UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

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

For The Quarterly Period Ended September 30, 2005

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2005 OR 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~~

(Exact name of registrant as specified in its charter) ~~Delaware 41-0423660 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.)~~

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

Schuchart Building

918 East Divide Avenue

Bismarck, North Dakota 58506-5650 ~~(Address~~

(Address of principal executive offices) ~~(Zip~~

(701) 222-7900 ~~(Registrant's~~

(Registrant's telephone number, including area code)

·	Acquisition, disposal and impairment of assets or facilities

·	Changes in operation, performance and construction of plant facilities or other assets

·	Changes in present or prospective generation

·	The availability of economic expansion or development opportunities

·	Population growth rates and demographic patterns

·	Market demand for, and/or available supplies of, energy products and services

·	Cyclical nature of large construction projects at certain operations

·	Changes in tax rates or policies

·	Unanticipated project delays or changes in project costs

·	Unanticipated changes in operating expenses or capital expenditures

·	Labor negotiations or disputes

·	Inability of the various contract counterparties to meet their contractual obligations

·	Changes in accounting principles and/or the application of such principles to the Company

·	Changes in technology

·	Changes in legal or regulatory proceedings

·	The ability to effectively integrate the operations and controls of acquired companies

INDEX Part I -- Financial Information Consolidated Statements of Income -- Three and Six Months Ended June 30, 2005 and 2004 Consolidated Balance Sheets -- June 30, 2005 and 2004, and December 31, 2004 Consolidated Statements of Cash Flows -- Six Months Ended June 30, 2005 and 2004 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 Unregistered Sales of Equity Securities and Use of Proceeds Exhibits Signatures Exhibit Index Exhibits

Part I -- Financial Information

Consolidated Statements of Income -- Three and Nine Months Ended September 30, 2005 and 2004

Consolidated Balance Sheets -- September 30, 2005 and 2004, and December 31, 2004

Consolidated Statements of Cash Flows -- Nine Months Ended September 30, 2005 and 2004

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

Unregistered Sales of Equity Securities and Use of Proceeds

Exhibits

Signatures

Exhibit Index

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (In thousands, except per share amounts) Operating revenues: Electric, natural gas distribution and pipeline and energy services $182,109 $159,368 $ 437,481 $ 391,215 Utility services, natural gas and oil production, construction materials and mining, independent power production and other 588,063 493,933 936,986 777,545 770,172 653,301 1,374,467 1,168,760 Operating expenses: Fuel and purchased power 14,547 16,370 30,733 33,095 Purchased natural gas sold 46,673 39,534 160,172 134,278 Operation and maintenance: Electric, natural gas distribution and pipeline and energy services 39,482 38,329 78,467 80,530 Utility services, natural gas and oil production, construction materials and mining, independent power production and other 475,784 397,084 766,788 643,454 Depreciation, depletion and amortization 51,588 51,787 104,427 101,298 Taxes, other than income 28,574 25,466 55,243 47,351 656,648 568,570 1,195,830 1,040,006 Operating income 113,524 84,731 178,637 128,754 Earnings from equity method investments 15,404 7,723 16,718 11,148 Other income 1,505 1,847 2,656 3,216 Interest expense 13,342 15,653 26,359 29,499 Income before income taxes 117,091 78,648 171,652 113,619 Income taxes 36,918 20,018 57,059 31,410 Net income 80,173 58,630 114,593 82,209 Dividends on preferred stocks 171 172 342 342 Earnings on common stock $ 80,002 $ 58,458 $ 114,251 $ 81,867 Earnings per common share -- basic $ .68 $ .50 $ .97 $ .71 Earnings per common share -- diluted $ .67 $ .50 $ .96 $ .70 Dividends per common share $ .18 $ .17 $ .36 $ .34 Weighted average common shares outstanding -- basic 118,348 116,559 118,089 115,609 Weighted average common shares outstanding -- diluted 119,037 117,567 118,767 116,632

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	186,104	$	149,623	$	623,585	$	540,837
Utility services, natural gas and oil production, construction materials and mining, independent power production and other		880,758		654,975		1,817,744		1,432,521
		1,066,862		804,598		2,441,329		1,973,358

Operating expenses:
Fuel and purchased power		16,286		15,995		47,019		49,090
Purchased natural gas sold		33,235		24,305		193,407		158,583
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services		39,211		37,307		117,676		117,834
Utility services, natural gas and oil production, construction materials and mining, independent power production and other		735,045		527,669		1,501,835		1,171,126
Depreciation, depletion and amortization		60,580		53,115		165,007		154,413
Taxes, other than income		32,910		25,525		88,153		72,876
Asset impairments (Notes 13 and 14)		---		6,106		---		6,106
		917,267		690,022		2,113,097		1,730,028

Operating income		149,595		114,576		328,232		243,330

Earnings from equity method investments		1,800		7,198		18,518		18,346

Other income		1,751		3,729		4,407		6,944

Interest expense		14,207		14,285		40,566		43,784

Income before income taxes		138,939		111,218		310,591		224,836

Income taxes		51,716		39,499		108,775		70,907

Net income		87,223		71,719		201,816		153,929

Dividends on preferred stocks		171		171		513		514

Earnings on common stock	$	87,052	$	71,548	$	201,303	$	153,415


Earnings per common share -- basic	$	.73	$	.61	$	1.70	$	1.32

Earnings per common share -- diluted	$	.72	$	.60	$	1.69	$	1.31

Dividends per common share	$	.19	$	.18	$	.55	$	.52

Weighted average common shares outstanding -- basic		119,619		117,109		118,605		116,112

Weighted average common shares outstanding -- diluted		120,389		118,278		119,302		117,225

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited) June 30, June 30, December 31, 2005 2004 2004 (In thousands, except shares and per share amounts) ASSETS Current assets: Cash and cash equivalents $ 57,711 $ 132,476 $ 99,377 Receivables, net 546,722 421,653 440,903 Inventories 158,886 121,920 143,880 Deferred income taxes 6,840 5,457 2,874 Prepayments and other current assets 56,859 62,304 41,144 827,018 743,810 728,178 Investments 98,563 78,067 120,555 Property, plant and equipment 4,273,670 3,744,146 3,931,428 Less accumulated depreciation, depletion and amortization 1,440,732 1,267,014 1,358,723 2,832,938 2,477,132 2,572,705 Deferred charges and other assets: Goodwill 214,972 200,553 199,743 Other intangible assets, net 30,297 21,105 22,269 Other 91,953 91,941 90,071 337,222 313,599 312,083 $4,095,741 $3,612,608 $3,733,521 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Long-term debt due within one year $ 26,866 $ 93,249 $ 72,046 Accounts payable 212,888 183,097 184,993 Taxes payable 26,300 23,031 28,372 Dividends payable 21,685 20,139 21,449 Other accrued liabilities 164,225 132,866 142,233 451,964 452,382 449,093 Long-term debt 1,119,719 887,721 873,441 Deferred credits and other liabilities: Deferred income taxes 505,651 467,376 494,589 Other liabilities 244,018 232,464 235,385 749,669 699,840 729,974 Commitments and contingencies Stockholders' equity: Preferred stocks 15,000 15,000 15,000 Common stockholders' equity: Common stock Shares issued -- $1.00 par value 120,093,303 at June 30, 2005, 117,829,664 at June 30, 2004 and 118,586,065 at December 31, 2004 120,093 117,830 118,586 Other paid-in capital 898,373 843,658 863,449 Retained earnings 770,361 617,222 699,095 Accumulated other comprehensive loss (24,347) (17,419) (11,491) Treasury stock at cost - 412,906 shares at June 30, 2005, and 359,281 shares at December 31, 2004 and June 30, 2004 (5,091) (3,626) (3,626) Total common stockholders' equity 1,759,389 1,557,665 1,666,013 Total stockholders' equity 1,774,389 1,572,665 1,681,013 $4,095,741 $3,612,608 $3,733,521

	September 30, 2005			September 30, 2004			December 31, 2004
	(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	98,392		$	145,001		$	99,377
Receivables, net		632,207			465,748			440,903
Inventories		193,934			152,043			143,880
Deferred income taxes		3,416			4,244			2,874
Prepayments and other current assets		42,100			51,824			41,144
		970,049			818,860			728,178
Investments		100,954			113,056			120,555
Property, plant and equipment		4,397,510			3,825,010			3,931,428
Less accumulated depreciation, depletion and amortization		1,490,465			1,313,695			1,358,723
		2,907,045			2,511,315			2,572,705
Deferred charges and other assets:
Goodwill		214,939			199,467			199,743
Other intangible assets, net		28,487			23,331			22,269
Other		90,256			88,451			90,071
		333,682			311,249			312,083
	$	4,311,730		$	3,754,480		$	3,733,521
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Long-term debt due within one year	$	86,802		$	86,792		$	72,046
Accounts payable		300,509			183,451			184,993
Taxes payable		75,263			51,891			28,372
Dividends payable		22,935			21,414			21,449
Other accrued liabilities		255,355			159,071			142,233
		740,864			502,619			449,093
Long-term debt		1,047,245			912,440			873,441
Deferred credits and other liabilities:
Deferred income taxes		473,419			475,354			494,589
Other liabilities		264,188			237,184			235,385
		737,607			712,538			729,974
Commitments and contingencies
Stockholders’ equity:
Preferred stocks		15,000			15,000			15,000
Common stockholders’ equity:
Common stock
Shares issued -- $1.00 par value 120,191,877 at September 30, 2005, 118,395,863 at September 30, 2004 and 118,586,065 at December 31, 2004		120,192			118,396			118,586
Other paid-in capital		901,302			854,519			863,449
Retained earnings		834,567			667,474			699,095
Accumulated other comprehensive loss		(81,421	)		(24,880	)		(11,491	)
Treasury stock at cost - 359,281 shares		(3,626	)		(3,626	)		(3,626	)
Total common stockholders’ equity		1,771,014			1,611,883			1,666,013
Total stockholders’ equity		1,786,014			1,626,883			1,681,013
	$	4,311,730		$	3,754,480		$	3,733,521

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) Six Months Ended June 30, 2005 2004 (In thousands) Operating activities: Net income $114,593 $ 82,209 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 104,427 101,298 Earnings, net of distributions, from equity method investments (14,619) (10,455) Deferred income taxes 5,120 10,141 Changes in current assets and liabilities, net of acquisitions: Receivables (34,399) (45,143) Inventories (12,963) (2,863) Other current assets (16,463) (11,508) Accounts payable 20,545 24,026 Other current liabilities (12,193) 23,814 Other noncurrent changes 9,282 809 Net cash provided by operating activities 163,330 172,328 Investing activities: Capital expenditures (216,912) (141,868) Acquisitions, net of cash acquired (162,274) (22,006) Net proceeds from sale or disposition of property 11,355 10,001 Investments 657 (22,684) Proceeds from notes receivable --- 22,000 Net cash used in investing activities (367,174) (154,557) Financing activities: Issuance of long-term debt 324,727 55,115 Repayment of long-term debt (123,734) (42,202) Proceeds from issuance of common stock 4,116 54,917 Dividends paid (42,931) (39,466) Net cash provided by financing activities 162,178 28,364 Increase (decrease) in cash and cash equivalents (41,666) 46,135 Cash and cash equivalents -- beginning of year 99,377 86,341 Cash and cash equivalents -- end of period $ 57,711 $132,476

	Nine Months Ended September 30,
	2005			2004
	(In thousands)
Operating activities:
Net income	$	201,816		$	153,929
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		165,007			154,413
Earnings, net of distributions, from equity method investments		(14,235	)		(17,203	)
Deferred income taxes		11,706			21,512
Asset impairments		---			6,106
Changes in current assets and liabilities, net of acquisitions:
Receivables		(162,612	)		(88,507	)
Inventories		(47,945	)		(32,066	)
Other current assets		(1,534	)		(1,021	)
Accounts payable		88,365			28,783
Other current liabilities		49,743			64,050
Other noncurrent changes		13,445			8,507

Net cash provided by operating activities		303,756			298,503

Investing activities:
Capital expenditures		(341,609	)		(225,165	)
Acquisitions, net of cash acquired		(162,774	)		(33,147	)
Net proceeds from sale or disposition of property		31,643			11,680
Investments		(1,863	)		(52,313	)
Proceeds from sale of equity method investment		38,166			---
Proceeds from notes receivable		---			22,000

Net cash used in investing activities		(436,437	)		(276,945	)

Financing activities:
Issuance of long-term debt		292,492			72,215
Repayment of long-term debt		(104,038	)		(41,041	)
Proceeds from issuance of common stock		7,858			65,533
Dividends paid		(64,616	)		(59,605	)

Net cash provided by financing activities		131,696			37,102

Increase (decrease) in cash and cash equivalents		(985	)		58,660
Cash and cash equivalents -- beginning of year		99,377			86,341

Cash and cash equivalents -- end of period	$	98,392		$	145,001

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS ~~June~~

September 30, 2005 and 2004

(Unaudited) ~~1. Basis of presentation~~

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 Annual Report ~~to Stockholders~~ on Form 10-K for the year ended December 31, 2004 (2004 Annual Report), and the standards of accounting measurement set forth in Accounting Principles Board (APB) Opinion No. 28 and any amendments thereto adopted by the Financial Accounting Standards Board (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 ~~Company's~~ 2004 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~~

2.	Seasonality of operations

Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year. ~~3. Allowance for doubtful accounts~~

3.	Allowance for doubtful accounts

The Company's allowance for doubtful accounts as of ~~June~~September 30, 2005 and 2004, and December 31, 2004, was ~~$7.4~~$8.6 million, ~~$8.0~~$7.5 million and $6.8 million, respectively. ~~4. Natural gas in underground storage~~

4.	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 ~~$7.2~~$45.0 million, ~~$5.2~~$34.6 million and $24.9 million at ~~June~~September 30, 2005 and 2004, and December 31, 2004, respectively. The remainder of natural gas in underground storage was included in other assets and was $43.3 million, $42.6 million and $43.3 million at ~~June~~September 30, 2005 and 2004, and December 31, 2004, respectively. ~~5. Inventories~~

Inventories, other than natural gas in underground storage for the ~~Company's~~Company’s regulated operations, consisted primarily of aggregates held for resale of ~~$84.2~~$79.5 million, ~~$68.1~~$68.8 million and $71.0 million; materials and supplies of ~~$45.8~~$47.3 million, ~~$36.0~~$33.3 million and $31.0 million; and other inventories of ~~$21.7~~$22.1 million, ~~$12.6~~$15.3 million and $17.0 ~~million;~~million, as of ~~June~~September 30, 2005 and 2004, and December 31, 2004, respectively. These inventories were stated at the lower of average cost or market. ~~6. Earnings per common share~~

6.	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 ~~six~~nine months ended ~~June~~September 30, 2004, 36,000 and 205,305 shares, respectively, with an average exercise price of $25.70 and $24.54, respectively, attributable to the exercise of outstanding stock options, were excluded from the calculation of diluted earnings per share because their effect was antidilutive. For the three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, no adjustments were made to reported earnings in the computation of earnings per share. Common stock outstanding includes issued shares less shares held in treasury. ~~7. Stock-based compensation~~

7.	Stock-based compensation

The Company has stock option plans for directors, key employees and employees. In 2003, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation," and began expensing the fair market value of stock options for all awards granted on or after January 1, 2003. Compensation expense recognized for awards granted on or after January 1, 2003, for the ~~six~~nine months ended ~~June~~September 30, 2005, was $4,000 (after tax). Compensation expense recognized for awards granted on or after January 1, 2003, for the three and ~~six~~nine months ended ~~June~~September 30, 2004, was ~~$2,000~~$3,000 and ~~$5,000,~~$8,000, respectively (after tax).

As permitted by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123," the Company accounts for stock options granted prior to January 1, 2003, under APB Opinion No. 25, "Accounting for Stock Issued to Employees." No compensation expense has 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 grant.

The Company adopted SFAS No. 123 effective January 1, 2003, for newly granted options only. The following table illustrates the effect on earnings and earnings per common share for the three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, 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 June 30, 2005 2004 (In thousands, except per share amounts) Earnings on common stock, as reported $ 80,002 $ 58,458 Stock-based compensation expense included in reported earnings, net of related tax effects --- 2 Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects (88) (79) Pro forma earnings on common stock $ 79,914 $ 58,381 Earnings per common share -- basic -- as reported $ .68 $ .50 Earnings per common share -- basic -- pro forma $ .68 $ .50 Earnings per common share -- diluted -- as reported $ .67 $ .50 Earnings per common share -- diluted -- pro forma $ .67 $ .50 Six Months Ended June 30, 2005 2004 (In thousands, except per share amounts) Earnings on common stock, as reported $114,251 $ 81,867 Stock-based compensation expense included in reported earnings, net of related tax effects 4 5 Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects (125) (172) Pro forma earnings on common stock $114,130 $ 81,700 Earnings per common share -- basic -- as reported $ .97 $ .71 Earnings per common share -- basic -- pro forma $ .97 $ .71 Earnings per common share -- diluted -- as reported $ .96 $ .70 Earnings per common share -- diluted -- pro forma $ .96 $ .70 8. Cash flow information

	Three Months Ended September 30,
	2005		2004
	(In thousands, except per share amounts)

Earnings on common stock, as reported	$	87,052	$	71,548
Stock-based compensation expense included in reported earnings, net of related tax effects		---		3
Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects		50		(79	)
Pro forma earnings on common stock	$	87,102	$	71,472

Earnings per common share -- basic -- as reported	$	.73	$	.61

Earnings per common share -- basic -- pro forma	$	.73	$	.61

Earnings per common share -- diluted -- as reported	$	.72	$	.60

Earnings per common share -- diluted -- pro forma	$	.72	$	.60

	Nine Months Ended September 30,
	2005			2004
	(In thousands, except per share amounts)

Earnings on common stock, as reported	$	201,303		$	153,415
Stock-based compensation expense included in reported earnings, net of related tax effects		4			8
Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects		(75	)		(251	)
Pro forma earnings on common stock	$	201,232		$	153,172

Earnings per common share -- basic -- as reported	$	1.70		$	1.32

Earnings per common share -- basic -- pro forma	$	1.70		$	1.32

Earnings per common share -- diluted -- as reported	$	1.69		$	1.31

Earnings per common share -- diluted -- pro forma	$	1.69		$	1.31

8.	Cash flow information

Cash expenditures for interest and income taxes were as follows: Six Months Ended June 30, 2005 2004 (In thousands) Interest, net of amount capitalized $ 23,184 $26,269 Income taxes paid $ 54,650 $21,295 9. Reclassifications

	Nine Months Ended September 30,
	2005		2004
	(In thousands)

Interest, net of amount capitalized	$	33,059	$	35,334
Income taxes paid	$	60,578	$	22,671

9.	Reclassifications

Certain reclassifications have been made in the financial statements for the prior year to conform to the current presentation. Such reclassifications had no effect on net income or ~~stockholders'~~stockholders’ equity as previously reported. ~~10. New accounting standards~~

10.	New accounting standards

In September 2004, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 106 (SAB No. 106) which is an interpretation regarding the application of SFAS No. 143, ~~"Accounting~~“Accounting for Asset Retirement ~~Obligations"~~Obligations” by oil and gas producing companies following the full-cost accounting method. SAB No. 106 clarifies that the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full-cost ceiling calculation. SAB No. 106 also states that a company is expected to disclose in the financial statement footnotes and MD&A how the ~~company's~~company’s calculation of the ceiling test and depreciation, depletion and amortization are affected by the adoption of SFAS No. 143. SAB No. 106 was effective for the Company as of January 1, 2005. The adoption of SAB No. 106 did not have a material effect on the Company's financial position or results of operations. The effects of the adoption of SFAS No. 143 and SAB No. 106 as they relate to the ~~Company's~~Company’s natural gas and oil production properties are described below.

