UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED 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 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.) Schuchart Building 918 East Divide Avenue P.O. Box 5650 Bismarck, North Dakota 58506-5650 (Address of principal executive offices) (Zip Code) (701) 222-7900 (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X. No. Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X. No. Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of July 27, 2005: 119,740,593 shares. INTRODUCTION This Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are all statements other than statements of historical fact, including without limitation, those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions. In addition to the risk factors and cautionary statements included in this Form 10-Q at Item 2 -- Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) - Risk Factors and Cautionary Statements that May Affect Future Results, the following are some other factors that should be considered for a better understanding of the financial condition of MDU Resources Group, Inc. (Company). These other factors may impact the Company's financial results in future periods. - 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 of acquired companies - Fluctuations in natural gas and crude oil prices - Decline in general economic environment - Changes in governmental regulation - Unanticipated increases in competition - Variations in weather The Company is a diversified natural resource company, which was incorporated under the laws of the state of Delaware in 1924. Its principal executive offices are at the Schuchart Building, 918 East Divide Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 222-7900. Montana-Dakota Utilities Co. (Montana-Dakota), a public utility division of the Company, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in the northern Great Plains. Great Plains Natural Gas Co. (Great Plains), another public utility division of the Company, distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added products and services in the northern Great Plains. The Company, through its wholly owned subsidiary, Centennial Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI Holdings), Knife River Corporation (Knife River), Utility Services, Inc. (Utility Services), Centennial Energy Resources LLC (Centennial Resources) and Centennial Holdings Capital LLC (Centennial Capital). WBI Holdings is comprised of the pipeline and energy services and the natural gas and oil production segments. 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. Knife River 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. Utility Services specializes in electrical line construction, pipeline construction, inside electrical wiring and cabling, and the manufacture and distribution of specialty equipment. Centennial Resources 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. Centennial Capital insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive is to fund the deductible layers of the insured companies' general liability and automobile liability coverages. Centennial Capital also owns certain real and personal property and contract rights. These activities are reflected in the Other category. 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 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 The accompanying notes are an integral part of these consolidated financial statements. 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 The accompanying notes are an integral part of these consolidated financial statements. 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 The accompanying notes are an integral part of these consolidated financial statements. MDU RESOURCES GROUP, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2005 and 2004 (Unaudited) 1. Basis of presentation The accompanying consolidated interim financial statements were prepared in conformity with the basis of presentation reflected in the consolidated financial statements included in the 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 Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year. 3. Allowance for doubtful accounts The Company's allowance for doubtful accounts as of June 30, 2005 and 2004, and December 31, 2004, was $7.4 million, $8.0 million and $6.8 million, respectively. 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 million, $5.2 million and $24.9 million at June 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 30, 2005 and 2004, and December 31, 2004, respectively. 5. Inventories Inventories, other than natural gas in underground storage for the Company's regulated operations, consisted primarily of aggregates held for resale of $84.2 million, $68.1 million and $71.0 million; materials and supplies of $45.8 million, $36.0 million and $31.0 million; and other inventories of $21.7 million, $12.6 million and $17.0 million; as of June 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 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 months ended June 30, 2004, 205,305 shares with an average exercise price of $24.54, 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 months ended June 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 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 months ended June 30, 2005, was $4,000 (after tax). Compensation expense recognized for awards granted on or after January 1, 2003, for the three and six months ended June 30, 2004, was $2,000 and $5,000, 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 months ended June 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 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 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' equity as previously reported. 10. New accounting standards SAB No. 106 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 for Asset Retirement 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 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 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 natural gas and oil production properties are subject to a "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 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 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 depreciation, depletion and amortization calculation. The 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" (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 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 FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations - An Interpretation of FASB Statement No. 