			17,909			17,390
Noncompete agreements		9,737			10,596			10,655
Accumulated amortization		(4,714	)		(3,170	)		(3,654	)
		5,023			7,426			7,001
Other		11,220			5,940			5,943
Accumulated amortization		(1,870	)		(2,160	)		(2,542	)
		9,350			3,780			3,401
Total	$	30,730		$	29,115		$	27,792

Amortization expense for amortizable intangible assets for the three and nine months ended September 30, 2008, was $1.0 million and $3.6 million, respectively. Amortization expense for the three and nine months ended September 30, 2007, and for the year ended December 31, 2007, was $1.0 million, $2.9 million and $4.4 million, respectively. Estimated amortization expense for amortizable intangible assets is $4.8 million in 2008, $4.6 million in 2009, $3.7 million in 2010, $3.2 million in 2011, $3.0 million in 2012 and $15.0 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 September 30, 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

At September 30, 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

At September 30, 2008, Fidelity held natural gas and oil swaps, a basis swap and collar agreements designated as cash flow hedging instruments. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on its forecasted sales of natural gas and oil production. These derivative instruments were designated as cash flow hedges of the forecasted sales of the related production.

The fair value of the hedging instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or 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 are generally based on market prices.

For the three and nine months ended September 30, 2008 and 2007, the amount of hedge ineffectiveness was immaterial. For the three and nine months ended September 30, 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 September 30, 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 39 months. The Company estimates that over the next 12 months net gains of approximately $24.0 million (after tax) will be reclassified from accumulated other comprehensive income into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings.

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 plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $30.7 million as of September 30, 2008, are classified as Investments on the Consolidated Balance Sheets. The decrease in the fair value of these investments for the three and nine months ended September 30, 2008, was $3.2 million (before tax) and $5.5 million (before tax),

respectively, which is considered part of the cost of the plan, and is classified in operation and maintenance expense on the Consolidated Statements of Income. The Company did not elect the fair value option for its remaining available-for-sale securities, which are auction rate securities, as they are not intended for long-term investment. The Company’s auction rate securities, which totaled $11.4 million at September 30, 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 September 30, 2008, Using
	Balance at September 30,		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	2008		(Level 1)		(Level 2)		(Level 3)
	(In thousands)
Assets:
Available-for-sale securities	$	42,142	$	30,742	$	11,400	$	---
Commodity derivative agreements		48,596		---		48,596		---
Total assets measured at fair value	$	90,738	$	30,742	$	59,996	$	---
Liabilities:
Commodity derivative agreements	$	56,745	$	---	$	56,745	$	---
Total liabilities measured at fair value	$	56,745	$	---	$	56,745	$	---

The estimated fair value of the Company’s Level 1 available-for-sale securities is based on quoted market prices in active markets for identical equity and fixed-income securities. The estimated fair value of the Company’s Level 2 available-for-sale securities is based on comparable market transactions. The estimated fair value of the Company’s commodity derivative instruments reflects the estimated amounts the Company would receive or pay to terminate the contracts at the reporting date based upon quoted market prices of comparable contracts.

15.	Income taxes

Prior to the sale of the domestic independent power production assets in July 2007, as discussed in Note 3, the Company considered earnings (including the gain from the sale of its foreign equity method investment in a natural gas-fired electric generating facility in Brazil in 2005) to be reinvested indefinitely outside of the United States and, accordingly,

no U.S. deferred income taxes were recorded with respect to such earnings. Following the sale of these assets, the Company reconsidered its long-term plans for future development and expansion of its foreign investment, and determined that it had no immediate plans to explore or invest in additional foreign investments. Therefore, in accordance with SFAS No. 109, deferred income taxes were accrued at that time with respect to the temporary differences which had not been previously recorded. The cumulative undistributed earnings at September 30, 2007, were approximately $36 million. The amount of deferred tax liability, net of allowable foreign tax credits, associated with the undistributed earnings and recognized in the third quarter of 2007 was approximately $10 million. Since the third quarter of 2007 these earnings have been and will continue to be subject to additional U.S. taxes, net of allowable foreign tax credits.

16. Business segment data

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The vast majority of the Company’s operations are located within the United States. The Company also has investments in foreign countries, which largely consist of Centennial Resources’ equity method investment in the Brazilian Transmission Lines.

The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Minnesota, Oregon and Washington. These operations also supply related value-added products and services.

The construction services segment specializes in constructing and maintaining electric, gas pipeline and communication lines, fire protection systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services, inside electrical wiring, cabling and mechanical services, and manufactures and distributes specialty equipment.

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

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

The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated 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 method investment in the Brazilian Transmission Lines.

The information below follows the same accounting policies as described in Note 1 of the Company’s Notes to Consolidated Financial Statements in the 2007 Annual Report. Information on the Company’s businesses was as follows:

			Inter-
	External		segment			Earnings
Three Months	Operating		Operating			on Common
Ended September 30, 2008	Revenues		Revenues			Stock
	(In thousands)
Electric	$	56,011	$	---		$	6,867
Natural gas distribution		94,001		---			(3,362	)
Pipeline and energy services		118,870		15,705			5,669
		268,882		15,705			9,174
Construction services		328,312		198			16,269
Natural gas and oil production		116,650		76,505			57,490
Construction materials and contracting		619,990		---			33,567
Other		---		2,557			1,711
		1,064,952		79,260			109,037
Intersegment eliminations		---		(94,965	)		---
Total	$	1,333,834	$	---		$	118,211


			Inter-
	External		segment			Earnings
Three Months	Operating		Operating			on Common
Ended September 30, 2007	Revenues		Revenues			Stock
	(In thousands)
Electric	$	53,986	$	---		$	5,668
Natural gas distribution		90,706		---			(4,544	)
Pipeline and energy services		90,870		11,627			9,408
		235,562		11,627			10,532
Construction services		293,286		46			13,678
Natural gas and oil production		76,839		46,242			33,182
Construction materials and contracting		639,623		---			50,389
Other		---		2,446			93,309
		1,009,748		48,734			190,558
Intersegment eliminations		---		(60,361	)		---
Total	$	1,245,310	$	---		$	201,090

			Inter-
	External		segment			Earnings
Nine Months	Operating		Operating			on Common
Ended September 30, 2008	Revenues		Revenues			Stock
	(In thousands)
Electric	$	154,140	$	---		$	15,134
Natural gas distribution		653,100		---			18,467
Pipeline and energy services		355,228		68,257			19,665
		1,162,468		68,257			53,266
Construction services		960,331		280			41,172
Natural gas and oil production		336,001		241,935			179,823
Construction materials and contracting		1,248,713		---			25,205
Other		---		7,853			4,960
		2,545,045		250,068			251,160
Intersegment eliminations		---		(318,325	)		---
Total	$	3,707,513	$	---		$	304,426


			Inter-
	External		segment			Earnings
Nine Months	Operating		Operating			on Common
Ended September 30, 2007	Revenues		Revenues			Stock
	(In thousands)
Electric	$	145,681	$	---		$	13,020
Natural gas distribution		280,172		---			1,041
Pipeline and energy services		273,210		54,579			21,346
		699,063		54,579			35,407
Construction services		793,406		520			33,938
Natural gas and oil production		200,032		169,023			98,969
Construction materials and contracting		1,322,665		---			66,135
Other		---		7,326			102,436
		2,316,103		176,869			301,478
Intersegment eliminations		---		(231,448	)		---
Total	$	3,015,166	$	---		$	336,885

The pipeline and energy services segment recognized income from discontinued operations, net of tax, of $189,000 and $246,000 for the three and nine months ended September 30, 2007. The Other category reflects income from discontinued operations, net of tax, of $96.6 million and $109.2 million for the three and nine months ended September 30, 2007.