Ceiling Test Calculation

As discussed in Note 1 of the 2004 Annual Report, the ~~Company's~~Company’s natural gas and oil production properties are subject to a ~~"ceiling test"~~“ceiling test” that limits capitalized costs to the aggregate of the present value of future net revenues of proved reserves based on single point-in-time spot market prices, as mandated under the rules of the SEC, and the cost of unproved properties. Prior to the adoption of SFAS No. 143, the Company calculated the full-cost ceiling by reducing its expected future revenues from proved natural gas and oil reserves by the estimated future expenditures to be incurred in developing and producing such reserves, including future retirements, discounted using a factor mandated by the rules of the SEC. While expected future cash flows related to the asset retirement obligations were included in the calculation of the ceiling test, no associated asset retirement obligation was recognized on the balance sheet.

Upon the adoption of SFAS No. 143 but prior to the effective date of SAB No. 106, the Company continued to calculate the full-cost ceiling as previously described. In addition, the Company recorded the fair value of a liability for the asset retirement obligation and capitalized the cost by increasing the carrying amount of the related long-lived asset.

Upon the adoption of SAB No. 106, the future capitalized discounted cash outflows associated with settling asset retirement obligations that are accrued on the consolidated balance sheet are excluded from the computation of the present value of estimated future net revenues for purposes of the ~~full- cost~~full-cost ceiling calculation in accordance with SAB No. 106.

Depreciation, Depletion, and Amortization

Costs subject to amortization include: (A) all capitalized costs, less accumulated amortization, other than the cost of acquiring and evaluating unproved property; (B) the estimated future expenditures (based on current costs) to be incurred in developing proved reserves; and (C) estimated dismantlement and abandonment costs, net of estimated salvage values.

Subsequent to the adoption of SFAS No. 143, the estimated future dismantlement and abandonment costs described in (C) above are included in the capitalized costs described in (A) above at the expected future cost discounted to the present value, to the extent that a legal obligation exists. Under SFAS No. 143, the recognition of the asset retirement obligation does not take into account estimated salvage values. The liability associated with the recognition of an asset retirement obligation is accreted over time with accretion expense recorded in depreciation, depletion, and amortization expense on the income statement. The ~~Company's~~Company’s estimated dismantlement and abandonment costs as described in (C) above were adjusted to account for asset retirement obligations accrued on the consolidated balance sheet when calculating the depreciation, depletion and amortization rates. In addition, estimated salvage values were included in the ~~Company's~~Company’s depreciation, depletion and amortization calculation. The ~~Company's~~Company’s estimate of future dismantlement and abandonment costs that will be incurred as a result of future development activities on proved reserves continues to be included in the calculation of costs to be amortized.

Any gains or losses on the settlement of an asset retirement obligation, if applicable, are treated as adjustments to the capitalized costs, consistent with the full-cost accounting method.

SFAS No. 123 (revised)

In December 2004, the FASB issued SFAS No. 123 (revised 2004), ~~"Share-Based Payment"~~“Share-Based Payment” (SFAS No. 123 (revised)). SFAS No. 123 (revised) 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) requires a company to record 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. SFAS No. 123 (revised) is effective for the Company on January 1, 2006. The Company is evaluating the effects of the adoption of SFAS No. 123 (revised).

In March 2005, the FASB issued FASB Interpretation No. 47, ~~"Accounting~~“Accounting for Conditional Asset Retirement Obligations - An Interpretation of FASB Statement No. ~~143"~~143” (FIN 47). FIN 47 addresses the diverse accounting practices that developed with respect to the timing of liability recognition for legal obligations associated with the retirement of a tangible ~~long- lived~~long-lived asset when the timing and/or method of settlement of the obligation are conditional on a future event. FIN 47 concludes that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the ~~liability's~~liability’s fair value can be reasonably estimated. FIN 47 is effective for the Company at the end of the fiscal year ending December 31, 2005. The Company is evaluating the effects of the adoption of FIN 47.

In March 2005, the FASB ratified Emerging Issues Task Force Issue No. 04-6, ~~"Accounting~~“Accounting for Stripping Costs in the Mining ~~Industry"~~Industry” (EITF No. 04-6). EITF No. 04-6 requires that ~~post- production~~post-production stripping costs be treated as a variable inventory production cost. As a result, such costs will be subject to inventory costing procedures in the period they are incurred. EITF No. 04-6 is effective for the Company on January 1, 2006. The ~~Company is evaluating the effects of the~~ adoption of EITF No. ~~04-6. 11. Comprehensive income~~ 04-6 is not expected to have a material effect on the Company’s financial position or results of operations.

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)~~loss resulted from ~~gains (losses)~~losses on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note 1415 of Notes to Consolidated Financial Statements.

Comprehensive income, and the components of other comprehensive ~~income (loss)~~loss and related tax effects, were as follows: Three Months Ended June 30, 2005 2004 (In thousands) Net income $80,173 $58,630 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 $1,225 and $3,711 in 2005 and 2004, respectively 1,957 (5,804) Less: Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $4,522 and $1,473 in 2005 and 2004, respectively (7,223) (2,304) Net unrealized gain (loss) on derivative instruments qualifying as hedges 9,180 (3,500) Foreign currency translation adjustment (925) (377) 8,255 (3,877) Comprehensive income $88,428 $54,753 Six Months Ended June 30, 2005 2004 (In thousands) Net income $114,593 $82,209 Other comprehensive loss: Net unrealized loss on derivative instruments qualifying as hedges: Net unrealized loss on derivative instruments arising during the period, net of tax of $8,467 and $6,424 in 2005 and 2004, respectively (13,525) (10,047) Less: Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $1,057 and $1,020 in 2005 and 2004, respectively (1,688) (1,595) Net unrealized loss on derivative instruments qualifying as hedges (11,837) (8,452) Foreign currency translation adjustment (1,019) (1,438) (12,856) (9,890) Comprehensive income $101,737 $72,319 12. Equity method investments

	Three Months Ended September 30,
	2005			2004
	(In thousands)

Net income	$	87,223		$	71,719
Other comprehensive loss:
Net unrealized loss on derivative instruments qualifying as hedges:
Net unrealized loss on derivative instruments arising during the period, net of tax of $39,038 and $7,255 in 2005 and 2004, respectively		(62,360	)		(11,768	)
Less: Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $3,353 and $2,166 in 2005 and 2004, respectively		(5,356	)		(3,388	)
Net unrealized loss on derivative instruments qualifying as hedges		(57,004	)		(8,380	)
Foreign currency translation adjustment		(70	)		919
		(57,074	)		(7,461	)
Comprehensive income	$	30,149		$	64,258

	Nine Months Ended September 30,
	2005			2004
	(In thousands)

Net income	$	201,816		$	153,929
Other comprehensive loss:
Net unrealized loss on derivative instruments qualifying as hedges:
Net unrealized loss on derivative instruments arising during the period, net of tax of $44,991 and $12,069 in 2005 and 2004, respectively		(71,869	)		(19,297	)
Less: Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $1,895 and $1,576 in 2005 and 2004, respectively		(3,028	)		(2,465	)
Net unrealized loss on derivative instruments qualifying as hedges		(68,841	)		(16,832	)
Foreign currency translation adjustment		(1,089	)		(519	)
		(69,930	)		(17,351	)
Comprehensive income	$	131,886		$	136,578

12.	Equity method investments

The Company has a number of equity method investments including Carib Power Management LLC (Carib Power) and Hartwell Energy Limited Partnership (Hartwell). 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~~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 February 2004, Centennial Energy Resources International, Inc. (Centennial International), an indirect wholly owned subsidiary of the Company, acquired 49.99 percent of Carib Power. Carib Power, through a wholly owned subsidiary, owns a 225-megawatt natural gas-fired electric generating facility located in Trinidad and Tobago (Trinity Generating Facility). The Trinity Generating Facility sells its output to the Trinidad and Tobago Electric Commission (T&TEC), the governmental entity responsible for the transmission, distribution and administration of electrical power to the national electrical grid of Trinidad and Tobago. The power purchase agreement expires in September 2029. T&TEC also is under contract to supply natural gas to the Trinity Generating Facility during the term of the power purchase contract. The functional currency for the Trinity Generating Facility is the U.S. dollar.

In September 2004, Centennial Resources, through wholly owned subsidiaries, acquired a 50-percent ownership interest in a ~~310- megawatt~~310-megawatt natural gas-fired electric generating facility located in Hartwell, Georgia (Hartwell Generating Facility). The Hartwell Generating Facility sells its output under a power purchase agreement with Oglethorpe Power Corporation (Oglethorpe) that expires in May 2019. Oglethorpe reimburses the Hartwell Generating Facility for actual costs of fuel acquired to operate the plant. American National Power, a wholly owned subsidiary of International Power of the United Kingdom, holds the remaining 50-percent ownership interest and is the operating partner for the facility.

In June 2005, an indirect wholly owned subsidiary of the Company completed the sale to Petrobras, the Brazilian ~~state- controlled~~state-controlled energy company, of its 49 percent interest in MPX Termoceara, Ltda. (MPX). The Company realized a gain of $15.6 million from the ~~sale.~~sale in the second quarter of 2005. MPX owns and operates a 220-megawatt natural gas-fired electric generating facility (Termoceara Generating Facility) in the Brazilian state of Ceara. Petrobras had entered into a contract to purchase all of the capacity and market all of the energy from the Termoceara Generating Facility. The electric power sales contract with Petrobras was scheduled to expire in mid-2008.

The functional currency for the Termoceara Generating Facility was the Brazilian Real. The electric power sales contract with Petrobras contained an embedded derivative, which derived its value from an annual adjustment factor, which largely indexed the contract capacity payments to the U.S. dollar. The Company's 49 percent share of the loss from the change in fair value of the embedded derivative in the electric power sales contract for the three months ended September 30, 2004, was $690,000 (after tax). The Company's 49 percent share of the gain from the change in fair value of the embedded derivative in the electric power sales contract for the ~~three and six~~nine months ended ~~June~~September 30, 2004, was ~~$4.1~~$3.4 million (after tax). The Company's 49 percent share of the foreign currency ~~loss~~gain resulting from ~~the decrease~~an increase in value of the Brazilian Real versus the U.S. dollar for the three and ~~six~~nine months ended ~~June~~September 30, 2004, was ~~$1.8~~$2.1 million (after tax) and ~~$2.0 million~~$124,000 (after tax), respectively.

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. ~~Centennial had unconditionally guaranteed a portion of certain bank borrowings of MPX. For more information on this guarantee, see Note 19.~~

At ~~June~~September 30, 2005, the ~~Company's~~Company’s equity method investments, including Carib Power and Hartwell, had total assets of ~~$243.6~~$244.3 million and long-term debt of $159.6 million. At December 31, 2004, MPX, Carib Power and Hartwell had total assets of $334.2 million, and long-term debt of $224.9 million. At ~~June~~September 30, 2004, MPX, ~~and~~ Carib Power and Hartwell had total assets of ~~$202.8~~$333.2 million and long-term debt of ~~$158.0~~$240.7 million. The ~~Company's~~Company’s investment in its equity method investments, including the Trinity and Hartwell Generating Facilities, was approximately ~~$43.4~~$44.0 million, including undistributed earnings of ~~$2.6~~$2.5 million, at ~~June~~September 30, 2005. The ~~Company's~~Company’s investment in the Termoceara, Trinity and Hartwell Generating Facilities was approximately $65.7 million, including undistributed earnings of $26.6 million, at December 31, 2004. The ~~Company's~~Company’s investment in the Termoceara, Trinity and ~~Trinity~~Hartwell Generating Facilities was approximately ~~$26.0~~$59.2 million, including undistributed earnings of ~~$14.8~~$20.8 million, at ~~June~~September 30, 2004. ~~13. Goodwill~~

13.	Impairment of long-lived asset

During the third quarter of 2004, the Company recognized a $2.1 million ($1.3 million after tax) adjustment reflecting the reduction in value of certain gathering facilities in the Gulf Coast region at the pipeline and ~~other intangible assets~~ energy services segment.

14.	Goodwill and other intangible assets

The changes in the carrying amount of goodwill were as follows: Balance Goodwill Balance as of Acquired as of Six Months January 1, During June 30, Ended June 30, 2005 2005 the Year* 2005 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services 62,632 12,102 74,734 Pipeline and energy services 5,464 --- 5,464 Natural gas and oil production --- --- --- Construction materials and mining 120,452 3,155 123,607 Independent power production 11,195 (28) 11,167 Other --- --- --- Total $199,743 $ 15,229 $214,972 Balance Goodwill Balance as of Acquired as of Six Months January 1, During June 30, Ended June 30, 2004 2004 the Year* 2004 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services 62,604 28 62,632 Pipeline and energy services 9,494 --- 9,494 Natural gas and oil production --- --- --- Construction materials and mining 120,198 (2,668) 117,530 Independent power production 7,131 3,766 10,897 Other --- --- --- Total $199,427 $ 1,126 $200,553 Balance Goodwill Goodwill Balance as of Acquired Impaired as of Year Ended January 1, During During December 31, December 31, 2004 2004 the Year* the Year 2004 (In thousands) Electric $ --- $ --- $ --- $ --- Natural gas distribution --- --- --- --- Utility services 62,604 28 --- 62,632 Pipeline and energy services 9,494 --- (4,030) 5,464 Natural gas and oil production --- --- --- --- Construction materials and mining 120,198 254 --- 120,452 Independent power production 7,131 4,064 --- 11,195 Other --- --- --- --- Total $199,427 $4,346 $(4,030) $199,743

	Balance			Goodwill			Balance
	as of			Acquired			as of
Nine Months Ended	January 1,			During			September 30,
September 30, 2005	2005			the Year*			2005
			(In thousands)

Electric	$	---		$	---		$	---
Natural gas distribution		---			---			---
Utility services		62,632			12,102			74,734
Pipeline and energy services		5,464			---			5,464
Natural gas and oil production		---			---			---
Construction materials and mining		120,452			3,122			123,574
Independent power production		11,195			(28	)		11,167
Other		---			---			---
Total	$	199,743		$	15,196		$	214,939

	Balance		Goodwill		Goodwill			Balance
	as of		Acquired		Impaired			as of
Nine Months Ended	January 1,		During		During			September 30,
September 30, 2004	2004		the Year*		the Year			2004
	(In thousands)

Electric	$	---	$	---	$	---		$	---
Natural gas distribution		---		---		---			---
Utility services		62,604		28		---			62,632
Pipeline and energy services		9,494		---		(4,030	)		5,464
Natural gas and oil production		---		---		---			---
Construction materials and mining		120,198		276		---			120,474
Independent power production		7,131		3,766		---			10,897
Other		---		---		---			---
Total	$	199,427	$	4,070	$	(4,030	)	$	199,467

	Balance		Goodwill		Goodwill			Balance
	as of		Acquired		Impaired			as of
Year Ended	January 1,		During		During			December 31,
December 31, 2004	2004		the Year*		the Year			2004
	(In thousands)

Electric	$	---	$	---	$	---		$	---
Natural gas distribution		---		---		---			---
Utility services		62,604		28		---			62,632
Pipeline and energy services		9,494		---		(4,030	)		5,464
Natural gas and oil production		---		---		---			---
Construction materials and mining		120,198		254		---			120,452
Independent power production		7,131		4,064		---			11,195
Other		---		---		---			---
Total	$	199,427	$	4,346	$	(4,030	)	$	199,743

__________________

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

Innovatum, Inc. (Innovatum), an indirect wholly owned subsidiary of the Company, which specializes in cable and pipeline magnetization and location, developed a hand-held locating device that can detect both magnetic and plastic materials, including unexploded ordnance. Innovatum was working with, and had demonstrated the device to, a Department of Defense contractor and had also met with individuals from the Department of Defense to discuss the possibility of using the hand-held locating device in their operations. In the third quarter of 2004, after communications with the Department of Defense, and delays in further testing resulting from a Department of Defense request to enhance the hand-held locating device, Innovatum decreased its expected future cash flows from the hand-held locating device. This decrease, coupled with the continued downturn in the telecommunications and energy industries, resulted in a revised earnings forecast for Innovatum, and as a result, a goodwill impairment loss of $4.0 million (before and after tax) was recognized in the third quarter of 2004. Innovatum, a reporting unit for goodwill impairment testing, is part of the pipeline and energy services segment. The fair value of Innovatum was estimated using the expected present value of future cash flows.

Other intangible assets were as follows: June 30, June 30, December 31, 2005 2004 2004 (In thousands) Amortizable intangible assets: Acquired contracts $ 18,707 $14,636 $ 15,041 Accumulated amortization (6,519) (3,036) (5,013) 12,188 11,600 10,028 Noncompete agreements 11,784 10,275 10,575 Accumulated amortization (8,310) (8,024) (8,186) 3,474 2,251 2,389 Other 14,698 6,656 9,535 Accumulated amortization (914) (362) (534) 13,784 6,294 9,001 Unamortizable intangible assets 851 960 851 Total $ 30,297 $ 21,105 $ 22,269

	September 30, 2005			September 30, 2004			December 31, 2004
	(In thousands)

Amortizable intangible assets:
Acquired contracts	$	18,707		$	14,731		$	15,041
Accumulated amortization		(7,640	)		(3,678	)		(5,013	)
		11,067			11,053			10,028
Noncompete agreements		11,784			13,275			10,575
Accumulated amortization		(8,434	)		(8,345	)		(8,186	)
		3,350			4,930			2,389
Other		14,699			6,853			9,535
Accumulated amortization		(1,480	)		(465	)		(534	)
		13,219			6,388			9,001
Unamortizable intangible assets		851			960			851
Total	$	28,487		$	23,331		$	22,269

The unamortizable intangible assets were recognized in accordance with SFAS No. 87, "Employers' Accounting for Pensions," 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 ~~six~~nine months ended ~~June~~September 30, 2005, was ~~$1.2~~$1.8 million and ~~$2.1~~$3.9 million, respectively. Amortization expense for amortizable intangible assets for the three and ~~six~~nine months ended ~~June~~September 30, 2004, and for the year ended December 31, 2004, was ~~$702,000, $1.3~~$1.0 million, $2.3 million and $3.8 million, respectively. Estimated amortization expense for amortizable intangible assets is ~~$5.9~~$5.7 million in 2005, $6.0 million in 2006, ~~$4.5~~$4.6 million in 2007, $4.0 million in 2008, $3.9 million in 2009 and ~~$7.2~~$7.3 million thereafter. ~~14. Derivative instruments~~

15.	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. The following information should be read in conjunction with Notes 1 and 5 in the Company's Notes to Consolidated Financial Statements in the 2004 Annual Report.

