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, 2006~~March 31, 2007

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer x Accelerated filer o Non-accelerated filer o

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 27,~~May 1, ~~2006: 180,881,227~~2007: 181,833,102 shares.

DEFINITIONS

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

Abbreviation or Acronym

~~2005~~2006 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, ~~2005~~2006
ALJ	Administrative Law Judge
~~Alusa~~	~~Tecnica de Engenharia Eletrica - Alusa~~
Anadarko	Anadarko Petroleum Corporation
APB	Accounting Principles Board
~~APB Opinion No. 25~~	~~Accounting for Stock-Based Compensation~~
APB Opinion No. 28	Interim Financial Reporting
Badger Hills Project	Tongue River-Badger Hills Project
~~Bbl~~Bcf	~~Barrel~~Billion cubic feet
BER	Montana Board of Environmental Review
~~Bitter Creek~~Big Stone Station	~~Bitter Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI Holdings~~450-MW coal-fired electric generating facility located near Big Stone City, South Dakota (22.7 percent ownership)
BLM	Bureau of Land Management
~~Brascan~~	~~Brascan Brasil Ltda.~~
Brazilian Transmission Lines	Company’s equity method investment in companies owning ECTE, ENTE and ERTE
~~Brush Generating Facility~~Btu	~~213 MW of natural gas-fired electric generating facilities located near Brush, Colorado~~British thermal unit
Carib Power	Carib Power Management LLC
Cascade	Cascade Natural Gas Corporation
CBNG	Coalbed natural gas
~~CELESC~~	~~Centrais Elétricas de Santa Catarina S.A.~~
CEM	Colorado Energy Management, LLC, a direct wholly owned subsidiary of Centennial Resources
~~CEMIG~~	~~Companhia Energética de Minas Gerais - CEMIG~~
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 direct wholly owned subsidiary of Centennial Resources
Centennial Resources	Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
Clean Air Act	Federal Clean Air Act
Clean Water Act	Federal Clean Water Act
Colorado Federal District Court	U.S. District Court for the District of Colorado
Company	MDU Resources Group, Inc.
D.C. Appeals Court	U.S. Court of Appeals for the District of Columbia Circuit
dk	Decatherm
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.
~~EITF~~	~~Emerging Issues Task Force~~
~~EITF No. 04-6~~	~~Accounting for Stripping Costs in the Mining Industry~~
EIS	Environmental Impact Statement
~~Elk Basin Storage Reservoir~~	~~Natural gas storage reservoir located in Montana and Wyoming owned by Williston Basin~~
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
FIN	FASB Interpretation No.
FIN 48	Accounting for Uncertainty in Income Taxes
Great Plains	Great Plains Natural Gas Co., a public utility division of the Company
Grynberg	Jack J. Grynberg
~~Hardin Generating Facility~~	~~116-MW coal-fired electric generating facility near Hardin, Montana~~
Hart-Scott-Rodino Act	Hart-Scott-Rodino Antitrust Improvements Act
Hartwell	Hartwell Energy Limited Partnership
~~Hobbs Power~~	~~Hobbs Power Funding, LLC, an indirect subsidiary of ArcLight Energy Partners Fund III, L.P.~~
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., ana former indirect wholly owned subsidiary of WBI Holdings (the stock and a portion of Innovatum’s assets were sold during the fourth quarter of 2006)
Knife River	Knife River Corporation, a direct wholly owned subsidiary of Centennial
kW	~~Kilowatts~~Kilowatt
kWh	Kilowatt-hour
~~LPP~~	~~Lea Power Partners, LLC, a direct wholly owned subsidiary of Centennial Power~~
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., ~~formerly Utility Services, Inc. (name change was effective December 23, 2005),~~ a direct wholly owned subsidiary of Centennial
MMBtu	Million Btu
MMcf	Million cubic feet
MMdk	Million decatherms
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
Montana DEQ	Montana State Department of Environmental Quality
Montana Federal District Court	U.S. District Court for the District of Montana
~~MNPUC~~Mortgage	~~Minnesota Public Utilities Commission~~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
~~Nance Petroleum~~	~~Nance Petroleum Corporation, a wholly owned subsidiary of St. Mary~~
ND Health Department	North Dakota Department of Health
NEPA	National Environmental Policy Act
NHPA	National Historic Preservation Act
Ninth Circuit	U.S. Ninth Circuit Court of Appeals
NPRC	Northern Plains Resource Council
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
SEC	U.S. Securities and Exchange Commission
SEIS	Supplemental Environmental Impact Statement
SFAS	Statement of Financial Accounting Standards
SFAS No. 87	Employers’ Accounting for Pensions
SFAS No. 109	Accounting for Income Taxes
SFAS No. ~~123~~	~~Accounting for Stock-Based Compensation~~
~~SFAS No. 123 (revised)~~	~~Share-Based Payment (revised 2004)~~
~~SFAS No.~~ 142	Goodwill and Other Intangible Assets
SFAS No. 144	Accounting for the Impairment ofor Disposal of Long-Lived Assets
SFAS No. ~~148~~157	~~Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123~~Fair Value Measurements
SFAS No. ~~158~~159	~~Employers’ Accounting~~The Fair Value Option for ~~Defined Benefit Pension~~Financial Assets and ~~Other~~ ~~Postretirement Plans~~ Financial Liabilities
SIP	State Implementation Plan
~~St. Mary~~	~~St. Mary Land & Exploration Company~~
~~Termoceara Generating Facility~~	~~220-MW natural gas-fired electric generating facility in the Brazilian state of Ceara (49 percent ownership)~~
~~Trinity Generating Facility~~	~~225-MW natural gas-fired electric generating facility in Trinidad and Tobago (49.99 percent ownership)~~
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
Wyoming Federal District Court	U.S. District Court for the District of Wyoming

INTRODUCTION

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

Montana-Dakota, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added products and services.

The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings (comprised of the pipeline and energy services and the natural gas and oil production segments), Knife River (construction materials and mining segment), MDU Construction Services (construction services segment), Centennial Resources (independent power production segment) and Centennial Capital (reflected in the Other category). For more information on the Company’s business segments, see Note 16.

On May 11, 2006, the Company’s Board of Directors approved a three-for-two common stock split. For more information on the common stock split, see Note 4.

INDEX

Part I -- Financial Information

Consolidated Statements of Income --

Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~

Consolidated Balance Sheets --

~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ and December 31, ~~2005~~2006

Consolidated Statements of Cash Flows --

~~Nine~~Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~

Notes to Consolidated Financial Statements

Management's Discussion and Analysis of Financial

Condition and Results of Operations

Quantitative and Qualitative Disclosures About Market Risk

Controls and Procedures

Part II -- Other Information

Legal Proceedings

Risk Factors

Unregistered Sales of Equity Securities and Use of Proceeds

Submission of Matters to a Vote of Security Holders

Exhibits

Signatures

Exhibit Index

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2007		2006
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	268,011	$	291,052
Construction services, natural gas and oil production, construction materials and mining, and other		519,480		512,467
		787,491		803,519
Operating expenses:
Fuel and purchased power		17,118		16,135
Purchased natural gas sold		98,835		126,960
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services		44,654		37,288
Construction services, natural gas and oil production, construction materials and mining, independent power production and other		445,851		438,847
Depreciation, depletion and amortization		69,802		60,981
Taxes, other than income		32,262		32,240
		708,522		712,451
Operating income		78,969		91,068

Earnings from equity method investments		2,054		3,202

Other income		1,332		2,380

Interest expense		17,376		14,052

Income before income taxes		64,979		82,598

Income taxes		23,572		30,153

Income from continuing operations		41,407		52,445

Income from discontinued operations, net of tax (Note 3)		5,255		801

Net income		46,662		53,246

Dividends on preferred stocks		171		171

Earnings on common stock	$	46,491	$	53,075
Earnings per common share -- basic
Earnings before discontinued operations	$	.23	$	.29
Discontinued operations, net of tax		.03		.01
Earnings per common share -- basic	$	.26	$	.30
Earnings per common share -- diluted
Earnings before discontinued operations	$	.23	$	.29
Discontinued operations, net of tax		.02		---
Earnings per common share -- diluted	$	.25	$	.29
Dividends per common share	$	.1350	$	.1267
Weighted average common shares outstanding -- basic		181,341		179,823
Weighted average common shares outstanding -- diluted		182,337		180,915

Three Months
Ended
September 30,

Nine Months
Ended
September 30,

2006 2005 2006 2005

(In thousands, except per share amounts)

Operating revenues:

Electric, natural gas distribution and pipeline and energy services

$
171,954

$
185,419

$
633,590

$
621,357

Construction services, natural gas and oil production, construction materials and mining, independent power production and other
1,018,682

880,758

2,344,981

1,817,744

1,190,636

1,066,177

2,978,571

2,439,101

Operating expenses:

Fuel and purchased power
20,727

16,286

53,973

47,019

Purchased natural gas sold
28,648

33,235

194,969

193,407

Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services
40,012

38,310

120,112

114,799

Construction services, natural gas and oil production, construction materials and mining, independent power production and other
812,899

735,045

1,906,366

1,501,835

Depreciation, depletion and amortization
71,312

60,504

203,675

164,798

Taxes, other than income
32,476

32,894

98,629

88,099

1,006,074

916,274

2,577,724

2,109,957

Operating income

184,562

149,903

400,847

329,144

Earnings from equity method investments

2,829

1,800

8,931

18,518

Other income

4,502

1,762

9,809

4,418

Interest expense

20,240

14,091

53,402

40,282

Income before income taxes

171,653

139,374

366,185

311,798

Income taxes

61,555

51,851

130,801

109,152

Income from continuing operations

110,098

87,523

235,384

202,646

Loss from discontinued operations, net of tax (Note 3)

(1,611
)

(300
)

(2,208
)

(830
)

Net income

108,487

87,223

233,176

201,816

Dividends on preferred stocks

171

171

514

513

Earnings on common stock

$
108,316

$
87,052

$
232,662

$
201,303

Earnings per common share - basic:

Earnings before discontinued operations
$
.61

$
.49

$
1.30

$
1.14

Discontinued operations, net of tax
(.01
)

---

(.01
)

(.01
)
Earnings per common share - basic
$
.60

$
.49

$
1.29

$
1.13

Earnings per common share - diluted:

Earnings before discontinued operations
$
.61

$
.48

$
1.30

$
1.13

Discontinued operations, net of tax

(.01
)

---

(.01
)

(.01
)
Earnings per common share - diluted
$
.60

$
.48

$
1.29

$
1.12

Dividends per common share

$
.1350

$
.1267

$
.3884

$
.3667

Weighted average common shares outstanding -- basic

180,291

179,429

181,010

177,907

Weighted average common shares outstanding -- diluted

181,307

180,584

181,010

178,953

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2007			March 31, 2006			December 31, 2006
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	51,574		$	107,970			$	73,078
Receivables, net		548,542			542,746				622,478
Inventories		206,250			171,474				204,440
Deferred income taxes		2,702			10,286				---
Prepayments and other current assets		96,766			70,818				81,083
Current assets held for sale		23,871			10,180				12,656
		929,705			913,474				993,735
Investments		133,454			103,404				155,111
Property, plant and equipment		4,850,268			4,293,811				4,727,725
Less accumulated depreciation, depletion and amortization		1,799,770			1,575,110				1,735,302
		3,050,498			2,718,701				2,992,423
Deferred charges and other assets:
Goodwill		226,937			214,967				224,298
Other intangible assets, net		17,929			10,222				22,802
Other		107,639			106,020				103,840
Noncurrent assets held for sale		410,282			415,596				411,265
		762,787			746,805				762,205
	$	4,876,444		$	4,482,384			$	4,903,474
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Long-term debt due within one year	$	83,446		$	101,707			$	84,034
Accounts payable		244,059			225,611				289,836
Taxes payable		67,223			62,466				54,290
Deferred income taxes		---			---				5,969
Dividends payable		24,693			22,964				24,606
Other accrued liabilities		143,045			138,392				180,327
Current liabilities held for sale		19,150			6,397				14,900
		581,616			557,537				653,962
Long-term debt		1,155,117			1,134,889				1,170,548
Deferred credits and other liabilities:
Deferred income taxes		556,522			525,755				546,602
Other liabilities		357,353			278,589				336,916
Noncurrent liabilities held for sale		33,680			29,670				30,533
		947,555			834,014				914,051
Commitments and contingencies
Stockholders’ equity:
Preferred stocks		15,000			15,000				15,000
Common stockholders’ equity:
Common stock
Shares issued -- $1.00 par value 182,319,441 at March 31, 2007, 120,290,305 at March 31, 2006 and 181,557,543 at December 31, 2006		182,319			120,290				181,558
Other paid-in capital		891,990			913,026				874,253
Retained earnings		1,126,270			914,899				1,104,210
Accumulated other comprehensive loss		(19,797	)		(3,645	)			(6,482	)
Treasury stock at cost - 538,921 shares at March 31, 2007 and December 31, 2006 and 359,281 shares at March 31, 2006		(3,626	)		(3,626	)			(3,626	)
Total common stockholders’ equity		2,177,156			1,940,944				2,149,913
Total stockholders’ equity		2,192,156			1,955,944				2,164,913
	$	4,876,444		$	4,482,384			$	4,903,474

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

~~MDU RESOURCES GROUP, INC.~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

September 30,
2006

September 30,
2005

December 31,
2005

(In thousands, except shares and per share amounts)

ASSETS
Current assets:

Cash and cash equivalents
$
70,205

$
98,392

$
107,435

Receivables, net 721,770
632,207

603,959

Inventories 226,398
193,934

172,201

Deferred income taxes 8,698
3,416

9,062

Prepayments and other current assets 80,545
42,100

40,539

1,107,616
970,049

933,196

Investments
155,989
100,954

98,217

Property, plant and equipment
5,044,720
4,397,510

4,594,355

Less accumulated depreciation, depletion and amortization 1,713,860
1,490,465

1,544,462

3,330,860
2,907,045

3,049,893

Deferred charges and other assets:

Goodwill 237,839
214,939

230,865

Other intangible assets, net 29,850
28,487

19,059

Other 104,402
90,256

92,332

372,091
333,682

342,256

$
4,966,556

$
4,311,730

$
4,423,562

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Long-term debt due within one year
$
98,980

$
86,802

$
101,758

Accounts payable 319,415
300,509

269,021

Taxes payable 46,633
75,263

50,533

Dividends payable 24,569
22,935

22,951

Other accrued liabilities 166,582
255,355

184,665

656,179
740,864

628,928

Long-term debt
1,307,050
1,047,245

1,104,752

Deferred credits and other liabilities:

Deferred income taxes 587,001
473,419

526,176

Other liabilities 295,496
264,188

272,084

882,497
737,607

798,260

Commitments and contingencies

Stockholders’ equity:

Preferred stocks 15,000
15,000

15,000

Common stockholders’ equity:
Common stock
Shares issued -- $1.00 par value 181,279,379 at September 30, 2006, 120,191,877 at September 30, 2005 and 120,262,786 at December 31, 2005 181,279
120,192

120,263

Other paid-in capital 872,973
901,302

909,006

Retained earnings 1,046,933
834,567

884,795

Accumulated other comprehensive income (loss) 8,271
(81,421
)

(33,816
)
Treasury stock at cost - 538,921 shares
at September 30, 2006, 359,281 shares at September 30, 2005 and December 31, 2005
(3,626 )
(3,626
)

(3,626
)
Total common stockholders’ equity 2,105,830
1,771,014

1,876,622

Total stockholders’ equity 2,120,830
1,786,014

1,891,622

$
4,966,556

$
4,311,730

$
4,423,562

~~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,						Three Months Ended March 31,
	2006			2005			2007				2006
	(In thousands)						(In thousands)
Operating activities:
Net income	$	233,176		$	201,816			$	46,662		$	53,246
Loss from discontinued operations, net of tax		2,208			830
Income from discontinued operations, net of tax									5,255			801
Income from continuing operations		235,384			202,646				41,407			52,445
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		203,675			164,798				69,802			60,981
Earnings, net of distributions, from equity method investments		(3,164	)		(14,235	)			1,056			(1,017	)
Deferred income taxes		28,945			11,747				13,686			5,850
Changes in current assets and liabilities, net of acquisitions:
Receivables		(102,271	)		(163,007	)			79,780			56,859
Inventories		(51,059	)		(47,781	)			(1,761	)		(260	)
Other current assets		(13,814	)		(1,544	)			(37,931	)		(24,777	)
Accounts payable		65,283			88,358				(48,729	)		(25,553	)
Other current liabilities		12,220			49,585				(25,951	)		10,521
Other noncurrent changes		13,740			13,421				9,174			(358	)
Net cash provided by continuing operations		388,939			303,988				100,533			134,691
Net cash used in discontinued operations		(297	)		(232	)
Net cash provided by (used in) discontinued operations									5,596			(2,900	)
Net cash provided by operating activities		388,642			303,756				106,129			131,791

Investing activities:
Capital expenditures		(398,079	)		(341,532	)			(123,758	)		(115,612	)
Acquisitions, net of cash acquired		(124,240	)		(162,774	)			(320	)		---
Net proceeds from sale or disposition of property		19,342			31,643				3,202			8,813
Investments		(55,956	)		(1,863	)			17,113			(4,408	)
Proceeds from sale of equity method investment		---			38,166
Net cash used in continuing operations		(558,933	)		(436,360	)			(103,763	)		(111,207	)
Net cash used in discontinued operations		(24	)		(77	)			(839	)		(21,276	)
Net cash used in investing activities		(558,957	)		(436,437	)			(104,602	)		(132,483	)

Financing activities:
Issuance of long-term debt		394,504			292,228				8,765			113,006
Repayment of long-term debt		(206,437	)		(104,038	)			(24,692	)		(91,441	)
Proceeds from issuance of common stock		13,255			7,858				13,933			1,698
Dividends paid		(68,881	)		(64,616	)			(24,607	)		(22,950	)
Tax benefit on stock-based compensation		2,050			---				3,566			2,851
Net cash provided by continuing operations		134,491			131,432
Net cash provided by (used in) continuing operations									(23,035	)		3,164
Net cash provided by discontinued operations		248			264				---			---
Net cash provided by financing activities		134,739			131,696
Net cash provided by (used in) financing activities									(23,035	)		3,164
Effect of exchange rate changes on cash and cash equivalents		(1,654	)		---				4			---
Decrease in cash and cash equivalents		(37,230	)		(985	)
Increase (decrease) in cash and cash equivalents									(21,504	)		2,472
Cash and cash equivalents -- beginning of year		107,435			99,377				73,078			105,498
Cash and cash equivalents -- end of period	$	70,205		$	98,392			$	51,574		$	$107,970

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

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~

(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 ~~2005~~2006 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 ~~2005~~2006 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements.