Excluding the income 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 from construction services, natural gas and oil production, construction materials and contracting, and other are all from nonregulated operations.

17. Acquisitions

During the first nine months of 2008, the Company acquired natural gas properties in Texas and construction materials and contracting businesses in Alaska, California, Idaho and Texas, none 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 $281.4 million. For information regarding the Intermountain acquisition which closed on October 1, 2008, and is not included in the total purchase consideration previously mentioned, see Note 21.

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.

18. Employee benefit plans

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

							Other
							Postretirement
Three Months	Pension Benefits						Benefits
Ended September 30,	2008			2007			2008			2007
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	1,752		$	2,568		$	28		$	446
Interest cost		4,230			5,389			71			1,071
Expected return on assets		(5,272	)		(6,497	)		(81	)		(1,235	)
Amortization of prior service cost (credit)		132			183			(40	)		(662	)
Amortization net actuarial loss		209			582			9			121
Amortization of net transition obligation		---			---			30			496
Net periodic benefit cost, including amount capitalized		1,051			2,225			17			237
Less amount capitalized		132			220			75			104
Net periodic benefit cost	$	919		$	2,005		$	(58	)	$	133

							Other
							Postretirement
Nine Months	Pension Benefits						Benefits
Ended September 30,	2008			2007			2008			2007
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	6,572		$	6,829		$	1,178		$	1,426
Interest cost		15,859			13,752			3,053			3,189
Expected return on assets		(19,766	)		(16,661	)		(3,469	)		(3,607	)
Amortization of prior service cost (credit)		496			599			(1,717	)		(637	)
Amortization net actuarial (gain) loss		783			1,082			370			(28	)
Amortization of net transition obligation		---			---			1,324			1,662
Net periodic benefit cost, including amount capitalized		3,944			5,601			739			2,005
Less amount capitalized		528			588			264			245
Net periodic benefit cost	$	3,416		$	5,013		$	475		$	1,760

In addition to the qualified plan defined pension benefits reflected in the table, the Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that generally provides for defined benefit payments at age 65 following the employee’s retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for this plan for the three and nine months ended September 30, 2008, was $2.0 million and $6.4 million, respectively. The Company’s net periodic benefit cost for this plan for the three and nine months ended September 30, 2007, was $2.1 million and $6.0 million, respectively.

19. Regulatory matters and revenues subject to refund

On August 20, 2008, Montana-Dakota filed an application with the WYPSC for an electric rate increase. Montana-Dakota requested a total increase of $757,000 annually or approximately 4 percent above current rates. An order is anticipated in the second quarter of 2009.

In November 2006, Montana-Dakota filed an application with the NDPSC requesting an advance determination of prudence of Montana-Dakota's ownership interest in Big Stone Station II. Hearings on the application were held in June 2007. In September 2007, Montana-Dakota informed the NDPSC that certain of the other participants in the project had withdrawn and it was considering the impact of these withdrawals on the project and its options. Supplemental hearings before the NDPSC were held in late April 2008 regarding possible plant configuration changes as a result of the participant withdrawals and updated supporting modeling. On August 27, 2008, the NDPSC approved Montana-Dakota’s request for advance determination of prudence for ownership in the proposed Big Stone Station II for a minimum of 121.8 MW up to a maximum of 133 MW and a proportionate ownership share of the associated transmission electric resources. On September 26, 2008, the intervenors in the proceeding appealed the NDPSC order to the North Dakota District Court.

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.

20. 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. Producers, including Fidelity, are operating under an order that allows 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.

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 was released on October 31, 2008, and a ROD is expected in early 2009.

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. As a result of the litigation, Fidelity is operating under an Order, based on a stipulation between the parties, that allows production from existing wells in Fidelity’s Badger Hills Project to continue pending preparation of a revised environmental analysis.

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.

The Powder River Basin Resource Council is funding litigation, filed in Wyoming State District Court in June 2007, on behalf of two surface owners against the Wyoming State Engineer and the Wyoming Board of Control. The plaintiffs seek a declaratory judgment that current ground water permitting practices are unlawful; that the state is required to adopt rules and procedures to ensure that coalbed groundwater is managed in accordance with the Wyoming Constitution and other laws; and that would prohibit the Wyoming State Engineer from issuing permits to produce coalbed groundwater and permits to store coalbed groundwater in reservoirs until the Wyoming State Engineer adopts such rules. The Petroleum Association of Wyoming has conditionally been granted intervention in this lawsuit and Fidelity is partly funding the intervention. On May 29, 2008, the Wyoming State District Court dismissed the case. The plaintiffs appealed to the Wyoming Supreme Court on June 27, 2008. Fidelity’s CBNG operations in Wyoming could be materially adversely affected if the plaintiffs are successful in this lawsuit.

Fidelity will continue to vigorously defend its interests in all CBNG-related litigation in which it is involved, including the proceedings challenging its water permits. In those cases where damage claims have been asserted, Fidelity is unable to quantify the damages sought and will be unable to do so until after the completion of discovery. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could adversely impact Fidelity’s existing CBNG operations and/or the future development of this resource in the affected regions.

Electric Operations 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 North Dakota District Court. 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 North Dakota District Court referenced above is dependant upon the outcome of the proposed rule.

On June 10, 2008, the Sierra Club filed a complaint in the South Dakota Federal District Court against Montana-Dakota and the two other co-owners of the Big Stone Station. The complaint alleges certain violations of the PSD and NSPS provisions of the Clean Air Act and certain violation of the South Dakota SIP. The action further alleges that the Big Stone Station was modified and operated without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. The Sierra Club alleges that these actions have contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. The Sierra Club seeks both declaratory and injunctive relief to bring the co-owners of the Big Stone Station into compliance with the Clean Air Act and the South Dakota SIP and to require them to remedy the alleged violations. The Sierra Club also seeks unspecified civil penalties, including a beneficial mitigation project. The Company believes that these claims are without merit and that Big Stone Station has been and is being operated in compliance with the Clean Air Act and the South Dakota SIP. The ultimate outcome of these matters cannot be determined at this time.

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 September 30, 2008, Williston Basin estimated that between 10.75 and 11.25 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 and on May 9, 2008, the Ninth Circuit affirmed the Montana Federal District Court’s decision.

