10-Q 1 mdu10q903.txt MDU RESOURCES GROUP, INC. 3RD QUARTER 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003 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 November 6, 2003: 113,234,956 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 - 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 MDU Resources Group, Inc.'s (Company) financial condition. These other factors may impact the Company's financial results in future periods. - Acquisition and disposal of assets or facilities - Changes in operation and construction of plant facilities - Changes in present or prospective generation - Changes in anticipated tourism levels - The availability of economic expansion or development opportunities - Population growth rates and demographic patterns - Market demand for energy from plants or facilities - 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 - Inflation rates - 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 and legal proceedings - The ability to effectively integrate the operations of acquired companies - Variations in weather - Unanticipated increases in competition - Changes in currency exchange rates - Changes in governmental regulation - Fluctuations in natural gas and crude oil prices - Decline in general economic environment 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 southeastern North Dakota and western Minnesota. 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 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 other related construction materials, including ready-mixed concrete, cement, asphalt and other value-added products, as well as performs integrated construction services, in the north central and western United States and in the states of Alaska, Hawaii and Texas. Utility Services is a diversified infrastructure company specializing in electric, gas and telecommunication utility construction, as well as industrial and commercial electrical, exterior lighting and traffic signalization throughout most of the United States. Utility Services also provides related specialty equipment manufacturing, sales and rental services. Centennial Resources owns electric generating facilities in the United States and has an investment in an electric generating facility in Brazil. Electric capacity and energy produced at these facilities are sold under long-term contracts to nonaffiliated entities. Centennial Resources includes investments in potential new growth opportunities that are not directly being pursued by the other business units, as well as projects outside the United States which are consistent with the Company's philosophy, growth strategy and areas of expertise. These activities are reflected in independent power production and other. Centennial Capital insures and reinsures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive program 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 independent power production and other. On August 14, 2003, the Company's Board of Directors approved a three-for-two common stock split. For more information on the common stock split see Note 3 of Notes to Consolidated Financial Statements. INDEX Part I -- Financial Information Consolidated Statements of Income -- Three and Nine Months Ended September 30, 2003 and 2002 Consolidated Balance Sheets -- September 30, 2003 and 2002, and December 31, 2002 Consolidated Statements of Cash Flows -- Nine Months Ended September 30, 2003 and 2002 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 Signatures Exhibit Index Exhibits PART I -- FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 (In thousands, except per share amounts) Operating revenues: Electric, natural gas distribution and pipeline and energy services $130,818 $ 79,581 $ 454,862 $ 317,684 Utility services, natural gas and oil production, construction materials and mining and other 585,281 532,817 1,277,209 1,156,866 716,099 612,398 1,732,071 1,474,550 Operating expenses: Fuel and purchased power 16,158 14,500 44,827 41,568 Purchased natural gas sold 19,888 4,644 123,619 60,120 Operation and maintenance: Electric, natural gas distribution and pipeline and energy services 33,375 29,719 104,852 95,080 Utility services, natural gas and oil production, construction materials and mining and other 461,100 415,953 1,015,483 928,482 Depreciation, depletion and amortization 47,749 40,589 138,725 114,536 Taxes, other than income 22,163 16,822 61,266 47,601 600,433 522,227 1,488,772 1,287,387 Operating income 115,666 90,171 243,299 187,163 Other income -- net 2,491 6,910 11,124 11,729 Interest expense 13,604 11,731 39,283 33,253 Income before income taxes 104,553 85,350 215,140 165,639 Income taxes 39,032 31,419 78,449 63,133 Income before cumulative effect of accounting change 65,521 53,931 136,691 102,506 Cumulative effect of