2. Seasonality of operations

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

3. Discontinued operations

~~Innovatum, a component of the pipeline and energy services segment, specializes in cable and pipeline magnetization and location.~~ During the third quarter of 2006, the Company initiated a plan to sell Innovatum ~~within the next year~~ because the Company ~~has~~ determined that Innovatum is a non-strategic asset. Innovatum, a component of the pipeline and energy services segment, specialized in cable and pipeline magnetization and location. During the fourth quarter of 2006, the stock and a portion of the assets of Innovatum were sold and the Company expects to sell the remaining assets of Innovatum within one year of the initial plan to sell. The loss on disposal on the portion of Innovatum that has been sold was not material. The Company does not expect to have any involvement in the operations of Innovatum after the sale.

During the fourth quarter of 2006, the Company initiated a plan to sell certain of the domestic assets of Centennial Resources, which largely comprise the independent power production segment. The plan to sell was based on the increased market demand for independent power production assets, combined with the Company’s desire to efficiently fund future capital needs. The results of operations of these assets were shown in continuing operations in the Company’s financial statements in the 2006 Annual Report as the Company intended to have significant continuing involvement with these assets in the form of continuing existing operation and maintenance agreements between CEM and these assets after the sale.

The Company subsequently committed to a plan to sell CEM due to strong interest in the operations of CEM during the bidding process for the domestic independent power production assets in the first quarter of 2007. As a result of the Company’s commitment to a plan to sell CEM, the Company will no longer have significant continuing involvement in the operations of the other domestic independent power production assets after the sale. Therefore, in accordance with SFAS No. 144, the results of operations of the domestic independent power production assets, including CEM, are presented as discontinued operations. For more information on the pending sale of the domestic independent power production assets, see Note 21.

In accordance with SFAS No. 144, the ~~Consolidated Statements of Income, Consolidated Statements of Cash Flows,~~Company’s consolidated financial statements and ~~related Notes to Consolidated Financial Statements~~accompanying notes for ~~current and~~ prior periods have been restated to present the results of operations of Innovatum and the domestic independent power production assets as a discontinued ~~operation.~~operations. In addition, the assets and liabilities of ~~Innovatum have been~~these operations are treated as held for sale, and as a result, no depreciation, depletion and amortization expense ~~will~~was recorded from the time each of the assets was classified as held for sale, respectively.

In accordance with SFAS No. 142, at the time the Company committed to the plan to sell each of the assets, the Company was required to test the respective assets for goodwill impairment. The fair value of Innovatum, a reporting unit for goodwill impairment testing, was estimated using the expected proceeds from the sale, which was estimated to be ~~recorded. The Company recorded~~the current book value of the assets of Innovatum other than its goodwill. As a result, a goodwill impairment loss of $4.3 million (before tax) during the third quarter of 2006 to write down goodwill (see Note 14), with the remaining assets of Innovatum recorded at net realizable value less estimated selling costs. The loss on the write-down has been excluded from continuing operationswas recognized and recorded inas part of discontinued operations, net of tax, in the Consolidated Statements of ~~Income.~~Income in the third quarter of 2006. There were no goodwill impairments associated with the other assets held for sale.

Operating results related to Innovatum were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2006			2005			2006			2005			2007			2006
	(In thousands)												(In thousands)
Operating revenues	$	654		$	685		$	1,796		$	2,228		$	250		$	509
Loss from discontinued operations		(4,743	)		(435	)		(5,606	)		(1,207	)
Loss from discontinued operations before income tax benefit														(75	)		(473	)
Income tax benefit		3,132			135			3,398			377			(44	)		(149	)
Net loss from discontinued operations	$	(1,611	)	$	(300	)	$	(2,208	)	$	(830	)
Loss from discontinued operations, net of tax													$	(31	)	$	(324	)

~~The income tax benefit for~~Operating results related to the three and nine months ended September 30, 2006, is larger than the customary relationship between the income tax benefit and the loss before tax due to an estimated capital loss tax benefit (which reflects the effect of the $4.0 million and $4.3 million goodwill impairments in 2004 and 2006, respectively) the Company will realize from the sale of the Innovatum stock.domestic independent power production assets were as follows:

	Three Months Ended March 31,
	2007		2006
	(In thousands)
Operating revenues	$	34,596	$	11,266
Income from discontinued operations before income tax expense (benefit)		7,390		492
Income tax expense (benefit)		2,104		(633	)
Income from discontinued operations, net of tax	$	5,286	$	1,125

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

September 30, 2006 September 30, 2005 December 31, 2005
(In thousands)
Inventories
$
1,164

$
1,144

$
988

Other current assets
126

147

863

Net property, plant and equipment
234

416

361

Goodwill
---

4,305

4,305

Deferred charges and other assets
3,491

487

478

Total assets
$
5,015

$
6,499

$
6,995

Current liabilities
$
28

$
203

$
36

Long-term debt
4,013

10,118

3,765

Deferred credits
188

265

209

Total liabilities
$
4,229

$
10,586

$
4,010

	March 31, 2007		March 31, 2006		December 31, 2006
	(In thousands)
Cash and cash equivalents	$	9,991	$	1,779	$	1,878
Receivables, net		6,697		5,251		8,307
Inventories		596		1,007		490
Prepayments and other current assets		6,587		2,143		1,981
Total current assets held for sale	$	23,871	$	10,180	$	12,656
Net property, plant and equipment	$	391,168	$	386,387	$	390,679
Goodwill		11,167		15,472		11,167
Other intangible assets, net		7,241		7,647		7,162
Other		706		6,090		2,257
Total noncurrent assets held for sale	$	410,282	$	415,596	$	411,265
Accounts payable	$	13,717	$	5,763	$	11,557
Other accrued liabilities		5,433		634		3,343
Total current liabilities held for sale	$	19,150	$	6,397	$	14,900
Deferred income taxes	$	29,664	$	27,517	$	27,956
Other liabilities		4,016		2,153		2,577
Total noncurrent liabilities held for sale	$	33,680	$	29,670	$	30,533

4. Common stock split

On May 11, 2006, the Company's Board of Directors approved a three-for-two common stock split to be effected in the form of a 50 percent common stock dividend. The additional shares of common stock were distributed on July 26, 2006, to common stockholders of record on July 12, 2006. Certain common stock information appearing in the accompanying consolidated financial statements has been restated in accordance with accounting principles generally accepted in the United States of America to give retroactive effect to the stock split. Additionally, preference share purchase rights have been appropriately adjusted to reflect the effects of the split.

5. Allowance for doubtful accounts

The Company's allowance for doubtful accounts as of ~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ and December 31, ~~2005,~~2006, was ~~$6.0~~$8.0 million, ~~$8.6~~$7.9 million and ~~$8.0~~$7.7 million, respectively.

6. Natural gas in underground storage

Natural gas in underground storage for the Company's regulated operations is carried at cost using the last-in, first-out method. The portion of the cost of natural gas in underground storage expected to be used within one year was included in inventories and was ~~$43.8~~$3.5 million, ~~$45.0~~$4.7 million and ~~$24.7~~$32.6 million at ~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ and December 31, ~~2005,~~2006, respectively. The remainder of natural gas in underground storage was included in other assets and was $44.2 million, $43.2 million ~~$43.3 million,~~ and ~~$43.2~~$44.2 million at ~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ and December 31, ~~2005,~~2006, respectively.

7. Inventories

Inventories, other than natural gas in underground storage for the Company’s regulated operations, consisted primarily of aggregates held for resale of ~~$92.1~~$95.2 million, ~~$79.5~~$89.3 million and ~~$78.1~~$88.1 million; materials and supplies of ~~$62.6~~$75.4 million, ~~$47.3~~$55.1 million and ~~$48.7~~$54.1 million; and other inventories of ~~$27.9~~$32.1 million, ~~$22.1~~$22.4 million and ~~$20.7~~$29.6 million, as of ~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ and December 31, ~~2005,~~2006, respectively. These inventories were stated at the lower of average cost or market value.

8. 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. For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ there were no shares excluded from the calculation of diluted earnings per share. Common stock outstanding includes issued shares less shares held in treasury.

9.	~~Stock-based compensation~~

On January 1, 2006, the Company adopted SFAS No. 123 (revised). This accounting standard revises SFAS No. 123 and requires entities to recognize compensation expense in an amount equal to the grant-date fair value of share-based payments granted to employees. SFAS No. 123 (revised) was adopted using the modified prospective method, recognizing compensation expense for all awards granted after the date of adoption of the standard and for the unvested portion of previously granted awards that remain outstanding at the date of adoption. In accordance with the modified prospective method, the Company’s consolidated financial statements for prior periods have not been restated to reflect, and do not include, the impact of SFAS No. 123 (revised).

In 2003, the Company adopted the fair value recognition provisions of SFAS No. 123 and began expensing the fair market value of stock options for all awards granted on or after January 1, 2003. As permitted by SFAS No. 148, the Company accounted for stock options granted prior to January 1, 2003, under APB Opinion No. 25. No compensation expense had been recognized for stock options granted prior to January 1, 2003, as the options granted had an exercise price equal to the market value of the underlying common stock on the date of the grant. Compensation expense recognized for stock option awards granted on or after January 1, 2003, for the nine months ended September 30, 2005, was $4,000, net of income taxes of $3,000.

The Company adopted SFAS No. 123, effective January 1, 2003, for newly granted stock options only. The following table illustrates the effect on earnings and earnings per common share for the three and nine months ended September 30, 2005, as if the Company had applied SFAS No. 123 and recognized compensation expense for all outstanding and unvested stock options based on the fair value at the date of grant:

Three Months
Ended
September 30, 2005

Nine Months
Ended
September 30, 2005

(In thousands, except per share amounts)
Earnings on common stock, as reported
$
87,052

$
201,303

Stock-based compensation expense included in reported earnings, net of related tax effects
---

4

Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects
50

(75
)
Pro forma earnings on common stock
$
87,102

$
201,232

Earnings per common share - basic - as reported
$
.49

$
1.13

Earnings per common share - basic - pro forma
$
.49

$
1.13

Earnings per common share - diluted - as reported
$
.48

$
1.12

Earnings per common share - diluted - pro forma
$
.48

$
1.12

Total stock-based compensation expense for the three and nine months ended September 30, 2006, was $848,000 and $3.0 million, net of income taxes of $542,000 and $1.9 million, respectively, including $140,000 and $282,000, net of income taxes of $90,000 and $180,000, respectively, related to stock option awards.

As of September 30, 2006, total remaining unrecognized compensation expense related to stock-based compensation was approximately $5.8 million (before income taxes) which will be amortized over a weighted-average period of 1.8 years.

The Company is authorized to grant options, restricted stock and stock for up to 17.1 million shares of common stock and has granted options, restricted stock and stock on 6.7 million shares through September 30, 2006.

~~The Company generally issues new shares of common stock to satisfy stock option exercises, restricted stock, stock and performance share awards.~~

~~Stock Options~~

The Company has stock option plans for directors, key employees and employees. The Company has not granted stock options since 2003. Options granted to key employees automatically vest after nine years, but the plan provides for accelerated vesting based on the attainment of certain performance goals or upon a change in control of the Company, and expire 10 years after the date of grant. Options granted to directors and employees vest at the date of grant and three years after the date of grant, respectively, and expire 10 years after the date of grant.

~~The fair value of each option outstanding was estimated on the date of grant using the Black-Scholes option-pricing model.~~

~~A summary of the status of the stock option plans for the nine months ended September 30, 2006, was as follows:~~

Weighted
Average
Weighted Remaining
Average Contractual
Exercise Life
Shares Price In Years
Outstanding at beginning of period 2,786,973 $ 12.99
Granted --- ---
Forfeited (89,873 ) 13.05
Exercised (263,746 ) 12.35
Outstanding at end of period 2,433,354 13.06 4.1
Exercisable at end of period 1,352,328 $ 12.61 3.9

~~Summarized information about stock options outstanding and exercisable as of September 30, 2006, was as follows:~~

Options Outstanding Options Exercisable
Remaining Weighted Aggregate Weighted Aggregate
Range of Number Contractual Average Intrinsic Number Average Intrinsic
Exercisable Out- Life Exercise Value Exer- Exercise Value
Prices standing in Years Price (000’s) cisable Price (000’s)
$ 7.28 - 8.00 10,124 0.8
$
7.28

$
152
10,124
$
7.28

$
152

8.01 - 11.00 290,565 1.7 9.60 3,702 287,673 9.60
3,666

11.01 - 14.00 1,877,924 4.4 13.18 17,202 962,831 13.19
8,809

14.01 - 17.13 254,741 4.5 16.32
1,534
91,700 16.54
532

Balance at end of period 2,433,354 4.1
$
13.06

$
22,590
1,352,328
$
12.61

$
13,159

The aggregate intrinsic value in the preceding table represents the total intrinsic value (before income taxes), based on the Company’s stock price on September 30, 2006, which would have been received by the option holders had all option holders exercised their options as of that date.

The Company received cash of $584,000 and $3.3 million from the exercise of stock options for the three and nine months ended September 30, 2006, respectively. The aggregate intrinsic value of options exercised during the three and nine months ended September 30, 2006, was $629,000 and $3.0 million, respectively.

~~Restricted Stock Awards~~

Prior to 2002, the Company granted restricted stock awards under a long-term incentive plan. The restricted stock awards granted vest at various times ranging from one year to nine years from the date of issuance, but certain grants may vest early based upon the attainment of certain performance goals or upon a change in control of the Company. The grant-date fair value is the market price of the Company’s stock on the grant date.

~~A summary of the status of the restricted stock awards for the nine months ended September 30, 2006, was as follows:~~

Weighted
Number Average
of Grant-Date
Shares Fair Value
Nonvested at beginning of period 130,764 $ 10.63
Granted --- ---
Vested (77,106 ) 8.82
Forfeited (21,541 ) 13.22
Nonvested at end of period 32,117 $ 13.22

~~The fair value of restricted stock awards that vested during the nine months ended September 30, 2006, was $1.8 million.~~

~~Stock Awards~~

Nonemployee directors may receive shares of common stock instead of cash in payment for directors' fees under the nonemployee director stock compensation plan. There were 40,500 shares with a fair value of $1.0 million issued under this plan during the nine months ended September 30, 2006.

~~Performance Share Awards~~

Since 2003, key employees of the Company have been awarded performance share awards each year. Entitlement to performance shares is based on the Company's total shareholder return over designated performance periods as measured against a selected peer group. The compensation expense is based on the grant-date fair value.

~~Target grants of performance shares outstanding at September 30, 2006, were as follows:~~


~~Grant Date~~	~~Performance Period~~		~~Target Grant~~ ~~of Shares~~
~~February 2004~~		~~2004-2006~~		~~278,600~~
~~February 2005~~		~~2005-2007~~		~~258,256~~
~~February 2006~~		~~2006-2008~~		~~203,343~~

Participants may earn additional performance shares if the Company's total shareholder return exceeds that of the selected peer group. Compensation expense assumes that the target payout will be achieved. The fair value of performance share awards that vested during the nine months ended September 30, 2006, was $2.2 million.

~~A summary of the status of the performance share awards for the nine months ended September 30, 2006, was as follows:~~

Weighted
Number Average
of Grant-Date
Shares Fair Value
Nonvested at beginning of period 634,275 $ 16.31
Granted 216,970 22.91
Additional performance shares earned 14,522 11.14
Vested (95,792 ) 11.14
Forfeited (29,776 ) 18.76
Nonvested at end of period 740,199 $ 18.72

~~10.~~9. Cash flow information

Cash expenditures for interest and income taxes were as follows:

	Nine Months Ended September 30,				Three Months Ended March 31,
	2006		2005		2007		2006
	(In thousands)				(In thousands)
Interest, net of amount capitalized	$	48,957	$	33,059	$	17,367	$	12,332
Income taxes	$	105,264	$	60,578	$	3,150	$	5,888

~~11.~~10. New accounting standards

~~SFAS No. 123 (revised)~~ In December 2004, the FASB issued SFAS No. 123 (revised). This accounting standard revises SFAS No. 123 and requires entities to recognize compensation expense in an amount equal to the grant-date fair value of share-based payments granted to employees. SFAS No. 123 (revised) was effective for the Company on January 1, 2006. As of the required effective date, the Company applied SFAS No. 123 (revised) using the modified prospective method, recognizing compensation expense for all awards granted after the date of adoption of SFAS No. 123 (revised) and for the unvested portion of previously granted awards that remain outstanding at the date of adoption. The Company used the Black-Scholes option-pricing model to calculate the fair value of stock options. For more information on the adoption of SFAS No. 123 (revised), see Note 9.

~~EITF No. 04-6~~ In March 2005, the FASB ratified EITF No. 04-6. EITF No. 04-6 requires that stripping costs during the production phase of a mine be treated as a variable inventory production cost when incurred. EITF No. 04-6 was effective for the Company on January 1, 2006. The adoption of EITF No. 04-6 did not have a material effect on the Company’s financial position or results of operations.

FIN 48 In July 2006, the FASB issued FIN 48. FIN 48 clarifies the application of SFAS No. 109 by defining a criterion that an individual tax position must meet for any part of the benefit of that position to be recognized in an enterprise’s financial statements. The criterion allows for recognition in the financial statements of a tax position when it is more likely than not that the position will be sustained upon examination. FIN 48 iswas effective for the Company on January 1, 2007. The ~~Company is evaluating the effects of the~~ adoption of FIN ~~48.~~48 did not have a material effect on the Company’s financial position or results of operations. For more information on the implementation of FIN 48, see Note 15.

SFAS No. ~~158~~157 In September 2006, the FASB issued SFAS No. ~~158.~~157. SFAS No. ~~158 requires an employer to recognize the overfunded or underfunded status of~~157 defines fair value, establishes a ~~defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its balance sheet~~framework for measuring fair value and ~~recognize changes in that funded status in the year in which the changes occur through comprehensive income.~~expands disclosures about fair value measurements. The standard ~~also requires an employer to measure the funded status of the plan as of the date of its year-end balance sheet.~~applies under other accounting pronouncements that require or permit fair value measurements with certain exceptions. SFAS No. ~~158~~157 is effective for the Company ~~as of December 31, 2006.~~on January 1, 2008. The Company is evaluating the effects of the adoption of SFAS No. ~~158.~~157.

~~12.~~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 is effective for the Company on January 1, 2008. The Company is evaluating the effects of the adoption of SFAS No. 159.

11. Comprehensive income

Comprehensive income is the sum of net income as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note ~~15.~~14.