In related litigation, Howell filed suit in Wyoming State District Court against Williston Basin in February 2006 asserting that it is entitled to produce any gas that might escape from the EBSR. In August 2006, Williston Basin moved for a preliminary injunction to halt Howell and Anadarko’s production in and near the EBSR. The Wyoming State District Court denied Williston Basin’s motion in July 2007. In December 2007, motions were argued to a court appointed special master concerning the application of certain legal principles to the production of Williston Basin’s storage gas, including gas residing outside the certificated boundaries of the EBSR, by Howell and Anadarko. 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 July 1, 2008, the Wyoming State District Court adopted the special master’s report. On July 16, 2008, Williston Basin filed a petition requesting the Wyoming Supreme Court to review a ruling by the Wyoming State District Court that the Natural Gas Act does not preempt the state law that permits an oil and gas producer to take gas that has been dedicated for use in a federally certificated gas storage reservoir. On August 5, 2008, the Wyoming Supreme Court denied the petition. The Wyoming State District Court has scheduled the case for trial beginning March 16, 2009.

In a related proceeding, the FERC issued an order on July 18, 2008, in response to a petition filed by Williston Basin on April 24, 2008, declaring that the certification of a storage facility under the Natural Gas Act conveys to the certificate holder the right to acquire native gas within the certificated boundaries of the storage facility. The FERC also concurred that state law precluding the certificate holder from acquiring the right to native gas would be preempted by federal law.

As previously noted, Williston Basin estimates that as of September 30, 2008, Howell and Anadarko had diverted between 10.75 and 11.25 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.

Expert reports were filed with the Wyoming State District Court in January 2008. Supplemental and rebuttal expert reports were filed September 15, 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 July 2008 is approximately $103 million if injection is completed by the end of the 2010 injection season. Williston Basin's experts also estimate that Williston Basin will expend $6.3 million to mitigate the damages that Williston Basin suffered during the period of Howell and Anadarko’s production if the replacement gas is injected by the end of the 2010 injection season. Williston Basin believes that its experts’ opinions are based on sound law, economics, reservoir engineering, geology and geochemistry. 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.

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 and received authorization from the FERC on October 29, 2008, to lease working gas for the 2008 - 2009 heating season. While installation of the additional compression and leasing working gas provide temporary relief, Williston Basin believes that the adverse physical and operational effects occasioned by the 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. In another effort to protect the viability of the EBSR, Williston Basin, on April 18, 2008, filed an application with the FERC to expand the boundaries of the EBSR. The proposed expansion includes the areas from which Howell and Anadarko are producing.

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 ROD 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 three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade’s predecessors.

The first claim is for soil and groundwater contamination at a site in Oregon and was received in 1995. There are potentially responsible parties in addition to Cascade that may be 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 results of the assessment may affect the selection and implementation of a cleanup alternative.

The second claim is for contamination at a site in Washington and was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants that will require further investigation and cleanup. A supplemental investigation is currently being conducted to better characterize the extent of the contamination. The data from the preliminary investigation indicates other current and former owners of properties and businesses in the vicinity of the site may also be responsible for the contamination. There is currently not enough information to estimate the potential liability associated with this claim.

The third claim is also for contamination at a site in Washington. Cascade received notice from a party in May 2008 that Cascade may be a potentially responsible party, along with other parties, for contamination from a manufactured gas plant owned by Cascade’s predecessor from about 1946 to 1962. The notice indicates that current estimates to

complete investigation and cleanup of the site exceed $8.0 million. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim.

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

Guarantees

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

Centennial 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. Substantial completion of construction is expected to occur during the fourth quarter of 2008, and the warranty period associated with this project will expire one year after the date of substantial completion of 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 September 30, 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 $900,000 and was reflected on the Consolidated Balance Sheets at September 30, 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 September 30, 2008, the fixed maximum amounts guaranteed under these agreements aggregated $291.5 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $4.1 million in 2008; $252.5 million in 2009; $600,000 in 2010; $25.0 million in 2011; $2.3 million in 2012; $800,000 in 2013; $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 $900,000 and was reflected on the Consolidated Balance Sheet at September 30, 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 September 30, 2008, the fixed maximum amounts guaranteed under these letters of credit, aggregated $42.5 million. In 2008 and 2009, $29.6 million and $12.9 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at September 30, 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 September 30, 2008, the fixed maximum amounts guaranteed under these agreements aggregated $24.0 million. Scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $20.0 million in 2009 and $4.0 million in 2011. In the event of Prairielands’ default in its payment obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee. The amount outstanding by Prairielands under the above guarantees was $1.7 million, which was not reflected on the Consolidated Balance Sheet at September 30, 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 September 30, 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 September 30, 2008, approximately $564 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

21. Subsequent event

On October 1, 2008, the acquisition of Intermountain was finalized and Intermountain became an indirect wholly owned subsidiary of the Company. Intermountain is headquartered in Boise, Idaho, and serves more than 300,000 customers in 74 communities in Idaho. The acquisition was a cash-for-stock transaction. The enterprise value of the

transaction, including outstanding indebtedness, is approximately $328 million. Future results of Intermountain will be part of the natural gas distribution segment.

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

OVERVIEW

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

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

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

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

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities and the issuance from time to time of debt securities and the Company’s equity securities. Although volatility in the capital markets has recently increased significantly, the Company continues to issue commercial paper, although at higher interest rates, to meet its current needs. At this time, accessing the long-term debt market may be more challenging and result in significantly higher interest rates. 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 16.

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, the ability of both segments to grow service territory and customer base is affected by the economic environment of the markets served and significant competition from other energy providers, including rural electric cooperatives. The construction of electric generating facilities and transmission lines are subject to increasing cost and lead time, as well as extensive permitting procedures.

Construction Services

Strategy Provide a competitive return on investment while operating in a competitive industry by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; focusing business development efforts on

project areas that will permit higher margins; and properly managing risk. This segment continuously seeks opportunities to expand through strategic acquisitions.

Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel and managing through 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, materials and 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 significant increases in the cost of raw materials such as diesel, gasoline, liquid asphalt and steel. Increased competition in certain construction markets has also lowered margins.

For further information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company’s financial condition, see Part II, Item 1A – Risk Factors, as well as Part I, Item 1A – Risk Factors in the 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						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(Dollars in millions, where applicable)
Electric	$	6.8		$	5.7		$	15.1		$	13.0
Natural gas distribution		(3.4	)		(4.5	)		18.5			1.1
Construction services		16.3			13.7			41.2			33.9
Pipeline and energy services		5.7			9.2			19.7			21.1
Natural gas and oil production		57.5			33.2			179.8			99.0
Construction materials and contracting		33.6			50.4			25.2			66.1
Other		1.7			(3.4	)		4.9			(6.8	)
Earnings before discontinued operations		118.2			104.3			304.4			227.4
Income from discontinued operations, net of tax		---			96.8			---			109.5
Earnings on common stock	$	118.2		$	201.1		$	304.4		$	336.9
Earnings per common share – basic:
Earnings before discontinued operations	$	.65		$	.57		$	1.66		$	1.25
Discontinued operations, net of tax		---			.53			---			.60
Earnings per common share – basic	$	.65		$	1.10		$	1.66		$	1.85
Earnings per common share – diluted:
Earnings before discontinued operations	$	.64		$	.57		$	1.66		$	1.24
Discontinued operations, net of tax		---			.53			---			.60
Earnings per common share – diluted	$	.64		$	1.10		$	1.66		$	1.84
Return on average common equity for the 12 months ended								15.5	%		18.7	%