accounting change (Note 8) --- --- (7,589) --- Net income 65,521 53,931 129,102 102,506 Dividends on preferred stocks 172 189 547 567 Earnings on common stock $ 65,349 $ 53,742 $ 128,555 $ 101,939 Earnings per common share -- basic: Earnings before cumulative effect of accounting change $ .58 $ .51 $ 1.23 $ .97 Cumulative effect of accounting change --- --- (.07) --- Earnings per common share -- basic $ .58 $ .51 $ 1.16 $ .97 Earnings per common share -- diluted: Earnings before cumulative effect of accounting change $ .58 $ .50 $ 1.22 $ .96 Cumulative effect of accounting change --- --- (.07) --- Earnings per common share -- diluted $ .58 $ .50 $ 1.15 $ .96 Dividends per common share $ .1700 $ .1600 $ .4900 $ .4666 Weighted average common shares outstanding -- basic 112,359 106,385 111,100 105,432 Weighted average common shares outstanding -- diluted 113,368 107,017 111,921 106,134 Pro forma amounts assuming retroactive application of accounting change: Net income $ 65,521 $ 53,332 $ 136,691 $ 100,713 Earnings per common share -- basic $ .58 $ .50 $ 1.23 $ .95 Earnings per common share -- diluted $ .58 $ .50 $ 1.22 $ .94 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, September 30, December 31, 2003 2002 2002 (In thousands, except shares and per share amount) ASSETS Current assets: Cash and cash equivalents $ 91,900 $ 42,806 $ 67,556 Receivables, net 410,666 363,568 325,395 Inventories 127,717 102,130 93,123 Deferred income taxes 1,950 15,020 8,877 Prepayments and other current assets 47,202 39,482 42,597 679,435 563,006 537,548 Investments 40,626 43,339 42,864 Property, plant and equipment 3,312,747 2,844,935 2,961,808 Less accumulated depreciation, depletion and amortization 1,198,382 1,042,938 1,079,110 2,114,365 1,801,997 1,882,698 Deferred charges and other assets: Goodwill 199,209 185,205 190,999 Other intangible assets, net 193,010 172,123 176,164 Other 106,723 103,959 106,976 498,942 461,287 474,139 $3,333,368 $2,869,629 $2,937,249 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Short-term borrowings $ --- $ 10,000 $ 20,000 Long-term debt and preferred stock due within one year 7,892 22,606 22,183 Accounts payable 183,506 148,312 132,120 Taxes payable 27,852 17,960 13,108 Dividends payable 19,436 17,335 17,959 Other accrued liabilities 113,463 104,720 94,275 352,149 320,933 299,645 Long-term debt 988,804 832,533 819,558 Deferred credits and other liabilities: Deferred income taxes 403,540 360,872 374,097 Other liabilities 170,138 139,021 144,004 573,678 499,893 518,101 Preferred stock subject to mandatory redemption (Note 8) --- 1,300 1,200 Commitments and contingencies Stockholders' equity: Preferred stocks 15,000 15,000 15,000 Common stockholders' equity: Common stock (Note 3) Shares issued -- $1.00 par value 113,583,312 at September 30, 2003, 71,681,396 at September 30, 2002 and 74,282,038 at December 31, 2002 113,583 71,681 74,282 Other paid-in capital 752,276 690,139 748,095 Retained earnings 548,506 446,820 474,798 Accumulated other comprehensive loss (7,002) (5,044) (9,804) Treasury stock at cost - 359,281 shares at September 30, 2003 and 239,521 shares at September 30, 2002 and December 31, 2002 (3,626) (3,626) (3,626) Total common stockholders' equity 1,403,737 1,199,970 1,283,745 Total stockholders' equity 1,418,737 1,214,970 1,298,745 $3,333,368 $2,869,629 $2,937,249 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended September 30, 2003 2002 (In thousands) Operating activities: Net income $129,102 $102,506 Cumulative effect of accounting change 7,589 --- Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 138,725 114,536 Deferred income taxes and investment tax credit 24,426 12,686 Changes in current assets and liabilities, net of acquisitions: Receivables (63,511) (64,437) Inventories (25,233) (4,585) Other current assets (8,364) (2,743) Accounts payable 36,838 27,941 Other current liabilities 33,046 14,142 Other noncurrent changes 5,587 1,594 Net cash provided by operating activities 278,205 201,640 Investing activities: Capital expenditures (212,361) (212,584) Acquisitions, net of cash acquired (132,070) (14,802) Net proceeds from sale or disposition of property 8,273 5,699 Investments 4,298 (2,827) Proceeds from notes receivable 7,812 4,000 Net cash used in investing activities (324,048) (220,514) Financing activities: Net change in short-term borrowings (20,000) 10,000 Issuance of long-term debt 243,063 68,039 Repayment of long-term debt (99,307) (8,043) Proceeds from issuance of common stock, net 366 200 Dividends paid (53,935) (50,327) Net cash provided by financing activities 70,187 19,869 Increase in cash and cash equivalents 24,344 995 Cash and cash equivalents -- beginning of year 67,556 41,811 Cash and cash equivalents -- end of period $ 91,900 $ 42,806 