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

Three Months Ended
September 30,

2006 2005
(In thousands)
Net income
$
108,487

$
87,223

Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $8,709 and $39,038 in 2006 and 2005, respectively
13,912

(62,360
)
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $2,654 and $3,353 in 2006 and 2005, respectively
4,240

(5,356
)
Net unrealized gain (loss) on derivative instruments qualifying as hedges
9,672

(57,004
)
Foreign currency translation adjustment
(401
)

(70
)

9,271

(57,074
)
Comprehensive income
$
117,758

$
30,149

	Nine Months Ended September 30,						Three Months Ended March 31,
	2006			2005			2007			2006
	(In thousands)						(In thousands)
Net income	$	233,176		$	201,816		$	46,662		$	53,246
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $15,840 and $44,991 in 2006 and 2005, respectively		25,304			(71,869	)
Less: Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $12,121 and $1,895 in 2006 and 2005, respectively		(19,361	)		(3,028	)
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $6,383 and $14,639 in 2007 and 2006, respectively								(10,196	)		23,385
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $3,271 and $4,249 in 2007 and 2006, respectively								5,226			(6,787	)
Net unrealized gain (loss) on derivative instruments qualifying as hedges		44,665			(68,841	)		(15,422	)		30,172
Foreign currency translation adjustment		(2,578	)		(1,089	)		2,107			(1	)
		42,087			(69,930	)		(13,315	)		30,171
Comprehensive income	$	275,263		$	131,886		$	33,347		$	83,417

~~13.~~12. Equity method investments

The ~~Company has~~Company’s equity method investments ~~including a 49.99-percent ownership interest in~~at March 31, 2007, include Hartwell and the Brazilian Transmission Lines.

In February 2004, Centennial International acquired 49.99 percent of Carib ~~Power and a 50-percent ownership interest in Hartwell.~~Power. Carib Power, through a wholly owned subsidiary, owns a 225-MW natural gas-fired electric generating facility in Trinidad and Tobago. On February 26, 2007, the Company sold its interest in Carib Power. The sale did not have a significant effect on the Company’s results of operations.

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. The Company has entered into an agreement to sell its ownership interest in Hartwell. For more information, see Note 21.

OnIn August ~~16,~~ 2006, MDU Brasil acquired ownership interests in companies owning three electric ~~energy~~ 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 ~~energy~~ transmission lines, which are ~~located~~ primarily in northeastern and southern Brazil. The contracts provide for revenues denominated in the Brazilian Real, annual inflation adjustments and change in tax law adjustments and have between 24 and 26 years remaining under the contracts. Alusa, Brascan, and CEMIG hold the remaining ownership interests, with CELESC also having an ownership interest in ECTE. Alusa is the operating partner for the transmission lines.

The Company assesses its equity method investments for impairment whenever events or changes in circumstances indicate that the related carrying values may not be recoverable. None of the Company’s equity method investments have been impaired and, accordingly, no impairment losses have been recorded in the accompanying consolidated financial statements or related equity method investment balances.

In June 2005, the Company completed the sale of its 49 percent interest in MPX to Petrobras, the Brazilian state-controlled energy company. The Company realized a gain of $15.6 million from the sale in the second quarter of 2005. In 2005, the Termoceara Generating Facility was accounted for as an asset held for sale and, as a result, no depreciation, depletion and amortization expense was recorded in 2005.

At ~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ and December 31, ~~2005,~~2006, the ~~Company’s~~Company's equity method investments had total assets of ~~$576.6~~$457.6 million, ~~$244.3~~$233.1 million and ~~$231.9~~$583.6 million, respectively, and long-term debt of ~~$324.3~~$275.5 million, ~~$159.6~~$154.8 million and ~~$154.8~~$321.5 million, respectively. The ~~Company’s~~Company's investment in its equity method investments was approximately ~~$99.2~~$79.6 million, ~~$44.0~~$43.0 million and ~~$41.8~~$102.0 million, including undistributed earnings of ~~$6.6 million, $2.5~~$930,000, $4.5 million and ~~$3.5~~$8.5 million, at ~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ and December 31, ~~2005,~~2006, respectively.

~~14.~~13. Goodwill and other intangible assets

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

	Balance		Goodwill		Goodwill			Balance
	as of		Acquired		Impaired			as of
Nine Months Ended	January 1,		During		During			September 30,
September 30, 2006	2006		the Year*		the Year			2006
Three Months Ended March 31, 2007										Balance as of January 1, 2007		Goodwill Acquired During the Year*			Balance as of March 31, 2007
	(In thousands)									(In thousands)
Electric	$	---	$	---	$	---		$	---	$	---	$	---		$	---
Natural gas distribution		---		---		---			---		---		---			---
Construction services		80,970		5,956		---			86,926		86,942		3,550			90,492
Pipeline and energy services		5,464		---		(4,305	)		1,159		1,159		---			1,159
Natural gas and oil production		---		---		---			---		---		---			---
Construction materials and mining		133,264		5,323		---			138,587		136,197		(911	)		135,286
Independent power production		11,167		---		---			11,167		---		---			---
Other		---		---		---			---		---		---			---
Total	$	230,865	$	11,279	$	(4,305	)	$	237,839	$	224,298	$	2,639		$	226,937

Nine Months Ended	Balance as of January 1,		Goodwill Acquired During			Balance as of September 30,
September 30, 2005	2005		the Year*			2005
Three Months Ended March 31, 2006								Balance as of January 1, 2006		Goodwill Acquired During the Year*			Balance as of March 31, 2006
	(In thousands)							(In thousands)
Electric	$	---	$	---		$	---	$	---	$	---		$	---
Natural gas distribution		---		---			---		---		---			---
Construction services		62,632		12,102			74,734		80,970		137			81,107
Pipeline and energy services		5,464		---			5,464		1,159		---			1,159
Natural gas and oil production		---		---			---		---		---			---
Construction materials and mining		120,452		3,122			123,574		133,264		(563	)		132,701
Independent power production		11,195		(28	)		11,167		---		---			---
Other		---		---			---		---		---			---
Total	$	199,743	$	15,196		$	214,939	$	215,393	$	(426	)	$	214,967

	Balance		Goodwill			Balance
	as of		Acquired			as of
Year Ended	January 1,		During			December 31,
December 31, 2005	2005		the Year*			2005
Year Ended December 31, 2006								Balance as of January 1, 2006		Goodwill Acquired During the Year*		Balance as of December 31, 2006
	(In thousands)							(In thousands)
Electric	$	---	$	---		$	---	$	---	$	---	$	---
Natural gas distribution		---		---			---		---		---		---
Construction services		62,632		18,338			80,970		80,970		5,972		86,942
Pipeline and energy services		5,464		---			5,464		1,159		---		1,159
Natural gas and oil production		---		---			---		---		---		---
Construction materials and mining		120,452		12,812			133,264		133,264		2,933		136,197
Independent power production		11,195		(28	)		11,167		---		---		---
Other		---		---			---		---		---		---
Total	$	199,743	$	31,122		$	230,865	$	215,393	$	8,905	$	224,298

Includes purchase price adjustments that were not material related to acquisitions in a prior period.

During the third quarter of 2006, the Company initiated a plan to sell Innovatum which is a reporting unit for goodwill impairment testing and part of the pipeline and energy services segment. In accordance with SFAS No. 142, the Company was required to test Innovatum for impairment at the time that the Company committed to the plan to sell. The fair value of Innovatum was estimated using the expected proceeds from the sale which is estimated to be the current book value of the assets of Innovatum other than its goodwill. As a result, a goodwill impairment loss of $4.3 million (before tax) was recognized in the third quarter of 2006. For more information on Innovatum, see Note 3.

Other intangible assets were as follows:

	September 30, 2006			September 30, 2005			December 31, 2005			March 31, 2007			March 31, 2006			December 31, 2006
	(In thousands)									(In thousands)
Amortizable intangible assets:
Acquired contracts	$	20,651		$	18,707		$	18,065
Customer relationships										$	13,959		$	4,400		$	13,030
Accumulated amortization		(9,958	)		(7,640	)		(9,458	)		(2,628	)		(620	)		(1,890	)
		10,693			11,067			8,607			11,331			3,780			11,140
Noncompete agreements		12,886			11,784			11,784			5,045			11,784			12,886
Accumulated amortization											(1,873	)		(8,680	)		(8,540	)
											3,172			3,104			4,346
Acquired contracts											1,186			3,504			8,307
Accumulated amortization		(9,104	)		(8,434	)		(8,557	)		(1,118	)		(3,150	)		(4,646	)
		3,782			3,350			3,227			68			354			3,661
Other		17,208			14,699			7,914			4,842			3,162			5,062
Accumulated amortization		(2,357	)		(1,480	)		(1,213	)		(1,484	)		(702	)		(1,407	)
		14,851			13,219			6,701			3,358			2,460			3,655
Unamortizable intangible assets		524			851			524			---			524			---
Total	$	29,850		$	28,487		$	19,059		$	17,929		$	10,222		$	22,802

The unamortizable intangible assets at March 31, 2006, were recognized in accordance with SFAS No. 87, which requires that if an additional minimum liability is recognized, an equal amount shall be recognized as an intangible asset provided that the asset recognized shall not exceed the amount of unrecognized prior service cost. ~~The unamortizable intangible asset will be eliminated or adjusted as necessary upon a new determination of the amount of additional liability.~~

Amortization expense for amortizable intangible assets for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2007 and 2006, ~~was $1.5 million and $4.3 million, respectively. Amortization expense for the three and nine months ended September 30, 2005,~~ and for the year ended December 31, ~~2005,~~2006, was ~~$1.8~~$1.0 million, ~~$3.9 million~~$863,000 and ~~$5.5~~$4.3 million, respectively. Estimated amortization expense for amortizable intangible assets is ~~$5.6 million in 2006, $6.2~~$3.7 million in 2007, ~~$5.2~~$2.8 million in 2008, ~~$4.2~~$2.4 million in 2009, ~~$3.6~~$1.9 million in 2010, $1.5 million in 2011 and ~~$8.8~~$6.6 million thereafter.

~~15.~~14. 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, 2006,~~March 31, 2007, the Company had no outstanding foreign currency or interest rate hedges. The following information should be read in conjunction with Notes 1 and 57 in the Company's Notes to Consolidated Financial Statements in the ~~2005~~2006 Annual Report.

~~Historically,~~At March 31, 2007, Fidelity ~~has~~ held ~~derivative instruments designated as cash flow hedging instruments. However, in the second quarter of 2006, the oil~~natural gas swap and collar ~~agreements became ineffective and no longer qualified for hedge accounting, as discussed below. At September 30, 2006, Fidelity held~~ derivative instruments designated as cash flow hedging instruments ~~as well as~~and had no outstanding oil derivative ~~instruments that did not qualify for hedge accounting.~~instruments.

Hedging activities

Fidelity utilizes natural gas and oil price swap and collar agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on its forecasted sales of natural gas and oil production. Each of the ~~natural gas and oil~~ price swap and collar agreements was designated as a hedge of the forecasted sale of ~~natural gas and oil~~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 production 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 the Company receives for its natural gas and oil production are also generally based on market prices.

For the three ~~and nine~~ months ended ~~September 30, 2005,~~March 31, 2007 and 2006, the amount of hedge ineffectiveness was immaterial. However, in the second quarter of 2006, the oil collar agreements became ineffective and no longer qualified for hedge accounting. The oil hedges became ineffective as the physical price received no longer correlated to the hedge price due to the widening of regional basis differentials on the price of the physical production received. The ineffectiveness related to these collar agreements resulted in a gain of approximately $841,000 (before tax) forFor the three months ended ~~September 30,~~March 31, 2007 and 2006, and a loss of approximately $138,000 (before tax) for the nine months ended September 30, 2006. The ineffectiveness related to these collar agreements was recorded in operation and maintenance expense. The amount of hedge ineffectiveness on Fidelity’s remaining hedges was immaterial for the three and nine months ended September 30, 2006.

~~For the three and nine months ended September 30, 2006 and 2005,~~ Fidelity did not exclude any components of the derivative instruments’ gain or loss 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, 2006,~~March 31, 2007, the maximum term of Fidelity’s swap and collar agreements, in which Fidelity is hedging its exposure to the variability in future cash flows for forecasted transactions, is 1521 months. The Company estimates that over the next 12 months net gains of approximately ~~$15.9~~$6.0 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.

15.Uncertainty in income taxes

On January 1, 2007, the Company adopted FIN 48 as discussed in Note 10.

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state, local and foreign jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years ending prior to 2003.

Upon the adoption of FIN 48, the Company recognized a decrease in the liability for unrecognized tax benefits, which was not material, and was accounted for as an increase to the January 1, 2007, balance of retained earnings. At the date of adoption, the amount of unrecognized tax benefits was $4.5 million.

Included in the balance of unrecognized tax benefits at the date of adoption are $3.0 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The amount of unrecognized tax benefits at the date of adoption that, if recognized, would affect the effective tax rate was $1.5 million, including $304,000 for the payment of interest and penalties. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.

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 investments in transmission and natural resource-based projects.

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 western Minnesota. These operations also supply related value-added products and services.

The construction services segment specializes in ~~electrical~~electric line ~~construction;~~construction, pipeline ~~construction;~~construction, inside electrical wiring, cabling and mechanical ~~services;~~work, fire protection and the manufacture and distribution of specialty equipment.

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

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

The construction materials and mining 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, as well as~~products. It also performs integrated construction ~~services~~services. The construction materials and mining segment operates in the central, southern and western United States and in Alaska and Hawaii.

The independent power production segment owns, builds and operates electric generating facilities in the United States and has domestic and international investments including transmission and natural resource-based projects. Electric capacity and energy produced at its power plants primarily are sold under mid- and long-term contracts to nonaffiliated entities. For more information regarding the discontinued operations of this segment, see Note 3.

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 information below follows the same accounting policies as described in Note 1 of the Company’s Notes to Consolidated Financial Statements in the ~~2005~~2006 Annual Report. Information on the Company’s businesses was as follows:

			Inter-
Three Months	External Operating		segment Operating			Earnings on Common
Ended September 30, 2006	Revenues		Revenues			Stock
Three Months Ended March 31, 2007									External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)								(In thousands)
Electric	$	53,204	$	---		$	5,698		$	47,104	$	---		$	3,784
Natural gas distribution		31,378		---			(2,347	)		136,061		---			6,145
Pipeline and energy services		87,372		16,434			7,141			84,846		28,292			5,710
		171,954		16,434			10,492			268,011		28,292			15,639
Construction services		262,188		139			8,300			236,638		125			7,234
Natural gas and oil production		71,885		50,607			35,012			55,269		63,311			30,621
Construction materials and mining		667,651		---			52,520			227,573		---			(9,796	)
Independent power production		16,958		---			1,714			---		---			2,517
Other		---		1,773			278			---		2,440			276
		1,018,682		52,519			97,824			519,480		65,876			30,852
Intersegment eliminations		---		(68,953	)		---			---		(94,168	)		---
Total	$	1,190,636	$	---		$	108,316		$	787,491	$	---		$	46,491

Inter-
Three Months
External
Operating

segment
Operating
Earnings on Common
Ended September 30, 2005 Revenues Revenues Stock
(In thousands)
Electric
$
50,195

$
---

$
6,169

Natural gas distribution
34,014

---

(3,016
)
Pipeline and energy services
101,210

17,086

5,282

185,419

17,086

8,435

Construction services
207,259

162

5,131

Natural gas and oil production
48,867

67,517

35,450

Construction materials and mining
610,499

---

34,120

Independent power production
14,133

---

3,730

Other
---

1,580

186

880,758

69,259

78,617

Intersegment eliminations
---

(86,345
)

---

Total
$
1,066,177

$
---

$
87,052

Inter-
Nine Months
External
Operating

segment
Operating
Earnings on Common
Ended September 30, 2006 Revenues Revenues Stock
(In thousands)
Electric
$
139,109

$
---

$
10,003

Natural gas distribution
229,497

---

446

Pipeline and energy services
264,984

67,808

17,290

633,590

67,808

27,739

Construction services
728,936

385

23,377

Natural gas and oil production
189,890

175,104

107,249

Construction materials and mining
1,386,214

---

68,957

Independent power production
39,941

---

4,560

Other
---

5,861

780

2,344,981

181,350

204,923

Intersegment eliminations
---

(249,158
)

---

Total
$
2,978,571

$
---

$
232,662

			Inter-
Nine Months	External Operating		segment Operating			Earnings on Common
Ended September 30, 2005	Revenues		Revenues			Stock
Three Months Ended March 31, 2006								External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)							(In thousands)
Electric	$	135,566	$	---		$	11,057	$	45,030	$	---		$	3,797
Natural gas distribution		233,679		---			523		152,279		---			5,321
Pipeline and energy services		252,112		58,889			17,245		93,743		32,806			4,569
		621,357		58,889			28,825		291,052		32,806			13,687
Construction services		457,879		294			10,748		223,685		110			5,398
Natural gas and oil production		130,664		170,542			94,204		55,098		73,292			41,258
Construction materials and mining		1,191,601		7			44,005		233,684		---			(8,874	)
Independent power production		37,600		---			23,069		---		---			1,342
Other		---		4,315			452		---		1,769			264
		1,817,744		175,158			172,478		512,467		75,171			39,388
Intersegment eliminations		---		(234,047	)		---		---		(107,977	)		---
Total	$	2,439,101	$	---		$	201,303	$	803,519	$	---		$	53,075

The pipeline and energy services segment recognized a loss from discontinued operations, net of tax, of ~~$1.6~~$31,000 and $324,000 for the three months ended March 31, 2007 and 2006, respectively. The independent power production segment recognized income from discontinued operations, net of tax, of $5.3 million and ~~$2.2~~$1.1 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2007 and 2006, ~~respectively, and $300,000 and $830,000 for the three and nine months ended September 30, 2005,~~ respectively. Excluding the loss from discontinued operations at pipeline and energy services, earnings ~~(loss)~~ from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings (loss) from construction services, natural gas and oil production, construction materials and mining, independent power production, and other are all from nonregulated operations.

17. ~~Acquisitions~~

During the first nine months of 2006, the Company acquired a construction services business in Nevada, natural gas and oil properties in Wyoming, construction materials and mining businesses in California and Washington, and a natural gas-fired electric generating facility in California at the independent power production segment, none of which was material. The total purchase consideration for these businesses and properties and purchase price adjustments with respect to certain other acquisitions made prior to 2006, consisting of the Company's common stock and cash, was $131.0 million.

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

~~18.~~ E~~mployee~~Employee benefit plans

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

Three Months Pension Benefits
Other
Postretirement
Benefits

Ended September 30, 2006 2005 2006 2005
(In thousands)
Components of net periodic benefit cost (income):
Service cost
$
3,197

$
2,084

$
782

$
211

Interest cost
5,861

4,155

1,107

666

Expected return on assets
(7,983
)

(4,987
)

(1,643
)

(979
)
Amortization of prior service cost
233

256

14

34

Recognized net actuarial (gain) loss
569

346

(18
)

(364
)
Amortization of net transition obligation (asset)
---

(11
)

704

531

Net periodic benefit cost
1,877

1,843

946

99

Less amount capitalized
179

190

80

123

Net periodic benefit cost (income)
$
1,698

$
1,653

$
866

$
(24
)

Nine Months	Pension Benefits						Other Postretirement Benefits
Ended September 30,	2006			2005			2006			2005
Three Months													Pension Benefits						Other Postretirement Benefits
Ended March 31,													2007			2006			2007			2006
	(In thousands)												(In thousands)
Components of net periodic benefit cost:
Service cost	$	7,799		$	6,252		$	1,725		$	1,242		$	2,250		$	2,301		$	533		$	471
Interest cost		14,009			12,463			2,964			2,802			4,141			4,074			938			929
Expected return on assets		(17,419	)		(14,960	)		(3,494	)		(3,004	)		(5,070	)		(4,718	)		(1,093	)		(925	)
Amortization of prior service cost		746			768			37			34			209			256			11			11
Recognized net actuarial (gain) loss		1,587			1,038			(187	)		(441	)
Amortization of net actuarial (gain) loss														74			509			(313	)		(84	)
Amortization of net transition obligation (asset)		(2	)		(33	)		1,766			1,594			---			(1	)		531			531
Net periodic benefit cost		6,720			5,528			2,811			2,227
Net periodic benefit cost, including amount capitalized														1,604			2,421			607			933
Less amount capitalized		560			547			205			329			151			156			52			46
Net periodic benefit cost	$	6,160		$	4,981		$	2,606		$	1,898		$	1,453		$	2,265		$	555		$	887

In addition to the qualified plan defined pension benefits reflected in the table, the Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that generally provides for defined benefit payments at age 65 following an employee’s retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for this plan for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2007 and 2006, was $1.8 million and ~~$5.7 million, respectively. The Company’s net periodic benefit cost for this plan for the three and nine months ended September 30, 2005, was $1.6 million and $4.9~~$2.0 million, respectively.