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 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 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. EITF No. 04-6 In March 2005, the FASB ratified Emerging Issues Task Force Issue No. 04-6, "Accounting for Stripping Costs in the Mining Industry" (EITF No. 04-6). EITF No. 04-6 requires that 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 Comprehensive income is the sum of net income as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note 14 of Notes to Consolidated Financial Statements. Comprehensive income, and the components of other comprehensive income (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 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 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 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 energy company, of its 49 percent interest in MPX Termoceara, Ltda. (MPX). The Company realized a gain of $15.6 million from the sale. 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 gain from the change in fair value of the embedded derivative in the electric power sales contract for the three and six months ended June 30, 2004, was $4.1 million (after tax). The Company's 49 percent share of the foreign currency loss resulting from the decrease in value of the Brazilian Real versus the U.S. dollar for the three and six months ended June 30, 2004, was $1.8 million (after tax) and $2.0 million (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 30, 2005, the Company's equity method investments, including Carib Power and Hartwell, had total assets of $243.6 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 30, 2004, MPX and Carib Power had total assets of $202.8 million and long-term debt of $158.0 million. The Company's investment in its equity method investments, including the Trinity and Hartwell Generating Facilities, was approximately $43.4 million, including undistributed earnings of $2.6 million, at June 30, 2005. The 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 investment in the Termoceara and Trinity Generating Facilities was approximately $26.0 million, including undistributed earnings of $14.8 million, at June 30, 2004. 13. 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 __________________ * Includes purchase price adjustments 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 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 months ended June 30, 2005 was $1.2 million and $2.1 million, respectively. Amortization expense for amortizable intangible assets for the three and six months ended June 30, 2004, and for the year ended December 31, 2004, was $702,000, $1.3 million and $3.8 million, respectively. Estimated amortization expense for amortizable intangible assets is $5.9 million in 2005, $6.0 million in 2006, $4.5 million in 2007, $4.0 million in 2008, $3.9 million in 2009 and $7.2 million thereafter. 14. Derivative instruments From time to time, the Company utilizes derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. 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 30, 2005, Fidelity Exploration & Production Company (Fidelity), an indirect wholly owned subsidiary of the Company, held derivative instruments designated as cash flow hedging instruments. Hedging activities Fidelity utilizes natural gas and oil price swap and collar agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on its forecasted sales of natural gas and oil production. Each of the natural gas and oil price swap and collar agreements was designated as a hedge of the forecasted sale of natural gas and oil production. For the three and six months ended June 30, 2005 and 2004, the amount of hedge ineffectiveness, which was included in operating revenues, was immaterial. For the three and six months ended June 30, 2005 and 2004, Fidelity did not exclude any components of the derivative instruments' gain or loss from the assessment of hedge effectiveness and there were no reclassifications into earnings as a result of the discontinuance of hedges. Gains and losses on derivative instruments that are reclassified from accumulated other comprehensive income (loss) to current-period earnings are included in the line item in which the hedged item is recorded. As of June 30, 2005, the maximum term of Fidelity's swap and collar agreements, in which it is hedging its exposure to the variability in future cash flows for forecasted transactions, is 18 months. Fidelity estimates that over the next 12 months net losses of approximately $13.7 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 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 Notes to Consolidated Financial Statements in the 2004 Annual Report. Information on the 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 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, 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 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. 16. Acquisitions During the first six 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 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 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 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 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 months ended June 30, 2005, was $1.4 million and $3.3 million, respectively. The Company's net periodic benefit cost for this plan for the three and six months ended June 30, 2004, was $2.3 million and $3.8 million, respectively. 18. Regulatory matters and revenues subject to refund 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 requested a total increase of $850,000 annually or 12.8 percent above current rates. A final order from the SDPUC is expected in late 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' 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 affirmed the 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 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 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 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 Litigation In June 1997, Jack J. Grynberg (Grynberg) filed suit under the Federal False Claims Act against Williston Basin and Montana- Dakota and 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 the dismissal of Williston Basin and Montana- Dakota. 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 because insufficient facts exist to support the allegations. Williston Basin and Montana-Dakota believe Grynberg's claims are without merit and intend to vigorously contest this suit. 