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 2003 and 2002 (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 for the year ended December 31, 2002 (2002 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 2002 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. Common stock split On August 14, 2003, the Company's Board of Directors approved a three-for-two common stock split to be effected in the form of a 50 percent common stock dividend. The additional shares of common stock were distributed on October 29, 2003, to common stockholders of record on October 10, 2003. All common stock information appearing in the accompanying consolidated financial statements has been restated to give retroactive effect to the stock split. Additionally, preference share purchase rights have been appropriately adjusted to reflect the effects of the split. 4. Allowance for doubtful accounts The Company's allowance for doubtful accounts as of September 30, 2003 and 2002, and December 31, 2002, was $8.3 million, $8.0 million and $8.2 million, respectively. 5. 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 months and nine months ended September 30, 2003, 209,805 shares with an average exercise price of $24.56 attributable to outstanding stock options, were excluded from the calculation of diluted earnings per share because their effect was antidilutive. For the three months and nine months ended September 30, 2002, 3,915,975 shares and 3,891,225 shares, respectively, with an average exercise price of $20.04 and $20.07, respectively, attributable to outstanding stock options were excluded from the calculation of diluted earnings per share because their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury. 6. Cash flow information Cash expenditures for interest and income taxes were as follows: Nine Months Ended September 30, 2003 2002 (In thousands) Interest, net of amount capitalized $ 31,871 $ 27,434 Income taxes $ 35,341 $ 42,421 7. Reclassifications Certain reclassifications have been made in the financial statements for the prior period to conform to the current presentation. Such reclassifications had no effect on net income or stockholders' equity as previously reported. 8. New accounting standards The Company has stock option plans for directors, key employees and employees. In the third quarter of 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 three months and nine months ended September 30, 2003, was $53,000 (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 the grant. Since 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 as if the Company had applied SFAS No. 123 and recognized compensation expense for all outstanding and unvested stock options based on the fair value at the date of grant: Three Months Ended September 30, 2003 2002 (In thousands, except per share amounts) Earnings on common stock, as reported $ 65,349 $ 53,742 Stock-based compensation expense included in reported earnings, net of related tax effects 53 --- Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects (618) (809) Pro forma earnings on common stock $ 64,784 $ 52,933 Earnings per common share -- basic -- as reported: Earnings before cumulative effect of accounting change $ .58 $ .51 Cumulative effect of accounting change --- --- Earnings per common share -- basic $ .58 $ .51 Earnings per common share -- basic -- pro forma: Earnings before cumulative effect of accounting change $ .58 $ .50 Cumulative effect of accounting change --- --- Earnings per common share -- basic $ .58 $ .50 Earnings per common share -- diluted -- as reported: Earnings before cumulative effect of accounting change $ .58 $ .50 Cumulative effect of accounting change --- --- Earnings per common share -- diluted $ .58 $ .50 Earnings per common share -- diluted -- pro forma: Earnings before cumulative effect of accounting change $ .57 $ .49 Cumulative effect of accounting change --- --- Earnings per common share -- diluted $ .57 $ .49 Nine Months Ended September 30, 2003 2002 (In thousands, except per share amounts) Earnings on common stock, as reported $128,555 $101,939 Stock-based compensation expense included in reported earnings, net of related tax effects 53 --- Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects (1,925) (2,409) Pro forma earnings on common stock $126,683 $ 99,530 Earnings per common share -- basic -- as reported: Earnings before cumulative effect of accounting change $ 1.23 $ .97 Cumulative effect of accounting change (.07) --- Earnings per common share -- basic $ 1.16 $ .97 Earnings per common share -- basic -- pro forma: Earnings before cumulative effect of accounting change $ 1.21 $ .94 Cumulative effect of accounting change (.07) --- Earnings per common share -- basic $ 1.14 $ .94 Earnings per common share -- diluted -- as reported: Earnings before