~~19.~~18. Regulatory matters and revenues subject to refund

In September 2004, Great Plains filed a natural gas rate application with the MNPUC requesting a revenue increase of $1.4 million annually, or approximately 4 percent. An interim increase of $1.4 million annually was effective January 10, 2005, subject to refund. The final order in the amount of $481,000 annually, or 1.3 percent, was issued on May 1, 2006. A compliance filing was submitted on August 11, 2006, for MNPUC approval and is still pending action. Great Plains has adequately provided a liability for the revenue subject to refund.

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. ~~In April 2005,~~Currently, the ~~FERC issued its Order on Compliance Filing and Motion for Refunds. In~~only remaining issue outstanding related to this ~~Order, the FERC approved Williston Basin’s refund rates and established rates~~rate change application is in regard to be effective April 19, 2005. Williston Basin made its compliance filing complying with the requirements of this Order regarding rates and issued refunds totaling approximately $18.5 million to its customers in May 2005. As a result of the Order, Williston Basin recorded a $5.0 million (after tax) benefit in the second quarter of 2005 from the resolution of the rate proceeding which included the reversal of a portion of the liability it had previously established for this regulatory proceeding. In June 2005, Williston Basin appealed to the D.C. Appeals Court certain ~~issues addressed by the FERC’s Order on Initial Decision dated July 2003 and its Order on Rehearing dated May 2004 concerning determinations associated with cost of~~ service and volumes used in allocating costs and designing rates. Oral argument was held on October 20, 2006 regarding those matters. Those matters are pending resolution by the D.C. Appeals Court. A provision has been established for certain issues pending before the D.C. Appeals Court. The Company believes that the provision is adequate based on its assessment of the ultimate outcome of the proceeding.

restrictions. In May 2004, the FERC remanded ~~issues regarding certain service and annual demand quantity restrictions~~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 ~~the~~certain service and annual demand quantity restrictions. OnIn April ~~20,~~ 2006, the FERC issued an Order on Rehearing denying Williston Basin’s Request for Rehearing of the FERC’s November 2005 Order. OnIn April ~~25,~~ 2006, Williston Basin appealed to the D.C. Appeals Court certain issues addressed by the FERC’s Order on Initial Decision dated November 2005 and its Order on Rehearing issued in April ~~20, 2006,~~2006. The matter concerning the service ~~and annual demand quantity restrictions. Those matters are~~restrictions is pending resolution by the D.C. Appeals Court.

~~20.~~19. Contingencies

Litigation

Royalties Case In June 1997, Grynberg, acting on behalf of the United States, filed suit under the Federal False Claims Act against Williston Basin and Montana-Dakota. He also filed more than 70 similar suits against natural gas transmission companies and producers, gatherers and processors of natural gas. Grynberg alleged improper measurement of the heating content and volume of natural gas purchased by the defendants resulting in the underpayment of royalties to the United States. All cases were consolidated in Wyoming Federal District Court.

In June 2004, following preliminary discovery, Williston Basin and Montana-Dakota joined with other defendants and filed a Motion to Dismiss on the ground that the information upon which Grynberg based his complaint was publicly disclosed prior to the filing of his complaint and further, that he is not the original source of such information. The Motion to Dismiss was heard in March 2005 by the Special Master appointed by the Wyoming Federal District Court. The Special Master, in his Written Report dated May 2005, recommended that the lawsuit be dismissed against certain defendants, including Williston Basin and Montana-Dakota. A hearing on the adoption of the Written Report was held in December 2005, before the Wyoming Federal District Court.

On October ~~20,~~ 2006, the Wyoming Federal District Court ~~adopted and modified the Special Master’s Written Report and~~ ordered that the actions against Williston Basin and Montana-Dakota be dismissed. ~~It is expected that~~ Grynberg ~~will appeal~~filed a Notice of Appeal of the decision to the U.S. Tenth Circuit Court of ~~Appeals.~~Appeals in November 2006.

~~In the event the Wyoming Federal District Court’s decision is overturned and Grynberg’s actions are reinstated, it is expected that further discovery will follow.~~On March 6, 2007, a settlement was reached between Grynberg, Williston Basin and ~~Montana-Dakota believe Grynberg will not prevail in~~Montana-Dakota. The case was dismissed by the suit or recover damages from Williston Basin and/or Montana-Dakota because insufficient facts exist to support the allegations. Williston Basin and Montana-Dakota believe Grynberg’s claims are without merit and intend to vigorously contest this suit.U.S. Tenth Circuit Court of Appeals on April 20, 2007.

~~Grynberg has not specified the amount he seeks to recover. Williston Basin and Montana-Dakota are unable to estimate their potential exposure and will be unable to do so until discovery is completed.~~

Coalbed Natural Gas Operations Fidelity has been named as a defendant in, and/or certain of its operations are or have been the subject of, more than a dozen lawsuits filed in connection with its CBNG development in the Powder River Basin in Montana and Wyoming. These lawsuits were filed in federal and state courts in Montana between June 2000 and ~~April 2006~~January 2007 by a number of environmental organizations, including the NPRC and the Montana Environmental Information Center, as well as the TRWUA and the Northern Cheyenne Tribe. Portions of three of the lawsuits have been transferred to the Wyoming Federal District Court. The lawsuits involve allegations that Fidelity and/or various government agencies are in violation of state and/or federal law, including the Clean Water Act, the NEPA, the Federal Land Management Policy Act, the NHPA, the Montana State Constitution, the Montana Environmental Policy Act and the Montana Water Quality Act. The suits that remain extant include a variety of claims that state and federal government agencies violated various environmental laws that impose procedural and substantive requirements. The lawsuits seek injunctive relief, invalidation of various permits and unspecified damages. Fidelity has intervened or moved to intervene in three lawsuits filed by other gas producers which challenge the adoption of rules by the BER related to management of water associated with CBNG production. The state of Wyoming has filed a similar suit and Fidelity has also moved to intervene in that action.

In suits filed in the Montana Federal District Court, the NPRC and the Northern Cheyenne Tribe asserted that ~~further development by Fidelity and others of CBNG in Montana should be enjoined until~~ the BLM ~~completes a SEIS.~~violated NEPA and other federal laws when approving the 2003 EIS analyzing CBNG development in southeastern Montana. The Montana Federal District Court, in February 2005, entered a ruling finding that the 2003 EIS was inadequate. The Montana Federal District Court later entered an order that would have allowed limited CBNG development in the Powder River Basin in Montana pending the BLM's preparation of a SEIS. The plaintiffs appealed the decision to the Ninth Circuit because the Montana Federal District Court declined to enter an injunction enjoining all development pending completion of the SEIS. The Montana Federal District Court also declined to enter an injunction pending the appeal. In May 2005, the Ninth Circuit granted the request of the NPRC and the Northern Cheyenne Tribe and, pending appeal or further order from the Ninth Circuit, enjoined the BLM from approving any new CBNG development ~~projects~~of federal minerals in the Montana Powder River ~~Basin in Montana. That court~~Basin. The Ninth Circuit also enjoined Fidelity from drilling any additional federally permitted wells associated with its Montana Coal Creek Project and from constructing infrastructure to produce and transport CBNG from the Coal Creek Project's existing federal wells. The matter has been fully briefed and argued before the Ninth Circuit and the parties are awaiting a decision of the court. 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 development 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 public comment period on the draft SEIS concluded on May 2, 2007. Fidelity cannot predict what the final terms of the SEIS will be. The final SEIS is scheduled for release in the summer of 2007.

In related actions in the Montana Federal District Court, the NPRC and the Northern Cheyenne Tribe 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 NHPA and the NEPA. ~~The NPRC also asserted that the environmental assessment that supported the BLM's prior approval of the Badger Hills Project was invalid.~~ In June 2005, the Montana Federal District Court issued orders in these cases enjoining operations on Fidelity's Badger Hills Project pending the BLM's consultation with the Northern Cheyenne Tribe as to satisfaction of the applicable requirements of the NHPA and a further environmental analysis under the NEPA. Fidelity sought and obtained stays of the injunctive relief from the Montana Federal District Court and production from Fidelity’s Badger Hills Project continues. In September 2005, the Montana Federal District Court entered an Order based on a stipulation between the parties to the NPRC action that production from existing wells in Fidelity’s Badger Hills Project may continue pending preparation of a revised environmental analysis. In November 2005, the Montana Federal District Court entered an Order ~~based on a stipulation between the parties to~~dismissing the Northern Cheyenne Tribe ~~action~~lawsuit based on the parties’ stipulation that production from existing wells in Fidelity’s Badger Hills Project ~~may~~could continue pending ~~preparation of a revised environmental analysis.~~consultation with the Tribe under the NHPA. In December 2005, Fidelity filed a Notice of Appeal of the NPRC lawsuit to the Ninth Circuit in connection with the Montana Federal District Court’s decision insofar as it found the BLM’s approval of Fidelity’s applications did not comply with applicable law.

In May 2005, the NPRC and other petitioners filed a petition with the BER ~~and~~to promulgate rules related to the management of water produced in association with CBNG operations. Thereafter, the BER initiated related rulemaking proceedings to ~~create~~consider rules that would, if promulgated, require re-injection of water produced in connection with CBNG operations, treatment of such water in the event re-injection is not feasible and amend the non-degradation policy in connection with CBNG development to include additional limitations on factors deemed harmful, thereby restricting discharges even further than under the previous standards. OnIn March ~~23,~~ 2006, the BER issued its decision on the ~~NPRC’s~~ rulemaking petition. The BER rejected the proposed requirement of re-injection of water produced in connection with CBNG and deferred action on the proposed treatment requirement. The BER adopted the proposed amendment to the non-degradation policy. While it is possible the BER’s ruling could have an adverse impact on Fidelity’s operations, Fidelity believes that two five-year water discharge permits issued by the Montana DEQ in February 2006 should, assuming normal operating conditions, allow Fidelity to continue its existing CBNG operations at least through the expiration of the permits in March 2011. However, these permits are now ~~being challenged~~under challenge in Montana state court by the Northern Cheyenne Tribe. Specifically, onin April 3, 2006, the Northern Cheyenne Tribe filed a complaint in the District Court of Big Horn County against the Montana DEQ seeking to set aside the two permits. The Northern Cheyenne Tribe asserted that the Montana DEQ issued the permits in violation of various federal and state environmental laws. In particular, the Northern Cheyenne Tribe claimed the agency 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 ignoring the BER’s recently adopted amendment to the non-degradation policy. 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 ~~environmental impact statement~~EIS and that it failed to consider other alternatives to the issuance of the permits. Fidelity, the NPRC and the TRWUA have been ~~allowed~~granted leave to intervene in this proceeding. ~~Fidelity has asserted that~~The parties have submitted cross motions for summary judgment. The motions were argued to the ~~Northern Cheyenne Tribe’s complaint should be dismissed with prejudice, that~~District Court of Big Horn County on February 28, 2007. Fidelity’s discharge of water pursuant to its two permits is its primary means for managing CBNG produced ~~water and that, if~~water. If its permits are set aside, Fidelity’s CBNG operations in Montana could be significantly and adversely affected.

In a related proceeding, onin July ~~25,~~ 2006, Fidelity filed a motion to intervene in a lawsuit filed in the District Court of Big Horn County by other producers. The lawsuit challenges the BER’s 2006 rulemaking, which amended the ~~nondegradation~~non-degradation policy, as well as the BER’s 2003 rulemaking procedure which first set numeric limits for certain parameters contained in water produced in connection with CBNG operations. Fidelity’s motion for intervention was granted onin August 1, 2006. The parties are currently briefing cross motions for summary judgment.

Similarly, industry members have filed two lawsuits, and the ~~State~~state of Wyoming has filed one lawsuit, in Wyoming Federal District Court. These lawsuits challenge the EPA’s failure to timely disapprove the 2006 rules. All three Wyoming lawsuits were consolidated onin September ~~22,~~ 2006. Fidelity has moved to intervene in these consolidated cases.

Fidelity will continue to vigorously defend its interests in all ~~coalbed-related~~CBNG-related lawsuits and related actions in which it is involved, including the Ninth Circuit injunction and 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 have a material effect on Fidelity’s existing CBNG operations and/or the future development of this resource in the affected regions.

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

In September 2005, the ND Health Department issued its final periodic review decision based on its August 2005 final air quality modeling report. The ND Health Department concluded there are 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 ~~is defending~~defended against the DRC claim and ~~it has~~ filed a motion to dismiss the case. The Colorado Federal District Court has ~~not yet ruled on~~dismissed the ~~motion.~~case.

Montana-Dakota expects the EPA to initiate a rulemaking proceeding to formally approve the conclusions contained in the September 2005 ND Health Department decision and the August 2005 final report. Once concluded, this rulemaking should result in a revision to the North Dakota SIP that, in turn, should allow for the dismissal of the case in Burleigh County District Court referenced above.

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

Natural Gas Storage Williston Basin filed suit in Montana Federal District Court on January 27, 2006, seeking to recover unspecified damages from Anadarko and its wholly owned subsidiary, Howell, and to enjoin Anadarko’s and Howell’s present and future operations in and near the Elk Basin Storage Reservoir. Based on ~~relevant information, including~~ reservoir and well pressure data and other information, Williston Basin believes that reservoir pressure in the ~~Elk Basin Storage Reservoir pressures have decreased and that quantities~~EBSR, one of its natural gas ~~have been diverted~~storage reservoirs, has decreased as a result of ~~Anadarko’s~~Howell and ~~Howell’s~~Anadarko’s drilling and production activities in areas within and near the boundaries of the ~~Elk Basin Storage Reservoir.~~EBSR. As of March 31, 2007, Williston Basin isestimated approximately 7.5 Bcf of storage gas had been diverted from the EBSR as a result of Howell and Anadarko’s drilling and production.

Williston Basin filed suit in Montana Federal District Court in January 2006, seeking ~~not only~~ to recover unspecified damages ~~for~~from Howell and Anadarko, and to enjoin Howell and Anadarko’s present and future production from specified wells in and near the ~~gas that has been diverted, but to prevent further loss of gas from the Elk Basin Storage Reservoir.~~EBSR. The Montana Federal District Court entered an Order onin July ~~14,~~ 2006, dismissing the case for lack of subject matter jurisdiction. Williston Basin filed a Notice of Appeal to the Ninth Circuit onin July ~~31,~~ 2006.

In related litigation, ~~Anadarko~~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 ~~Elk~~EBSR. In August 2006, Williston Basin ~~Storage Reservoir.~~moved for a preliminary injunction to halt Howell and Anadarko’s production in and near the EBSR. A district court-appointed special master conducted a hearing on the motion in December 2006, and recommended denial of the motion on February 15, 2007. The district court is expected to rule on the special master’s recommendation in the first half of 2007. A trial in Wyoming state district court is scheduled for October 22, 2007.

As noted above, Williston Basin estimates that as of March 31, 2007, Howell and Anadarko had diverted approximately 7.5 Bcf from the EBSR. Williston Basin believes Howell and Anadarko continue to divert gas from the EBSR and Williston Basin continues to monitor and analyze the situation. At trial, Williston Basin will seek recovery based on the amount of gas that has been and continues to be diverted as well as on the amount of gas that must be recovered as a result of the equalization of the pressures of various interconnected geological formations.

In light of the actions of Howell and Anadarko, Williston Basin installed additional compression at the site in order to maintain deliverability into the transmission system. While installation of the additional compression has provided temporary relief, Williston Basin believes that the adverse physical and operational effects occasioned by the continued loss of storage gas, if left unchecked, could threaten the operation and viability of the EBSR, impair Williston Basin’s ability to comply with the EBSR certificated operating requirements mandated by the FERC and adversely affect Williston Basin’s ability to meet its contractual storage and transportation service commitments to customers. 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 this proceeding.

The Company also is ~~also~~ 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~~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 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 of the harbor site for both the EPA and the Oregon DEQ are being recorded, and initially paid, through an administrative consent order by the LWG, a group of 10 entities, which does not include MBI or Georgia-Pacific West, Inc., the seller of the commercial property to MBI. 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 has been completed, the EPA has decided on a strategy and a record of decision has been published. While the remedial investigation and feasibility study for the harbor site has commenced, it is expected to take several more years to complete. The development of a proposed plan and record of decision on the harbor site is not anticipated to occur until 2010, after which a cleanup plan will be undertaken.

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 administrative action.

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 ~~which~~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 from approximately two 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.

In addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas ~~and oil~~ price swap and collar agreement obligations. Fidelity’s obligations at ~~September 30, 2006,~~March 31, 2007, were ~~immaterial.~~$3.4 million. 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, 2006,~~March 31, 2007, expire in ~~2006~~2007 and ~~2007;~~2008; 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 reflected on the Consolidated Balance ~~Sheet~~Sheets at ~~September 30, 2006.~~March 31, 2007. 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 natural gas transportation and sales agreements, electric power supply agreements, construction contracts, gathering contracts, a conditional purchase agreement and certain other guarantees. At ~~September 30, 2006,~~March 31, 2007, the fixed maximum amounts guaranteed under these agreements aggregated ~~$180.1~~$175.3 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate ~~$1.0 million in 2006; $102.1~~$14.9 million in 2007; ~~$4.7~~$86.0 million in 2008; ~~$2.7~~$3.1 million in 2009; ~~$30.1~~$30.3 million in 2010; $23.0 million in 2011; ~~$12.0~~$12.7 million in 2012; ~~$500,000,~~$300,000 in 2028; $1.0 million, which is subject to expiration 30 days after the receipt of written ~~notice~~notice; and $4.0 million, which has no scheduled maturity date. A guarantee for an unfixed amount estimated at $250,000 at ~~September 30, 2006,~~March 31, 2007, has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was ~~$700,000~~$641,000 and was reflected on the Consolidated Balance Sheet at ~~September 30, 2006.~~March 31, 2007. 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.