As of ~~June~~September 30, 2005, Fidelity Exploration & Production Company (Fidelity), an indirect wholly owned subsidiary of the Company, held derivative instruments designated as cash flow hedging instruments.

Fidelity utilizes natural gas and oil price swap and collar agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on its forecasted sales of natural gas and oil production. 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 production.

The fair value of the hedging instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or liability. Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in accumulated other comprehensive income (loss) until the hedged oil or natural gas quantities are settled. Based on the recent rise in market prices of natural gas and oil, the fair value of the Company’s derivative liability has increased significantly since the end of the second quarter of 2005 (and also since the end of 2004). The proceeds the Company receives for its natural gas and oil production are also generally based on market prices.

For the three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, the amount of hedge ineffectiveness, which was included in operating revenues, was immaterial. For the three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, Fidelity did not exclude any components of the derivative ~~instruments'~~instruments’ gain or loss from the assessment of hedge effectiveness and there were no reclassifications into earnings as a result of ~~the~~a 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 ~~June~~September 30, 2005, the maximum term of ~~Fidelity's~~Fidelity’s swap and collar agreements, in which it is hedging its exposure to the variability in future cash flows for forecasted transactions, is 1815 months. Fidelity estimates that over the next 12 months net losses of approximately ~~$13.7~~$63.4 million will be reclassified from accumulated other comprehensive loss into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings. ~~15. Business segment data~~

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. Prior to the fourth quarter of 2004, the Company reported six reportable segments consisting of electric, natural gas distribution, utility services, pipeline and energy services, natural gas and oil production and construction materials and mining. The independent power production and other operations did not individually meet the criteria to be considered a reportable segment. In the fourth quarter of 2004, the Company separated independent power production as a reportable business segment due to the significance of its operations. The Company's operations are now conducted through seven reportable segments and all prior period information has been restated to reflect this change.

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 natural resource-based projects.

The electric segment generates, transmits and distributes electricity, and the natural gas distribution segment distributes natural gas. These operations also supply related value-added products and services in the northern Great Plains.

The utility services segment specializes in electrical line construction, pipeline construction, inside electrical wiring and cabling, 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, including cable and pipeline magnetization and locating.

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 region 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 and other value-added products, as well as performs integrated construction services, in the central and western United States and in the states of Alaska and Hawaii.

The independent power production segment owns, builds and operates electric generating facilities in the United States and has investments in domestic and international natural resource-based projects. Electric capacity and energy produced at its power plants are sold primarily under mid- and long-term contracts to nonaffiliated entities.

The information below follows the same accounting policies as described in Note 1 in the ~~Company's~~Company’s Notes to Consolidated Financial Statements in the 2004 Annual Report. Information on the ~~Company's~~Company’s businesses was as follows: Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Three Months Ended June 30, 2005 Electric $ 41,052 $ --- $ 1,755 Natural gas distribution 54,691 --- (1,283) Pipeline

			Inter-
	External		segment			Earnings
	Operating		Operating			on Common
	Revenues		Revenues			Stock
	(In thousands)
Three Months
Ended September 30, 2005

Electric	$	50,195	$	---		$	6,169
Natural gas distribution		34,014		---			(3,016	)
Pipeline and energy services		101,895		17,086			5,282
		186,104		17,086			8,435
Utility 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	$	1,066,862	$	---		$	87,052

			Inter-
	External		segment			Earnings
	Operating		Operating			on Common
	Revenues		Revenues			Stock
	(In thousands)
Three Months
Ended September 30, 2004

Electric	$	47,888	$	---		$	5,580
Natural gas distribution		32,389		---			(3,230	)
Pipeline and energy services		69,346		17,675			(1,639	)
		149,623		17,675			711
Utility services		111,765		1,138			(568	)
Natural gas and oil production		40,475		45,193			27,398
Construction materials and mining		486,625		263			34,974
Independent power production		16,110		---			8,708
Other		---		1,267			325
		654,975		47,861			70,837
Intersegment eliminations		---		(65,536	)		---
Total	$	804,598	$	---		$	71,548

			Inter-
	External		segment			Earnings
	Operating		Operating			on Common
	Revenues		Revenues			Stock
	(In thousands)
Nine Months
Ended September 30, 2005

Electric	$	135,566	$	---		$	11,057
Natural gas distribution		233,679		---			523
Pipeline and energy services		254,340		58,889			17,245
		623,585		58,889			28,825
Utility services		457,879		294			10,748
Natural gas and oil production		130,664		170,542			94,204
Construction materials and mining		1,191,601		7			44,005
Independent power production		37,600		---			23,069
Other		---		4,315			452
		1,817,744		175,158			172,478
Intersegment eliminations		---		(234,047	)		---
Total	$	2,441,329	$	---		$	201,303

			Inter-
	External		segment			Earnings
	Operating		Operating			on Common
	Revenues		Revenues			Stock
	(In thousands)
Nine Months
Ended September 30, 2004

Electric	$	134,711	$	---		$	9,723
Natural gas distribution		208,167		---			(2,002	)
Pipeline and energy services		197,959		58,711			5,478
		540,837		58,711			13,199
Utility services		309,243		1,138			(4,763	)
Natural gas and oil production		117,019		133,837			78,794
Construction materials and mining		973,098		463			43,437
Independent power production		33,161		---			22,107
Other		---		3,104			641
		1,432,521		138,542			140,216
Intersegment eliminations		---		(197,253	)		---
Total	$	1,973,358	$	---		$	153,415

Excluding the asset impairments at pipeline and energy services 86,366 15,055 8,737 182,109 15,055 9,209 Utility services 136,911 (19) 3,659 Natural gas and oil production 43,487 54,255 29,949 Construction materials and mining 394,015 --- 18,421 Independent power production 13,650 --- 18,582 Other --- 1,367 182 588,063 55,603 70,793 Intersegment eliminations --- (70,658) --- Total $ 770,172 $ --- $ 80,002 Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Three Months Ended June 30,of $5.3 million (after tax) in 2004, Electric $ 39,834 $ --- $ 735 Natural gas distribution 47,461 --- (1,097) Pipeline and energy services 72,073 13,423 4,434 159,368 13,423 4,072 Utility services 97,226 --- (2,294) Natural gas and oil production 39,038 45,181 26,136 Construction materials and mining 347,026 200 20,345 Independent power production 10,643 --- 10,136 Other --- 919 63 493,933 46,300 54,386 Intersegment eliminations --- (59,723) --- Total $ 653,301 $ --- $ 58,458 Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Six Months Ended June 30, 2005 Electric $ 85,371 $ --- $ 4,888 Natural gas distribution 199,665 --- 3,539 Pipeline and energy services 152,445 41,803 11,963 437,481 41,803 20,390 Utility services 250,621 132 5,617 Natural gas and oil production 81,797 103,025 58,754 Construction materials and mining 581,102 7 9,885 Independent power production 23,466 --- 19,339 Other --- 2,735 266 936,986 105,899 93,861 Intersegment eliminations --- (147,702) --- Total $1,374,467 $ --- $114,251 Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Six Months Ended June 30, 2004 Electric $ 86,824 $ --- $ 4,143 Natural gas distribution 175,779 --- 1,228 Pipeline and energy services 128,612 41,036 7,117 391,215 41,036 12,488 Utility services 197,477 --- (4,195) Natural gas and oil production 76,544 88,644 51,395 Construction materials and mining 486,473 200 8,464 Independent power production 17,051 --- 13,399 Other --- 1,837 316 777,545 90,681 69,379 Intersegment eliminations --- (131,717) --- Total $1,168,760 $ --- $ 81,867 Earningsearnings (loss) from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings (loss) from utility services, natural gas and oil production, construction materials and mining, independent power production, and other are all from nonregulated operations. ~~16. Acquisitions~~

17.	Acquisitions

During the first ~~six~~nine months of 2005, the Company acquired utility services businesses in Nevada and construction materials and mining businesses in Idaho and Oregon, and natural gas and oil properties in south Texas, none of which was individually material. The total purchase consideration for these businesses and properties and purchase price adjustments with respect to certain other acquisitions acquired prior to 2005, including the Company's common stock and cash, was ~~$192.9~~$194.3 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. Final fair market values are pending the completion of the review of the relevant assets, liabilities and issues identified as of the acquisition date. The results of operations of the acquired businesses and properties are included in the financial statements since the date of each acquisition. Pro forma financial amounts reflecting the effects of the above acquisitions are not presented, as such acquisitions were not material to the Company's financial position or results of operations. ~~17. Employee benefit plans~~

18.	Employee benefit plans

The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. The Company recognized the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (2003 Medicare Act) during the second quarter of 2004. Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans were as follows: Other Pension Postretirement Three Months Benefits Benefits Ended June 30, 2005 2004 2005 2004 (In thousands) Components of net periodic benefit cost: Service cost $2,121 $ 1,984 $ 546 $ 312 Interest cost 4,152 4,011 1,039 850 Expected return on assets (5,063) (5,100) (1,042) (979) Amortization of prior service cost 256 283 --- 72 Recognized net actuarial (gain) loss 483 (8) (38) (27) Amortization of net transition obligation (asset) (11) (62) 525 550 Net periodic benefit cost 1,938 1,108 1,030 778 Less amount capitalized 185 117 115 80 Net periodic benefit cost $1,753 $ 991 $ 915 $ 698 Other Pension Postretirement Six Months Benefits Benefits Ended June 30, 2005 2004 2005 2004 (In thousands) Components of net periodic benefit cost: Service cost $4,168 $ 3,833 $1,031 $ 896 Interest cost 8,308 7,952 2,136 2,173 Expected return on assets (9,973) (10,187) (2,025)(1,972) Amortization of prior service cost 512 561 --- 72 Recognized net actuarial (gain) loss 692 239 (77) (82) Amortization of net transition obligation (asset) (22) (125) 1,063 1,076 Net periodic benefit cost 3,685 2,273 2,128 2,163 Less amount capitalized 357 191 206 182 Net periodic benefit cost $3,328 $ 2,082 $1,922 $1,981

Three Months	Pension Benefits						Other Postretirement Benefits
Ended September 30,	2005			2004			2005			2004
	(In thousands)
Components of net periodic benefit cost (income):
Service cost	$	2,084		$	1,917		$	211		$	447
Interest cost		4,155			3,976			666			1,086
Expected return on assets		(4,987	)		(5,094	)		(979	)		(986	)
Amortization of prior service cost		256			280			34			36
Recognized net actuarial (gain) loss		346			121			(364	)		(40	)
Amortization of net transition obligation (asset)		(11	)		(63	)		531			538
Net periodic benefit cost		1,843			1,137			99			1,081
Less amount capitalized		190			111			123			137
Net periodic benefit cost (income)	$	1,653		$	1,026		$	(24	)	$	944

Nine Months	Pension Benefits						Other Postretirement Benefits
Ended September 30,	2005			2004			2005			2004
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	6,252		$	5,750		$	1,242		$	1,343
Interest cost		12,463			11,928			2,802			3,259
Expected return on assets		(14,960	)		(15,281	)		(3,004	)		(2,958	)
Amortization of prior service cost		768			841			34			108
Recognized net actuarial (gain) loss		1,038			360			(441	)		(122	)
Amortization of net transition obligation (asset)		(33	)		(188	)		1,594			1,614
Net periodic benefit cost		5,528			3,410			2,227			3,244
Less amount capitalized		547			302			329			319
Net periodic benefit cost	$	4,981		$	3,108		$	1,898		$	2,925

In addition to the qualified plan defined pension benefits reflected in the table above, the Company also has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that generally provides for defined benefit payments at age 65 following the ~~employee's~~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 ~~six~~nine months ended ~~June~~September 30, 2005, was ~~$1.4~~$1.6 million and ~~$3.3~~$4.9 million, respectively. The Company's net periodic benefit cost for this plan for the three and ~~six~~nine months ended ~~June~~September 30, 2004, was ~~$2.3~~$1.8 million and ~~$3.8~~$5.6 million, respectively. ~~18.~~

19.	Regulatory matters and revenues subject to refund

On September 30, 2005, Montana-Dakota filed an application with the Montana Public Service Commission (MTPSC) for a natural gas rate increase. Montana-Dakota requested a total increase of $1.1 million annually or 1.3 percent above current rates. Montana-Dakota also requested an interim increase of $700,000 annually, subject to ~~refund~~ refund. A final order from the MTPSC is expected in mid-2006.

On March 24, 2005, Montana-Dakota filed an application with the South Dakota Public Utilities Commission (SDPUC) for the East River service area for a natural gas rate increase. ~~Montana- Dakota~~Montana-Dakota requested a total increase of $850,000 annually or 12.8 percent above current rates. ~~A final order from~~On August 31, 2005, the SDPUC ~~is expected~~approved the settlement authorizing an increase in ~~late~~revenues of $850,000 annually, or 12.8 percent, effective with service rendered on and after September 1, 2005.

In September 2004, Great Plains filed an application with the Minnesota Public Utilities Commission (MPUC) for a natural gas rate increase. Great Plains had requested a total increase of $1.4 million annually or approximately 4.0 percent above current rates. Great Plains also requested an interim increase of $1.4 million annually. In November 2004, the MPUC issued an Order authorizing an interim increase of $1.4 million annually effective with service rendered on or after January 10, 2005, subject to refund. A final order from the MPUC is expected in early 2006.

A liability has been provided for a portion of the revenues that have been collected subject to refund with respect to Great ~~Plains'~~Plains’ pending regulatory proceeding. Great Plains believes that the liability is adequate based on its assessment of the ultimate outcome of the proceeding.

In December 1999, Williston Basin Interstate Pipeline Company (Williston Basin), an indirect wholly owned subsidiary of the Company, filed a general natural gas rate change application with the Federal Energy Regulatory Commission (FERC). Williston Basin began collecting such rates effective June 1, 2000, subject to refund. In May 2001, the Administrative Law Judge (ALJ) issued an Initial Decision on Williston Basin's natural gas rate change application. The Initial Decision addressed numerous issues relating to the rate change application, including matters relating to allowable levels of rate base, return on common equity, and cost of service, as well as volumes established for purposes of cost recovery, and cost allocation and rate design. In July 2003, the FERC issued its Order on Initial ~~Decision. The Order on Initial~~ Decision which affirmed the ~~ALJ's~~ALJ’s Initial Decision on many of the issues including rate base and certain cost of service items as well as volumes to be used for purposes of cost recovery, and cost allocation and rate design. However, there were other issues as to which the FERC differed with the ALJ including return on common equity and the correct level of corporate overhead expense. In August 2003, Williston Basin requested rehearing of a number of issues including determinations associated with cost of service, throughput, and cost allocation and rate design, as discussed in the FERC's Order on Initial Decision. In May 2004, the FERC issued an Order on ~~Rehearing. The Order on~~ Rehearing which denied rehearing on all of the issues addressed by Williston Basin in its August 2003 request for rehearing except for the issue of the proper rate to utilize for transmission system negative salvage expenses. In addition, the FERC remanded the issues regarding certain service and annual demand quantity restrictions to an ALJ for resolution. In June 2004, Williston Basin requested clarification of a few of the issues addressed in the Order on Rehearing including determinations associated with cost of service and cost allocation, as discussed in the ~~FERC's~~FERC’s Order on Rehearing. In June 2004, Williston Basin also made its filing to comply with the requirements of the various FERC orders in this proceeding. Williston Basin participated in a hearing before the ALJ in early January 2005, regarding certain service and annual demand quantity restrictions remanded to the ALJ by the FERC in its Order on Rehearing. On April 8, 2005, the ALJ issued an Initial Decision on the matters remanded by the FERC. In the Initial Decision, the ALJ decided that Williston Basin had not supported its position regarding the service and annual demand quantity restrictions. Williston Basin filed its Brief on Exceptions regarding these issues with the FERC on May 9, 2005, and its Brief Opposing Exceptions to issues raised by Northern States Power Company on May 31, 2005. On April 19, 2005, the FERC issued its Order on Compliance Filing and Motion for Refunds. In this Order, the FERC approved Williston ~~Basin's~~Basin’s refund rates and established rates to be effective April 19, 2005. Williston Basin filed its compliance filing complying with the requirements of this Order regarding rates and issued refunds totaling approximately $18.5 million to its customers on May 19, 2005. Williston Basin filed its Refund Report, detailing the $18.5 million in refunds it issued to its customers, with the FERC on June 1, 2005. As a result of the Order, Williston Basin recorded a $5.0 million (after tax) benefit from the resolution of the rate proceeding. ~~19. Contingencies~~ On June 16, 2005, Williston Basin appealed to the United States Court of Appeals for the District of Columbia Circuit (U.S. Appeals Court) certain issues addressed by the FERC’s Order on Initial Decision and its Order on Rehearing concerning determinations associated with cost of service and volumes used in allocating costs and designing rates. Those matters are pending resolution by the U.S. Appeals Court. On October 27, 2005, the FERC issued a Letter Order accepting Williston Basin’s May 19, 2005, compliance filing and June 1, 2005, Refund Report as being consistent with the April 19, 2005, Order in this proceeding.

20.	Contingencies

In June 1997, Jack J. Grynberg (Grynberg) filed suit under the Federal False Claims Act against Williston Basin and ~~Montana- Dakota and~~Montana-Dakota. Grynberg also filed over 70 similar suits against natural gas transmission companies and producers, gatherers, and processors of natural gas. Grynberg, acting on behalf of the United States under the Federal False Claims Act, 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. In April 1999, the United States Department of Justice decided not to intervene in these cases. In response to a motion filed by Grynberg, the Judicial Panel on Multidistrict Litigation consolidated all of these cases in the United States District Court for the District of Wyoming (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 is additionally based on the ground that Grynberg disclosed the filing of the complaint prior to the entry of a court order allowing such disclosure and that Grynberg failed to provide adequate information to the government prior to filing suit. The Motion to Dismiss was heard on March 17 and 18, 2005, by the Special Master appointed by the Wyoming Federal District Court. The Special Master, in his Written Report dated May 13, 2005, recommended that the ~~dismissal of~~lawsuit against Williston Basin and ~~Montana- Dakota.~~Montana-Dakota be dismissed. The Written Report will be considered for adoption by the Wyoming Federal District Court.