Three Months Ended September 30, 2008 and 2007 Consolidated earnings for the quarter ended September 30, 2008, decreased $82.9 million from the comparable prior period largely due to:

·	The absence in 2008 of income from discontinued operations net of tax, largely related to the gain on the sale of the Company's domestic independent power production assets, which were sold in the third quarter of 2007, as discussed in Note 3

·	Construction workloads and margins as well as product volumes that were significantly lower at the construction materials and contracting business as a result of the economic downturn primarily as it relates to the residential market

·	The absence in 2008 of the gain of $6.1 million (after tax) related to the sale of Hartwell in 2007, reflected in the Other category

Partially offsetting these decreases were:

·	Higher average natural gas and oil prices of 37 percent and 53 percent, respectively, and increased oil and natural gas production of 29 percent and 2 percent, respectively, partially offset by higher depreciation, depletion and amortization expense at the natural gas and oil production business

·	The absence in 2008 of an income tax adjustment of $10.0 million in 2007 associated with the anticipated repatriation of profits from Brazilian operations as discussed in Note 15, reflected in the Other category

Nine Months Ended September 30, 2008 and 2007 Consolidated earnings for the nine months ended September 30, 2008, decreased $32.5 million largely due to:

·	The absence in 2008 of income from discontinued operations net of tax, as previously discussed

·	Construction workloads and margins as well as product volumes that were significantly lower at the construction materials and contracting business, as previously discussed

·	The absence in 2008 of the gain of $6.1 million (after tax) related to the sale of Hartwell in 2007, reflected in the Other category

Partially offsetting these decreases were:

·	Higher average natural gas and oil prices of 29 percent and 78 percent, respectively, and increased oil and natural gas production of 21 percent and 6 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 distributions business, largely earnings at Cascade, which was acquired on July 2, 2007

·	Higher construction workloads at the construction services business

·	The absence in 2008 of an income tax adjustment of $10.0 million in 2007 associated with the anticipated repatriation of profits from Brazilian operations as discussed in Note 15, reflected in the Other category

FINANCIAL AND OPERATING DATA

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

Electric

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(Dollars in millions, where applicable)
Operating revenues	$	56.0	$	54.0	$	154.1	$	145.7
Operating expenses:
Fuel and purchased power		19.6		20.3		54.0		52.9
Operation and maintenance		15.9		16.0		47.4		45.6
Depreciation, depletion and amortization		6.0		5.7		18.1		16.9
Taxes, other than income		2.2		2.1		6.6		6.4
		43.7		44.1		126.1		121.8
Operating income		12.3		9.9		28.0		23.9
Earnings	$	6.8	$	5.7	$	15.1	$	13.0
Retail sales (million kWh)		660.7		703.5		1,946.2		1,945.5
Sales for resale (million kWh)		58.8		39.2		158.7		130.4
Average cost of fuel and purchased power per kWh	$	.026	$	.027	$	.024	$	.025

Three Months Ended September 30, 2008 and 2007 Electric earnings increased $1.1 million from the comparable prior period largely due to higher retail sales margins, primarily related to the implementation of higher rates in Montana, partially offset by lower retail sales volumes of 6 percent.

Nine Months Ended September 30, 2008 and 2007 Electric earnings increased $2.1 million largely due to:

·	Higher retail sales margins, as previously discussed

·	Higher sales for resale volumes of 22 percent, largely due to the addition of wind-powered electric generation and higher plant availability

Partially offsetting these increases were higher operation and maintenance costs of $1.0 million (after tax), including higher benefit-related costs, as well as increased depreciation, depletion and amortization expense of $800,000 (after tax), largely related to higher property, plant and equipment balances.

Natural Gas Distribution

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(Dollars in millions, where applicable)
Operating revenues	$	94.0		$	90.7		$	653.1		$	280.2
Operating expenses:
Purchased natural gas sold		55.9			53.3			475.9			193.9
Operation and maintenance		26.9			26.6			82.6			57.8
Depreciation, depletion and amortization		7.4			7.1			21.7			12.0
Taxes, other than income		4.7			5.9			30.3			9.1
		94.9			92.9			610.5			272.8
Operating income (loss)		(.9	)		(2.2	)		42.6			7.4
Earnings (loss)	$	(3.4	)	$	(4.5	)	$	18.5		$	1.1
Volumes (MMdk):
Sales		6.4			7.2			53.0			28.4
Transportation		24.9			22.7			70.0			29.0
Total throughput		31.3			29.9			123.0			57.4
Degree days (% of normal)*
Montana-Dakota		70	%		71	%		103	%		93	%
Cascade		111	%		102	%		111	%		102	%
Average cost of natural gas, including transportation, per dk**
Montana-Dakota	$	9.71		$	5.15		$	8.33		$	6.45
Cascade	$	7.80		$	7.60		$	8.03		$	7.60
* 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 September 30, 2008 and 2007 The natural gas distribution business experienced a seasonal loss of $3.4 million in the third quarter of 2008 compared to a loss of $4.5 million in the third quarter of 2007. The decrease in the seasonal loss is largely due to increased transportation volumes and margins as well as higher non-regulated energy-related services.

Nine Months Ended September 30, 2008 and 2007 Earnings at the natural gas distribution business increased $17.4 million due to:

·	Earnings of $15.2 million, including a $4.4 million (after tax) gain on the sale of its natural gas management service, at Cascade since the comparable prior period

·	Increased retail sales volumes from existing operations resulting from colder weather than last year

·	Higher non-regulated energy-related services of $700,000 (after tax)

·	Increased transportation volumes and margins

Partially offsetting these increases was increased operation and maintenance expense from existing operations of $1.1 million (after tax), including higher payroll-related and materials costs.

Construction Services

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(In millions)
Operating revenues	$	328.5	$	293.3	$	960.6	$	793.9
Operating expenses:
Operation and maintenance		288.0		258.1		848.5		700.4
Depreciation, depletion and amortization		3.3		3.5		9.8		10.5
Taxes, other than income		9.5		8.5		31.9		24.8
		300.8		270.1		890.2		735.7
Operating income		27.7		23.2		70.4		58.2
Earnings	$	16.3	$	13.7	$	41.2	$	33.9

Three Months Ended September 30, 2008 and 2007 Construction services earnings increased $2.6 million due to higher construction workloads, largely in the Southwest region.

Nine Months Ended September 30, 2008 and 2007 Construction services earnings increased $7.3 million over the comparable prior period. Higher construction workloads were partially offset by lower construction margins and higher general and administrative expense, largely payroll-related.