Centennial has outstanding letters of credit to third parties related to insurance policies and other agreements that guarantee the performance of other subsidiaries of the Company. At ~~September 30, 2006,~~March 31, 2007, the fixed maximum amounts guaranteed under these letters of credit aggregated $42.5 million. In ~~2006~~2007 and ~~2007, $5.8~~2008, $15.6 million and ~~$36.7~~$26.9 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at ~~September 30, 2006.~~March 31, 2007.

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, 2006,~~March 31, 2007, the fixed maximum amounts guaranteed under these agreements aggregated ~~$22.9~~$25.1 million. Scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $2.2 million in 2007, $2.9 million in 2008 and $20.0 million in 2009. 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 ~~$1.6~~$1.7 million, which was not reflected on the Consolidated Balance Sheet at ~~September 30, 2006,~~March 31, 2007, because these intercompany transactions are eliminated in consolidation.

In addition, Centennial ~~has~~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, 2006.~~March 31, 2007.

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, 2006,~~March 31, 2007, approximately ~~$544~~$466 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

~~21.~~20. ~~Related party transactions~~Pending acquisition

In 2004, Bitter Creek entered into two natural gas gathering agreements with Nance Petroleum. Robert L. Nance, an executive officer and shareholder of St. Mary, was also a member of the Board of Directors of the Company until his retirement on August 17, 2006. The natural gas gathering agreements with Nance Petroleum were effective upon completion of certain high and low pressure gathering facilities, which occurred in mid-December 2004. Bitter Creek's capital expenditures related to the completion of the gathering lines and the expansion of its gathering facilities to accommodate the natural gas gathering agreements were $11,000 and $39,000 for the three and nine months ended September 30, 2006, and were $245,000 and $2.3 million for the three and nine months ended September 30, 2005, respectively, and are estimated for the next three years to be $41,000 in 2006, $3.3 million in 2007 and $2.2 million in 2008. The natural gas gathering agreements are each for a term of 15 years and month-to-month thereafter. Bitter Creek's revenues from these contracts were $420,000 and $1.2 million for the three and nine months ended September 30, 2006, respectively, and were $316,000 and $855,000 for the three and nine months ended September 30, 2005, respectively. Estimated revenues from these contracts for the next three years are $1.8 million in 2006, $2.1 million in 2007 and $3.2 million in 2008. The amount due from Nance Petroleum at September 30, 2006, was $139,000.

In 2005, Montana-Dakota entered into agreements to purchase natural gas from Nance Petroleum through March 31, 2006. Montana-Dakota’s expenses under these agreements through March 31, 2006, were $1.9 million. There were no amounts due to Nance Petroleum at September 30, 2006.

In 2005, Fidelity entered into an agreement for the purchase of an ownership interest in a natural gas and oil property with a third party whereunder it became a party to a joint operating agreement in which St. Mary is the operator of the property. St. Mary receives an overhead fee as operator of this property. The Company recorded its proportionate share of capital costs allocable to its ownership interest in the related property, which were not material to Fidelity.

~~22.~~

~~Pending acquisition~~

On July 8, 2006, the Company entered into a definitive merger agreement to acquire Cascade, subject to approval of Cascade’s shareholders and various regulatory authorities, as well as antitrust clearance under the Hart-Scott-Rodino Act, and the satisfaction of other customary closing conditions. OnIn October ~~27,~~ 2006, shareholders of Cascade approved the merger agreement. In November 2006, the Company obtained clearance under the Hart-Scott-Rodino Act. In March 2007, regulatory approvals were received from the North Dakota Public Service Commission and the Minnesota Public Utilities Commission.

On May 1, 2007, the Company filed stipulations with the Oregon Public Utility Commission to resolve pending proceedings before that commission. The filed stipulations relate to the application for approval of the pending merger with Cascade, as well as a pending show cause proceeding (applicable to Cascade’s level of rates) in Oregon, which commenced in August 2006. Parties to the stipulations include the commission’s staff as well as various interveners. In addition, the Washington Utilities and Transportation Commission staff, various interveners, Cascade and the Company have reached a settlement in principle of all issues in the merger proceeding pending before the Washington Utilities and Transportation Commission and a settlement stipulation is expected to be filed by mid-May 2007. The Oregon and Washington stipulations include certain commitments and rate credits applicable to the approval of the merger and are subject to the approval of the respective commissions.

Regulatory approvals in Oregon and Washington are anticipated ~~to be obtained~~ by mid-year 2007. The total value of the transaction, including the ~~assumption~~outstanding indebtedness of ~~certain indebtedness,~~Cascade, is approximately $475 million. Cascade’s natural gas service areas are concentrated in western and south central Washington and south central and eastern Oregon.

~~23.~~ 21. ~~Subsequent event~~Pending sale

On ~~October 20, 2006,~~April 25, 2007, Centennial Resources entered into a definitive purchase and sale agreement with Montana Acquisition Company LLC. Under the agreement, the Company will sell its domestic independent power production business consisting of Centennial Power ~~sold 100 percent~~and CEM to Montana Acquisition Company LLC.

The transaction is valued at $636 million, which includes the assumption of ~~its membership interest in the recently formed LPP to Hobbs Power. LPP was formed to develop a 550-MW combined-cycle generating facility to be built near Hobbs, New Mexico.~~approximately $36 million of project-related debt. The facility will consist of two combustion turbine generators, two heat-recovery boilers and one steam turbine generator. Southwestern Public Service Company, a subsidiary of Xcel Energy, has signed a 25-year power purchase agreement for the entire capacity and outputclosing of the ~~Hobbs facility. CEM is currently in negotiations to construct and operate the new facility. Onsite construction~~sale is expected to ~~begin by~~occur in June 2007 and is subject to the ~~spring~~receipt of ~~2007 with power coming online by~~regulatory approvals and fulfillment of other conditions established in the ~~summer of 2008. Because of expected continuing involvement by certain subsidiaries of Centennial Resources, revenues associated with~~agreement. Proceeds from the sale will be used to fund the Company’s acquisition of ~~LPP to Hobbs Power are currently expected to be recognized over~~Cascade and will provide additional cash for growth opportunities that exist in the ~~period~~Company’s core lines of ~~construction of the new facility.~~

business.

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 ~~returns~~return on invested capital

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities and the issuance from time to time of debt securities and the Company’s equity securities. For more information on the Company’s net capital expenditures, see Liquidity and Capital Commitments. Net capital expenditures are comprised of (A) capital expenditures plus (B) acquisitions (including the issuance of the Company’s equity securities, less cash acquired) less (C) net proceeds from the sale or disposition of property.

The key strategies for each of the Company’s business segments, and certain related business challenges, are summarized below.

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 an opportunity for the Company to earn a competitive return on investment. The natural gas distribution segment also continues to pursue growth by expanding its level of energy-related services.

Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and permitted returns on investment as well as subject to certain operational regulations at the federal level. The ability of these segments to grow through acquisitions is subject to significant competition from other energy providers. In addition, as to the electric business, the ability of this segment to grow its service territory and customer base is affected by significant competition from other energy providers, including rural electric cooperatives.

Construction Services

Strategy Provide a competitive return on investment while operating in a competitive industry by: building new and strengthening existing customer relationships; effectively controlling costs; recruiting, developing and retaining 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 and retention of key personnel are ongoing challenges.

Pipeline and Energy Services

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

Challenges Fluctuations in natural gas and oil prices; ongoing environmental litigation and administrative proceedings; timely receipt of necessary permits and approvals; recruitment and retention of a skilled workforce; availability of drilling rigs, auxiliary equipment and industry-related field services; and increased competition from many of the larger natural gas and oil companies.

Construction Materials and Mining

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 ~~acquisitions.~~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), negotiation of contract price escalation provisions and the utilization of national purchasing accounts. 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 in the higher-margin materials business (rock, sand, gravel, liquid asphalt, ~~cement, ready-mix~~ready-mixed concrete and related products), complementing and expanding on the Company’s expertise. 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 (asphalt cement, diesel fuel, cement, etc.), negotiation of contract price escalation provisions and the utilization of national purchasing accounts. A critical element of the Company’s long term strategy for this business is the acquisition and development of reserves deemed strategic to Company operations. Ownership of, and access to aggregate reserves, is key to the vertical integration strategy.

Challenges Price volatility with respect to, and availability of, raw materials such as liquid asphalt, ~~cement,~~ diesel fuel and cement; recruitment and retention of a skilled workforce; and management of fixed price construction contracts, which are particularly vulnerable to volatility of these energy and material prices. Some of our markets are likely to be affected by the slowdown in housing, which should be partially mitigated by increased commercial spending.

Independent Power Production

Strategy ~~Achieve growth through~~Divest domestic assets due to the ~~acquisition, construction and operation of domestic nonregulated electric generation facilities and through international investments in~~increased market demand for independent power production assets, combined with the ~~energy and natural resources sectors. The segment continues~~Company’s desire to ~~seek projects with mid- to long-term agreements with financially stable customers, while maintaining diversity in customers, geographic markets and fuel source.~~efficiently fund its future capital needs.

Challenges Overall business challenges for this segment include: the risks and uncertainties associated with the sale of the domestic assets; construction, startup and operation of power plant facilities; ~~changes in energy market pricing; increased competition from other independent power producers;~~ and foreign currency fluctuation and political risk in the countries where this segment does business.

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 ~~2005~~2006 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 September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
	2006			2005			2006			2005				2007			2006
	(Dollars in millions, where applicable)
(Dollars in millions, where applicable)													(Dollars in millions, where applicable)
Electric	$	5.7		$	6.2		$	10.0		$	11.1			$	3.8		$	3.8
Natural gas distribution		(2.3	)		(3.0	)		.4			.5				6.2			5.3
Construction services		8.3			5.1			23.4			10.7				7.2			5.4
Pipeline and energy services		7.1			5.3			17.3			17.2				5.7			4.9
Natural gas and oil production		35.0			35.5			107.2			94.2				30.6			41.3
Construction materials and mining		52.5			34.1			69.0			44.0				(9.8	)		(8.9	)
Independent power production		1.7			3.7			4.6			23.1				(2.8	)		.2
Other		.3			.2			.8			.5				.3			.3
Earnings before discontinued operations															41.2			52.3
Income from discontinued operations, net of tax															5.3			.8
Earnings on common stock	$	108.3		$	87.1		$	232.7		$	201.3			$	46.5		$	53.1
Earnings per common share - basic:
Earnings before discontinued operations														$	.23		$	.29
Discontinued operations, net of tax															.03			.01
Earnings per common share - basic	$	.60		$	.49		$	1.29		$	1.13			$	.26		$	.30
Earnings per common share - diluted:
Earnings before discontinued operations														$	.23		$	.29
Discontinued operations, net of tax															.02			---
Earnings per common share - diluted	$	.60		$	.48		$	1.29		$	1.12			$	.25		$	.29
Return on average common equity for the 12 months ended								15.7	%		15.0	%			14.8	%		16.2	%

Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~Consolidated earnings for the quarter ended ~~September 30, 2006, increased $21.2~~March 31, 2007, decreased $6.6 million from the comparable ~~period~~prior period. Earnings at the natural gas and oil production business decreased largely due ~~to:~~

·	Higher earnings from construction due to increased volumes and margins, earnings from companies acquired since the comparable prior period and higher earnings from aggregate and asphalt due to higher margins at the construction materials and mining business

·	~~Higher earnings from increased outside and inside construction workloads and margins at the construction services business~~

~~Nine Months Ended September 30, 2006~~to lower average realized natural gas prices of 11 percent, higher depreciation, depletion and ~~2005~~ ~~Consolidated earnings for the nine months ended September 30, 2006,~~amortization expense, and higher lease operating expense, partially offset by increased ~~$31.4 million from the comparable period largely due to:~~

·	~~Higher earnings from construction materials and mining business, as previously discussed~~

·	Higher average realized natural gas and oil prices of 9 percent and 26 percent, respectively, and increased natural gas and oil production of 5 percent and 18 percent, respectively at the natural gas and oil production business

·	~~Higher earnings from increased outside and inside construction workloads and margins, and earnings from companies acquired since the comparable prior period at the construction services business~~

·	Higher transportation, storage and gathering volumes, largely offset by the absence in 2006 of the benefit from the resolution of a rate proceeding of $5.0 million (after tax) recorded in 2005 at the pipeline and energy services business. For more information, see Note 19.

oil production of 24 percent. Partially offsetting the ~~increase~~earnings decrease were ~~decreased earnings from equity method investments, which largely reflect the absence~~higher construction margins in ~~2006 of the 2005 $15.6 million benefit from the sale of the Termoceara Generating Facility~~most regions at the ~~independent power production~~construction services business.

FINANCIAL AND OPERATING DATA

~~The following tables contain~~Below are key financial and operating ~~statistics~~data for each of the Company's businesses.

Electric

	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
	2006		2005		2006		2005			2007		2006
	(Dollars in millions, where applicable)
(Dollars in millions, where applicable)									(Dollars in millions, where applicable)
Operating revenues	$	53.2	$	50.2	$	139.1	$	135.5		$ 47.1		$ 45.0
Operating expenses:
Fuel and purchased power		19.1		16.3		51.2		47.0			17.1		16.1
Operation and maintenance		16.3		15.0		46.0		43.7			15.1		14.0
Depreciation, depletion and amortization		5.4		5.2		15.9		15.5			5.6		5.3
Taxes, other than income		2.1		2.1		6.4		6.5			2.2		2.2
		42.9		38.6		119.5		112.7			40.0		37.6
Operating income		10.3		11.6		19.6		22.8			7.1		7.4
Earnings	$	5.7	$	6.2	$	10.0	$	11.1		$	3.8	$	3.8
Retail sales (million kWh)		652.1		626.3		1,828.1		1,785.5			645.8		612.9
Sales for resale (million kWh)		172.3		169.1		423.9		482.4			44.1		166.4
Average cost of fuel and purchased power per kWh	$	.022	$	.019	$	.022	$	.019		$	.024	$	.020

Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ Electric earnings ~~decreased $500,000 due to higher~~were unchanged at $3.8 million. Higher retail sales volumes and margins were offset by lower sales for resale volumes and increased operation and maintenance expense, ~~of $800,000 (after tax), including costs related to a scheduled maintenance outage at an electric generating station. This decrease was partially offset by higher retail sales margins,~~ largely ~~due to increased volumes of 4 percent.~~payroll related.

~~Nine Months Ended September 30, 2006 and 2005~~ ~~Electric earnings decreased $1.1 million due to:~~

·	~~Higher operation and maintenance expense of $1.4 million (after tax), primarily the result of scheduled maintenance outages at electric generating stations~~

·	~~Decreased sales for resale margins due to lower average rates of 13 percent and decreased volumes of 12 percent largely due to plant availability~~

~~Partially offsetting the decrease were:~~

·	~~Lower interest expense of $600,000 (after tax), resulting from lower average interest rates due to the repurchase and redemption of certain higher cost long-term debt~~

·	~~Higher retail sales margins, largely due to increased volumes of 2 percent~~

Natural Gas Distribution

Three Months Ended
September 30,

Nine Months Ended
September 30,

2006 2005 2006 2005

(Dollars in millions, where applicable)

Operating revenues:

Sales
$
30.5

$
33.0

$
226.6

$
230.2

Transportation and other
0.9

1.0

2.9

3.5

31.4

34.0

229.5

233.7

Operating expenses:

Purchased natural gas sold
20.7

23.2

182.5

185.3

Operation and maintenance
11.0

11.3

35.7

34.5

Depreciation, depletion and amortization
2.5

2.4

7.3

7.2

Taxes, other than income
1.4

1.3

4.5

4.3

35.6

38.2

230.0

231.3

Operating income (loss)

(4.2
)

(4.2
)

(.5
)

2.4

Earnings (loss)

$
(2.3
)
$
(3.0
)
$
.4

$
.5

Volumes (MMdk):

Sales
3.1

3.0

21.9

24.1

Transportation
2.6

2.9

9.8

9.9

Total throughput

5.7

5.9

31.7

34.0

Degree days (% of normal)*

94
%

50
%

83
%

92
%
Average cost of natural gas, including transportation, per dk

$
6.67

$
7.78

$
8.32

$
7.68

* Degree days are a measure of the daily temperature-related demand for energy for heating.

	Three Months Ended March 31,
	2007			2006
(Dollars in millions, where applicable)
Operating revenues	$	136.0		$	152.3
Operating expenses:
Purchased natural gas sold		106.2			128.4
Operation and maintenance		15.5			11.8
Depreciation, depletion and amortization		2.5			2.4
Taxes, other than income		1.7			1.5
		125.9			144.1
Operating income		10.1			8.2
Earnings	$	6.2		$	5.3
Volumes (MMdk):
Sales		15.9			14.2
Transportation		3.4			4.4
Total throughput		19.3			18.6
Degree days (% of normal)*		94	%		85	%
Average cost of natural gas, including transportation, per dk	$	6.70		$	9.01
* Degree days are a measure of the daily temperature-related demand for energy for heating.

Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ The natural gas distribution business experienced a seasonal loss of $2.3 million in the third quarter compared to a loss of $3.0 million in the third quarter of 2005. The increase in earnings of $700,000 was largely due to higher nonregulated earnings from energy-related services.

~~Nine Months Ended September 30, 2006 and 2005~~Earnings at the natural gas distribution business ~~decreased $100,000~~increased $900,000, largely due ~~to:~~to increased retail sales volumes, resulting from 10 percent colder weather than last year.

·	Lower retail sales margin due to lower sales volumes of 9 percent, resulting from 10 percent warmer weather than last year, partially offset by higher weather-normalized revenues in certain jurisdictions

·	~~Higher operation and maintenance expense of $800,000 (after tax), largely due to higher payroll-related costs from an early retirement program~~

~~Largely offsetting~~The pass-through of lower natural gas prices is reflected in the decrease in ~~earnings were higher~~both sales revenues and purchased natural gas sold. The decrease in sales revenues was partially offset by revenues from nonregulated ~~earnings from~~ energy-related services. Nonregulated energy-related services also contributed to the operation and maintenance expense increase.