In the event the Motion to Dismiss is not granted, it is expected that further discovery will follow. Williston Basin and Montana-Dakota believe Grynberg will not prevail in the suit or recover damages from Williston Basin and/or ~~Montana- Dakota~~Montana-Dakota because insufficient facts exist to support the allegations. Williston Basin and Montana-Dakota believe ~~Grynberg's~~Grynberg’s claims are without merit and intend to vigorously contest this suit.

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.

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 coalbed natural gas 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 November 2004 by a number of environmental organizations, including the Northern Plains Resource Council (NPRC) and the Montana Environmental Information Center, as well as the Tongue River Water Users' Association and the Northern Cheyenne Tribe. Portions of two 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 Federal Clean Water Act, the National Environmental Policy Act (NEPA), the Federal Land Management Policy Act, the National Historic Preservation Act (NHPA) and the Montana Environmental Policy Act. The cases involving alleged violations of the Federal Clean Water Act have been resolved without a finding that Fidelity is in violation of the Federal Clean Water Act. There presently are no claims pending for penalties, fines or damages under the Federal Clean Water Act. The suits that remain extant include a variety of claims that state and federal government agencies violated various environmental laws that impose procedural requirements and the lawsuits seek injunctive relief, invalidation of various permits and unspecified damages.

In suits filed in the United States District Court for the District of Montana (Montana Federal District Court), the NPRC and the Northern Cheyenne Tribe asserted that further development by Fidelity and others of coalbed natural gas in Montana should be enjoined until the Bureau of Land Management (BLM) completes a Supplemental Environmental Impact Statement (SEIS). The Montana Federal District Court, in February 2005, entered a ruling requiring the BLM to complete a SEIS. The Montana Federal District Court later entered an order that would have allowed limited coalbed natural gas production in the Powder River Basin in Montana pending the BLM's preparation of the SEIS. The plaintiffs appealed the decision to the United States Ninth Circuit Court of Appeals (Ninth Circuit). The Montana Federal District Court declined to enter an injunction requested by the NPRC and the Northern Cheyenne Tribe that would have enjoined production pending the appeal. In late May 2005, the Ninth Circuit granted the request of the NPRC and the Northern Cheyenne Tribe and, pending further order from the Ninth Circuit, enjoined the BLM from approving any coalbed natural gas production projects in the Powder River Basin in Montana. That court also enjoined Fidelity from drilling any additional federally permitted wells in its Montana Coal Creek Project and from constructing infrastructure to produce and transport coalbed natural gas 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 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 Tongue River-Badger Hills Project in Montana (Badger Hills Project) 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. On June 6, 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 NHPA and a further environmental analysis under NEPA. Fidelity has sought and obtained stays of the injunctive relief from the Montana Federal District Court and production from ~~Fidelity's~~Fidelity’s Badger Hills Project continues. On September 2, 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. On November 1, 2005, the Montana Federal District Court entered an Order based on a stipulation between the parties to the Northern Cheyenne Tribe action that production from existing wells in Fidelity’s Badger Hills Project may continue pending preparation of a revised environmental analysis.

Fidelity is vigorously defending all coalbed-related lawsuits and related actions in which it is involved, including the ~~recent~~ Ninth Circuit ~~and Montana Federal District Court injunctions.~~injunction. 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~~Fidelity’s existing coalbed natural gas operations and/or the future development of this resource in the affected regions.

Montana-Dakota has joined with two electric generators in appealing a finding by the North Dakota Department of Health (ND Health Department) in September 2003 that the ND Health Department 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~~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 have been stayed pending discussions with the U.S. Environmental Protection Agency (EPA), the ND Health Department and the other electric generators.

The Company 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 financial position or results of operations.

Environmental matters

In December 2000, Morse Bros., Inc. (MBI), an indirect wholly owned subsidiary of the Company, was named by the EPA as a Potentially Responsible Party in connection with the cleanup of a commercial property site, acquired by MBI in 1999, and 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 State Department of Environmental Quality (DEQ) are being recorded, and initially paid, through an administrative consent order by the Lower Willamette Group (LWG), a group of 10 entities, which does not include MBI. The LWG estimates the overall remedial investigation and feasibility study will cost approximately $10 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 years to complete. The development of a proposed plan and record of decision on the harbor site is not anticipated to occur until 2006, after which a cleanup plan will be undertaken.

Based upon a review of the Portland Harbor sediment contamination evaluation by the DEQ and other information available, MBI does not believe it is a Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc., the seller of the commercial property site to MBI, 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.

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.

In August 2004, Colorado Power Partners (CPP) and BIV Generation Company, LLC (BIV), indirect wholly owned subsidiaries of the Company, were each issued a draft Compliance Order on Consent (Compliance Orders) by the Colorado Department of Public Health and Environment (CDPHE). The Compliance Orders were issued in connection with excess emission periods of nitrogen oxides and carbon monoxide at the ~~Company's~~Company’s electric generating facilities in Brush, Colorado, occurring mainly during start-up and shut-down periods. In June 2005, CPP, BIV and the CDPHE agreed upon the Compliance Orders. The terms of the Compliance Orders for CPP and BIV include administrative penalties of $9,900 and $10,600, and noncompliance/economic benefit penalties of $7,700 and $8,300, respectively. In addition, the terms of the Compliance Orders include an agreement for CPP and BIV to make a non-tax deductible ~~donation~~donations for a Supplemental Environmental ~~Project (SEP)~~Projects (SEPs) in Morgan County, Colorado with total expenditures of not less than $39,600 and $42,400, respectively. If the parties ~~cannot~~could not come to an agreement on ~~the~~a SEP to be funded within 120 days of the Compliance Order, CPP and BIV ~~shall~~would have been required to pay $39,600 and $42,400, respectively, as administrative penalties. ~~Guarantees Centennial had unconditionally guaranteed a portion of certain bank borrowings of MPX in connection with~~In October 2005, CPP, BIV and the Company's equity method investment in the Termoceara Generating Facility, as discussed in Note 12. The Company, through an indirect wholly owned subsidiary, owned 49 percent of MPX. The guaranteeCDPHE agreed upon three SEPs to MPX's creditors expired on July 25, 2005, as the outstanding bank borrowings were repaid on that date. At June 30, 2005, the aggregate amount of borrowings outstanding subject to these guarantees was $29.6 million. These guarantees are not reflected on the Consolidated Balance Sheets. be funded.

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 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.~~ Petrobras for periods ranging from approximately two to five years and six months from the date of sale.

In addition, WBI Holdings has guaranteed certain of Fidelity's natural gas and oil price swap and collar agreement obligations. Fidelity's obligations at ~~June~~September 30, 2005, were ~~$11.3~~$35.9 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 ~~June~~September 30, 2005, expire in 2005 and 2006; 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 Sheets at ~~June~~September 30, 2005. 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, insurance policies and certain other guarantees. At ~~June~~September 30, 2005, the fixed maximum amounts guaranteed under these agreements aggregated ~~$99.3~~$107.8 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate ~~$15.0~~$12.3 million in 2005; ~~$27.4~~$36.3 million in 2006; ~~$2.2~~$2.3 million in 2007; ~~$200,000~~$2.4 million in 2008; $900,000 in 2009; $30.0 million in 2010; $12.0 million in 2012; $2.1 million in 2028; $500,000, which is subject to expiration 30 days after the receipt of written ~~notice~~notice; and $9.0 million, which has no scheduled maturity date. A guarantee for an unfixed amount estimated at ~~$300,000~~$250,000 at ~~June~~September 30, 2005, has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was ~~$528,000~~$2.8 million and was reflected on the Consolidated Balance Sheets at ~~June~~September 30, 2005. 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.

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 Energy Marketing, Inc. (Prairielands), an indirect wholly owned subsidiary of the Company. At ~~June~~September 30, 2005, the fixed maximum amounts guaranteed under these agreements aggregated $22.9 million. Scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $2.9 million in 2008 and $20.0 million in 2009. In the event of ~~Prairielands'~~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 ~~$1.5~~$1.6 million, which was not reflected on the Consolidated Balance ~~Sheet~~Sheets at ~~June~~September 30, 2005, because these intercompany transactions are eliminated in consolidation.

In addition, Centennial has issued guarantees to third parties related to the ~~Company's~~Company’s routine purchase of maintenance items 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, Centennial would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these maintenance items were reflected on the Consolidated Balance ~~Sheet~~Sheets at ~~June~~September 30, 2005.

As of ~~June~~September 30, 2005, Centennial was contingently liable for the performance of certain of its subsidiaries under approximately ~~$614~~$546 million of surety bonds. These bonds are principally for construction contracts and reclamation obligations of these subsidiaries entered into in the normal course of business. Centennial indemnifies the respective surety bond companies against any exposure under the bonds. The purpose of Centennial's indemnification is to allow the subsidiaries to obtain bonding at competitive rates. In the event a subsidiary of the Company does not fulfill its obligations in relation to its bonded contract or obligation, Centennial may be required to make payments under its indemnification. A large portion of these contingent commitments 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. The surety bonds were not reflected on the Consolidated Balance Sheets. ~~20. Related party transactions~~

21.	Related party transactions

In 2004, Bitter Creek Pipelines, LLC (Bitter Creek), an indirect wholly owned subsidiary of the Company, entered into two natural gas gathering agreements with Nance Petroleum Corporation (Nance Petroleum), a wholly owned subsidiary of St. Mary Land & Exploration Company (St. Mary). Robert L. Nance, an executive officer and shareholder of St. Mary, is also a member of the Board of Directors of the Company. 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 ~~$1.1 million~~$245,000 and ~~$2.1~~$2.3 million for the three and ~~six~~nine months ended ~~June~~September 30, 2005, respectively, and are estimated for the next three years to be ~~$3.2~~$3.1 million in 2005, $2.2 million in 2006 and $3.3 million in 2007. 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 ~~$287,000~~$316,000 and ~~$539,000~~$855,000 for the three and ~~six~~nine months ended ~~June~~September 30, 2005, respectively, and estimated revenues from these contracts for the next three years are ~~$1.8~~$1.2 million in 2005, ~~$4.3~~$2.8 million in 2006 and ~~$6.0~~$3.5 million in 2007. The amount due from Nance Petroleum at ~~June~~September 30, 2005, was ~~$98,000.~~ $109,000.

Montana-Dakota entered into ~~an agreement~~agreements to purchase natural gas from Nance Petroleum through March 31, 2006. Montana-Dakota’s expenses under these agreements for the ~~period April 1,~~three and nine months ended September 30, 2005, ~~to October 31, 2005.~~were $1.2 million and $2.0 million, respectively. Montana-Dakota estimates that it will purchase ~~between $2.0 million to $2.5~~approximately $5.0 million of natural gas from Nance Petroleum ~~during this period. Montana-Dakota's expenses under this agreement for the three and six months ended June 30,~~from October 1, 2005 ~~were $760,000.~~through March 31, 2006. The amount due to Nance Petroleum at ~~June~~September 30, 2005, was ~~$251,000.~~ $512,000.

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

OVERVIEW

This subsection of MD&A is an overview of the important factors that management focuses on in evaluating the ~~Company's~~Company’s businesses, the ~~Company's~~Company’s financial condition and operating performance, the ~~Company's~~Company’s overall business strategy and the earnings of the Company for the period covered by this report. This subsection is not intended to be a substitute for reading the entire MD&A section. Reference is made to the various important factors listed under the heading Risk Factors and Cautionary Statements that May Affect Future Results, as well as other factors that are listed in the Introduction in relation to any forward-looking statement.

Business and Strategy Overview Prior to the fourth quarter of 2004, the Company reported six reportable segments consisting of electric, natural gas distribution, utility services, pipeline and energy services, natural gas and oil production and construction materials and mining. The independent power production and other operations did not individually meet the criteria to be considered a reportable segment. In the fourth quarter of 2004, the Company separated independent power production as a reportable business segment due to the significance of its operations. The Company's operations are now conducted through seven reportable segments and all prior period information has been restated to reflect this change.

The vast majority of the Company's operations are located within the United States. The Company also has investments in foreign countries, which consist of investments in natural resource-based projects, as discussed in Note 12 of Notes to Consolidated Financial Statements.

The electric segment includes the electric generation, transmission and distribution operations of Montana-Dakota. The natural gas distribution segment includes the natural gas distribution operations of Montana-Dakota and Great Plains Natural Gas Co. The electric and natural gas distribution segments also supply related value-added products and services in the northern Great Plains.

The utility services segment includes all the operations of Utility Services, Inc., which specializes in electrical line construction, pipeline construction, inside electrical wiring and cabling, and the manufacture and distribution of specialty equipment.

The pipeline and energy services segment includes WBI ~~Holdings'~~Holdings’ 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, including cable and pipeline magnetization and locating.

The natural gas and oil production segment includes WBI ~~Holdings'~~Holdings’ natural gas and oil acquisition, exploration, development and production operations, primarily in the Rocky Mountain region of the United States and in and around the Gulf of Mexico.

The construction materials and mining segment includes the results of Knife River, which mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ~~ready- mixed~~ready-mixed concrete, cement, asphalt and other value-added products, as well as performs integrated construction services, in the central and western United States and in the states of Alaska and Hawaii.

The independent power production operations of Centennial Resources own, build and operate electric generating facilities in the United States and have investments in domestic and international natural resource-based projects. Electric capacity and energy produced at its power plants are sold primarily under mid- and long-term contracts to nonaffiliated entities. ~~Earnings~~

Excluding the asset impairments at pipeline and energy services of $5.3 million (after tax) in 2004, earnings (loss) from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings (loss) from utility services, natural gas and oil production, construction materials and mining, independent power production, and other are all from nonregulated operations.

The Company's strategy is to apply its expertise in energy and transportation infrastructure industries to increase market share through internal growth along with acquisition of well-managed companies and properties, and development of projects that enhance shareholder value and are accretive to earnings per share and returns on invested capital.

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper credit facilities and through the issuance of ~~long- term~~long-term debt and the ~~Company's~~Company’s equity securities. ~~Net~~The Company’s net capital expenditures are estimated to be approximately ~~$700~~$780 million for ~~2005.~~ 2005 and include:

·	Capital expenditures

·	Acquisitions (including the issuance of the Company’s equity securities, less cash acquired)

·	Less net proceeds from the sale or disposition of property

The Company faces certain challenges and risks as it pursues its growth strategies, including, but not limited to the following: -

· The natural gas and oil production business experiences fluctuations in natural gas and oil prices. These prices are volatile and subject to significant change at any time. The Company hedges a portion of its natural gas and oil production in order to mitigate the effects of price volatility. -

· Economic volatility both domestically and in the foreign countries where the Company does business affects the ~~Company's~~Company’s operations as well as the demand for its products and services and, as a result, may have a negative impact on the ~~Company's~~Company’s future revenues. -

· Fidelity continues to seek additional reserve and production growth, both in areas of existing activity and in other regions, through acquisition, exploration, development and production of natural gas and oil resources, including the development and production of its coalbed natural gas properties in the Powder River Basin. In this context, Fidelity has been named as a defendant in, and/or certain of its operations are the subject of, more than a dozen lawsuits filed in connection with its coalbed natural gas development program. Some of these actions have been successfully resolved and Fidelity is actively defending the others. If the plaintiffs are successful in the outstanding lawsuits, the ultimate outcome of the actions could have a material effect on Fidelity's existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties in this region.

For further information on certain factors that should be considered for a better understanding of the ~~Company's~~Company’s financial condition, see the various important factors listed under the heading Risk Factors and Cautionary Statements that May Affect Future Results, as well as other factors that are listed in the Introduction.

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,
		2005			2004			2005		2004
	(Dollars in millions, where applicable)
Electric		$	6.2		$	5.6		$	11.1	$	9.7
Natural gas distribution			(3.0	)		(3.2	)		.5		(2.0	)
Utility services			5.1			(.6	)		10.7		(4.8	)
Pipeline and energy services			5.3			(1.6	)		17.2		5.5
Natural gas and oil production			35.5			27.4			94.2		78.8
Construction materials and mining			34.1			34.9			44.0		43.4
Independent power production			3.7			8.7			23.1		22.1
Other			.2			.3			.5		.7
Earnings on common stock		$	87.1		$	71.5		$	201.3	$	153.4

Earnings per common share - basic		$	.73		$	.61		$	1.70	$	1.32

Earnings per common share - diluted		$	.72		$	.60		$	1.69	$	1.31

Return on average common equity for the 12 months ended									15.0%		13.2%

Three Months ~~Six Months~~ Ended ~~Ended June 30, June~~September 30, 2005 and 2004

Consolidated earnings for the third quarter ended September 30, 2005, ~~2004 (Dollars in millions, where applicable) Electric $ 1.8 $ .7 $ 4.9 $ 4.2 Natural~~increased $15.6 million largely due to:

· Higher natural gas ~~distribution (1.3) (1.1) 3.5 1.2 Utility services 3.7 (2.3) 5.6 (4.2) Pipeline~~prices of 39 percent and ~~energy services 8.7 4.4 12.0 7.1 Natural~~higher oil prices of 20 percent at the natural gas and oil production 29.9 26.2 58.8 51.4 Construction materials and mining 18.4 20.4 9.9 8.5 Independent power production 18.6 10.1 19.3 13.4 Other .2 .1 .3 .3 Earnings on common stock $80.0 $ 58.5 $114.3 $81.9 Earnings per common share - basic $ .68 $ .50 $ .97 $ .71 Earnings per common share - diluted $ .67 $ .50 $ .96 $ .70 Return on average common equity for the 12 months ended 14.4% 13.3% ________________________________ Three Months Ended June 30, 2005 and 2004 Consolidated earnings for the second quarter ended June 30, 2005, increased $21.5 million largely due to: - A $15.6 million benefit from the sale of the Termoceara Generating Facility, partially offset by thebusiness

· The absence in 2005 of a $4.0 million (before and after tax) noncash goodwill impairment relating to the ~~2004~~Company’s cable and pipeline magnetization and location business, as well as a $1.3 million (after tax) adjustment reflecting the reduction in value of certain gathering facilities in the Gulf Coast region

· Increased outside electrical construction workloads as well as earnings from acquisitions made in the second quarter of 2005 at the utility services business

Partially offsetting the increase in earnings was the absence of operating results in 2005 from the Termoceara Generating Facility due to the sale in June 2005, at the independent power production ~~business -~~ business.