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. 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 Badger Hills Project continues. 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. In those cases where damage claims have been asserted, Fidelity is unable to quantify the damages sought and will be unable to do so until after the completion of discovery. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material effect on Fidelity's existing 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 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 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 for a Supplemental Environmental Project (SEP) in Morgan County, Colorado with total expenditures of not less than $39,600 and $42,400, respectively. If the parties cannot come to an agreement on the SEP to be funded within 120 days of the Compliance Order, CPP and BIV shall 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 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. These guarantees are not reflected on the Consolidated Balance Sheets. In connection with the sale of MPX 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. 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 30, 2005, were $11.3 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 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 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 30, 2005, the fixed maximum amounts guaranteed under these agreements aggregated $99.3 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $15.0 million in 2005; $27.4 million in 2006; $2.2 million in 2007; $200,000 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 and $9.0 million, which has no scheduled maturity date. A guarantee for an unfixed amount estimated at $300,000 at June 30, 2005, has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $528,000 and was reflected on the Consolidated Balance Sheets at June 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 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' 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 million, which was not reflected on the Consolidated Balance Sheet at June 30, 2005, because these intercompany transactions are eliminated in consolidation. In addition, Centennial has issued guarantees to third parties related to the 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 at June 30, 2005. As of June 30, 2005, Centennial was contingently liable for the performance of certain of its subsidiaries under approximately $614 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 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 and $2.1 million for the three and six months ended June 30, 2005, respectively, and are estimated for the next three years to be $3.2 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 and $539,000 for the three and six months ended June 30, 2005, respectively, and estimated revenues from these contracts for the next three years are $1.8 million in 2005, $4.3 million in 2006 and $6.0 million in 2007. The amount due from Nance Petroleum at June 30, 2005, was $98,000. Montana-Dakota entered into an agreement to purchase natural gas from Nance Petroleum for the period April 1, 2005 to October 31, 2005. Montana-Dakota estimates that it will purchase between $2.0 million to $2.5 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, 2005, were $760,000. The amount due to Nance Petroleum at June 30, 2005, was $251,000. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION 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 businesses, the Company's financial condition and operating performance, the 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' 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' 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 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 (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 debt and the Company's equity securities. Net capital expenditures are estimated to be approximately $700 million for 2005. 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 operations as well as the demand for its products and services and, as a result, may have a negative impact on the Company's future revenues. - 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 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 Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (Dollars in millions, where applicable) Electric $ 1.8 $ .7 $ 4.9 $ 4.2 Natural gas distribution (1.3) (1.1) 3.5 1.2 Utility services 3.7 (2.3) 5.6 (4.2) Pipeline and energy services 8.7 4.4 12.0 7.1 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 the absence in 2005 of the 2004 operating results from the Termoceara Generating Facility at the independent power production business - Increased outside electrical line construction and inside electrical workloads and margins at the utility services business - A $5.0 million (after tax) benefit from the resolution of a rate proceeding, as discussed in Note 18 of Notes to Consolidated Financial Statements 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 of $1.2 million (after tax), including interest. Six Months Ended June 30, 2005 and 2004 Electric earnings increased $700,000 due to: - Decreased operation and maintenance expense of $600,000 (after tax) - Higher retail sales margins, largely due to higher volumes - Higher sales for resale margins, primarily the result of higher average realized prices of 11 percent and lower purchased power- related costs, offset in part by decreased sales for resale volumes of 21 percent - Lower net interest expense of $500,000 (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 _____________________ * Degree days are a measure of the daily temperature-related demand for energy for heating. Three Months Ended June 30, 2005 and 2004 The natural gas distribution business experienced a seasonal loss of $1.3 million in the second quarter compared to a loss of $1.1 million in the second quarter of 2004. The decrease in earnings of $200,000 was largely due to: - 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, partially offset by - Higher retail sales margins, primarily due to rate increases effective in North Dakota, Minnesota, South Dakota and Montana Six Months Ended June 30, 2005 and 2004 The natural gas distribution business experienced an increase in earnings of $2.3 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) 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 June 30, 2005 and 2004 Utility services realized $3.7 million in earnings for the second quarter