Construction Services

	Three Months Ended March 31,
	2007		2006
	(In millions)
Operating revenues	$	236.8	$	223.8
Operating expenses:
Operation and maintenance		211.7		202.8
Depreciation, depletion and amortization		3.5		3.5
Taxes, other than income		8.8		7.4
		224.0		213.7
Operating income		12.8		10.1
Earnings	$	7.2	$	5.4

Three Months Ended
September 30,

Nine Months Ended
September 30,

2006 2005 2006 2005

(In millions)

Operating revenues

$
262.3

$
207.4

$
729.3

$
458.2

Operating expenses:

Operation and maintenance
236.8

188.8

656.2

412.4

Depreciation, depletion and amortization
3.6

3.9

11.0

9.7

Taxes, other than income
6.6

5.0

19.5

15.2

247.0

197.7

686.7

437.3

Operating income

15.3

9.7

42.6

20.9

Earnings

$
8.3

$
5.1

$
23.4

$
10.7

Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ Construction services earnings increased ~~$3.2~~$1.8 million compared to the ~~third~~first quarter of the comparable prior period due to:

·	Higher ~~outside~~ construction ~~workloads and~~ margins in most regions of ~~$2.2~~$1.7 million (after tax)~~, largely in the Southwest region~~

·	~~Higher inside construction workloads and margins of $900,000 (after tax), largely in the Southwest region~~

·	Increased equipment sales and rentals

~~Partially offsetting this increase were higher general and administrative expenses of $600,000 (after tax), primarily payroll related.~~

~~Nine Months Ended September 30, 2006 and 2005~~ ~~Construction services earnings increased $12.7 million compared to the nine months of the comparable period due to:~~

·	Earnings from acquisitions made since the comparable prior period, which contributed approximately 4019 percent of the earnings increase

·	~~Higher inside construction workloads and margins of $4.6 million (after tax) in the Central, Southwest and Northwest regions~~

·	~~Higher outside construction workloads and margins of $2.8 million (after tax), largely in the Southwest region, partially offset by decreased workloads and margins in the Northwest region~~

·	~~Increased equipment sales and rentals~~

Partially offsetting this increase were higher general and administrative expenses of ~~$1.7 million~~$500,000 (after tax)~~, primarily payroll related.~~.

Pipeline and Energy Services

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2006		2005		2006		2005		2007		2006
	(Dollars in millions)								(Dollars in millions)
Operating revenues:
Pipeline	$	27.7	$	21.5	$	74.5	$	63.7	$	25.9	$	20.7
Energy services		76.1		96.8		258.3		247.3		87.2		105.8
		103.8		118.3		332.8		311.0		113.1		126.5
Operating expenses:
Purchased natural gas sold		69.0		89.3		236.1		226.1		79.6		97.8
Operation and maintenance		12.8		11.9		38.4		36.7		14.1		11.6
Depreciation, depletion and amortization		4.9		4.6		14.9		7.7		5.4		4.9
Taxes, other than income		2.5		2.1		7.6		6.1		2.7		2.5
		89.2		107.9		297.0		276.6		101.8		116.8
Operating income		14.6		10.4		35.8		34.4		11.3		9.7
Income from continuing operations										5.7		4.9
Loss from discontinued operations, net of tax										---		(.3	)
Earnings	$	7.1	$	5.3	$	17.3	$	17.2	$	5.7	$	4.6
Transportation volumes (MMdk):
Montana-Dakota		7.5		7.7		22.6		23.1		8.0		8.0
Other		29.3		19.7		75.4		53.1		20.6		18.1
		36.8		27.4		98.0		76.2		28.6		26.1
Gathering volumes (MMdk)		21.9		20.6		64.8		60.2		22.1		21.7

Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ ~~Pipeline and energy services experienced an increase in earnings of $1.8 million due to:~~

·	~~Higher transportation, storage and gathering volumes ($3.1 million after tax)~~

·	~~Higher gathering and storage rates ($1.1 million after tax)~~

~~Partially offsetting this increase were:~~

·	~~Higher operation and maintenance expense, primarily related to the natural gas storage litigation. For more information, see Note 20.~~

·	~~An increased loss from discontinued operations of $1.3 million (after tax) related to Innovatum. For more information, see Notes 3 and 14.~~

~~Nine Months Ended September 30, 2006 and 2005~~ Pipeline and energy services experienced an increase in earnings of ~~$100,000~~$1.1 million due to:

·	Higher storage services revenue of $1.9 million (after tax)

·	Higher transportation ~~storage~~ and gathering volumes ~~($6.4~~of $1.0 million ~~after~~(after tax)

·	~~Higher gathering rates ($2.7 million after tax)~~

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

·	Absence in 2006 of the benefit from the resolution of a rate proceeding of $5.0 million (after tax) recorded in 2005, which included a reduction to depreciation, depletion and amortization expense. For more information, see Note 19.

·	~~Higher operation and maintenance expense, primarily due to the natural gas storage litigation, as previously discussed~~

·	~~An increased loss from discontinued operations of $1.4 million (after tax) related to Innovatum, as previously discussed~~

·	~~Higher taxes, other than income of $900,000 (after tax), primarily due to property taxes~~

The decrease in energy services revenues and purchased natural gas sold reflects the effect of lower natural gas prices.

Natural Gas and Oil Production

	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
	2006		2005		2006		2005			2007		2006
	(Dollars in millions, where applicable)
(Dollars in millions, where applicable)									(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	89.1	$	94.3	$	281.7	$	247.2		$	94.0	$	105.4
Oil		31.6		20.5		78.0		52.3			24.6		21.0
Other		1.8		1.6		5.3		1.7			---		2.0
		122.5		116.4		365.0		301.2			118.6		128.4
Operating expenses:
Purchased natural gas sold		1.5		1.5		5.2		1.7			.3		2.0
Operation and maintenance:
Lease operating costs		14.0		10.9		38.3		28.6			15.5		11.9
Gathering and transportation		4.5		3.8		13.9		9.5			4.5		4.7
Other		7.2		9.5		23.9		21.4			8.4		7.4
Depreciation, depletion and amortization		27.7		22.3		78.1		60.6			29.8		24.5
Taxes, other than income:
Production and property taxes		8.5		9.3		26.4		22.7			8.9		9.9
Other		.2		.1		.7		.4			.2		.2
		63.6		57.4		186.5		144.9			67.6		60.6
Operating income		58.9		59.0		178.5		156.3			51.0		67.8
Earnings	$	35.0	$	35.5	$	107.2	$	94.2		$	30.6	$	41.3
Production:
Natural gas (MMcf)		15,603		15,015		46,207		44,069			15,440		15,362
Oil (MBbls)		554		477		1,475		1,250			556		450
Average realized prices (including hedges):
Natural gas (per Mcf)	$	5.71	$	6.28	$	6.10	$	5.61		$	6.08	$	6.86
Oil (per barrel)	$	57.01	$	42.95	$	52.90	$	41.88		$	44.34	$	46.71
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	5.13	$	6.87	$	5.72	$	5.88		$	5.74	$	6.90
Oil (per barrel)	$	57.69	$	50.72	$	53.99	$	47.83		$	44.34	$	47.65
Production costs, including taxes, per net equivalent Mcf:
Production costs, including taxes, per equivalent Mcf:
Lease operating costs	$	.74	$	.61	$	.70	$	.55		$	.83	$	.66
Gathering and transportation		.23		.21		.25		.19			.24		.26
Production and property taxes		.45		.52		.48		.44			.47		.55
	$	1.42	$	1.34	$	1.43	$	1.18		$	1.54	$	1.47

Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ The natural gas and oil production business experienced a ~~$500,000~~$10.7 million decrease in earnings due to:

·	Lower average realized ~~natural~~ gas prices of 911 percent and lower average realized oil prices of 5 percent

·	Higher depreciation, depletion and amortization expense of ~~$3.4~~$3.3 million (after tax) due to higher depletion rates and increased production

·	Higher lease operating expense of ~~$1.9~~$2.1 million (after tax), largely ~~CBNG~~acquisition and ~~acquisition-related~~CBNG-related costs

·	Increased general and administrative expense of $600,000 (after tax), primarily due to higher payroll related costs

Partially offsetting the decrease ~~were:~~were increased oil production of 24 percent and natural gas production of 1 percent, largely due to increased production in the Rocky Mountain region, including the Baker and Bowdoin fields and the May 2006 Big Horn acquisition, as well as from the South Texas properties.

·	Increased oil production of 16 percent and natural gas production of 4 percent, largely due to increased production in the Rocky Mountain region as well as from the May 2005 South Texas and May 2006 Big Horn acquisitions

·	~~Higher average realized oil prices of 33 percent~~

·	~~Decreased general and administrative expense of $900,000 (after tax), primarily lower outside service costs~~

Construction Materials and Mining

	Three Months Ended March 31,
	2007			2006
	(Dollars in millions)
Operating revenues	$	227.6		$	233.7
Operating expenses:
Operation and maintenance		208.9			215.7
Depreciation, depletion and amortization		22.6			20.1
Taxes, other than income		7.7			8.4
		239.2			244.2
Operating loss		(11.6	)		(10.5	)
Loss	$	(9.8	)	$	(8.9	)
Sales (000's):
Aggregates (tons)		5,557			6,084
Asphalt (tons)		336			333
Ready-mixed concrete (cubic yards)		626			711

~~Nine~~Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ ~~The natural gas~~Construction materials and ~~oil production business~~mining experienced a ~~$13.0~~normal seasonal first quarter loss of $9.8 million. The seasonal loss increased by $900,000 from $8.9 million ~~increase~~ in ~~earnings~~2006. The increased seasonal loss was due to:

·	~~Higher average realized natural gas prices~~Lower earnings from ready-mixed concrete operations of ~~9 percent and higher average realized oil prices~~$2.1 million (after tax), primarily the result of ~~26 percent~~lower volumes

·	~~Increased natural gas production of 5 percent and oil production of 18 percent, as previously discussed~~

~~Partially offsetting the increase were:~~

·	Higher depreciation, depletion and amortization of ~~$10.8 million (after tax) due to higher depletion rates and increased production~~

·	~~Higher lease operating expenses of $6.0 million (after tax), as previously discussed~~

·	~~Increased gathering and transportation expense of $2.7~~$1.2 million (after tax), largely the result of higher ~~gathering rates~~property, plant and equipment balances

·	~~Increased general and administrative expense of $1.7 million (after tax), including higher payroll-related and office expenses~~

·	~~Higher interest expense of $1.1 million (after tax), primarily due to higher average debt balances~~

~~Construction Materials and Mining~~

Three Months Ended
September 30,

Nine Months Ended
September 30,

2006 2005 2006 2005

(Dollars in millions)

Operating revenues

$
667.6

$
610.5

$
1,386.2

$
1,191.6

Operating expenses:

Operation and maintenance
546.9

518.3

1,167.1

1,018.8

Depreciation, depletion and amortization
22.6

19.8

64.8

57.0

Taxes, other than income
10.0

12.3

30.3

30.7

579.5

550.4

1,262.2

1,106.5

Operating income

88.1

60.1

124.0

85.1

Earnings

$
52.5

$
34.1

$
69.0

$
44.0

Sales (000's):

Aggregates (tons)
14,961

17,518

34,386

34,447

Asphalt (tons)
3,669

4,331

6,358

6,831

Ready-mixed concrete (cubic yards)
1,420

1,463

3,391

3,347

~~Three Months Ended September 30, 2006 and 2005~~ ~~Earnings at the construction materials and mining business increased $18.4 million due to:~~

·	~~Higher earnings of $9.3 million (after tax) from construction, largely due to increased volumes and margins, the result of strong markets and favorable weather~~

·	~~Earnings~~Losses from companies acquired since the comparable prior period ~~which contributed approximately 29 percent~~ of ~~the earnings increase~~$700,000 (after tax)

·	~~Increased earnings from aggregate and asphalt operations of $5.0 million (after tax), largely due to higher margins, partially offset by lower volumes~~

Partially offsetting the ~~increase in~~decrease were increased earnings ~~were:~~

·	~~Higher depreciation, depletion and amortization of $900,000 (after tax), primarily due to higher plant and equipment balances~~

·	~~Lower earnings of $900,000 (after tax)~~ from ~~ready-mixed concrete operations, largely due to lower volumes~~

~~Nine Months Ended September 30, 2006 and 2005~~ ~~Earnings at the~~ construction ~~materials and mining business increased $25.0~~of $3.1 million (after tax) due ~~to:~~to higher margins.

·	~~Higher earnings of $15.0 million (after tax) from construction, as previously discussed~~

·	~~Increased earnings from aggregate operations of $5.6 million (after tax), largely due to higher margins~~

·	~~Increased earnings from asphalt and ready-mixed concrete operations of $3.8 million (after tax) due to higher margins, partially offset by lower volumes from existing operations~~

·	~~Earnings from companies acquired since the comparable period, which contributed approximately 19 percent of the earnings increase~~

~~Partially offsetting the increase in earnings were:~~

·	~~Higher depreciation, depletion and amortization of $2.9 million (after tax), as previously discussed~~

·	~~Increased general and administrative expense of $2.0 million (after tax), primarily payroll-related~~

Independent Power Production

Three Months Ended
September 30,

Nine Months Ended
September 30,

2006 2005 2006 2005

(Dollars in millions)

Operating revenues

$
17.0

$
14.1

$
39.9

$
37.6

Operating expenses:

Fuel and purchased power
1.7

---

3.0

---

Operation and maintenance
8.5

8.0

22.8

21.7

Depreciation, depletion and amortization
4.3

2.2

10.9

6.9

Taxes, other than income
1.1

.7

3.1

2.1

15.6

10.9

39.8

30.7

Operating income

1.4

3.2

.1

6.9

Earnings

$
1.7

$
3.7

$
4.6

$
23.1

Net generation capacity (kW)*

437,600

279,600
437,600
279,600

Electricity produced and sold (thousand kWh)*

300,951

89,646
592,226
217,658

* Excludes equity method investments.

	Three Months Ended March 31,
	2007			2006
	(Dollars in millions)
Operating revenues	$	---		$	---
Operating expenses:
Operation and maintenance		1.7			1.8
Depreciation, depletion and amortization		.1			.1
Taxes, other than income		.1			.1
		1.9			2.0
Operating loss		(1.9	)		(2.0	)
Income (loss) from continuing operations		(2.8	)		.2
Income from discontinued operations, net of tax		5.3			1.1
Earnings	$	2.5		$	1.3
Net generation capacity (kW)*		437,600			389,600
Electricity produced and sold (thousand kWh)*		238,011			88,497
* Excludes equity method investments.

Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ ~~Earnings at the independent power production business decreased $2.0 million largely due to:~~

·	~~Lower margins of $2.0 million (after tax) related to domestic electric generating facilities primarily due to lower capacity revenues~~

·	~~Higher interest expense of $1.9 million (after tax) largely due to debt related to the Hardin Generating Facility which was placed in commercial operation in March 2006~~

~~Partially offsetting the decrease in earnings were:~~

·	~~Higher earnings from equity method investments of $700,000 (after tax), due to the acquisition of the Brazilian Transmission Lines in August 2006~~

·	~~Earnings from an acquisition of a domestic electric generating facility made since the comparable prior period~~

~~Nine Months Ended September 30, 2006 and 2005~~ Earnings at the independent power production business ~~decreased $18.5~~increased $1.2 million due to increased income from discontinued operations, net of tax, of $4.2 million, largely due to:

Decreased earnings from equity method investments of $11.8 million, which largely reflect the absence in 2006 of the 2005 $15.6 million benefit from the sale of the Termoceara Generating Facility, partially offset by increased earnings from the acquisition of the Brazilian Transmission Lines in August 2006 and increased earnings at the Trinity Generating Facility partially resulting from a one-time benefit due to a tax rate deduction

·	~~Lower margins of $4.0 million (after tax) related to domestic electric generating facilities, as previously discussed~~

·	Higher ~~interest~~income at the Hardin Generating Station which was placed in service in March 2006

·	The absence in 2007 of depreciation expense ~~of $3.7 million (after tax), as previously discussed~~related to assets held for sale

·	Earnings related to an electric generating facility construction project in Hobbs, New Mexico

Partially offsetting ~~the decrease in earnings were~~this increase was decreased income from continuing operations, largely due to lower earnings from ~~an acquisition of a~~equity method investments and higher interest expense. The higher interest expense is primarily from debt related to the domestic ~~electric generating facility made since the comparable prior period.~~assets held for sale. For more information, see Note 21.

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 September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2006		2005		2006		2005		2007		2006
	(In millions)								(In millions)
Other:
Operating revenues	$	1.8	$	1.6	$	5.9	$	4.3	$	2.4	$	1.8
Operation and maintenance		1.2		1.4		4.3		3.7		1.9		1.3
Depreciation, depletion and amortization		.3		.1		.8		.2		.3		.2
Taxes, other than income		.1		---		.1		.1
Intersegment transactions:
Operating revenues	$	69.0	$	86.3	$	249.1	$	234.0	$	94.1	$	108.0
Fuel and purchased power		.1		---		.2		---
Purchased natural gas sold		62.6		80.8		228.8		219.7		87.3		101.2
Operation and maintenance		6.3		5.5		20.1		14.3		6.8		6.8

For further information on intersegment eliminations, see Note 16.

PROSPECTIVE INFORMATION

The following information ~~includes~~ highlights of 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~~“forward-looking statements.” There is no assurance that the Company’s projections, including estimates for growth and ~~increases~~changes in revenues and 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 ~~2005~~2006 Annual Report. Changes in such assumptions and factors could cause actual future results to differ materially from the Company’s targeted growth, revenue and earnings projections.

MDU Resources Group, Inc.

The information noted below excludes any possible gain from the previously announced potential sale of independent power production assets.

·	Earnings per common share for ~~2006,~~2007, diluted, are projected in the range of ~~$1.50~~$1.55 to ~~$1.65,~~$1.75, an increase from prior guidance of ~~$1.47~~$1.50 to ~~$1.60.~~$1.70.

·	The ~~Company’s long-term~~Company expects the percentage of 2007 earnings per common share, diluted, by quarter to be in the following approximate ranges:

o	Second quarter - 25 percent to 30 percent

o	Third quarter - 30 percent to 35 percent

o	Fourth quarter - 25 percent to 30 percent

·	Long-term compound annual growth ~~goal~~goals on earnings per share isfrom 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 ~~expiring~~expired purchased power contract with ~~Company-owned~~company-owned generation. This will add to ~~the Company’s~~ base-load capacity and rate base. New generation is projected to be on line in late 2011 or early 2012. A major commitment decision on the project will be made in ~~mid-year~~late 2007. A filing in North Dakota for prudence approval of the potential 600-MW Big Stone II generation project was made in November 2006. The Company would own approximately 116 MW of the Big Stone II project.

~~This business continues~~In addition, the Company has entered into a contract to ~~pursue growth opportunities by expanding energy-related services.~~build approximately 20 MW of wind-powered electric generation near Baker, Montana. The project includes 13, 1.5-MW wind turbines at a project cost of approximately $37 million. The project is expected to be rate based and on line in late 2007.

Montana-Dakota has obtained and holds, or is in the process of renewing, valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises.

Natural gas distribution

·	As discussed in Note ~~22,~~20, the Company has entered into a definitive merger agreement to acquire Cascade. When the acquisition is completed, it is expected to significantly enhance regulated earnings and cash flows. ~~Regulatory approvals are anticipated by mid-year 2007.~~

Construction services

·	The Company is awaiting approval by the MNPUC of its compliance filing reflecting a natural gas rate increase of $481,000 annually, or 1.3 percent, stemming from a general rate case filing made in September 2004. For further information, see Note 19.

·	~~This business continues to pursue growth by expanding energy-related services.~~

Montana-Dakota and Great Plains have obtained and hold, or are in the process of renewing, valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. Montana-Dakota and Great Plains intend to protect their service areas and seek renewal of all expiring franchises.