Nine Months Ended September 30, 2005 and 2004

Consolidated earnings for the nine months ended September 30, 2005, increased $47.9 million largely due to:

· Increased outside ~~electrical line construction~~ and inside electrical workloads and margins as well as earnings from acquisitions made in the second quarter of 2005 at the utility services business -

· Higher natural gas prices of 22 percent and higher oil prices of 26 percent at the natural gas and oil production business

· A 2005 $5.0 million (after tax) benefit from the resolution of a rate proceeding as(as discussed in Note 1819 of Notes to Consolidated Financial ~~Statements~~Statements) and the absence in 2005 of the 2004 $4.0 million (before and after tax) noncash goodwill impairment and the 2004 $1.3 million (after tax) asset valuation adjustment, as previously discussed, all at the pipeline and energy services business ~~- Higher natural gas prices of 19 percent and higher oil prices of 29 percent at the natural gas and oil production business~~

Partially offsetting the increase was the absence of the favorable resolution of federal and related state income tax matters, which resulted in a benefit of $5.9 million (after tax), including interest, for the three months ended June 30, 2004. Six Months Ended June 30, 2005 and 2004 Consolidated earnings for the six months ended June 30, 2005, increased $32.4 million largely due to: - Increased outside electrical line construction and inside electrical workloads and margins at the utility services business - Higher natural gas prices of 14 percent and higher oil prices of 28 percent at the natural gas and oil production business - A $15.6 million benefit from the sale of the Termoceara Generating Facility, partially offset by the absence in 2005 of the 2004 operating results from the Termoceara Generating Facility at the independent power production business - A $5.0 million (after tax) benefit from the resolution of a rate proceeding, as previously discussed Partially offsetting the increase was the absence of the favorable resolution of federal and related state income tax matters realized in 2004. FINANCIAL AND OPERATING DATA The following tables contain key financial and operating statistics for each of the Company's businesses. Electric Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (Dollars in millions, where applicable) Operating revenues $ 41.1 $ 39.8 $ 85.4 $ 86.8 Operating expenses: Fuel and purchased power 14.5 16.4 30.7 33.1 Operation and maintenance 14.9 14.6 28.7 29.6 Depreciation, depletion and amortization 5.2 5.0 10.4 10.0 Taxes, other than income 2.1 2.0 4.3 4.2 36.7 38.0 74.1 76.9 Operating income $ 4.4 $ 1.8 $ 11.3 $ 9.9 Retail sales (million kWh) 554.7 505.3 1,159.2 1,126.5 Sales for resale (million kWh) 115.3 170.0 313.3 397.2 Average cost of fuel and purchased power per kWh $ .021 $ .022 $ .020 $ .020 Three Months Ended June 30, 2005 and 2004 Electric earnings increased $1.1 million due to: - Increased retail sales margins, largely the result of a 10 percent increase in retail sales volumes - Increased sales for resale margins of $400,000 (after tax), due to lower fuel costs which were partially offset by a 32 percent decrease in sales for resale volumes - Lower interest expense of $300,000 (after tax) The increase in earnings was partially offset by the absence of the favorable resolution of federal and related state income tax matters realized in 2004, which resulted in a benefit of ~~$1.2~~$5.9 million (after tax), including ~~interest. Six~~interest, for the nine months ended September 30, 2004.

FINANCIAL AND OPERATING DATA

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

Electric

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(Dollars in millions, where applicable)
Operating revenues	$	50.2	$	47.9	$	135.5	$	134.7

Operating expenses:
Fuel and purchased power		16.3		16.0		47.0		49.1
Operation and maintenance		15.0		14.0		43.7		43.5
Depreciation, depletion and amortization		5.2		5.0		15.5		15.1
Taxes, other than income		2.1		2.0		6.5		6.2
		38.6		37.0		112.7		113.9

Operating income	$	11.6	$	10.9	$	22.8	$	20.8

Retail sales (million kWh)		626.3		595.5		1,785.5		1,721.9
Sales for resale (million kWh)		169.1		190.8		482.4		588.1
Average cost of fuel and purchased power per kWh	$	.019	$	.019	$	.019	$	.020

Three Months Ended ~~June~~September 30, 2005 and 2004 ~~Electric~~

Earnings at the electric business increased $600,000 due to:

·	Higher retail sales margins, largely the result of a 5 percent increase in retail sales volumes

· Increased sales for resale margins due to higher average realized prices, partially offset by an 11 percent decrease in sales for resale volumes

The increase in earnings ~~increased $700,000 due to: - Decreased~~was partially offset by an increase in operation and maintenance expense, ~~of $600,000 (after tax) - Higher retail sales margins, largely~~including higher transmission and electric generation facility maintenance.

Nine Months Ended September 30, 2005 and 2004

Electric earnings increased $1.4 million due ~~to higher volumes -~~ to:

·	Higher retail sales margins, largely due to 4 percent higher volumes

· Higher sales for resale margins, primarily the result of higher average realized prices of 1120 percent and lower fuel and purchased ~~power- related~~power-related costs, offset in part by decreased sales for resale volumes of 2118 percent ~~- Lower net interest expense of $500,000 (after tax)~~

·	Lower net interest expense of $700,000 (after tax)

Partially offsetting the increase in earnings was the absence of the favorable resolution of federal and related state income tax matters realized in 2004 of $1.2 million (after tax), including interest.

Natural Gas Distribution Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (Dollars in millions, where applicable) Operating revenues: Sales $ 53.6 $ 46.5 $ 197.3 $ 173.5 Transportation and other 1.1 1.0 2.4 2.3 54.7 47.5 199.7 175.8 Operating expenses: Purchased natural gas sold 41.6 35.4 162.1 141.0 Operation and maintenance 11.3 11.3 23.2 25.1 Depreciation, depletion and amortization 2.3 2.3 4.8 4.7 Taxes, other than income 1.4 1.4 3.0 2.9 56.6 50.4 193.1 173.7 Operating income (loss) $ (1.9) $ (2.9) $ 6.6 $ 2.1 Volumes (MMdk): Sales 5.3 5.4 21.2 21.7 Transportation 3.0 2.6 6.9 6.5 Total throughput 8.3 8.0 28.1 28.2 Degree days (% of normal)* 92% 98% 93% 96% Average cost of natural gas, including transportation thereon, per dk $ 7.82 $ 6.58 $ 7.66 $ 6.49

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(Dollars in millions, where applicable)
Operating revenues:
Sales	$	33.0		$	31.4		$	230.2		$	204.9
Transportation and other		1.0			1.0			3.5			3.3
		34.0			32.4			233.7			208.2
Operating expenses:
Purchased natural gas sold		23.2			22.1			185.3			163.1
Operation and maintenance		11.3			11.3			34.5			36.4
Depreciation, depletion and amortization		2.4			2.4			7.2			7.0
Taxes, other than income		1.3			1.3			4.3			4.3
		38.2			37.1			231.3			210.8

Operating income (loss)	$	(4.2	)	$	(4.7	)	$	2.4		$	(2.6	)

Volumes (MMdk):
Sales		3.0			3.1			24.1			24.9
Transportation		2.9			2.7			9.9			9.1
Total throughput		5.9			5.8			34.0			34.0

Degree days (% of normal)*		50	%		66	%		92	%		95	%
Average cost of natural gas, including transportation, per dk	$	7.78		$	7.07		$	7.68		$	6.56

_____________________

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

Three Months Ended ~~June~~September 30, 2005 and 2004

The natural gas distribution business experienced a seasonal loss of ~~$1.3~~$3.0 million in the ~~second~~third quarter compared to a loss of ~~$1.1~~$3.2 million in the ~~second~~third quarter of 2004. The ~~decrease in earnings~~variance of $200,000 was due primarily to higher average realized rates, largely ~~due to: - The absence~~as the result of the favorable resolution of federal and related state income tax matters realized in 2004 of $1.1 million (after tax), including interest, partially offset by - Higher retail sales margins, primarily due to rate increases ~~effective~~ in ~~North Dakota, Minnesota, South Dakota and Montana Six~~various state jurisdictions.

Nine Months Ended ~~June~~September 30, 2005 and 2004

The natural gas distribution business experienced an increase in earnings of ~~$2.3~~$2.5 million due to: - Higher average realized rates, largely as a result of rate increases in North Dakota, Minnesota, South Dakota and Montana - Decreased operation and maintenance expenses of $1.2 million (after tax)

·	Higher average realized rates, largely as a result of rate increases in various state jurisdictions

·	Decreased operation and maintenance expenses of $1.2 million (after tax)

The increase was partially offset by the absence of the favorable resolution of federal and related state income tax matters realized in 2004 of $1.1 million (after tax), including interest.

Utility Services Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (In millions) Operating revenues $ 136.9 $ 97.2 $ 250.8 $ 197.5 Operating expenses: Operation and maintenance 122.6 93.5 223.7 188.9 Depreciation, depletion and amortization 3.1 2.5 5.9 5.2 Taxes, other than income 4.3 3.7 10.1 8.5 130.0 99.7 239.7 202.6 Operating income (loss) $ 6.9 $ (2.5) $ 11.1 $ (5.1)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In millions)
Operating revenues	$	207.4	$	112.9	$	458.2	$	310.4

Operating expenses:
Operation and maintenance		188.8		106.4		412.4		295.3
Depreciation, depletion and amortization		3.9		2.6		9.7		7.9
Taxes, other than income		5.0		3.8		15.2		12.2
		197.7		112.8		437.3		315.4

Operating income (loss)	$	9.7	$	.1	$	20.9	$	(5.0	)

Three Months Ended ~~June~~September 30, 2005 and 2004

Utility services realized ~~$3.7~~$5.1 million in earnings for the ~~second~~third quarter compared to a ~~$2.3~~loss of $600,000 in the comparable prior period. The increase is due to:

·	Increased outside electrical construction workloads

· Earnings from acquisitions made during the second quarter 2005, which contributed approximately 32 percent of the earnings increase

·	Decreased general and administrative expense of $1.0 million (after tax), largely lower severance-related expenses

·	Increased equipment sales and rentals

Nine Months Ended September 30, 2005 and 2004

Utility services realized $10.7 million in earnings for the first nine months of 2005 compared to a $4.8 million loss in the comparable prior period. The increase is due to: - Increased outside electrical line construction workloads and margins - Higher inside electrical workloads and margins - Higher equipment sales and rentals - Earnings from acquisitions made during the second quarter 2005 which contributed less than 10 percent to the increase Six Months Ended June 30, 2005 and 2004 Utility services realized $5.6 million in earnings for the first six months of 2005 compared to a $4.2 million loss in the comparable prior period. The increase is due to: - Increased outside electrical line construction workloads and margins - Higher inside electrical workloads and margins - Higher equipment sales and rentals - Lower general and administrative expenses of $600,000 (after tax), largely lower payroll-related costs -

·	Higher outside and inside electrical workloads and margins

· Earnings from businesses acquired during the second quarter 2005, which contributed approximately 14 percent of the earnings increase

·	Lower general and administrative expenses of $1.6 million (after tax), largely lower severance-related expenses

·	Higher equipment sales and rentals

Pipeline and Energy Services Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (Dollars in millions) Operating revenues: Pipeline $ 22.5 $ 22.7 $ 42.3 $ 45.7 Energy services 78.9 62.8 151.9 123.9 101.4 85.5 194.2 169.6 Operating expenses: Purchased natural gas sold 71.4 59.2 136.9 116.5 Operation and maintenance 13.3 12.5 26.6 25.9 Depreciation, depletion and amortization (1.5) 4.7 3.1 9.2 Taxes, other than income 2.0 1.9 4.1 3.8 85.2 78.3 170.7 155.4 Operating income $ 16.2 $ 7.2 $ 23.5 $ 14.2 Transportation volumes (MMdk): Montana-Dakota 7.7 7.6 15.4 15.9 Other 19.6 20.4 33.5 34.5 27.3 28.0 48.9 50.4 Gathering volumes (MMdk) 19.7 19.8 39.7 39.3

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(Dollars in millions)
Operating revenues:
Pipeline	$	21.5	$	21.5	$	63.7	$	67.2
Energy services		97.5		65.5		249.5		189.4
		119.0		87.0		313.2		256.6
Operating expenses:
Purchased natural gas sold		89.3		60.5		226.1		177.1
Operation and maintenance		12.8		12.0		39.5		37.9
Depreciation, depletion and amortization		4.7		4.1		7.9		13.3
Taxes, other than income		2.1		1.9		6.2		5.7
Asset impairments		---		6.1		---		6.1
		108.9		84.6		279.7		240.1

Operating income	$	10.1	$	2.4	$	33.5	$	16.5

Transportation volumes (MMdk):
Montana-Dakota		7.7		8.2		23.1		24.1
Other		19.7		26.4		53.1		60.9
		27.4		34.6		76.2		85.0

Gathering volumes (MMdk)		20.6		20.3		60.2		59.6

Three Months Ended ~~June~~September 30, 2005 and 2004

Earnings at the pipeline and energy services business were $5.3 million, compared to a loss of $1.6 million for the same period last year. The increase is primarily due to:

· The absence in 2005 of a $4.0 million (before and after tax) noncash goodwill impairment and a $1.3 million (after tax) asset valuation adjustment, as previously discussed

·	Higher gathering, transportation and storage rates of $1.9 million (after tax)

Partially offsetting the increase in earnings were lower transportation volumes, largely volumes transported to storage.

Nine Months Ended September 30, 2005 and 2004

Pipeline and energy services experienced an increase in earnings of ~~$4.3~~$11.7 million due to: -

· The absence in 2005 of the $4.0 million (before and after tax) noncash goodwill impairment and the $1.3 million (after tax) asset valuation adjustment, as previously discussed

· The benefit from the resolution of a rate proceeding of $5.0 million (after tax) which included a reduction to depreciation, depletion and amortization expense. For further information see Note 1819 of Notes to Consolidated Financial Statements. ~~- Higher gathering rates of $1.3 million (after tax)~~

·	Higher gathering rates of $3.7 million (after tax)

Partially offsetting the increase in earnings were: -

· Lower transportation and storage rates in 2005 of $1.7 million (after tax), largely the result of lower rates effective July 1, 2004

· The absence of the favorable resolution of federal and related state income tax matters realized in 2004 of $1.6 million (after tax), including interest - Decreased transportation and storage rates in 2005, the result of lower rates effective July 1, 2004 Six Months Ended June 30, 2005 and 2004 Pipeline and energy services experienced an increase in earnings of $4.9 million due to: - The benefit from the resolution of a rate proceeding of $5.0 million (after tax), as previously discussed - Higher gathering rates of $2.5 million (after tax) - Decreased operation and maintenance expenses, largely payroll- related expenses Partially offsetting the increase in earnings were: - Lower transportation and storage rates in 2005 of $2.4 million (after tax), the result of lower rates effective July 1, 2004 - The absence of the favorable resolution of federal and related state income tax matters realized in 2004 of $1.6 million (after tax), including interest

Natural Gas and Oil Production Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (Dollars in millions, where applicable) Operating revenues: Natural gas $ 80.3 $ 68.5 $ 152.8 $ 134.9 Oil 17.3 14.9 31.8 29.1 Other .1 .8 .2 1.2 97.7 84.2 184.8 165.2 Operating expenses: Purchased natural gas sold .1 .7 .2 1.1 Operation and maintenance: Lease operating costs 9.8 8.6 17.7 16.8 Gathering and transportation 2.8 2.7 5.6 5.2 Other 6.4 5.9 11.9 11.9 Depreciation, depletion and amortization 21.2 17.9 38.3 34.5 Taxes, other than income: Production and property taxes 7.5 5.7 13.5 10.4 Other .1 .1 .3 .3 47.9 41.6 87.5 80.2 Operating income $ 49.8 $ 42.6 $ 97.3 $ 85.0 Production: Natural gas (MMcf) 14,627 14,796 29,054 29,302 Oil (000's of barrels) 406 450 773 907 Average realized prices (including hedges): Natural gas (per Mcf) $ 5.49 $ 4.63 $ 5.26 $ 4.60 Oil (per barrel) $ 42.60 $ 33.09 $ 41.21 $ 32.12 Average realized prices (excluding hedges): Natural gas (per Mcf) $ 5.71 $ 4.78 $ 5.37 $ 4.73 Oil (per barrel) $ 47.81 $ 35.75 $ 46.06 $ 34.03 Production costs, including taxes, per net equivalent Mcf: Lease operating costs $ .57 $ .49 $ .52 $ .48 Gathering and transportation .17 .15 .17 .15 Production and property taxes .44 .33 .40 .30 $ 1.18 $ .97 $ 1.09 $ .93

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	94.3	$	68.2	$	247.2	$	203.0
Oil		20.5		16.2		52.3		45.4
Other		1.6		1.2		1.7		2.4
		116.4		85.6		301.2		250.8
Operating expenses:
Purchased natural gas sold		1.5		1.1		1.7		2.2
Operation and maintenance:
Lease operating costs		10.9		8.6		28.6		25.4
Gathering and transportation		3.8		3.4		9.5		8.6
Other		9.5		5.4		21.4		17.3
Depreciation, depletion and amortization		22.3		18.1		60.6		52.6
Taxes, other than income:
Production and property taxes		9.3		5.6		22.7		16.0
Other		.1		.1		.4		.4
		57.4		42.3		144.9		122.5

Operating income	$	59.0	$	43.3	$	156.3	$	128.3

Production:
Natural gas (MMcf)		15,015		15,074		44,069		44,376
Oil (000’s of barrels)		477		455		1,250		1,362

Average realized prices (including hedges):
Natural gas (per Mcf)	$	6.28	$	4.52	$	5.61	$	4.58
Oil (per barrel)	$	42.95	$	35.74	$	41.88	$	33.33

Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	6.87	$	4.66	$	5.88	$	4.70
Oil (per barrel)	$	50.72	$	40.05	$	47.83	$	36.05

Production costs, including taxes, per net equivalent Mcf:
Lease operating costs	$	.61	$	.49	$	.55	$	.48
Gathering and transportation		.21		.19		.19		.16
Production and property taxes		.52		.31		.44		.31
	$	1.34	$	.99	$	1.18	$	.95

Three Months Ended ~~June~~September 30, 2005 and 2004

The natural gas and oil production business experienced an increase in earnings of ~~$3.7~~$8.1 million due to: ~~- Higher average realized natural gas prices of 19 percent - Higher average realized oil prices of 29 percent~~