compared to a $2.3 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 - Earnings from businesses acquired during the second quarter 2005 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 June 30, 2005 and 2004 Pipeline and energy services experienced an increase in earnings of $4.3 million due to: - 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 18 of Notes to Consolidated Financial Statements. - Higher gathering rates of $1.3 million (after tax) Partially offsetting the increase were: - 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 June 30, 2005 and 2004 The natural gas and oil production business experienced an increase in earnings of $3.7 million due to: - Higher average realized natural gas prices of 19 percent - Higher average realized oil prices of 29 percent Partially offsetting the increase were: - Higher depreciation, depletion and amortization expense of $2.0 million (after tax) due to higher rates, largely driven by a recent acquisition - Decreased oil production volumes 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 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 Six Months Ended June 30, 2005 and 2004 Natural gas and oil production earnings increased $7.4 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: - Decreased oil production of 15 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 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 June 30, 2005 and 2004 Construction materials and mining had $18.4 million in earnings for the second quarter of 2005 compared to $20.4 million in the comparable prior period. The $2.0 million decrease in earnings was due to: - 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 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 _____________________ * Excludes equity method investments. NOTE: The earnings from the Company's equity method investments are not reflected in the above table. Three Months Ended June 30, 2005 and 2004 Independent power production experienced an increase in earnings of $8.5 million, 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 a domestic electric-generating facility acquired since the comparable prior period Six Months Ended June 30, 2005 and 2004 Independent power production experienced an increase in earnings of $5.9 million, 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 Other and Intersegment Transactions Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's other operations and the elimination of intersegment transactions. The amounts relating to these items are as follows: Three Months 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 For further information on intersegment eliminations, see Note 15 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 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 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 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 business and its results of operations. The construction and operation of power generation facilities involves many risks, including start-up risks, 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, as well as the risk of performance below expected levels of output or efficiency. Such unanticipated events could negatively impact the Company's 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' ability to continue its return to profitability on a sustained basis will depend upon improved capital spending for electric construction services and continuing success in management's ability to refocus the business on more profitable markets, reduce operating costs and implement process improvements in project management. Economic volatility affects the Company's operations as well as the demand for its products and services and, as a result, may have a negative impact on the Company's future revenues. 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 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 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 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 Environmental and Regulatory Risks Some of the Company's operations are subject to extensive environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities. The Company is subject to extensive environmental laws and regulations affecting many aspects of its present and future operations including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, and delays as a result of ongoing litigation and 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 results of operations. One of the 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 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 operating environment and may affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on the Company's results of operations. Risks Relating to Foreign Operations The value of the Company's investments in foreign operations may diminish due to 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 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 operations and revenues. The 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 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 businesses. Many of these highlighted points are forward-looking statements. There is no assurance that the Company's projections, including estimates for growth and increases in revenues and earnings, will in fact be achieved. Reference is made 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 to $2.10, an increase from prior guidance of $1.80 to $2.00. - 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'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. - 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 include participation in a proposed 600-megawatt (MW) coal-fired facility to be located in northeastern South Dakota and 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. - 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. - 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 effective January 10, 2005, subject to refund. A final order is expected in early 2006. - In March 2005, a natural gas rate case was filed with the SDPUC for the East River service area requesting an increase of $850,000 annually, or 12.8 percent. A final order is expected in late 2005. - 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. 