Pipeline and Energy Services

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(Dollars in millions)
Operating revenues	$	134.6	$	102.5	$	423.5	$	327.8
Operating expenses:
Purchased natural gas sold		97.6		60.9		308.3		216.3
Operation and maintenance		17.2		17.1		51.4		47.7
Depreciation, depletion and amortization		5.9		5.4		17.4		16.1
Taxes, other than income		2.9		2.7		8.5		8.1
		123.6		86.1		385.6		288.2
Operating income		11.0		16.4		37.9		39.6
Income from continuing operations		5.7		9.2		19.7		21.1
Income from discontinued operations, net of tax		---		.2		---		.3
Earnings	$	5.7	$	9.4	$	19.7	$	21.4
Transportation volumes (MMdk):
Montana-Dakota		8.2		6.6		23.7		21.7
Other		29.1		33.5		77.3		83.7
		37.3		40.1		101.0		105.4
Gathering volumes (MMdk)		26.8		23.5		76.2		68.2

Three Months Ended September 30, 2008 and 2007 Pipeline and energy services experienced a decrease in earnings of $3.7 million compared to the third quarter of 2007 due to:

·	Lower storage services revenue of $1.4 million (after tax), largely due to lower storage balances

·	Decreased volumes transported to storage of 28 percent

·	Increased operation and maintenance cost, including higher legal costs, outside services and payroll-related costs

·	Higher depreciation, depletion and amortization expense of $300,000 (after tax), largely due to higher property, plant and equipment balances

Partially offsetting these decreases were increased off-system transportation and demand fees related to an expansion of the Grasslands system, higher gathering volumes of 14 percent and higher gathering rates.

Results in 2008 reflect the absence of operating revenues as well as operation and maintenance expense related to a non-regulated energy-related service project completed in 2007.

Nine Months Ended September 30, 2008 and 2007 Pipeline and energy services earnings decreased $1.7 million largely due to:

·	Increased operation and maintenance expense of $2.4 million (after tax), including higher material, outside services, payroll-related and legal costs

·	Decreased volumes transported to storage of 35 percent

·	Lower storage services revenue of $900,000 (after tax), largely due to lower storage balances

·	Higher depreciation, depletion and amortization expense of $800,000 (after tax), largely due to higher property, plant and equipment balances

Partially offsetting these decreases were:

·	Higher gathering volumes of 12 percent and higher average gathering rates of $1.0 million (after tax)

·	Increased off-system transportation and demand fees, as previously discussed

Natural Gas and Oil Production

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	121.1	$	86.4	$	379.1	$	276.4
Oil		72.0		36.5		198.7		92.3
Other		.1		.2		.1		.4
		193.2		123.1		577.9		369.1
Operating expenses:
Purchased natural gas sold		---		---		.1		.3
Operation and maintenance:
Lease operating costs		21.0		17.6		58.5		48.7
Gathering and transportation		6.6		5.3		18.5		14.9
Other		10.5		8.9		33.1		26.3
Depreciation, depletion and amortization		44.5		33.2		125.5		92.7
Taxes, other than income:
Production and property taxes		15.5		8.5		45.4		26.7
Other		.2		.1		.7		.6
		98.3		73.6		281.8		210.2
Operating income		94.9		49.5		296.1		158.9
Earnings	$	57.5	$	33.2	$	179.8	$	99.0
Production:
Natural gas (MMcf)		16,188		15,865		49,280		46,536
Oil (MBbls)		729		565		2,067		1,710
Total Production (MMcf equivalent)		20,566		19,256		61,684		56,799
Average realized prices (including hedges):
Natural gas (per Mcf)	$	7.48	$	5.45	$	7.69	$	5.94
Oil (per Bbl)	$	98.61	$	64.54	$	96.09	$	53.94
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	7.84	$	4.51	$	8.02	$	5.35
Oil (per Bbl)	$	99.60	$	64.64	$	97.01	$	53.98
Average depreciation, depletion and amortization rate, per equivalent Mcf	$	2.10	$	1.65	$	1.97	$	1.56
Production costs, including taxes, per net equivalent Mcf:
Lease operating costs	$	1.02	$	.91	$	.95	$	.86
Gathering and transportation		.32		.28		.30		.26
Production and property taxes		.75		.44		.73		.47
	$	2.09	$	1.63	$	1.98	$	1.59

Three Months Ended September 30, 2008 and 2007 Natural gas and oil production earnings increased $24.3 million due to:

·	Higher average realized natural gas prices of 37 percent and higher average realized oil prices of 53 percent

·	Increased oil and natural gas production of 29 percent and 2 percent, respectively, largely related to the East Texas property acquired in January 2008 and additional drilling activity including wells in the Bakken play, South Texas and Paradox Basin

Partially offsetting these increases were:

·	Higher depreciation, depletion and amortization expense of $7.1 million (after tax) due to higher depletion rates and increased production

·	Higher production taxes of $4.3 million (after tax) associated with increased revenue

·	Absence in 2008 of an income tax benefit of $3.1 million received in 2007, due to lower effective state income tax rates

·	Increased lease operating expenses of $2.1 million (after tax)

Nine Months Ended September 30, 2008 and 2007 The natural gas and oil production business experienced an increase in earnings of $80.8 million due to:

·	Higher average realized natural gas prices of 29 percent and higher average realized oil prices of 78 percent

·	Increased oil and natural gas production of 21 percent and 6 percent, respectively, as previously discussed

Partially offsetting these increases were:

·	Higher depreciation, depletion and amortization expense of $20.3 million (after tax) due to higher depletion rates and increased production

·	Higher production taxes of $11.6 million (after tax) associated with increased revenue

·	Increased lease operating expenses of $6.0 million (after tax)

·	Higher general and administrative expense of $4.3 million, including increased outside services and payroll-related costs

·	Absence in 2008 of an income tax benefit of $3.1 million received in 2007, as previously discussed

Construction Materials and Contracting

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(Dollars in millions)
Operating revenues	$	620.0	$	639.6	$	1,248.7	$	1,322.7
Operating expenses:
Operation and maintenance		524.0		519.7		1,085.3		1,101.4
Depreciation, depletion and amortization		25.8		23.2		76.7		69.1
Taxes, other than income		11.6		11.8		31.1		33.4
		561.4		554.7		1,193.1		1,203.9
Operating income		58.6		84.9		55.6		118.8
Earnings	$	33.6	$	50.4	$	25.2	$	66.1
Sales (000's):
Aggregates (tons)		11,100		11,769		24,060		27,665
Asphalt (tons)		2,890		3,330		4,538		5,435
Ready-mixed concrete (cubic yards)		1,244		1,328		2,907		3,046

Three Months Ended September 30, 2008 and 2007 Earnings at the construction materials and contracting business decreased $16.8 million due to:

Decreased construction workloads, margins and product volumes that were significantly lower as a result of the economic downturn, primarily as it relates to the residential market, as well as higher diesel fuel costs at existing operations had a combined negative effect on earnings of $15.8 million (after tax)

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

Nine Months Ended September 30, 2008 and 2007 The construction materials and contracting business experienced a decrease in earnings of $40.9 million due to:

·	Decreased construction workloads, margins and product volumes that were significantly lower, as previously discussed, as well as higher diesel fuel costs at existing operations had a combined negative effect on earnings of $39.0 million (after tax)

·	Higher depreciation, depletion and amortization expense, as previously discussed

Partially offsetting these decreases were earnings from companies acquired since the comparable prior period which contributed 10 percent to earnings for the current period.