~~Construction services~~

·	~~Revenues in 2006 will be significantly~~anticipates higher ~~than 2005 record levels.~~

·	~~The Company expects higher~~average margins in ~~2006~~2007 as compared to ~~2005 levels.~~2006, and continues to focus on costs and efficiencies to improve margins.

·	Work backlog as of ~~September 30, 2006,~~March 31, 2007, was approximately ~~$505~~$747 million, including an acquisition, compared to ~~$406~~$439 million at ~~September 30, 2005.~~March 31, 2006.

Pipeline and energy services

~~Firm capacity for the Grasslands Pipeline increased from 90,000 Mcf per day to 97,000 Mcf per day effective November 1, 2006, with possible expansion to 200,000 Mcf per day.~~ Based on anticipated demand, additional incremental expansions to the Grasslands Pipeline are forecasted over the next few ~~years beginning~~years. The next expansion, to 138,000 Mcf per day, is scheduled for completion in ~~2008.~~late 2007 and is dependent upon the timing of receipt of necessary regulatory approvals. Through additional compression, the pipeline capacity could ultimately reach 200,000 Mcf per day.

·	In ~~2006,~~2007, total gathering and transportation throughput is expected to ~~increase approximately 15 percent over 2005~~be consistent with 2006 record levels.

Natural gas and oil production

·	~~The Company’s long-term~~Long-term compound annual growth ~~goal~~goals for production isare in the range of 7 percent to 10 percent. In ~~2006,~~2007, the Company expects ~~to be within this~~a combined natural gas and oil production increase in that range.

·	The Company expects to drill ~~more than~~between 300 and 350 wells in ~~2006.~~2007, dependent on the timely receipt of regulatory approvals. Currently, this segment’s net combined natural gas and oil production is approximately 200,000 Mcf equivalent to 210,000 Mcf equivalent per day.

·	~~The Company’s 2006 earnings~~Earnings guidance reflects estimated ~~November-December NYMEX~~natural gas prices for ~~natural gas in the range of $6.25~~May through December 2007 as follows:

Index*	Price Per Mcf
Ventura	$6.25 to $6.75 ~~per Mcf,~~
NYMEX	$6.75 to $7.25
CIG	$5.25 to $5.75
* Ventura ~~prices in the range of $5.75~~is an index pricing point related to ~~$6.25 and~~Northern Natural Gas Co.’s system; CIG ~~prices in the range of $4.75~~is an index pricing point related to $5.25. Also reflected are the actual natural gas index prices for October, which were lower than the November-December estimates. For the first nine months of 2006, more than three-fourths of this segment’s natural gas production was priced at non-NYMEX prices, the majority of which was at Ventura pricing.Colorado Interstate Gas Co.’s system.

During 2006, more than three-fourths of natural gas production was priced at non-NYMEX prices, the majority of which was at Ventura pricing.

·	~~Estimates of~~ Earnings guidance reflects estimated NYMEX crude oil prices for ~~October-December, reflected in the Company’s 2006 earnings guidance, are projected~~April through December 2007 in the range of ~~$60~~$58 to ~~$65~~$63 per barrel.

The Company has hedged approximately 30 percent to 35 percent of its estimated natural gas production ~~and 20 percent to 25 percent of its estimated oil production~~ for the last ~~three~~nine months of ~~2006.~~2007. For ~~2007,~~2008, the Company has hedged approximately 2515 percent to 3020 percent of its estimated natural gas production. The hedges that are in place as of ~~October 27, 2006,~~May 4, 2007, are summarized in the following chart:

Commodity
Index*
Period
Outstanding
Forward Notional Volume
(MMBtu)/(Bbl)
Price Swap or
Costless Collar
Floor-Ceiling
(Per MMBtu/Bbl)
Natural Gas Ventura 10/06 - 12/06 460,000 $6.00-$7.60
Natural Gas Ventura 10/06 - 12/06 920,000 $6.655
Natural Gas Ventura 10/06 - 12/06 460,000 $6.75-$7.71
Natural Gas Ventura 10/06 - 12/06 460,000 $6.75-$7.77
Natural Gas Ventura 10/06 - 12/06 460,000 $7.00-$8.85
Natural Gas NYMEX 10/06 - 12/06 460,000 $7.75-$8.50
Natural Gas Ventura 10/06 - 12/06 460,000 $7.76
Natural Gas CIG 10/06 - 12/06 460,000 $6.50-$6.98
Natural Gas CIG 10/06 - 12/06 460,000 $7.00-$8.87
Natural Gas Ventura 10/06 - 12/06 230,000 $8.50-$10.00
Natural Gas Ventura 10/06 - 12/06 230,000 $8.50-$10.15
Natural Gas Ventura 10/06 - 10/06 155,000 $9.25-$12.88
Natural Gas Ventura 10/06 - 10/06 155,000 $9.25-$12.80
Natural Gas CIG 11/06 - 12/06 305,000 $7.00-$8.65
Natural Gas Ventura 1/07 - 12/07 1,825,000 $8.00-$11.91
Natural Gas Ventura 1/07 - 12/07 912,500 $8.00-$11.80
Natural Gas Ventura 1/07 - 12/07 912,500 $8.00-$11.75
Natural Gas Ventura 1/07 - 12/07 1,825,000 $7.50-$10.55
Natural Gas CIG 1/07 - 12/07 1,825,000 $7.40
Natural Gas CIG 1/07 - 12/07 1,825,000 $7.405
Natural Gas Ventura 1/07 - 12/07 1,460,000 $8.25-$10.80
Natural Gas CIG 1/07 - 12/07 912,500 $7.50-$9.12
Natural Gas Ventura 1/07 - 12/07 1,825,000 $8.29
Natural Gas Ventura 11/06 - 3/07 755,000 $8.00-$9.80
Natural Gas Ventura 1/07 - 12/07 1,825,000 $7.85-$9.70
Natural Gas Ventura 1/07 - 12/07 3,650,000 $7.67
Crude Oil NYMEX 10/06 - 12/06 46,000 $43.00-$54.15
Crude Oil NYMEX 10/06 - 12/06 36,800 $60.00-$69.20
Crude Oil NYMEX 10/06 - 12/06 23,000 $60.00-$76.80
*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.

Commodity	Index*	Period Outstanding	Forward Notional Volume (MMBtu)	Price Swap or Costless Collar Floor-Ceiling (Per MMBtu)
Natural Gas	Ventura	4/07 - 12/07	1,375,000	$8.00-$11.91
Natural Gas	Ventura	4/07 - 12/07	687,500	$8.00-$11.80
Natural Gas	Ventura	4/07 - 12/07	687,500	$8.00-$11.75
Natural Gas	Ventura	4/07 - 12/07	1,375,000	$7.50-$10.55
Natural Gas	CIG	4/07 - 12/07	1,375,000	$7.40
Natural Gas	CIG	4/07 - 12/07	1,375,000	$7.405
Natural Gas	Ventura	4/07 - 12/07	1,100,000	$8.25-$10.80
Natural Gas	CIG	4/07 - 12/07	687,500	$7.50-$9.12
Natural Gas	Ventura	4/07 - 12/07	1,375,000	$8.29
Natural Gas	Ventura	4/07 - 12/07	1,375,000	$7.85-$9.70
Natural Gas	Ventura	4/07 - 12/07	2,750,000	$7.67
Natural Gas	Ventura	4/07 - 10/07	1,605,000	$7.16
Natural Gas	NYMEX	4/07 - 12/07	1,375,000	$7.50-$8.50
Natural Gas	Ventura	11/07 - 3/08	1,520,000	$8.00-$8.75
Natural Gas	Ventura	1/08 - 3/08	910,000	$9.35
Natural Gas	CIG	1/08 - 3/08	910,000	$7.00-$7.79
Natural Gas	CIG	1/08 - 3/08	910,000	$8.06
Natural Gas	Ventura	4/08 - 10/08	1,070,000	$7.00-$8.05
Natural Gas	Ventura	4/08 - 10/08	1,070,000	$7.00-$8.06
Natural Gas	Ventura	4/08 - 10/08	1,070,000	$7.45
Natural Gas	Ventura	4/08 - 10/08	1,070,000	$7.50-$8.70
Natural Gas	Ventura	4/08 - 10/08	1,070,000	$8.005
Natural Gas	Ventura	1/08 - 12/08	1,830,000	$7.00-$8.45
Natural Gas	Ventura	1/08 - 12/08	1,830,000	$7.50-$8.34
Natural Gas	Ventura	11/08 - 12/08	610,000	$8.85
* 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.

Construction materials and mining

A key element of the Company’s long-term strategy for this business is to further expand its presence in the higher-margin materials business (rock, sand, gravel, asphalt cement, ready-mixed concrete and related products), complementing and expanding on the Company’s expertise. 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 (asphalt cement, diesel fuel, cement, etc.), negotiation of contract price escalation provisions and the utilization of national purchasing accounts. Ownership of, and access to aggregate reserves, is key to the vertical integration strategy.

·	The ~~Company’s overall margin is expected to improve~~Company anticipates higher average margins in ~~2006~~2007 as compared to ~~2005 because of strong markets and demand for construction materials and services, favorable weather, and continued operational improvements in Texas.~~2006.

·	Work backlog as of ~~September 30, 2006,~~March 31, 2007, of approximately ~~$594~~$586 million includes a higher expected average margin than the backlog of ~~$597~~$610 million at ~~September 30, 2005.~~March 31, 2006.

Independent power production

~~Earnings at this segment are expected to be minimal in 2006, reflecting primarily~~For information regarding the pending sale of the Company’s Brazilian electric generating facility in June 2005, significantly higher interest expense related to the construction of the Hardin Generating Facility and lower revenues because of the bridge contract renewal at the Brush Generating Facility. The bridge contract will be replaced by a more favorably priced 10-year contract beginning in May 2007.domestic independent power production assets, see Note 21.

·	~~This segment continues to evaluate opportunities for domestic and international investments, utilizing the Company’s disciplined approach for acquisitions.~~

NEW ACCOUNTING STANDARDS

For information regarding new accounting standards, see Note ~~11,~~10, 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, and pension and other postretirement benefits. There were no material changes in the Company’s critical accounting policies involving significant estimates from those reported in the ~~2005~~2006 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the ~~2005~~2006 Annual Report.

LIQUIDITY AND CAPITAL COMMITMENTS

Cash flows

Operating activitiesNet 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~~three months of ~~2006 increased $84.9~~2007 decreased $25.7 million from the comparable ~~2005~~2006 period, the result of increased working capital requirements of $51.4 million, largely due to the effects of:

·	~~Higher depreciation, depletion, and amortization expense of $38.9 million, largely at the~~Lower natural gas costs and ~~oil production business, as previously discussed~~

·	~~Increased net income~~the timing of ~~$31.4 million, largely increased earnings at the construction materials and mining, natural gas and oil production and construction services businesses~~

~~Higher deferred income taxes of $17.2 million due to increased property, plant, and equipment balances at the natural gas and oil production business;~~ natural gas costs recoverable through rate adjustments at the natural gas distribution ~~business; and costs associated with the repurchase of certain first mortgage bonds at the electric and natural gas distribution businesses~~business

·	~~Decreased earnings, net of distributions, from equity method investments of $11.1 million, primarily~~Lower natural gas prices at the ~~result of the sale of the Termoceara Generating Facility~~natural gas and oil production business

Partially offsetting the ~~increase in cash flows from operating activities~~decrease were higher ~~working capital requirements~~depreciation, depletion and amortization expense of ~~$15.3~~$8.8 million and higher deferred income taxes of $7.8 million.

Investing activities Cash flows used in investing activities in the first ~~nine~~three months of ~~2006 increased $122.5~~2007 decreased $27.9 million compared to the comparable ~~2005~~2006 period, the result of:

~~Increased capital expenditures at~~Lower investments of $21.5 million, primarily the ~~natural gas and oil production business, largely due to additional exploration and development, and higher ongoing capital expenditures at~~result of the ~~construction materials and mining business; partially offset by~~sale of the Trinity Generating Facility during the first quarter of 2007

·	Decreased cash used in investing activities from discontinued operations of $20.4 million, primarily the result of lower capital expenditures related to the Hardin Generating Facility

·	~~Lower proceeds from sale of equity method investment due to the absence in 2006 of the 2005 sale of the Termoceara Generating Facility~~

·	~~Increased investments largely due to the acquisition of the Brazilian Transmission Lines in 2006~~

Partially offsetting this ~~increase was a~~ decrease ~~in cash flows used for acquisitions~~were increased net capital expenditures of ~~$38.5~~$14.1 million, ~~largely~~primarily at the natural gas and oil production ~~business.~~and electric businesses.

Financing activities Cash flows ~~provided~~used by financing activities in the first ~~nine~~three months of ~~2006~~2007 increased ~~$3.0~~$26.2 million ~~compared to~~from the comparable ~~2005~~ period in 2006, primarily the result of a decrease in the issuance of long-term debt of $104.2 million, partially offset by a decrease in the repayment of long-term debt of $66.7 million and an increase in the issuance of ~~long-term debt and~~ common stock ~~partially offset by an increase in the repayment~~ of ~~long-term debt and dividends paid.~~$12.2 million.

Defined benefit pension plans

There are no material changes to the Company’s qualified noncontributory defined benefit pension plans from those reported in the ~~2005~~2006 Annual Report. For further information, see Note ~~18.~~17 and Part II, Item 7 in the 2006 Annual Report.

Capital expenditures

Net capital expenditures for the first ~~nine~~three months of ~~2006~~2007 were ~~$487.1~~$126.1 million and are estimated to be approximately ~~$620 million~~$1.07 billion for 2007. With the ~~year 2006.~~exception of the anticipated acquisition of Cascade, the estimated 2007 capital expenditures exclude potential future acquisitions, proceeds related to the disposal of unidentified assets and potential proceeds related to the sale of domestic independent power production assets. Estimated capital expenditures include those for:

·	~~Completed acquisitions~~

·	System upgrades

·	Routine replacements

·	Service extensions

·	Routine equipment maintenance and replacements

·	Buildings, land and building improvements

·	Pipeline and gathering projects

·	Further enhancement of natural gas and oil production and reserve growth

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

·	Anticipated acquisition of Cascade

·	Other growth opportunities

Approximately 2445 percent of estimated ~~2006~~2007 net capital expenditures are associated with ~~completed acquisitions.~~the anticipated acquisition of Cascade. 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 ~~2006~~2007 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; commercial paper credit facilities at Centennial ~~Energy Holdings, Inc.~~ and MDU Resources Group, Inc., 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, 2006.~~March 31, 2007.

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 and upon regulatory approval, up to a maximum of $150 million). There were no amounts outstanding under the credit agreement at ~~September 30, 2006.~~March 31, 2007. The credit agreement supports the Company’s $100 million commercial paper program. Under the Company’s commercial paper program, ~~$12.0~~$1.9 million was outstanding at ~~September 30, 2006.~~March 31, 2007. The commercial paper borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings (supported by the credit agreement, which expires in June 2011). In August 2006, the Company borrowed $100 million through the issuance of unsecured notes. The funds were used primarily to pay down commercial paper borrowings and for general corporate purposes in connection with the Company’s electric and natural gas distribution businesses.

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. One source of alternative funding might involve the securitization of certain Company assets.

To the extent short-term financing is needed for the Cascade acquisition, the Company may utilize bridge financing for up to $310 million. For more information, see Notes 20 and 21.

In order to borrow under the Company’s credit agreement, the Company must be in compliance with the applicable covenants and certain other ~~conditions, including~~conditions. For information on the covenants ~~not to permit, as~~and certain other conditions of the ~~end of any fiscal quarter, (A)~~Company’s credit agreement, see Part II, Item 7, in the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent or (B) the ratio of funded debt to capitalization (determined with respect to the Company alone, excluding its subsidiaries) to be greater than 65 percent. Also included is 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 alone, excluding its subsidiaries), for the 12-month period ended each fiscal quarter, to be less than 2.5 to 1. Other covenants include restrictions on the sale of certain assets and on the making of certain investments.2006 Annual Report. The Company was in compliance with these covenants and met the required conditions at ~~September 30, 2006.~~March 31, 2007. In the event the Company does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued, as previously described.

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 ~~Indenture of~~ 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 Indenture and, in some cases, to certify to the trustee that annual earnings (pretax and before interest charges), as defined in the Indenture, equal at least two times its annualized first mortgage bond interest costs. Under the more restrictive of the tests, as of ~~September 30, 2006,~~March 31, 2007, the Company could have issued approximately ~~$452~~$470 million of additional first mortgage bonds.

The Company's coverage of fixed charges including preferred dividends was ~~6.2~~6.0 times and ~~6.1~~6.4 times for the 12 months ended ~~September 30, 2006~~March 31, 2007 and December 31, ~~2005,~~2006, respectively. Additionally, the Company's first mortgage bond interest coverage was ~~25.0~~27.1 times and ~~10.2~~26.0 times for the 12 months ended ~~September 30, 2006~~March 31, 2007 and December 31, ~~2005,~~2006, respectively. Common stockholders' equity as a percent of total capitalization (net of long-term debt due within one year) was ~~61 percent and 63~~65 percent at ~~September 30, 2006~~both March 31, 2007 and December 31, ~~2005, respectively.~~2006.

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. ~~Between January 1 and September 30, 2006, the Company repurchased $68.0 million of first mortgage bonds.~~ As of ~~September 30, 2006,~~March 31, 2007, the Company had $57.0 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. At such time as the aggregate principal amount of the Company’s outstanding first mortgage bonds, other than those held by the Indenture trustee, is $20 million or less, the Company would have the ability, subject to satisfying certain specified conditions, to require that any debt issued under its Indenture ~~dated as of December 15, 2003, as supplemented, from the Company to The Bank of New York, as trustee,~~ become unsecured and rank equally with all of the Company’s other unsecured and unsubordinated debt (as of ~~September 30, 2006,~~March 31, 2007, 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 July 27, 2006, the Company entered into a Sales Agency Financing Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 3,000,000 shares of the Company’s common stock, par value $1.00 per share, together with preference share purchase rights appurtenant thereto. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement, which terminates on June 30, 2007. The Company is considering extending the Sales Agency Financing Agreement. Proceeds from the sale of shares of common stock under the agreement are expected to be used for corporate development purposes and other general corporate purposes. The offering iswould be made pursuant to the Company’s shelf registration statement on Form S-3, as amended, which became effective on September 26, 2003, as supplemented by a prospectus supplement, dated July 27, 2006, filed with the ~~Securities and Exchange Commission~~SEC pursuant to Rule 424(b) under the Securities Act of 1933, as amended. The Company has not issued any stock under the Sales Agency Financing Agreement through ~~September 30, 2006.~~March 31, 2007.