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. - The labor contract that Williston Basin was negotiating, as reported in Items 1 and 2 - Business and Properties - General in the Company's 2004 Annual Report, remains in negotiations. Natural gas and oil production - The Company is expecting to drill approximately 300 wells in 2005. - In 2005, the Company expects combined natural gas and oil production to approximate the record levels achieved in 2004, assuming continued production from existing wells at its Badger Hills Project in southeastern Montana. The Badger Hills Project has been 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's net combined natural gas and oil production is approximately 200,000 Mcf equivalent to 210,000 Mcf equivalent per day. - Estimates of natural gas prices in the Rocky Mountain region for August through December 2005 reflected in earnings guidance are in the range of $4.75 to $5.25 per Mcf. The Company's estimates for natural gas prices on the NYMEX for August through December 2005 reflected in earnings guidance are in the range of $5.75 to $6.25 per Mcf. During 2004, more than three-fourths of this segment's natural gas production was priced using Rocky Mountain or other non- NYMEX prices. - Estimates of NYMEX crude oil prices for July through December 2005 reflected in earnings guidance are in the range of $45 to $50 per barrel. - The Company has hedged a portion of its natural gas and oil production. The hedges that are in place as of July 20, 2005, for production in the last six months of 2005 and the twelve 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 * Ventura is an index pricing point related to Northern Natural Gas Co.'s system; CIG is an index pricing point related to Colorado Interstate Gas Co.'s system. Construction materials and mining - 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 5 percent to 10 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 1 and 2 - Business and Properties - General in the Company's 2004 Annual Report, has been ratified. 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 of the embedded derivative in the Brazilian electric power sales contract, as well as the absence of ongoing earnings resulting from the Termoceara Generating Facility sale. - 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. 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 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. 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 critical accounting policies involving significant estimates include impairment testing of long-lived assets and intangibles, impairment testing of natural gas and oil production properties, revenue recognition, purchase accounting, asset retirement obligations, and pension and other postretirement benefits. There were no material changes in the Company's critical accounting policies involving significant estimates from those reported in the 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 months of 2005 decreased by $9.0 million from the comparable 2004 period, largely the result of a decrease in working capital of $43.8 million due in part to increased income tax payments. Partially offsetting the decrease was an increase in net income of $32.4 million. Investing activities Cash flows used in investing activities in the first six months of 2005 increased $212.6 million compared to the comparable 2004 period, primarily due 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 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 equity securities. The noncash transactions were $30.6 million and $32.6 million for the six months ended June 30, 2005 and 2004, respectively. Financing activities Cash flows provided by financing activities in the first six months of 2005 increased by $133.8 million compared to the comparable 2004 period, largely the result of an increase in the issuance of 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 repayment of long-term debt of $81.5 million, partially due to the redemption of $20.9 million in Pollution Control Refunding Revenue bonds, and a $50.8 million decrease in the issuance of common stock as the result of 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' accumulated benefit obligations exceeded these 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 pension expense is currently projected to be approximately $6.5 million to $7.5 million in 2005. A reduction in the 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 Pension Plans, see Note 17 of Notes to Consolidated Financial Statements. Capital expenditures Net capital expenditures for the first six months of 2005 were $398.4 million. Net capital expenditures, including the issuance of the Company's equity securities in connection with acquisitions, are estimated to be approximately $700 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 - Power generation opportunities, including certain costs for additional electric generating capacity and for a 116-megawatt coal- fired development project, as previously discussed - Other growth opportunities Approximately 31 percent of estimated 2005 net capital expenditures 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 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 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 30, 2005. The credit agreement supports the Company's $75 million commercial paper program. There were no amounts outstanding under the Company's commercial paper program at June 30, 2005. The commercial paper borrowings classified as long-term debt are intended to be refinanced on a 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 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 30, 2005, as there were no variable rate borrowings. Prior to the maturity of the credit agreement, the Company plans to negotiate the extension or replacement of this agreement, which provides credit support to access the capital markets. In the event the Company is unable to successfully negotiate the credit agreement, or in the event the fees on this facility became too expensive, which it 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 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 on sale of assets and limitation on investments. The Company was in compliance with these covenants and met the required conditions at June 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 30, 2005, the Company could have issued approximately $350 million of additional first mortgage bonds. The Company's coverage of fixed charges including preferred dividends was 5.4 times and 4.7 times for the twelve months ended June 30, 2005, and December 31, 2004, respectively. Additionally, the Company's first mortgage bond interest coverage was 9.3 times and 7.1 times for the twelve months ended June 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 61 percent and 65 percent at June 30, 2005, and December 31, 2004, respectively. Centennial Energy Holdings, Inc. Centennial has three revolving credit agreements with various banks and institutions that support $331.4 million of Centennial's $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at June 30, 2005. Under the Centennial commercial paper program, $300.8 million was outstanding at June 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 $300 million and expires on August 17, 2007, and 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. 