·	Higher average realized natural gas prices of 39 percent

·	Higher average realized oil prices of 20 percent

Partially offsetting the increase were: -

· Higher depreciation, depletion and amortization expense of ~~$2.0~~$2.5 million (after tax) due to higher rates and higher lease operating costs of $1.6 million (after tax), both largely ~~driven by a recent acquisition - Decreased oil production volumes~~the result of ~~10 percent, due in part to normal production declines, offset in part by production from~~ an acquisition ~~made~~ in the second quarter of 2005 ~~- Decreased~~

·	Increased general and administrative expenses of $2.5 million (after tax), including payroll-related costs

Nine Months Ended September 30, 2005 and 2004

The natural gas and oil production business experienced an increase in earnings of ~~1 percent, primarily~~$15.4 million due to:

·	Higher average realized natural gas prices of 22 percent

·	Higher average realized oil prices of 26 percent

Partially offsetting the increase were:

· Higher depreciation, depletion and amortization expense of $4.9 million (after tax) due to ~~normal production declines~~higher rates and ~~timing-related delays affecting coalbed natural gas drilling activity as a~~higher lease operating costs of $2.5 million (after tax), both largely the result of ~~ongoing environmental litigation, largely offset by increased production from natural gas properties in the Rocky Mountain region and production from~~ an acquisition ~~made~~ in the second quarter of 2005 ~~Six Months Ended June 30, 2005~~

· Increased general and ~~2004 Natural gas and oil production earnings increased $7.4~~administrative expenses of $2.6 million ~~due to: - Higher average realized natural gas prices of 14 percent - Higher average realized oil prices of 28 percent Partially offsetting the increase were: -~~ (after tax), including payroll-related costs

· Decreased oil production of 158 percent, primarily due to normal production declines, offset in part by production from an acquisition made in the second quarter of 2005 ~~- Higher depreciation, depletion and amortization expense of $2.4 million (after tax) due to higher rates -~~

· Lower natural gas production of 1 percent, primarily due to normal production declines and timing-related delays affecting coalbed natural gas drilling activity as a result of ongoing environmental litigation, largely offset by increased production from natural gas properties in the Rocky Mountain region and production from an acquisition made in the second quarter of 2005

· The absence of the favorable resolution of federal and related state income tax matters realized in 2004 of $1.0 million (after tax)

Construction Materials and Mining Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (Dollars in millions) Operating revenues $ 394.0 $ 347.2 $ 581.1 $ 486.7 Operating expenses: Operation and maintenance 330.0 286.6 500.5 419.7 Depreciation, depletion and amortization 19.0 17.0 37.2 33.2 Taxes, other than income 10.5 9.6 18.4 16.1 359.5 313.2 556.1 469.0 Operating income $ 34.5 $ 34.0 $ 25.0 $ 17.7 Sales (000's): Aggregates (tons) 11,023 11,187 16,929 15,994 Asphalt (tons) 2,139 2,346 2,500 2,648 Ready-mixed concrete (cubic yards) 1,224 1,239 1,884 1,813

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(Dollars in millions)
Operating revenues	$	610.5	$	486.9	$	1,191.6	$	973.6

Operating expenses:
Operation and maintenance		518.3		400.5		1,018.8		820.3
Depreciation, depletion and amortization		19.8		18.5		57.0		51.6
Taxes, other than income		12.3		10.2		30.7		26.3
		550.4		429.2		1,106.5		898.2

Operating income	$	60.1	$	57.7	$	85.1	$	75.4

Sales (000's)
Aggregates (tons)		17,518		15,653		34,447		31,647
Asphalt (tons)		4,331		3,938		6,831		6,586
Ready-mixed concrete (cubic yards)		1,463		1,426		3,347		3,239

Three Months Ended ~~June~~September 30, 2005 and 2004

Construction materials and mining had ~~$18.4~~$34.1 million in earnings for the ~~second~~third quarter of 2005 compared to ~~$20.4~~$34.9 million in the comparable prior period. The ~~$2.0 million~~$800,000 decrease in earnings was due to:

· Lower construction and aggregate margins in Texas offset in part by higher volumes in all product lines and improved margins in most other regions, including significant improvements in Oregon. Affecting the lower margins were:

- Higher fuel and asphalt oil costs

- Increased equipment repair and maintenance costs

· Higher depreciation, depletion and amortization expense of $700,000 (after tax), the result of higher property, plant and equipment balances and higher aggregate volumes

Earnings from acquisitions, which contributed less than 5 percent of earnings for the quarter, partially offset the decrease.

Nine Months Ended September 30, 2005 and 2004

Earnings at the construction materials and mining business increased $600,000 due to:

·	Increased ready-mixed concrete volumes and margins, largely in the Pacific and Northwest regions

·	Earnings from companies acquired since the comparable prior period, which contributed less than 5 percent of earnings

·	Higher cement volumes

Partially offsetting the increase were:

·	Higher depreciation, depletion and amortization expense

·	Decreased aggregate and construction margins, largely in Texas, offset in part by increases in most other regions

· The absence in 2005 of the 2004 favorable resolution of federal and related ~~state income~~ tax matters of $1.2 million (after tax), including interest - Increased depreciation, depletion and amortization expenses of $1.0 million (after tax) due to higher property, plant and equipment balances - The effects of unfavorable weather on asphalt and construction volumes and margins Partially offsetting the decline were increased ready-mixed concrete margins. Six Months Ended June 30, 2005 and 2004 Earnings at the construction materials and mining business increased $1.4 million due to: - Increased ready-mixed concrete volumes and margins - Higher cement volumes - Earnings from companies acquired since the comparable prior period, which contributed approximately 6 percent of earnings Partially offsetting the increase were: - Higher depreciation, depletion and amortization expenses, the result of higher property, plant and equipment balances - Lower asphalt volumes and margins due largely to effects of weather and higher fuel prices - The absence in 2005 of the 2004 favorable resolution of federal and related state income tax matters of $1.2 million (after tax), including interest

·	Higher fuel and asphalt oil costs

Independent Power Production Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (Dollars in millions) Operating revenues $ 13.7 $ 10.6 $ 23.5 $ 17.1 Operating expenses: Operation and maintenance 7.3 2.8 13.7 6.8 Depreciation, depletion and amortization 2.2 2.3 4.7 4.4 Taxes, other than income .7 1.1 1.4 1.1 10.2 6.2 19.8 12.3 Operating income $ 3.5 $ 4.4 $ 3.7 $ 4.8 Net generation capacity - kW* 279,600 279,600 279,600 279,600 Electricity produced and sold (thousand kWh)* 90,762 84,148 128,012 115,503

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(Dollars in millions)
Operating revenues	$	14.1	$	16.1	$	37.6	$	33.2

Operating expenses:
Operation and maintenance		8.0		8.7		21.7		15.4
Depreciation, depletion and amortization		2.2		2.3		6.9		6.7
Taxes, other than income		.7		.6		2.1		1.8
		10.9		11.6		30.7		23.9

Operating income	$	3.2	$	4.5	$	6.9	$	9.3

Net generation capacity - kW*		279,600		279,600		279,600		279,600
Electricity produced and sold (thousand kWh)*		89,646		61,877		217,658		177,380

_____________________

* Excludes equity method investments.

NOTE: The earnings from the ~~Company's~~Company’s equity method investments are not reflected in the above table.

Three Months Ended ~~June~~September 30, 2005 and 2004

Independent power production experienced a decrease in earnings of $5.0 million, largely due to:

·	The absence in 2005 of operating results from the Termoceara Generating Facility due to the sale

·	Increased general and administrative expense of $800,000 (after tax), largely consulting and payroll-related costs

The decrease in earnings was partially offset by earnings from an equity method investment in a domestic electric generating facility acquired since the comparable prior period, which contributed approximately 19 percent of earnings.

Nine Months Ended September 30, 2005 and 2004

Independent power production experienced an increase in earnings of ~~$8.5~~$1.0 million, largely due to: -

· A $15.6 million benefit from the sale of the Termoceara Generating Facility, ~~partially~~largely offset by the absence in 2005 of ~~the 2004~~ operating results from the Termoceara Generating Facility - due to the sale

· Earnings from an equity method investment in a domestic ~~electric-generating~~electric generating facility acquired since the comparable prior period, ~~Six Months Ended June 30, 2005~~which contributed approximately 8 percent of earnings

·	Lower interest expense of $1.0 million (after tax)

Partially offsetting the earnings increase was higher general and ~~2004 Independent power production experienced an increase in earnings~~administrative expense of ~~$5.9~~$1.2 million (after tax), largely due to: - A $15.6 million benefit from the sale of the Termoceara Generating Facility, partially offset by the absence in 2005 of the 2004 operating results from the Termoceara Generating Facility - Earnings from equity method investments acquired since the comparable prior period consulting and payroll-related costs.

Other and Intersegment Transactions

Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the ~~Company's~~Company’s other operations and the elimination of intersegment transactions. The amounts relating to these items are as follows: Three Months Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (In millions) Other: Operating revenues $ 1.4 $ 1.0 $ 2.7 $ 1.8 Operation and maintenance 1.2 .8 2.4 1.5 Depreciation, depletion and amortization .1 .1 .1 .1 Taxes, other than income --- --- .1 --- Intersegment transactions: Operating revenues $ 70.7 $ 59.7 $ 147.7 $ 131.7 Purchased natural gas sold 66.4 55.8 139.0 124.3 Operation and maintenance 4.3 3.9 8.7 7.4

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In millions)
Other:
Operating revenues	$	1.6	$	1.3	$	4.3	$	3.1
Operation and maintenance		1.4		.8		3.7		2.3
Depreciation, depletion and amortization		.1		.1		.2		.2
Taxes, other than income		---		---		.1		---

Intersegment transactions:
Operating revenues	$	86.3	$	65.5	$	234.0	$	197.2
Purchased natural gas sold		80.8		59.4		219.7		183.8
Operation and maintenance		5.5		6.1		14.3		13.4

For further information on intersegment eliminations, see Note 1516 of Notes to Consolidated Financial Statements.

RISK FACTORS AND CAUTIONARY STATEMENTS THAT MAY AFFECT FUTURE RESULTS

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, are also 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.

Following are some specific factors that should be considered for a better understanding of the ~~Company's~~Company’s financial condition. These factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

Economic Risks

The ~~Company's~~Company’s natural gas and oil production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, which cannot be predicted or controlled.

These factors include: ~~price~~ fluctuations in natural gas and crude oil prices; fluctuations in commodity price basis differentials; availability of economic supplies of natural gas; drilling successes in natural gas and oil operations; the timely receipt of necessary permits and approvals; the ability to contract for or to secure necessary drilling rig contracts and to retain employees to drill for and develop reserves; the ability to acquire natural gas and oil properties; and other risks incidental to the operations of natural gas and oil wells. Significant changes in these factors could negatively affect the results of operations and financial condition of the ~~Company's~~Company’s natural gas and oil production and pipeline and energy services businesses.

The construction and operation of power generation facilities may involve unanticipated changes or delays that could negatively impact the ~~Company's~~Company’s business and its results of operations.

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

The Company is constructing a 116-MW coal-fired electric generating facility near Hardin, Montana. The projected on-line date for this plant is late 2005. Additional increases in costs to construct the plant or delays in the timing of the completion of construction could negatively affect the independent power production business and its results of operations.

The Company's utility services business operates in highly competitive markets characterized by low margins in a number of service lines and geographic areas. ~~This business'~~

The ability of this business to ~~continue its return to~~maintain profitability ~~on a sustained basis~~ will depend upon improved capital spending for electric construction services and ~~continuing success in~~ management's continued ability to ~~refocus~~successfully focus the business on more profitable markets, reduce operating costs and implement process improvements in project management.

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

The global demand for natural resources, interest rates, governmental budget constraints, and the ongoing threat of terrorism can create volatility in the financial markets. A soft economy could negatively affect the level of public and private expenditures on projects and the timing of these projects which, in turn, would negatively affect the demand for the ~~Company's~~Company’s products and services.

The Company relies on financing sources and capital markets. If the Company is unable to obtain financing in the future, the ~~Company's~~Company’s ability to execute its business plans, make capital expenditures or pursue acquisitions that the Company may otherwise rely on for future growth could be impaired.

The Company relies on access to both short-term borrowings, including the issuance of commercial paper, and long-term capital markets as a source of liquidity for capital requirements not satisfied by its cash flow from operations. If the Company is not able to access capital at competitive rates, the ability to implement its business plans may be adversely affected. Market disruptions or a downgrade of the ~~Company's~~Company’s credit ratings may increase the cost of borrowing or adversely affect its ability to access one or more financial markets. Such disruptions could include: - A severe prolonged economic downturn - The bankruptcy of unrelated industry leaders in the same line of business - A deterioration in capital market conditions - Volatility in commodity prices - Terrorist attacks - Fluctuations in the value of the dollar on currency exchanges

·	A severe prolonged economic downturn

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

·	A deterioration in capital market conditions

·	Volatility in commodity prices

·	Terrorist attacks

·	Fluctuations in the value of the dollar on currency exchanges

Environmental and Regulatory Risks

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

The Company is subject to extensive environmental laws and regulations affecting many aspects of its present and future operations including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, and delays as a result of ongoing litigation and compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions and coalbed natural gas development. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Public officials and entities, as well as private individuals and organizations, may seek injunctive relief or other remedies to enforce applicable environmental laws and regulations. The Company cannot predict the outcome (financial or operational) of any related litigation that may arise. Existing environmental regulations may be revised and new regulations seeking to protect the environment may be adopted or become applicable to the Company. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on the ~~Company's~~Company’s results of operations.

One of the ~~Company's~~Company’s subsidiaries is subject to litigation in connection with its coalbed natural gas development activities. These proceedings have caused delays in coalbed natural gas drilling activity in 2005, and the ultimate outcome of the actions could have a material effect on existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties.

Fidelity has been named as a defendant in, and/or certain of its operations are the subject of, a number of lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. Injunctive orders issued by the Ninth Circuit and the Montana Federal District Court have occasioned reductions in ~~Fidelity's~~Fidelity’s estimated total 2005 natural gas production levels. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material effect on Fidelity's existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties.

The Company is subject to extensive government regulations that may delay and/or have a negative impact on its business and its results of operations.

The Company is subject to regulation by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return, financings, industry rate structures, and recovery of purchased power and purchased gas costs. These governmental regulations significantly influence the ~~Company's~~Company’s operating environment and may affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from the future regulatory activities of any of these agencies.

Changes in regulations or the imposition of additional regulations could have an adverse impact on the ~~Company's~~Company’s results of operations.

Risks Relating to Foreign Operations

The value of the ~~Company's~~Company’s investments in foreign operations may diminish ~~due to~~because of political, regulatory and economic conditions in countries where the Company does business.

The Company is subject to political, regulatory and economic conditions 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~~Company’s investments located in these countries.

Other Risks Competition is increasing in all of the Company's businesses. All of the Company's businesses are subject to increased competition. The independent power production industry includes many strong and capable competitors, some of which have greater resources and more experience in the operation, acquisition and development of power generation facilities. Utility services' competition is based primarily on price and reputation for quality, safety and reliability. The construction materials products are marketed under highly competitive conditions and are subject to such competitive forces as price, service, delivery time and proximity to the customer. The electric utility and natural gas industries are also experiencing increased competitive pressures as a result of consumer demands, technological advances, deregulation, greater availability of natural gas-fired generation and other factors. Pipeline and energy services competes with several pipelines for access to natural gas supplies and gathering, transportation and storage business. The natural gas and oil production business is subject to competition in the acquisition and development of natural gas and oil properties as well as in the sale of its production output. The increase in competition could negatively affect the Company's results of operations and financial condition.

Weather conditions can adversely affect the ~~Company's~~Company’s operations and ~~revenues.~~ revenues, with the recent hurricanes in the Gulf Coast region having caused some reduction in natural gas and oil production.

The ~~Company's~~Company’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, affect the wind-powered operation at the independent power production business, affect the price of energy commodities, affect the ability to perform services at the utility services and construction materials and mining businesses and affect ongoing operation and maintenance and construction and drilling activities for the pipeline and energy services and natural gas and oil production businesses. In addition, severe weather can be destructive, causing outages, reduced natural gas and oil production, and/or property damage, which could require additional costs to be incurred. As a result, adverse weather conditions could negatively affect the ~~Company's~~Company’s results of operations and financial condition.

Certain of the Company’s net daily natural gas and oil production is shut in due to the impacts from hurricanes Katrina and Rita, as discussed in Prospective Information - Natural Gas and Oil Production. The Company is continuing to assess damages caused by the hurricanes to facilities in which it has an interest as well as the duration of the remaining production shut-ins. The extent of damages and the duration of the production shut-ins, which the Company is unable to fully predict at this time, could have a negative affect on the Company’s results of operations.

Competition is increasing in all of the Company’s businesses.

All of the Company’s businesses are subject to increased competition. The independent power production industry has many competitors in the operation, acquisition and development of power generation facilities. Utility services’ competition is based primarily on price and reputation for quality, safety and reliability. The construction materials products are marketed under highly competitive conditions and are subject to such competitive forces as price, service, delivery time and proximity to the customer. The electric utility and natural gas industries are also experiencing increased competitive pressures as a result of consumer demands, technological advances, deregulation, increased natural gas prices and other factors. Pipeline and energy services competes with several pipelines for access to natural gas supplies and gathering, transportation and storage business. The natural gas and oil production business is subject to competition in the acquisition and development of natural gas and oil properties as well as in the sale of its production output. The increase in competition could negatively affect the Company’s results of operations and financial condition.

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~~Company’s businesses. Many of these highlighted points are forward-looking statements. There is no assurance that the ~~Company's~~Company’s projections, including estimates for growth and increases in revenues and earnings, will in fact be achieved. ~~Reference is made~~Please refer to assumptions contained in this section, as well as the various important factors listed under the heading Risk Factors and Cautionary Statements that May Affect Future Results, and other factors that are listed in the Introduction. Changes in such assumptions and factors could cause actual future results to differ materially from targeted growth, revenue and earnings projections.

MDU Resources Group, Inc. -

· Earnings per common share for 2005, diluted, are projected in the range of ~~$1.90~~$2.10 to ~~$2.10,~~$2.30, an increase from prior guidance of ~~$1.80~~$2.00 to ~~$2.00. -~~ $2.20.

· The Company expects the percentage of 2005 earnings per common share, diluted, by quarter to be in the following approximate ranges: - Third quarter - 30 percent to 35 percent - Fourth quarter - 18 percent to 23 percent - The Company'sCompany’s long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent. ~~- The Company anticipates investing approximately $700 million in capital expenditures during 2005.~~

Electric ~~- The expected earnings in 2005 are anticipated to be slightly lower than 2004. -~~

·	The expected earnings in 2005 are anticipated to be slightly higher than 2004.