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				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(In millions)
Other:
Operating revenues	$	2.5	$	2.4	$	7.9	$	7.3
Operation and maintenance		2.5		4.5		8.0		12.0
Depreciation, depletion and amortization		.3		.3		.9		1.0
Taxes, other than income		---		.1		.2		.2
Intersegment transactions:
Operating revenues	$	95.0	$	60.3	$	318.3	$	231.5
Purchased natural gas sold		87.9		53.3		297.0		210.5
Operation and maintenance		7.1		7.0		21.3		21.0

For further information on intersegment eliminations, see Note 16.

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, 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 growth and earnings projections.

MDU Resources Group, Inc.

·	Earnings per common share for 2008 are projected in the range of $1.95 to $2.10.

·	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. The Company is a participant in the Big Stone Station II project. On June 5, 2008, the MNPUC voted to delay its decision on the Big Stone Station II application for a transmission certificate of need and a route permit. The decision to delay was made so that the MNPUC could receive information from an independent expert on construction costs, natural gas prices and potential costs related to carbon dioxide. A report was issued on October 22, 2008, and project participants are in the process of reviewing the report and preparing a response. A final decision is expected in early 2009. If the decision is to proceed with construction of the plant, it is projected to be completed in 2015. The Company anticipates it would own at least 116 MW of this plant or own other generation sources.

·	On August 20, 2008, Montana-Dakota filed an application with the WYPSC for an electric rate increase, as discussed in Note 19.

·	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, Oregon and Idaho.

·	For more information on the acquisition of Intermountain, see Note 21.

Construction services

·	The Company anticipates margins in 2008 to be comparable to 2007.

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

·	Work backlog as of September 30, 2008, was approximately $608 million, compared to $826 million at September 30, 2007.

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

Pipeline and energy services

Based on the results from a recent open season, an incremental expansion to the Grasslands Pipeline of 75,000 Mcf per day is now anticipated for 2009. The expected in-service date is August 2009, pending regulatory approvals. Through additional compression, the firm capacity of the Grasslands Pipeline will reach full capacity of 213,000 Mcf per day, an increase from the current firm capacity of 138,000 Mcf per day.

The Company is pursuing the development of the Bakken Pipeline, a new natural gas pipeline designed to transport natural gas from the fast-growing Bakken play in northwestern North Dakota and northeastern Montana to a new pipeline interconnect with Alliance Pipeline. The Bakken Pipeline is anticipated to have an initial capacity of approximately 100,000 Mcf per day, with the flexibility to expand capacity to 200,000 Mcf per day. The pipeline project remains subject to shipper commitment and regulatory approvals.

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

Natural gas and oil production

The Company expects a combined natural gas and oil production increase in 2008 in the range of 7 percent to 9 percent over 2007 levels. The decrease from previous guidance relates primarily to the effects of the September hurricanes in the Gulf. A lesser contributing factor is the lower growth expectations for a portion of the Company's exploratory activities.

The Company is involved in exploratory drilling in the Bakken area in North Dakota and in the Paradox Basin in Utah. Net acreage in the Bakken includes approximately 65,000 acres with plans to participate in 50 to 60 wells in 2008, roughly half of which will be operated. The Company is exploring the Three Forks/Sanish formation located below the Bakken formation. If the Three Forks/Sanish formation proves to be a separate reservoir from the Bakken, it would provide additional opportunities to grow reserves and production within its existing leasehold position. In the Paradox Basin, the Company has net acreage of approximately 90,000 acres with plans to spud its sixth well in the fourth quarter.

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

·	Earnings guidance reflects estimated natural gas prices for November and December as follows:

Index*	Price Per Mcf
Ventura	$5.50 to $6.00
NYMEX	$6.00 to $6.50
CIG	$3.25 to $3.75
* 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 November and December in the range of $60 to $65 per barrel.

For the last three months of 2008, the Company has hedged approximately 50 percent to 55 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 35 percent to 40 percent and less than 5 percent for 2010 and 2011. The hedges that are in place as of October 30, 2008, are summarized in the following chart:

Commodity	Type	Index*	Period Outstanding	Forward Notional Volume (MMBtu/Bbl)	Price (Per MMBtu/Bbl)
Natural Gas	Collar	Ventura	10/08	155,000	$7.00-$8.05
Natural Gas	Collar	Ventura	10/08	155,000	$7.00-$8.06
Natural Gas	Swap	Ventura	10/08	155,000	$7.45
Natural Gas	Collar	Ventura	10/08	155,000	$7.50-$8.70
Natural Gas	Swap	Ventura	10/08	155,000	$8.005
Natural Gas	Collar	Ventura	10/08	108,500	$7.25-$8.02
Natural Gas	Collar	CIG	10/08	108,500	$5.75-$7.40
Natural Gas	Collar	Ventura	10/08 - 12/08	460,000	$7.00-$8.45
Natural Gas	Collar	Ventura	10/08 - 12/08	460,000	$7.50-$8.34
Natural Gas	Swap	Ventura	10/08 - 12/08	828,000	$8.55
Natural Gas	Collar	NYMEX	10/08 - 12/08	460,000	$7.50-$10.15
Natural Gas	Swap	HSC	10/08 - 12/08	625,600	$7.91
Natural Gas	Collar	CIG	10/08 - 12/08	460,000	$6.75-$7.04
Natural Gas	Swap	CIG	10/08 - 12/08	460,000	$6.35
Natural Gas	Swap	CIG	10/08 - 12/08	460,000	$6.41
Natural Gas	Swap	Ventura	10/08 - 12/08	1,288,000	$9.10
Natural Gas	Collar	NYMEX	10/08 - 12/08	460,000	$9.00-$10.50
Natural Gas	Swap	Ventura	11/08 - 12/08	427,000	$9.25
Natural Gas	Swap	Ventura	11/08 - 12/08	610,000	$8.85
Natural Gas	Swap	Ventura	11/08 - 12/08	915,000	$12.465
Natural Gas	Swap	CIG	1/09 - 3/09	225,000	$8.45
Natural Gas	Swap	HSC	1/09 - 12/09	2,482,000	$8.16
Natural Gas	Collar	Ventura	1/09 - 12/09	1,460,000	$7.90-$8.54
Natural Gas	Collar	Ventura	1/09 - 12/09	4,380,000	$8.25-$8.92
Natural Gas	Swap	Ventura	1/09 - 12/09	3,650,000	$9.02
Natural Gas	Collar	CIG	1/09 - 12/09	3,650,000	$6.50-$7.20
Natural Gas	Swap	CIG	1/09 - 12/09	912,500	$7.27
Natural Gas	Collar	NYMEX	1/09 - 12/09	1,825,000	$8.75-$10.15
Natural Gas	Swap	Ventura	1/09 - 12/09	3,650,000	$9.20
Natural Gas	Collar	NYMEX	1/09 - 12/09	3,650,000	$11.00-$12.78
Natural Gas	Basis	NYMEX to Ventura	1/09 - 12/09	3,650,000	$0.61
Natural Gas	Swap	HSC	1/10 - 12/10	1,606,000	$8.08
Natural Gas	Swap	HSC	1/11 - 12/11	1,350,500	$8.00
Crude Oil	Collar	NYMEX	10/08 - 12/08	18,400	$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. It is expected that 2008 earnings will be significantly lower than 2007.