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 million was outstanding at June 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 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 (after tax) based on June 30, 2005, variable rate borrowings. Based on Centennial's overall interest rate exposure at June 30, 2005, this change would not have a material effect on the Company's results of operations or cash flows. Prior to the maturity of the Centennial credit agreements, Centennial plans to negotiate the extension or replacement of these agreements, which provide credit support to access the capital markets. In the event Centennial was unable to successfully negotiate these agreements, or in the event the fees on such facilities became too expensive, which Centennial does not currently anticipate, it would seek alternative funding. One source of alternative funding might involve the securitization of certain Centennial assets. In order to borrow under Centennial's credit agreements and the Centennial uncommitted long-term master shelf agreement, Centennial and certain of its subsidiaries must be in compliance with the applicable covenants and certain other conditions 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 60 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, for the twelve-month period ended each fiscal quarter, to be less than 2.25 to 1 (for the credit agreements) and 1.75 to 1 (for the master shelf agreement). Other covenants include minimum consolidated net worth, limitation on priority debt, limitation on sale of assets and limitation on loans and investments. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at June 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 financing agreements contain cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the applicable agreements will be in default. Certain of Centennial's financing agreements and Centennial's practice limit the amount of subsidiary indebtedness. Williston Basin Interstate Pipeline Company Williston Basin has an uncommitted long-term master shelf agreement that allows for borrowings of up to $100 million. Under the terms of the master shelf agreement, $55.0 million was outstanding at June 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 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 on sale of assets and limitation on investments. Williston Basin was in compliance with these covenants and met the required conditions at June 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 30, 2005, Centennial was contingently liable for the performance of certain of its subsidiaries under approximately $614 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. Contractual obligations and commercial commitments There are no material changes in the Company's contractual obligations relating to operating leases and purchase commitments from those reported in the 2004 Annual Report. The Company's long-term debt at June 30, 2005, increased $201.1 million or 21 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. At June 30, 2005, the Company's long-term debt and estimated interest payments (for the twelve months ended June 30, of each year listed in the table below) 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 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 14 of Notes to Consolidated Financial Statements. The following table summarizes hedge agreements entered into by Fidelity as of June 30, 2005. These agreements call for Fidelity to receive fixed prices and pay variable prices. (Notional amount and fair value in thousands) Weighted Forward Average Notional Fixed Price Volume (Per MMBtu) (In MMBtu's) Fair Value Natural gas 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 gas 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) 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 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 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 chief executive officer and chief financial officer have evaluated the effectiveness of the Company's disclosure controls and procedures and they have concluded that, as of the end of the period covered by this report, such controls and procedures were effective. Changes in internal controls The Company maintains a system of internal accounting controls that is designed to provide reasonable assurance that the Company's transactions are properly authorized, the Company's assets are safeguarded against unauthorized or improper use, and the Company's transactions are properly recorded and reported to permit preparation of the Company's financial statements in conformity with generally accepted accounting principles in the United States of America. There were no changes in the Company's internal control over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS For information regarding legal proceedings, see Note 19 of Notes to Consolidated Financial Statements, which is incorporated by reference. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS Between April 1, 2005 and June 30, 2005, the Company issued 1,271,389 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 of the issued and outstanding capital stock with respect to businesses acquired during this period. The Common Stock and Rights issued by the Company in these transactions were issued in a private transaction exempt from registration under the Securities Act of 1933 pursuant to Section 4(2) thereof, Rule 506 promulgated thereunder, or both. The classes of persons to whom these securities were sold were either accredited investors or other persons to whom such securities were permitted to be offered under the applicable exemption. The following table includes information with respect to the issuer's purchase of equity securities: ISSUER PURCHASES OF EQUITY SECURITIES (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 (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. (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 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 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