Centennial Energy Holdings, Inc. Centennial has ~~three~~two revolving credit agreements with various banks and institutions totaling ~~$437.9~~$425 million with certain provisions allowing for increased borrowings. These credit agreements support Centennial’s $400 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at ~~September 30, 2006.~~March 31, 2007. Under the Centennial commercial paper program, ~~$292.5~~$105.8 million was outstanding at ~~September 30, 2006.~~March 31, 2007. 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). One of these credit agreements 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 August 26, 2010. ~~Another agreement is for $17.9 million and expires on April 30, 2007. Centennial intends to negotiate the extension or replacement of these agreements prior to their maturities.~~ The ~~third~~second agreement is an uncommitted line for $25 million (previously $20 ~~million~~million), and may be terminated by the bank at any time. As of ~~September 30, 2006,~~March 31, 2007, $42.5 million of letters of credit were outstanding, as discussed in Note ~~20,~~19, of which ~~$25.9~~$28.4 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 (previously $450 million).~~million. Under the terms of the master shelf agreement, ~~$489.5~~$538.5 million was outstanding at ~~September 30, 2006. On October 16, 2006, Centennial borrowed an additional $50.0 million under this agreement.~~March 31, 2007. The ability to request additional borrowings under this master shelf agreement expires on May 8, 2009. To meet potential future financing needs, Centennial may pursue other financing arrangements, including private and/or public financing.

Centennial’s objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Minor fluctuations in Centennial’s credit ratings have not limited, nor would they be expected to limit, Centennial’s ability to access the capital markets. In the event of a minor downgrade, Centennial may experience a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If Centennial were to experience a significant downgrade of its credit ratings, it may need to borrow under its committed bank lines.

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

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 ~~including covenants not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 65 percent (for~~for the $400 ~~million credit agreement) and 60 percent (for the $17.9~~ million credit agreement and the master shelf ~~agreement). Also included is a covenant that does not permit~~agreement, see Part II, Item 7, in the ratio of Centennial’s earnings before interest, taxes, depreciation and amortization to interest expense, for the 12-month period ended each fiscal quarter, to be less than 2.5 to 1 (for the $400 million credit agreement), 2.25 to 1 (for the $17.9 million credit agreement) and 1.75 to 1 (for the master shelf agreement). Other covenants include minimum consolidated net worth, limitation on priority debt and restrictions on the sale of certain assets and on the making of certain loans and investments.2006 Annual Report. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at ~~September 30, 2006.~~March 31, 2007. 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 as previously described.

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 practice 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, 2006.~~March 31, 2007. 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, including covenants not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 55 percent. Other covenants include limitation on priority debt and some restrictionsconditions. For more information on the ~~sale of~~covenants and certain ~~assets and~~other conditions for the ~~making of certain investments.~~uncommitted long-term master shelf agreement, see Part II, Item 7, in the 2006 Annual Report. Williston Basin was in compliance with these covenants and met the required conditions at ~~September 30, 2006.~~March 31, 2007. 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

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 from approximately two 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.

Contractual obligations and commercial commitments

~~At September 30, 2006,~~There are no material changes in the Company’s contractual obligations ~~related~~relating to long-term debt, ~~estimated interest payments,~~ operating leases and purchase commitments ~~(for the twelve months ended September 30, of each year listed~~from those reported in the ~~table below) were as follows:~~2006 Annual Report.

2007

2008

2009

2010

2011
Thereafter
Total

(In millions)

Long-term debt
$
99.0

$
131.9

$
87.3

$
314.7

$
79.3

$
693.8

$
1,406.0

Estimated interest payments*
75.6

69.9

62.5

58.2

40.7

218.2

525.1

Operating leases 15.9 12.5 10.5 9.6 8.4 35.6 92.5
Purchase commitments 205.2 101.4 66.5 63.0 58.5 245.4 740.0

$
395.7

$
315.7

$
226.8

$
445.5

$
186.9

$
1,193.0

$
2,763.6

* Estimated interest payments are calculated based on the applicable rates and payment dates.
For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2006 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 ~~interest rates.~~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. At March 31, 2007, Fidelity held natural gas swap and collar derivative instruments designated as cash flow hedging instruments and had no outstanding oil derivative instruments. For more information on derivative instruments and commodity price risk, see Part II, Item 7A in the ~~2005~~2006 Annual Report, and Notes 1211 and ~~15.~~14.

The following table summarizes ~~derivative instruments~~hedge agreements entered into by Fidelity as of ~~September 30, 2006.~~March 31, 2007. These agreements call for Fidelity to receive fixed prices and pay variable prices.

(Notional amount and fair value in thousands)

	Weighted Average Fixed Price (Per MMBtu)		Forward Notional Volume (In MMBtu's)	Fair Value		Weighted Average Fixed Price (Per MMBtu)		Forward Notional Volume (In MMBtu's)		Fair Value
Natural gas swap agreements maturing in 2006		$7.02	1,380		$2,218
Natural gas swap agreements maturing in 2007		$7.70	5,475		$6,362	$	7.59		8,480	$	5,947
Natural gas swap agreements maturing in 2008						$	7.45		1,070	$	(415	)

	Weighted Average Floor/Ceiling Price (Per MMBtu)		Forward Notional Volume (In MMBtu's)		Fair Value		Weighted Average Floor/Ceiling Price (Per MMBtu)		Forward Notional Volume (In MMBtu's)		Fair Value
Natural gas collar agreements maturing in 2006	$	7.24/$8.72		4,600		$10,027
Natural gas collar agreements maturing in 2007	$	7.87/$10.74		10,123		$12,787	$	7.82/$10.31		9,273	$	5,644
Natural gas collar agreements maturing in 2008							$	7.24/$8.27		7,620	$	(4,165	)

Weighted
Average
Floor/Ceiling
Price
(Per barrel)

Forward
Notional
Volume
(In barrels)

Fair Value

Oil collar agreements maturing in 2006 $ 52.61/$64.31 106
$(464)

Interest rate risk

There were no material changes to interest rate risk faced by the Company from those reported in the ~~2005~~2006 Annual Report. For more information on interest rate risk, see Part II, Item 7A in the ~~2005~~2006 Annual Report.

At March 31, 2007 and 2006, and December 31, 2006, 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 Note 4 in the 2006 Annual Report.

At March 31, 2007 and 2006, and December 31, 2006, 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 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 period covered by this report 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,~~19, which is incorporated by reference.

ITEM 1A. RISK FACTORS

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

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

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

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

There are no material changes in the Company’s risk factors from those reported in Part I, Item 1A - Risk Factors of the ~~2005~~2006 Annual Report other than the ~~risks~~risk associated with the ~~ongoing litigation and administrative proceedings in connection with the Company’s CBNG development activities, and risks related to foreign operations, a~~ pending ~~utility company acquisition, litigation in connection with one~~sale of the ~~Company’s storage reservoirs and increases in employee and retiree benefit costs,~~domestic independent power production assets, 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.

~~Environmental and Regulatory Risks~~

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

Fidelity has been named as a defendant in, and/or certain of its operations are or have been the subject of, more than a dozen lawsuits filed in connection with its CBNG development in the Powder River Basin in Montana and Wyoming. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material negative effect on Fidelity's existing CBNG operations and/or the future development of its CBNG properties.

The BER in March 2006 issued a decision in a rulemaking proceeding, initiated by the NPRC, that amends the non-degradation policy applicable to water discharged in connection with CBNG operations. The amended policy includes additional limitations on factors deemed harmful, thereby restricting water discharges even further than previous standards. Due in part to this amended policy, in May 2006, the Northern Cheyenne Tribe commenced litigation in Montana state court challenging two five-year water discharge permits that the Montana DEQ granted to Fidelity in February 2006 and which are critical to Fidelity’s ability to manage water produced under present and future CBNG operations. If these permits are set aside, Fidelity’s CBNG operations in Montana could be significantly and adversely affected.

~~Risks Relating to Foreign Operations~~

The value of the Company’s investments in foreign operations may diminish due to political, regulatory and economic conditions and changes in currency exchange rates in countries where the Company does business.

The Company is subject to political, regulatory and economic conditions and changes in currency exchange rates in foreign countries where the Company does business. Significant changes in the political, regulatory or economic environment in these countries could negatively affect the value of the Company’s investments located in these countries. Also, since the Company is unable to predict the fluctuations in the foreign currency exchange rates, these fluctuations may have an adverse impact on the Company’s results of operations.

Other Risks

The Company’s pending ~~acquisition~~sale of ~~Cascade~~the domestic independent power production assets may be delayed or may not occur if certain conditions are not satisfied. ~~Upon completion of the acquisition, if the Company is unable to integrate the Cascade operations effectively, its future financial position or results of operations may be adversely affected.~~

The ~~Company has entered into a definitive merger agreement to acquire Cascade. The total value of the transaction, including the assumption of certain indebtedness, is approximately $475 million. The~~ completion of the ~~acquisition~~pending sale is subject to the ~~approval~~fulfillment of ~~various~~ regulatory ~~authorities, as well as antitrust clearance under the Hart-Scott-Rodino Act,~~approvals and ~~the satisfaction of other customary~~ closing conditions. The inability to complete the sale in a timely manner could affect the Company’s ~~pending~~options for funding the Cascade acquisition, ~~of Cascade may be delayed or may not occur if~~and could result in the Company ~~is unable~~having to timely obtain necessary regulatory approvals, satisfy closing conditions or obtain financing. If the Company is unable to integrate the Cascade operations effectively, its future financial position or results of operations may be adversely affected.incur additional indebtedness and financing costs.

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 storage gas from one of its storage reservoirs. If the subsidiary is not able to obtain relief through the courts or regulatory process, its storage operations could be materially and adversely affected.

Williston Basin has filed suit in Federal court in Montana seeking to recover unspecified damages from Anadarko and its wholly owned subsidiary, Howell, and to enjoin Anadarko’s and Howell’s present and future operations in and near the Elk Basin Storage Reservoir. Based on relevant information, including reservoir and well pressure data, Williston Basin believes that Elk Basin Storage Reservoir pressures have decreased and that the storage reservoir has lost gas as a result of Anadarko’s and Howell’s drilling and production activities. 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 could be materially and adversely affected.

~~Other factors that could impact the Company’s businesses.~~

~~In addition to those reported in Part I, Item 1A - Risk Factors of the 2005 Annual Report, the following factor may also impact the Company’s financial results in future periods:~~

·	~~Increases in employee and retiree benefit costs~~

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

Between ~~July~~January 1, ~~2006~~2007 and ~~September 30, 2006,~~March 31, 2007, the Company issued ~~320,697~~83,097 shares of ~~Common Stock,~~common stock, $1.00 par value, and the preference share purchase rights appurtenant thereto, as part of the consideration paid by the Company in the acquisition of ~~a business~~businesses acquired by the Company in ~~this~~a prior period. The ~~Common Stock~~common stock and preference share purchase rights issued by the Company in ~~this transaction~~these transactions were issued in a private transaction exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 4 (2) thereof, Rule 506 promulgated thereunder, or both. The classes of persons to whom these securities were sold were either accredited investors or other persons to whom such securities were permitted to be offered under the applicable exemption.

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

ISSUER PURCHASES OF EQUITY SECURITIES

Period
(a)

Total Number of Shares
(or Units) Purchased (1)
(b)

Average Price Paid
per Share
(or Unit)
(c)
Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)
(d)
Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2)
January 1 through January 31, 2007
February 1 through February 28, 2007 77,834 $26.08
March 1 through March 31, 2007
Total 77,834

(1) Represents shares of common stock withheld by the Company to pay taxes in connection with the vesting of shares granted pursuant to a compensation plan.

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

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

The Company’s Annual Meeting of Stockholders was held on April 24, 2007. Five proposals were submitted to stockholders as described in the Company’s Proxy Statement dated March 8, 2007, and were voted upon and approved by stockholders at the meeting. The table below briefly describes the proposals and the results of the stockholder votes.

Shares
Shares Against or Broker
For Withheld Abstentions Non-Votes
Proposal to elect four directors:
For terms expiring in 2010 --

Terry D. Hildestad 162,206,699 1,678,213 --- ---
Dennis W. Johnson 161,958,358 1,926,554 --- ---
John L. Olson 160,627,881 3,257,031 --- ---
John K. Wilson
162,181,991 1,702,921 --- ---

Proposal to increase the authorized shares of common stock

147,112,808

15,757,319

1,014,785

---

Proposal to declassify the board of directors 159,184,819 3,278,410 1,421,683 ---

Proposal to ratify the appointment of Deloitte & Touche LLP as the Company’s independent auditors for 2007

162,102,994

1,032,520

749,398

---

Shareholder proposal requesting a
sustainability report
40,135,023 75,528,517 11,998,709 36,229,708

ITEM 6. EXHIBITS

3
12	~~Computation~~Certificate of ~~Ratio~~Amendment, dated April 24, 2007, of ~~Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends~~Restated Certificate of Incorporation of the Company

~~31(a)~~10(a)	~~Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~Centennial Power, Inc. and Colorado Energy Management, LLC Purchase and Sale Agreement by and between Centennial Energy Resources LLC, as Seller, and Montana Acquisition Company LLC, as Buyer, dated April 25, 2007

~~31(b)~~+10(b)	~~Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~MDU Resources Group, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as amended February 14, 2007

32+10(c)	~~Certification of Chief~~Montana-Dakota Utilities Co. Executive ~~Officer~~Incentive Compensation Plan and ~~Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350,~~Rules and Regulations as ~~adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~amended February 14, 2007

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.

~~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.~~

+10(d)		~~MDU RESOURCES GROUP, INC.~~WBI Holdings, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as amended February 26, 2007

+10(e)	Knife River Corporation Executive Incentive Compensation Plan and Rules and Regulations, as amended February 26, 2007

+10(f)			MDU Construction Services Group, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as adopted May 2, 2006

~~DATE: November 3, 2006~~		~~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.~~

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

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

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

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

+ Management contract, compensatory plan or arrangement.

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

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

MDU RESOURCES GROUP, INC.
DATE: May 8, 2007
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.

3 Certificate of Amendment, dated April 24, 2007, of Restated Certificate of Incorporation of the Company
10(a) Centennial Power, Inc. and Colorado Energy Management, LLC Purchase and Sale Agreement by and between Centennial Energy Resources LLC, as Seller, and Montana Acquisition Company LLC, as Buyer, dated April 25, 2007
+10(b) MDU Resources Group, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as amended February 14, 2007
+10(c) Montana-Dakota Utilities Co. Executive Incentive Compensation Plan and Rules and Regulations as amended February 14, 2007
+10(d) WBI Holdings, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as amended February 26, 2007
+10(e) Knife River Corporation Executive Incentive Compensation Plan and Rules and Regulations, as amended February 26, 2007
+10(f) MDU Construction Services Group, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as adopted May 2, 2006
12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends
31(a) Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31(b) Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32 Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

	Three Months Ended September 30, 2005		Nine Months Ended September 30, 2005
	(In thousands, except per share amounts)
Earnings on common stock, as reported	$	87,052	$	201,303
Stock-based compensation expense included in reported earnings, net of related tax effects		---		4
Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects		50		(75	)
Pro forma earnings on common stock	$	87,102	$	201,232
Earnings per common share - basic - as reported	$	.49	$	1.13
Earnings per common share - basic - pro forma	$	.49	$	1.13
Earnings per common share - diluted - as reported	$	.48	$	1.12
Earnings per common share - diluted - pro forma	$	.48	$	1.12

						Weighted
						Average
				Weighted		Remaining
				Average		Contractual
				Exercise		Life
	Shares			Price		In Years
Outstanding at beginning of period		2,786,973		$	12.99
Granted		---			---
Forfeited		(89,873	)		13.05
Exercised		(263,746	)		12.35
Outstanding at end of period		2,433,354			13.06		4.1
Exercisable at end of period		1,352,328		$	12.61		3.9

	Options Outstanding								Options Exercisable
			Remaining		Weighted		Aggregate				Weighted		Aggregate
Range of	Number		Contractual		Average		Intrinsic		Number		Average		Intrinsic
Exercisable	Out-		Life		Exercise		Value		Exer-		Exercise		Value
Prices	standing		in Years		Price		(000’s)		cisable		Price		(000’s)
$ 7.28 - 8.00		10,124		0.8	$	7.28	$	152		10,124	$	7.28	$	152
8.01 - 11.00		290,565		1.7		9.60		3,702		287,673		9.60		3,666
11.01 - 14.00		1,877,924		4.4		13.18		17,202		962,831		13.19		8,809
14.01 - 17.13		254,741		4.5		16.32		1,534		91,700		16.54		532
Balance at end of period		2,433,354		4.1	$	13.06	$	22,590		1,352,328	$	12.61	$	13,159

	2007		2008		2009		2010		2011		Thereafter		Total
	(In millions)
Long-term debt	$	99.0	$	131.9	$	87.3	$	314.7	$	79.3	$	693.8	$	1,406.0
Estimated interest payments*		75.6		69.9		62.5		58.2		40.7		218.2		525.1
Operating leases		15.9		12.5		10.5		9.6		8.4		35.6		92.5
Purchase commitments		205.2		101.4		66.5		63.0		58.5		245.4		740.0
	$	395.7	$	315.7	$	226.8	$	445.5	$	186.9	$	1,193.0	$	2,763.6
* Estimated interest payments are calculated based on the applicable rates and payment dates.

	Weighted Average Floor/Ceiling Price (Per barrel)		Forward Notional Volume (In barrels)		Fair Value
Oil collar agreements maturing in 2006	$	52.61/$64.31		106		$(464)

Period	(a) Total Number of Shares (or Units) Purchased (1)	(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2)
January 1 through January 31, 2007
February 1 through February 28, 2007	77,834	$26.08
March 1 through March 31, 2007
Total	77,834

		Shares
	Shares	Against or		Broker
	For	Withheld	Abstentions	Non-Votes
Proposal to elect four directors: For terms expiring in 2010 --
Terry D. Hildestad	162,206,699	1,678,213	---	---
Dennis W. Johnson	161,958,358	1,926,554	---	---
John L. Olson	160,627,881	3,257,031	---	---
John K. Wilson	162,181,991	1,702,921	---	---

Proposal to increase the authorized shares of common stock	147,112,808	15,757,319	1,014,785	---

Proposal to declassify the board of directors	159,184,819	3,278,410	1,421,683	---

Proposal to ratify the appointment of Deloitte & Touche LLP as the Company’s independent auditors for 2007	162,102,994	1,032,520	749,398	---

Shareholder proposal requesting a sustainability report	40,135,023	75,528,517	11,998,709	36,229,708


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.



DATE: May 8, 2007	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

3	Certificate of Amendment, dated April 24, 2007, of Restated Certificate of Incorporation of the Company

10(a)	Centennial Power, Inc. and Colorado Energy Management, LLC Purchase and Sale Agreement by and between Centennial Energy Resources LLC, as Seller, and Montana Acquisition Company LLC, as Buyer, dated April 25, 2007

+10(b)	MDU Resources Group, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as amended February 14, 2007

+10(c)	Montana-Dakota Utilities Co. Executive Incentive Compensation Plan and Rules and Regulations as amended February 14, 2007

+10(d)	WBI Holdings, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as amended February 26, 2007

+10(e)	Knife River Corporation Executive Incentive Compensation Plan and Rules and Regulations, as amended February 26, 2007

+10(f)	MDU Construction Services Group, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as adopted May 2, 2006

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