The Company continues its strong emphasis on industrial, energy and public works projects and cost containment. It also is pursuing opportunities for expansion of its liquid asphalt materials business to cost effectively meet the liquid asphalt and diesel requirements of the Company, as well as third-party customers.

·	Work backlog as of September 30, 2008, was approximately $557 million, compared to $520 million at September 30, 2007. Margins on the backlog have declined as a result of a shift to more public sector work and increased competition.

·	A key long-term strategy for the Company is growing its 1.2 billion tons of strategically located aggregate reserves.

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 nine months of 2008 increased $135.4 million from the comparable 2007 period, the result of:

·	Higher income from continuing operations of $77.0 million, largely reflecting increases at the natural gas and oil production and natural gas distribution businesses, partially offset by lower income at the construction materials and contracting business

·	The absence in 2008 of cash used in 2007 by discontinued operations of $46.8 million, primarily the result of quarterly income tax payments due to the estimated gain on the sale of the domestic independent power production assets

·	Higher depreciation, depletion and amortization expense of $51.9 million, largely at the natural gas and oil production business

·	Higher deferred income taxes of $24.3 million, largely due to increased capital expenditures at the natural gas and oil production and natural gas distribution businesses

Partially offsetting the increase in cash flows from operating activities was increased cash used for working capital requirements.

Investing activities Cash flows used in investing activities in the first nine months of 2008 increased $614.6 million from the comparable period in 2007, the result of:

·	The absence in 2008 of cash provided in 2007 by discontinued operations of $548.2 million, primarily the result of the sale of the domestic independent power production assets in the third quarter of 2007

·	Increased cash used for capital expenditures of $178.1 million, largely at the natural gas and oil production and natural gas distribution businesses

·	The absence in 2008 of cash provided in 2007 from the proceeds from the sale of equity method investments of $56.2 million

Partially offsetting the increase in cash flows used in investing activities were:

·	An increase in cash flows provided by investments of $79.2 million, primarily due to the sale of auction rate securities

·	A decrease in cash flows used for acquisitions, net of cash acquired, of $65.5 million, largely the absence in 2008 of the Cascade acquisition in the third quarter of 2007, partially offset by acquisitions at the natural gas and oil production business in 2008

·	An increase in the sale or disposition of property of $23.3 million, primarily at the construction materials and contracting and natural gas and oil production businesses

Financing activities Cash flows provided by financing activities in the first nine months of 2008 increased $409.4 million from the comparable period in 2007, the result of an increase in the issuance of long-term debt of $267.0 million and a decrease in the repayment of long-term debt of $72.4 million. Also reflected in the cash flows from financing activities is the issuance of $87.3 million in short-term borrowings and the absence in 2008 of the 2007 issuance and subsequent repayment of short-term borrowings of $310.0 million from the term loan agreement entered into in connection with the funding of the Cascade acquisition.

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 18 and Part II, Item 7 in the 2007 Annual Report.

Capital expenditures

Net capital expenditures for the first nine months of 2008 were $811.3 million and are estimated to be approximately $1.3 billion for 2008. Estimated capital expenditures include:

·	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 45 percent of estimated 2008 net capital expenditures referred to previously are associated with completed acquisitions, including the acquisition of Intermountain. 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 September 30, 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 September 30, 2008. The credit agreement supports the Company’s $125 million commercial paper program. Although volatility in the capital markets has recently increased significantly, the Company continues to issue commercial paper, although at higher interest rates, to meet its current needs. Under the Company’s commercial paper program, $33.5 million was outstanding at September 30, 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 on June 21, 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 September 30, 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.

In connection with the funding of the Intermountain acquisition, on September 26, 2008, the Company entered into a term loan agreement providing for a commitment amount of $175 million. The Company borrowed $170 million under this agreement on October 1, 2008. For more information, see Note 21. The agreement contains customary covenants and default provisions, including covenants of the Company not to permit, as of the end of any fiscal quarter, (i) the ratio of funded debt to total capitalization (on a consolidated basis) to be greater than 65 percent or (ii) the ratio of funded debt to capitalization (determined with respect to the Company only, excluding subsidiaries) to be greater than

65 percent. The agreement also includes a covenant that does not permit the ratio of the Company’s earnings before interest, taxes, depreciation and amortization to interest expense (determined with respect to the Company only, excluding subsidiaries), for the twelve month period ended each fiscal quarter, to be less than 2.5 to 1.

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 September 30, 2008, the Company could have issued approximately $592 million of additional first mortgage bonds.

The Company's coverage of fixed charges including preferred dividends was 7.4 times and 6.4 times for the 12 months ended September 30, 2008 and December 31, 2007, respectively. Common stockholders' equity as a percent of total capitalization was 63 percent and 66 percent at September 30, 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 September 30, 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 September 30, 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).

On September 5, 2008, the Company entered into a Sales Agency Financing Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 5,000,000 shares of the Company’s common stock, par value $1.00 per share, together with preference share purchase rights appurtenant thereto. The agreement replaces a similar agreement with Wells Fargo Securities, LLC for the sale of up to 3,000,000 shares of common stock, which was scheduled to expire on December 1, 2008. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement, which terminates on May 28, 2011. Proceeds from the sale of shares of common stock under the agreement are expected to be used for corporate development purposes and other general corporate purposes. The Company has not issued any stock under the Sales Agency Financing Agreement through September 30, 2008.

On May 28, 2008, the Company filed a registration statement with the SEC, pursuant to Rule 415 under the Securities Act, relating to the possible issuance from time to time of common stock or debt securities of the Company. The amount of securities issuable by the Company is established from time to time by its board of directors. At September 30, 2008, the Company's board of directors had authorized the issuance of up to an aggregate offering price of $1.0 billion of registered securities. The

Company may sell all or a portion of such securities if warranted by market conditions and the Company's capital requirements. Any offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder.

MDU Energy Capital, LLC On October 1, 2008, MDU Energy Capital entered into an amendment to its master shelf agreement which increased the facility amount from $125 million to $175 million. Under the terms of the master shelf agreement, $85.0 million was outstanding at September 30, 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.

On October 1, 2008, MDU Energy Capital borrowed $80.0 million under the agreement. The indebtedness consists of $30 million of senior notes due October 1, 2013, and $50 million of senior notes due October 1, 2015. MDU Energy Capital used the proceeds from the borrowing to pay a dividend to the Company which, in turn, used this dividend to partially fund the acquisition of Intermountain, as previously discussed.

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. In addition, the amendment to the master shelf agreement includes a covenant of MDU Energy Capital not to permit the ratio of Intermountain's total debt (determined on a consolidated basis) to total capitalization to be greater than 65 percent. MDU Energy Capital was in compliance with the applicable covenants and met the required conditions at September 30, 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 credit agreement expires on December 28, 2012, with provisions allowing for an extension of up to two years upon consent of the banks. Under the terms of the credit agreement, $9.1 million was outstanding at September 30, 2008. As of September 30, 2008, there were outstanding letters of credit, as discussed in Note 20, of which $1.9 million reduced amounts available under the credit agreement.

In order to borrow under Cascade's credit agreement, Cascade must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of Cascade's credit agreement, see Part II, Item 8 – Note 9, in the 2007 Annual Report. Cascade was in compliance with these covenants and met the required conditions at September 30, 2008.