· This segment is involved in the review of potential power projects to replace capacity associated with expiring purchased power contracts and to provide for future growth. Those projects under consideration include ~~participation in~~ a proposed 600-megawatt ~~(MW)~~ coal-fired facility to be located in northeastern South Dakota, ~~and~~a separate coal-fired unit to be located in the upper Midwest or construction of a 175-MW lignite coal-fired facility (Vision 21) to be located in southwestern North Dakota. The costs of building and/or acquiring the additional generating capacity needed by the utility are expected to be recovered in rates. - In addition, Montana-Dakota is currently evaluating a response to a request for proposal, as well as other alternatives, for 70 megawatts to 100 megawatts of capacity for the summer seasons of 2007 through 2012.

· Montana-Dakota has obtained and holds 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. - On October 25, 2004, Montana-Dakota issued a request for proposal for 70 megawatts to 100 megawatts of firm capacity and associated energy for the period of November 1, 2006 through December 31, 2010. Montana-Dakota is currently in the process of evaluating the responses. A decision is expected to be made late 2005.

Natural gas distribution -

· The expected earnings for this segment for 2005 are projected to be significantly higher than ~~the~~ earnings for ~~2004. -~~ 2004 largely because of several general natural gas rate increases implemented during late 2004 and 2005.

· In September 2004, a natural gas rate case was filed with the MPUC requesting an increase of $1.4 million annually, or 4.0 percent. An interim increase of $1.4 million annually was approved by the ~~MPUC~~commission effective January 10, 2005, subject to refund. A final order on this case is expected in early 2006. -

· In ~~March~~September 2005, a natural gas rate case was filed with the ~~SDPUC for the East River service area~~MTPSC requesting an increase of ~~$850,000~~$1.1 million annually, or ~~12.8~~1.3 percent. The Company requested an interim increase of $700,000 annually. A final order on this case is expected in ~~late 2005. -~~ mid-2006.

· Montana-Dakota and Great Plains have obtained and hold 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.

Utility services - Revenues are expected to be in the range of $550 million to $600 million in 2005. - The Company anticipates margins to increase substantially in 2005 as compared to 2004 levels. - Work backlog as of June 30, 2005, was approximately $358 million, compared to $217 million at June 30, 2004.

·	Revenues are expected to be in the range of $600 million to $650 million in 2005.

·	The Company anticipates margins to increase substantially in 2005 as compared to 2004 levels.

·	Work backlog as of September 30, 2005, was approximately $406 million, compared to $220 million at September 30, 2004.

Pipeline and energy services -

· In 2005, total natural gas gathering and transportation throughput is expected to be down approximately 5 percent from

the record levels achieved in 2004. ~~- Firm capacity for the Grasslands Pipeline is currently 90,000 Mcf per day with expansion possible to 200,000 Mcf per day. -~~

·	Firm capacity for the Grasslands Pipeline is 90,000 Mcf per day with expansion possible to 200,000 Mcf per day.

· The labor contract that Williston Basin was negotiating, as reported in Items 1 and 2 - Business and Properties - General in the ~~Company's~~Company’s 2004 Annual Report, ~~remains in negotiations.~~ has been ratified.

Natural gas and oil production ~~- The Company is expecting to drill approximately 300 wells in 2005. -~~

·	The Company is expecting to drill more than 300 wells in 2005.

· In 2005, the Company expects combined natural gas and oil production to approximate or be down slightly from the record levels achieved in 2004, ~~assuming continued~~reflecting the effects of ongoing litigation and the Company’s estimate of the impacts from hurricanes Katrina and Rita. As a result of these storms, the Company is estimating that approximately 15,000 Mcf equivalent to 20,000 Mcf equivalent of net daily production is shut in. The Company is continuing to assess damages caused by the hurricanes to facilities in which it has an interest as well as the duration of the remaining production shut-ins. Including the estimate of shut-in production from ~~existing wells at its Badger Hills Project in southeastern Montana. The Badger Hills Project has been~~hurricanes Katrina and Rita, this segment estimates the subject of two related actions filed in the Montana Federal District Court, in connection with which the Montana Federal District Court issued orders enjoining operations on the project. Subsequently, the Montana Federal District Court issued temporary stays of the injunction orders in these cases, thereby permitting continued production at the project pending further developments in the cases. Currently, this segment'scurrent net combined natural gas and oil production is approximately ~~200,000~~185,000 Mcf equivalent to ~~210,000~~195,000 Mcf equivalent per day. -

· Estimates of natural gas prices in the Rocky Mountain region for ~~August~~November through December 2005 reflected in earnings guidance are in the range of ~~$4.75~~$9.00 to ~~$5.25~~$9.50 per Mcf. The ~~Company's~~Company’s estimates for natural gas prices on the NYMEX for ~~August~~November through December 2005 reflected in earnings guidance are in the range of ~~$5.75~~$12.00 to ~~$6.25~~$12.50 per Mcf. During 2004, more than three-fourths of this ~~segment's~~segment’s natural gas production was priced using Rocky Mountain or other ~~non- NYMEX~~non-NYMEX prices. -

· Estimates of NYMEX crude oil prices for ~~July~~October through December 2005 reflected in earnings guidance are in the range of ~~$45~~$55 to ~~$50~~$60 per barrel. -

· The Company has hedged ~~a portion~~approximately 45 percent to 50 percent of its estimated natural gas production for the last three months of 2005 and approximately 40 percent to 45 percent of its estimated oil production for the last three months of 2005. The Company has hedged approximately 30 percent to 35 percent of its 2006 estimated natural gas production and approximately 15 percent to 20 percent of its 2006 estimated oil production. The hedges that are in place as of ~~July 20,~~September 30, 2005, for production in the last ~~six~~three months of 2005 and the ~~twelve~~12 months of 2006 are summarized below: Commodity Index* Period Forward Price Swap or Outstanding Notional Costless Volume Collar (MMBtu)/(Bbl) Floor-Ceiling (Per MMBtu/Bbl) Natural Gas Ventura 7/05 - 12/05 920,000 $5.00 Natural Gas Ventura 7/05 - 12/05 920,000 $4.75-$5.25 Natural Gas Ventura 7/05 - 12/05 1,840,000 $5.41-$6.80 Natural Gas Ventura 7/05 - 12/05 1,840,000 $5.00-$5.865 Natural Gas CIG 7/05 - 12/05 1,840,000 $5.25-$6.47 Natural Gas Ventura 7/05 - 12/05 920,000 $5.15 Natural Gas NYMEX 7/05 - 12/05 920,000 $6.50-$8.70 Natural Gas Ventura 7/05 - 12/05 1,840,000 $5.56 Natural Gas Ventura 7/05 - 12/05 920,000 $5.50-$7.18 Natural Gas CIG 11/05 - 12/05 549,000 $7.0500 Natural Gas NYMEX 8/05 - 12/05 1,530,000 $7.50-$8.40 Natural Gas Ventura 1/06 - 12/06 1,825,000 $6.00-$7.60 Natural Gas Ventura 1/06 - 12/06 3,650,000 $6.6550 Natural Gas CIG 1/06 - 03/06 900,000 $7.1600 Natural Gas CIG 1/06 - 03/06 810,000 $7.0500 Natural Gas Ventura 1/06 - 12/06 1,825,000 $6.75-$7.71 Natural Gas Ventura 1/06 - 12/06 1,825,000 $6.75-$7.77 Natural Gas Ventura 1/06 - 12/06 1,825,000 $7.00-$8.85 Natural Gas NYMEX 1/06 - 12/06 1,825,000 $7.75-$8.50 Natural Gas Ventura 1/06 - 12/06 1,825,000 $7.76 Natural Gas CIG 4/06 - 12/06 1,375,000 $6.50-$6.98 Crude Oil NYMEX 7/05 - 12/05 82,800 $32.00-$36.50 Crude Oil NYMEX 7/05 - 12/05 92,000 $43.00-$52.05 Crude Oil NYMEX 7/05 - 12/05 63,770 $39.00-$47.20 Crude Oil NYMEX 7/05 - 12/05 92,000 $30.70 Crude Oil NYMEX 1/06 - 12/06 182,500 $43.00-$54.15

Commodity	Index*	Period Outstanding	Forward Notional Volume (MMBtu)/(Bbl)	Price Swap or Costless Collar Floor-Ceiling (Per MMBtu/Bbl)
Natural Gas	Ventura	10/05 - 12/05	460,000	$5.00
Natural Gas	Ventura	10/05 - 12/05	460,000	$4.75-$5.25
Natural Gas	Ventura	10/05 - 12/05	920,000	$5.41-$6.80
Natural Gas	Ventura	10/05 - 12/05	920,000	$5.00-$5.865
Natural Gas	CIG	10/05 - 12/05	920,000	$5.25-$6.47
Natural Gas	Ventura	10/05 - 12/05	460,000	$5.15
Natural Gas	NYMEX	10/05 - 12/05	460,000	$6.50-$8.70
Natural Gas	Ventura	10/05 - 12/05	920,000	$5.56
Natural Gas	Ventura	10/05 - 12/05	460,000	$5.50-$7.18
Natural Gas	CIG	11/05 - 12/05	549,000	$7.05
Natural Gas	NYMEX	10/05 - 12/05	920,000	$7.50-$8.40
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$6.00-$7.60
Natural Gas	Ventura	1/06 - 12/06	3,650,000	$6.655
Natural Gas	CIG	1/06 - 3/06	900,000	$7.16
Natural Gas	CIG	1/06 - 3/06	810,000	$7.05
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$6.75-$7.71
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$6.75-$7.77
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$7.00-$8.85
Natural Gas	NYMEX	1/06 - 12/06	1,825,000	$7.75-$8.50
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$7.76
Natural Gas	CIG	4/06 - 12/06	1,375,000	$6.50-$6.98
Natural Gas	CIG	4/06 - 12/06	1,375,000	$7.00-$8.87
Natural Gas	Ventura	1/06 - 12/06	912,500	$8.50-$10.00
Natural Gas	Ventura	1/06 - 12/06	912,500	$8.50-$10.15
Crude Oil	NYMEX	10/05 - 12/05	41,400	$32.00-$36.50
Crude Oil	NYMEX	10/05 - 12/05	46,000	$43.00-$52.05
Crude Oil	NYMEX	10/05 - 12/05	26,400	$39.00-$47.20
Crude Oil	NYMEX	10/05 - 12/05	46,000	$30.70
Crude Oil	NYMEX	1/06 - 12/06	182,500	$43.00-$54.15
Crude Oil	NYMEX	1/06 - 12/06	146,000	$60.00-$69.20

* Ventura is an index pricing point related to Northern Natural Gas Co.'s’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.'s’s system.

Construction materials and mining - The Company anticipates improved earnings in 2005 as compared to 2004 with an expected return to normal weather conditions in Texas, improved construction volumes and margins and earnings from acquisitions. - Aggregate, asphalt and ready-mixed concrete volumes in 2005 are expected to be comparable to 2004 levels. -

· Revenues in 2005 are expected to be approximately 515 percent to 1020 percent higher than 2004 levels. - The Company expects that the replacement funding legislation for the Transportation Equity Act for the 21st Century (TEA-21) will be equal to or higher than previous funding levels. - Work backlog as of June 30, 2005, was approximately $740 million, compared to $545 million at June 30, 2004. - The labor contract that Knife River was negotiating, as reported in Items 1levels driven primarily by increased construction materials prices and ~~2 - Business and Properties - General in the Company's 2004 Annual Report, has been ratified.~~ construction activity.

·	Aggregate, asphalt and ready-mixed concrete volumes in 2005 are expected to be slightly higher than 2004 levels.

·	Work backlog as of September 30, 2005, was approximately $597 million, compared to $501 million at September 30, 2004.

Independent power production -

· Earnings for 2005 are expected to be somewhat lower than 2004 earnings primarily ~~due to benefits realized in 2004 from foreign currency gains and the effects~~because of ~~the embedded derivative in the Brazilian electric power sales contract, as well as~~ the absence of ongoing earnings resulting from the sale of the Termoceara Generating Facility, ~~sale. -~~ partially offset by the 2005 gain resulting from the sale, as previously discussed.

· The Company is constructing a 116-MW coal-fired electric generating facility near Hardin, Montana. A power sales agreement with Powerex Corp., a subsidiary of BC Hydro, has been secured for the entire output of the plant for a term expiring October 31, 2008, with the purchaser having an option for a two-year extension. The projected on-line date for this plant is late 2005. The construction of the generating plant was approximately 89 percent complete as of October 22, 2005. Costs of constructing the facility have exceeded initial estimates; however, the estimated costs of construction remain consistent with current market costs for constructing a similar coal-fired electric generating facility. Based on the Company’s assessment of future market prices for power, the Company believes the facility can generate suitable economic returns over the long term.

·This segment sells a significant percentage of the output at its electric generating facilities under mid- and long-term power purchase contracts to various entities. Prior to the expiration of the power purchase contracts, the Company expects that this segment will negotiate the extension or replacement of these agreements. This segment owns 213 megawatts of natural gas-fired electric generating facilities near Brush, Colorado. Ninety-five percent of the output from these facilities is sold under two power purchase contracts. One of the contracts, for 75 megawatts, expired in October 2005 and the other contract expires in September 2012. The Company anticipates that an extension and/or replacement of the power purchase contract that expired in October 2005 will be negotiated.

NEW ACCOUNTING STANDARDS

SAB No. 106

In September 2004, the SEC issued SAB No. 106 which is an interpretation regarding the application of SFAS No. 143 by oil and gas producing companies following the full-cost accounting method. SAB No. 106 was effective for the Company as of January 1, 2005. The adoption of SAB No. 106 did not have a material effect on the Company's financial position or results of operations.

SFAS No. 123 (revised)

In December 2004, the FASB issued SFAS No. 123 (revised). SFAS No. 123 (revised) 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) requires a company to record 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. SFAS No. 123 (revised) is effective for the Company on January 1, 2006. The Company is evaluating the effects of the adoption of SFAS No. 123 (revised).

FIN 47

In March 2005, the FASB issued FIN 47. FIN 47 addresses the diverse accounting practices that developed with respect to the timing of liability recognition for legal obligations associated with the retirement of a tangible long-lived asset when the timing and/or method of settlement of the obligation are conditional on a future event. FIN 47 is effective for the Company at the end of the fiscal year ending December 31, 2005. The Company is evaluating the effects of the adoption of FIN 47.

EITF No. 04-6

In March 2005, the FASB ratified EITF No. 04-6. EITF No. 04-6 requires that post-production stripping costs be treated as a variable inventory production cost. EITF No. 04-6 is effective for the Company on January 1, 2006. The ~~Company is evaluating the effects of the~~ adoption of EITF No. ~~04-6.~~ 04-6 is not expected to have a material effect on the Company’s financial position or results of operations.

For further information on SAB No. 106, SFAS No. 123 (revised), FIN 47 and EITF No. 04-6, see Note 10 of Notes to Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

The ~~Company's~~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~~Company’s critical accounting policies involving significant estimates from those reported in the 2004 Annual Report.

For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2004 Annual Report.

LIQUIDITY AND CAPITAL COMMITMENTS

Cash flows

Operating activities

Cash flows provided by operating activities in the first ~~six~~nine months of 2005 ~~decreased~~increased by ~~$9.0~~$5.3 million from the comparable 2004 period, largely the result of:

·	Increased net income of $47.9 million

· Increased depreciation, depletion and amortization expense of ~~a decrease in~~$10.6 million, due to higher depletion rates, property, plant and equipment balances and aggregate volumes

Partially offsetting the increase was decreased working capital of ~~$43.8~~$45.2 million due in part to:

·	Higher income tax payments due to lower tax depreciation and higher net income

·	Higher receivables, largely increased construction activity and construction materials prices

·	Higher inventories, partially due to higher natural gas in storage resulting from higher natural gas prices

· Partially offset by increased ~~income tax payments. Partially offsetting the decrease was an increase in net income of $32.4 million.~~ accounts payable, largely increased construction activity and construction materials prices

Investing activities

Cash flows used in investing activities in the first ~~six~~nine months of 2005 increased ~~$212.6~~by $159.5 million compared to the comparable 2004 period, primarily due ~~to an~~to:

· An increase in net capital expenditures ~~(capital expenditures; acquisitions, net~~ of ~~cash acquired; and net proceeds from the sale or disposition of property) of $214.0~~$226.1 million due largely to acquisitions, ~~in the second quarter of 2005,~~ the construction of a 116-megawatt coal-fired electric generating facility near Hardin, Montana and higher ongoing capital expenditures. Net capital expenditures exclude ~~the~~ noncash transactions, ~~related to acquisitions,~~ including the issuance of the ~~Company's~~Company’s equity ~~securities.~~securities in connection with acquisitions. The noncash transactions were ~~$30.6~~$50.8 million and ~~$32.6~~$33.1 million for the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, respectively.

Partially offsetting the increase were:

· Lower investments of $50.5 million, including the absence in 2005 of the 2004 investments in the Hartwell and Trinity Generating Facilities

·	Proceeds of $38.2 million from the sale of the Termoceara Generating Facility

Financing activities

Cash flows provided by financing activities in the first ~~six~~nine months of 2005 increased by ~~$133.8~~$94.6 million compared to the comparable 2004 period, largely the result of an increase in the issuance of ~~long- term~~long-term debt due in part to acquisitions ~~in the second quarter of 2005~~ and the construction of a 116-megawatt coal-fired electric generating facility near Hardin, Montana.

The increase was partially offset ~~by an increase in the~~by:

· Increased repayment of long-term debt of ~~$81.5~~$63.0 million, ~~partially due to~~including the redemption of $20.9 million inof Pollution Control Refunding Revenue bonds and ~~a $50.8~~certain scheduled debt repayments

· A $57.7 million decrease in the issuance of common stock asreflecting the ~~result~~absence in 2005 of the 2004 proceeds received from an underwritten public offering ~~in 2004.~~

Defined benefit pension plans

The Company has qualified noncontributory defined benefit pension plans (Pension Plans) for certain employees. Plan assets consist of investments in equity and fixed income securities. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to the Pension Plans. Actuarial assumptions include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as determined by the Company within certain guidelines. At December 31, 2004, certain Pension ~~Plans'~~Plans’ accumulated benefit obligations exceeded these ~~plans'~~plans’ assets by approximately $3.7 million. Pretax pension expense (income) reflected in the years ended December 31, 2004, 2003 and 2002, was $4.1 million, $153,000, and ($2.4) million, respectively. The ~~Company's~~Company’s pension expense is currently projected to be approximately $6.5 million to $7.5 million in 2005. A reduction in the ~~Company's~~Company’s assumed discount rate for Pension Plans along with declines in the equity markets experienced in 2002 and 2001 have combined to largely produce the increase in these costs. Funding for the Pension Plans is actuarially determined. The minimum required contributions for 2004, 2003 and 2002 were approximately $1.2 million, $1.6 million, and $1.2 million, respectively.