Cascade's 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. Although volatility in the capital markets has recently increased

significantly, the Company continues to issue commercial paper, although at higher interest rates, to meet its current needs. There were no outstanding borrowings under the Centennial credit agreements at September 30, 2008. Under the Centennial commercial paper program, $151.5 million was outstanding at September 30, 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 September 30, 2008, Centennial had letters of credit outstanding, as discussed in Note 20, 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, $510.0 million was outstanding at September 30, 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. In the event of a downgrade, Centennial may experience an increase in overall interest rates with respect to its cost of borrowings and may need to borrow under its committed bank lines.

Prior to the maturity of the Centennial credit 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 September 30, 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.

On June 27, 2008, Centennial entered into an $80 million term loan agreement which matures on December 26, 2008. At September 30, 2008, $80.0 million was outstanding under the term loan agreement. The term loan agreement contains customary covenants and default provisions, including a covenant not to permit, as of the end of any fiscal quarter, Centennial’s ratio of total debt to total capitalization to exceed 65 percent. The covenants also include certain limitations on subsidiary indebtedness and restrictions on the sale of certain assets and on the making of certain loans and investments. Centennial was in compliance with these covenants and met the required conditions at September 30, 2008.

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 September 30, 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 September 30, 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 20.

Contractual obligations and commercial commitments

There are no material changes in the Company’s contractual obligations relating to estimated interest payments, operating leases and uncertain tax positions from those reported in the 2007 Annual Report.

At September 30, 2008, there were no material changes to the Company’s contractual obligations relating to purchase commitments, except for the acquisition of Intermountain, which was completed on October 1, 2008. For more information, see Note 21.

The Company’s contractual obligations relating to long-term debt at September 30, 2008, increased $197.3 million or 15 percent from December 31, 2007. At September 30, 2008, the Company’s contractual obligations related to long-term debt aggregated $1,505.7 million. The scheduled amounts of redemption (for the twelve months ended September 30, of each year listed) aggregate $87.4 million in 2009; $22.5 million in 2010; $100.8 million in 2011; $75.4 million in 2012; $436.4 million in 2013; and $783.2 million thereafter.

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 September 30, 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)

	Weighted		Forward
	Average		Notional
	Fixed Price		Volume
	(Per MMBtu)		(MMBtu)		Fair Value
Fidelity
Natural gas swap agreements maturing in 2008	$	8.91		5,924	$	13,401
Natural gas swap agreements maturing in 2009	$	8.73		10,920	$	11,951
Natural gas swap agreements maturing in 2010	$	8.08		1,606	$	(226	)
Natural gas swap agreements maturing in 2011	$	8.00		1,351	$	(307	)
Natural gas basis swap agreement maturing in 2009	$	.61		3,650	$	(1,030	)

Cascade
Natural gas swap agreements maturing in 2008	$	8.48		7,347	$	(17,056	)
Natural gas swap agreements maturing in 2009	$	8.26		19,350	$	(27,359	)
Natural gas swap agreements maturing in 2010	$	8.03		8,922	$	(7,375	)
Natural gas swap agreements maturing in 2011	$	8.10		2,270	$	(1,996	)

	Weighted
	Average		Forward
	Floor/Ceiling		Notional
	Price (Per		Volume
	MMBtu/Bbl)		(MMBtu/Bbl)		Fair Value
Fidelity
Natural gas collar agreements maturing in 2008	$	7.41/$8.71		2,982	$	3,016
Natural gas collar agreements maturing in 2009	$	8.52/$9.56		14,965	$	19,241
Oil collar agreement maturing in 2008	$	67.50/$78.70		18	$	(409	)

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 September 30, 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 September 30, 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 September 30, 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 20, 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; the risk related to economic volatility; the risk related to access to financing sources and capital markets; the risk related to environmental laws and regulations; the risk related to government regulations; and the risk related to litigation with a nonaffiliated natural gas producer; 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 and 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.

Economic volatility affects the Company's operations, as well as the demand for its products and services and, as a result, may have a negative impact on the Company's future revenues and cash flows.

The global demand for natural resources, interest rates, governmental budget constraints and the ongoing threat of terrorism can create volatility in the financial markets. The current economic downturn has negatively affected the level of public and private expenditures on projects and the timing of these projects which, in turn, has negatively affected the demand for certain of the Company's products and services.

The construction materials and contracting segment is experiencing a reduction in construction activity and product sales volumes in some markets due to lower demand, which is negatively affecting the Company's results of operations and cash flows.

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

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

·	A severe prolonged economic downturn

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

·	Further deterioration in capital market conditions

·	Turmoil in the financial services industry

·	Volatility in commodity prices

·	Terrorist attacks

Economic turmoil, market disruptions and volatility in the securities trading markets, as well as other factors including changes in the Company's financial condition, results of operations and prospects, and sales of substantial amounts of the Company's common stock, or the perception that such sales could occur, may adversely affect the market price of the Company's common stock.

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.

The Company is subject to extensive government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party’s ability to acquire the Company.

The Company is subject to regulation by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return, financing, industry rate structures, and recovery of purchased power and purchased gas costs. These governmental regulations significantly influence the Company’s operating environment and may affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on the Company’s results of operations and cash flows. Approval from a number of federal and state regulatory agencies would need to be obtained by any potential acquirer of the Company. The approval process could be lengthy and the outcome uncertain.

Other Risks

One of the Company's subsidiaries is engaged in litigation with a nonaffiliated natural gas producer that has been conducting drilling and production operations that the subsidiary believes is causing diversion and loss of quantities of storage gas from one of its storage reservoirs. If the subsidiary is not able to obtain relief through the courts or the regulatory process, its storage operations could be materially and adversely affected.

Based on relevant information, including reservoir and well pressure data, Williston Basin believes that EBSR pressures have decreased and that the storage reservoir has lost gas and continues to lose gas as a result of the drilling and production activities of Anadarko and its wholly owned subsidiary, Howell. Williston Basin filed suit in Montana Federal District Court seeking to recover unspecified damages from Anadarko and Howell, and to enjoin Anadarko and Howell's present and future production operations in and near the EBSR. This suit was dismissed by the Montana Federal District Court. The dismissal was affirmed by the Ninth Circuit. In related litigation, Howell filed suit in Wyoming State District Court against Williston Basin asserting that it is entitled to produce any gas that might escape from Williston Basin's storage reservoir. Williston Basin has answered Howell's complaint and has asserted counterclaims. If Williston Basin is unable to obtain timely relief through the courts or regulatory process, its present and future gas storage operations, including its ability to meet its contractual storage and transportation obligations to customers, could be materially and adversely affected.

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: November 5, 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.

4(a)	Term Loan Agreement, dated September 26, 2008, among MDU Resources Group, Inc., Wells Fargo Bank, National Association, as Administrative Agent, and The Other Financial Institutions party thereto

4(b)	Amendment No. 1 to Master Shelf Agreement, dated October 1, 2008, among MDU Energy Capital, LLC, Prudential Investment Management, Inc., The Prudential Insurance Company of America, and the holders of the notes thereunder

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

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.