For further information on the ~~Company's~~Company’s Pension Plans, see Note 1718 of Notes to Consolidated Financial Statements.

Capital expenditures

Net capital expenditures for the first ~~six~~nine months of 2005 were ~~$398.4 million. Net capital expenditures, including the issuance of the Company's equity securities in connection with acquisitions,~~$523.6 million and are estimated to be approximately ~~$700~~$780 million for the year 2005. Estimated capital expenditures include those for: - Potential future acquisitions - System upgrades - Routine replacements - Service extensions - Routine equipment maintenance and replacements - Buildings, land and building improvements - Pipeline and gathering expansion projects - Further enhancement of natural gas and oil production and reserve growth -

·	Completed acquisitions

·	System upgrades

·	Routine replacements

·	Service extensions

·	Routine equipment maintenance and replacements

·	Buildings, land and building improvements

·	Pipeline and gathering expansion projects

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

· Power generation opportunities, including certain costs for additional electric generating capacity and for a 116-megawatt ~~coal- fired~~coal-fired development project, as previously discussed ~~- Other growth opportunities~~

·	Other growth opportunities

Approximately 3135 percent of estimated 2005 net capital ~~expenditures~~cxpenditures are associated with completed ~~and potential future~~ acquisitions. The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimated 2005 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 and MDU Resources Group, Inc., as described below; and through the issuance of long-term debt and the ~~Company's~~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 ~~June~~September 30, 2005.

MDU Resources Group, Inc.

The Company has a revolving credit agreement with various banks totaling $100 million (with provision for an increase, at the option of the Company on stated conditions, up to a maximum of $125 million) ~~at June 30, 2005.~~. There were no amounts outstanding under the credit agreement at ~~June~~September 30, 2005. The credit agreement supports the ~~Company's~~Company’s $75 million commercial paper program. There ~~were no amounts~~was $21.0 million outstanding under the ~~Company's~~Company’s commercial paper program at ~~June~~September 30, 2005. The commercial paper borrowings classified as long-term debt are intended to be refinanced on a ~~long- term~~long-term basis through continued MDU Resources commercial paper borrowings and as further supported by the credit agreement, which expires in June 2010.

The ~~Company's goal~~Company’s objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. If the Company were to experience a minor downgrade of its credit ratings, it would not anticipate any change in its ability to access the capital markets. However, in such event, the Company would expect 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, ~~which it does not currently anticipate,~~ it may need to borrow under its credit agreement.

To the extent the Company needs to borrow under its credit agreement, it would be expected to incur increased annualized interest expense on its variable rate ~~debt. This was not applicable at June~~debt of approximately $32,000 (after tax) based on September 30, 2005, ~~as there were no~~ variable rate borrowings.

Prior to the maturity of the credit agreement, the Company ~~plans to~~expects that it will negotiate the extension or replacement of this ~~agreement, which provides credit support to access the capital markets. In the event~~agreement. If the Company is unable to successfully negotiate an extension of, or replacement for, the credit agreement, or ~~in the event~~if the fees on this facility became too expensive, which itthe Company does not currently anticipate, the Company would seek alternative funding. One source of alternative funding might involve the securitization of certain Company assets.

In order to borrow under the ~~Company's~~Company’s credit agreement, the Company 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, (A) 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 twelve-month period ended each fiscal quarter, to be less than 2.5 to 1. Other covenants include ~~limitation~~some restrictions on the sale of certain assets and ~~limitation~~ on the making of certain investments. The Company was in compliance with these covenants and met the required conditions at ~~June~~September 30, 2005. 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 ~~June~~September 30, 2005, the Company could have issued approximately ~~$350~~$356 million of additional first mortgage bonds.

The Company's coverage of fixed charges including preferred dividends was ~~5.4~~5.8 times and 4.7 times for the twelve months ended ~~June~~September 30, 2005, and December 31, 2004, respectively. Additionally, the Company's first mortgage bond interest coverage was ~~9.3~~9.7 times and 7.1 times for the twelve months ended ~~June~~September 30, 2005, and December 31, 2004, respectively. Common stockholders' equity as a percent of total capitalization (net of long-term debt due within one year) was 6162 percent and 65 percent at ~~June~~September 30, 2005, and December 31, 2004, respectively.

Centennial Energy Holdings, Inc.

Centennial has three revolving credit agreements with various banks and institutions ~~that~~totaling $431.4 million with certain provisions allowing for increased borrowings. These credit agreements support ~~$331.4 million of Centennial's~~Centennial’s $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at ~~June~~September 30, 2005. Under the Centennial commercial paper program, ~~$300.8~~$161.5 million was outstanding at ~~June~~September 30, 2005. 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 and as further supported by ~~the~~ Centennial credit agreements. One of these credit agreements is for $400 million (replacing a similar $300 million revolving credit facility) 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 ~~17, 2007, and another~~26, 2010. Another agreement is for $21.4 million (previously $25 million) and expires on April 30, 2007. Pursuant to this credit agreement, on the last business day of April 2006, the line of credit will be reduced by $3.6 million. Centennial intends to negotiate the extension or replacement of these agreements prior to their ~~maturities, and is currently in the process of negotiating the extension of the $300 million credit facility.~~maturities. The third agreement is an uncommitted line for $10 million, which was effective on January 25, 2005, and may be terminated by the bank at any time.

Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $450 million. Under the terms of the master shelf agreement, ~~$388~~$450 million was outstanding at ~~June~~September 30, 2005. The ability to request additional borrowings under this master shelf agreement will expire in April 2008. To meet potential future financing needs, Centennial may pursue other financing arrangements, including private and/or public financing. ~~Centennial's goal~~

Centennial’s objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. If Centennial were to experience a minor downgrade of its credit ratings, it would not anticipate any change in its ability to access the capital markets. However, in such event, Centennial would expect 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, ~~which it does not currently anticipate,~~ it may need to borrow under its committed bank lines.

To the extent Centennial needs to borrow under its committed bank lines, it would be expected to incur increased annualized interest expense on its variable rate debt of approximately ~~$451,000~~$242,000 (after tax) based on ~~June~~September 30, 2005, variable rate borrowings. Based on ~~Centennial's~~Centennial’s overall interest rate exposure at ~~June~~September 30, 2005, this change would not have a material effect on the ~~Company's~~Company’s results of operations or cash flows.

Prior to the maturity of the Centennial credit agreements, Centennial ~~plans to~~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~~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 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 the $400 million credit agreement) and 60 ~~percent.~~percent (for the $21.4 million credit agreement and the master shelf agreement). 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, for the twelve-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 $21.4 million credit ~~agreements)~~agreement) and 1.75 to 1 (for the master shelf agreement). Other covenants include minimum consolidated net worth, limitation on priority debt ~~limitation~~and some restrictions on the sale of certain assets and ~~limitation~~ on the making of certain loans and investments. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at ~~June~~September 30, 2005. 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~~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~~Centennial’s financing agreements and ~~Centennial's~~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, $55.0 million was outstanding at ~~June~~September 30, 2005. The ability to request additional borrowings under this master shelf agreement expires on December 20, 2005.

In order to borrow under Williston ~~Basin's~~Basin’s uncommitted long-term master shelf agreement, it 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 ~~limitation~~and some restrictions on the sale of certain assets and ~~limitation on~~the making of certain investments. Williston Basin was in compliance with these covenants and met the required conditions at ~~June~~September 30, 2005. In the event Williston Basin does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.

Off balance sheet arrangements Centennial had unconditionally guaranteed a portion of certain bank borrowings of MPX in connection with the Company's equity method investment in the Termoceara Generating Facility, as discussed in Note 12. The Company, through an indirect wholly owned subsidiary, owned 49 percent of MPX. The guarantee to MPX's creditors expired on July 25, 2005, as the outstanding bank borrowings were repaid on that date. At June 30, 2005, the aggregate amount of borrowings outstanding subject to these guarantees was $29.6 million.

As of ~~June~~September 30, 2005, Centennial was contingently liable for the performance of certain of its subsidiaries under approximately ~~$614~~$546 million of surety bonds. These bonds are principally for construction contracts and reclamation obligations of these subsidiaries entered into in the normal course of business. Centennial indemnifies the respective surety bond companies against any exposure under the bonds. The purpose of ~~Centennial's~~Centennial’s indemnification is to allow the subsidiaries to obtain bonding at competitive rates. In the event a subsidiary of the Company does not fulfill its obligations in relation to its bonded contract or obligation, Centennial may be required to make payments under its indemnification. A large portion of these contingent commitments 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. The surety bonds were not reflected on the Consolidated Balance Sheets.

Contractual obligations and commercial commitments

There are no material changes in the ~~Company's~~Company’s contractual obligations relating to operating leases ~~and purchase commitments~~ from those reported in the 2004 Annual Report.

The ~~Company's~~Company’s long-term debt at ~~June~~September 30, 2005, increased ~~$201.1~~$188.6 million or 2120 percent from December 31, 2004, due in part to acquisitions ~~in the second quarter of 2005~~ and the construction of a 116-megawatt coal-fired electric generating facility near Hardin, Montana. Contractual obligations relating to purchase commitments at September 30, 2005, were $887.5 million, compared to purchase commitments of $728.5 million at December 31, 2004. At ~~June~~September 30, 2005, the ~~Company's~~Company’s long-term debt, ~~and~~ estimated interest payments (for the twelve months ended ~~June~~September 30, of each year listed in the table below) and contractual obligations related to purchase commitments were as follows: ~~2006 2007 2008 2009 2010 Thereafter Total (In millions) Long-term debt $26.9 $482.8 $131.3 $86.3 $36.8 $382.5 $1,146.6~~

	2006	2007	2008	2009	2010	Thereafter	Total
	(In millions)
Long-term debt	$ 86.8	$122.0	$131.3	$ 86.9	$218.5	$488.5	$1,134.0
Estimated interest
payments *	62.4	53.8	47.4	39.7	35.5	125.5	364.3
Purchase commitments	350.8	115.2	65.3	60.9	58.3	237.0	887.5
	$500.0	$291.0	$244.0	$187.5	$312.3	$851.0	$2,385.8

*Estimated ~~interest payments* 60.3 46.8 36.6 29.1 25.1 103.7 301.6 $87.2 $529.6 $167.9 $115.4 $61.9 $486.2 $1,448.2 *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 2004 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 and interest rates. 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 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. For more information on commodity price risk, see Part II, Item 7A in the 2004 Annual Report, and Notes 11 and 1415 of Notes to Consolidated Financial Statements.

The following table summarizes hedge agreements entered into by Fidelity as of ~~June~~September 30, 2005. These agreements call for Fidelity to receive fixed prices and pay variable prices. ~~(Notional~~

(Notional amount and fair value in thousands) ~~Weighted Forward Average Notional Fixed Price Volume (Per MMBtu) (In MMBtu's) Fair Value Natural~~

	Weighted Average Fixed Price (Per MMBtu)		Forward Notional Volume (In MMBtu's)		Fair Value

Natural gas swap agreements maturing in 2005	$	5.72		2,389	$	(19,296	)

Natural gas swap agreements maturing in 2006	$	7.04		7,185	$	(27,010	)

	Weighted Average Floor/Ceiling Price (Per MMBtu)		Forward Notional Volume (In MMBtu's)		Fair Value

Natural gas collar agreements maturing in 2005	$	5.73/$6.93		5,060	$	(28,733	)

Natural gas collar agreements maturing in 2006	$	7.05/$8.32		13,700	$	(37,081	)

	Weighted Average Fixed Price (Per barrel)		Forward Notional Volume (In barrels)		Fair Value

Oil swap agreement maturing in 2005	$	30.70		46	$	(1,630	)

	Weighted Average Floor/Ceiling Price (Per barrel)		Forward Notional Volume (In barrels)		Fair Value

Oil collar agreements maturing in 2005	$	38.07/$45.27		114	$	(2,391	)

Oil collar agreements maturing in 2006	$	50.56/$60.84		329	$	(2,896	)

For further information on Fidelity’s natural gas and oil price swap agreements maturing in 2005 $ 5.54 4,229 $ (5,908) Natural gas swap agreements maturing in 2006 $ 7.04 7,185 $ (4,542) Weighted Average Forward Floor/Ceiling Notional Price Volume (Per MMBtu) (In MMBtu's) Fair Value Natural gasand collar agreements, maturing in 2005 $ 5.68/$6.88 9,810 $ (5,709) Natural gas collar agreements maturing in 2006 $ 6.85/$8.09 9,125 $ (3,014) Weighted Forward Average Notional Fixed Price Volume (Per barrel) (In barrels) Fair Value Oil swap agreement maturing in 2005 $ 30.70 92 $ (2,523) Weighted Average Forward Floor/Ceiling Notional Price Volume (Per barrel) (In barrels) Fair Value Oil collar agreements maturing in 2005 $38.11/$45.36 239 $ (3,202) Oil collar agreement maturing in 2006 $43.00/$54.15 183 $ (1,450) see Note 15 of Notes to Consolidated Financial Statements.

Interest rate risk

There were no material changes to interest rate risk faced by the Company from those reported in the 2004 Annual Report. For more information on interest rate risk, see Part II, Item 7A in the 2004 Annual Report.

Foreign currency risk

The ~~Company's~~Company’s investment, through an indirect wholly owned subsidiary, in the Termoceara Generating Facility was sold as discussed in Note 12 of Notes to Consolidated Financial Statements and, as a result, the Company no longer has any material exposure to foreign currency exchange risk.

ITEM 4. CONTROLS AND PROCEDURES

The following information includes the evaluation of disclosure controls and procedures by the ~~Company's~~Company’s acting 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 Securities Exchange Act of 1934 (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~~Company’s acting chief executive officer and chief financial officer have evaluated the effectiveness of the ~~Company's~~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~~Company’s transactions are properly authorized, the ~~Company's~~Company’s assets are safeguarded against unauthorized or improper use, and the ~~Company's~~Company’s transactions are properly recorded and reported to permit preparation of the ~~Company's~~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~~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~~Company’s internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 1920 of Notes to Consolidated Financial Statements, which is incorporated by reference.

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

Between ~~April~~July 1, 2005 and ~~June~~September 30, 2005, the Company issued ~~1,271,389~~35,887 shares of Common Stock, $1.00 par value, and the Preference Share Purchase Rights appurtenant thereto, as part of the consideration paid by the Company ~~for all~~in the acquisition of a business acquired by the ~~issued and outstanding capital stock with respect to businesses acquired during this~~Company in a prior period. The Common Stock and Rights issued by the Company in ~~these transactions~~this transaction were issued in a private transaction exempt from registration under the Securities Act of 1933 pursuant to Section ~~4(2)~~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~~issuer’s purchase of equity securities:

ISSUER PURCHASES OF EQUITY SECURITIES (a) (b) (c) (d) Maximum Number (or Total Total Number of Approximate Dollar Number of Average Shares (or Units) Value) of Shares (or Shares Price Purchased as Part Units) that May Yet (or Units) Paid of Publicly Be Purchased Under Purchased per Share Announced Plans the Plans or Period (or Unit) or Programs (3) Programs (3) April 1 through April 30, 2005 34,655(1) $26.97 May 1 through May 31, 2005 53,625(2) $27.33 June 1 through June 30, 2005 Total 88,280

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)
July 1 through July 31, 2005	52,829	$28.73
August 1 through August 31, 2005
September 1 through September 30, 2005	26,114	$33.57
Total	78,943

(1) Represents ~~13,055~~ shares of common stock withheld by the Company to pay taxes in connection with the vesting of shares granted pursuant to a compensation ~~plan and 21,600 shares of common stock purchased on the open market in connection with annual stock grants made to the Company's non-employee directors.~~ plan.

(2) ~~Represents shares of common stock withheld by the Company to pay taxes in connection with vesting of restricted shares. (3)~~ Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.

ITEM 6. EXHIBITS 4(a) Centennial Energy Holdings, Inc. Master Shelf Agreement, dated April 29, 2005, among Centennial Energy Holdings, Inc. and The Prudential Insurance Company of America 4(b) MDU Resources Group, Inc. Credit Agreement, dated June 21, 2005, among MDU Resources Group, Inc., Wells Fargo Bank, National Association, as Administrative Agent, and The Other Financial Institutions Party thereto 10(a) Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005 (Flores) 10(b) Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005 (Tabasco and Texas Gardens) 10(c) First Amendment to the Purchase and Sale Agreements between Fidelity and Smith Production Inc., dated April 19, 2005 10(d) Second Amendment to the Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005 10(e) Directors' Compensation Policy, as amended on May 12, 2005 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

3(a)	Company Bylaws, as amended, August 11, 2005

4(a)	Centennial Energy Holdings, Inc. Credit Agreement, dated August 26, 2005, among Centennial Energy Holdings, Inc., U.S. Bank National Association, as Administrative Agent, and The Other Financial Institutions party thereto

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

31(a)	Certification of Acting 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 Acting 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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. MDU RESOURCES GROUP, INC. DATE: August 3, 2005 BY: /s/ Warren L. Robinson Warren L. Robinson Executive Vice President and Chief Financial Officer BY: /s/ Vernon A. Raile Vernon A. Raile Senior Vice President and Chief Accounting Officer

	MDU RESOURCES GROUP, INC.



DATE: November 3, 2005	BY:	/s/ Warren L. Robinson
		Warren L. Robinson
		Executive Vice President
		and Chief Financial Officer


	BY:	/s/ Vernon A. Raile
		Vernon A. Raile
		Senior Vice President and Chief Accounting Officer

EXHIBIT INDEX

Exhibit No. 4(a) Centennial Energy Holdings, Inc. Master Shelf Agreement, dated April 29, 2005, among Centennial Energy Holdings, Inc. and The Prudential Insurance Company of America 4(b) MDU Resources Group, Inc. Credit Agreement, dated June 21, 2005, among MDU Resources Group, Inc., Wells Fargo Bank, National Association, as Administrative Agent, and The Other Financial Institutions Party thereto 10(a) Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005 (Flores) 10(b) Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005 (Tabasco and Texas Gardens) 10(c) First Amendment to the Purchase and Sale Agreements between Fidelity and Smith Production Inc., dated April 19, 2005 10(d) Second Amendment to the Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005 10(e) Directors' Compensation Policy, as amended on May 12, 2005 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

3(a)	Company Bylaws, as amended, August 11, 2005

4(a)	Centennial Energy Holdings, Inc. Credit Agreement, dated August 26, 2005, among Centennial Energy Holdings, Inc., U.S. Bank National Association, as Administrative Agent, and The Other Financial Institutions party thereto

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

31(a)	Certification of Acting 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 Acting 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