cumulative effect of accounting change $ 1.22 $ .96 Cumulative effect of accounting change (.07) --- Earnings per common share -- diluted $ 1.15 $ .96 Earnings per common share -- diluted -- pro forma: Earnings before cumulative effect of accounting change $ 1.20 $ .94 Cumulative effect of accounting change (.07) --- Earnings per common share -- diluted $ 1.13 $ .94 In June 2001, the FASB approved SFAS No. 141, "Business Combinations," which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In June 2001, the FASB also approved SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS No. 141 and SFAS No. 142 clarify that more assets should be distinguished and classified between tangible and intangible. The Company did not change or reclassify contractual mineral rights included in property, plant and equipment related to its natural gas and oil production business upon adoption of SFAS No. 142. The Company has included such mineral rights as part of property, plant and equipment under the full cost method of accounting for natural gas and oil properties. An issue has arisen within the natural gas and oil industry as to whether contractual mineral rights under SFAS No. 142 should be classified as intangible rather than as part of property, plant and equipment. This accounting matter is anticipated to be addressed by the FASB's Emerging Issues Task Force. The resolution of this matter may result in certain reclassifications of amounts in the Company's Consolidated Balance Sheets, as well as changes to the Company's Notes to Consolidated Financial Statements in the future. The applicable provisions of SFAS No. 141 and SFAS No. 142 only affect the balance sheet and associated footnote disclosure, so any reclassifications that might be required in the future will not affect the Company's cash flows or results of operations. The Company believes that the resolution of this matter will not have a material effect on the Company's financial position because the mineral rights acquired by its natural gas and oil production business after the June 30, 2001, effective date of SFAS No. 142 are not material. In June 2001, the FASB approved SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for the recorded amount or incurs a gain or loss upon settlement. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. For more information on the adoption of SFAS No. 143, see Note 13. In April 2002, the FASB approved SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." FASB No. 4 required all gains or losses from extinguishment of debt to be classified as extraordinary items net of income taxes. SFAS No. 145 requires that gains and losses from extinguishment of debt be evaluated under the provisions of APB Opinion No. 30, and be classified as ordinary items unless they are unusual or infrequent or meet the specific criteria for treatment as an extraordinary item. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. The adoption of SFAS No. 145 did not have a material effect on the Company's financial position or results of operations. In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 clarifies the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. FIN 45 also requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing certain types of guarantees. Certain types of guarantees are not subject to the initial recognition and measurement provisions of FIN 45 but are subject to its disclosure requirements. The initial recognition and initial measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, regardless of the guarantor's fiscal year-end. The guarantor's previous accounting for guarantees issued prior to the date of the initial application of FIN 45 is not required to be revised or restated. The disclosure requirements in FIN 45 are effective for financial statements of interim or annual periods ended after December 15, 2002. The Company is applying the initial recognition and initial measurement provisions of FIN 45 to guarantees issued or modified after December 31, 2002. For more information on the Company's guarantees and the disclosure requirements of FIN 45, as applicable to the Company, see Note 18. In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 clarifies the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements" to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated support from other parties. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. All companies with variable interests in variable interest entities created after January 31, 2003, were required to apply the provisions of FIN 46 to those entities immediately. Although the Company has not created any variable interest entities after January 31, 2003, the Company will apply the provisions of FIN 46 to variable interest entities if and when they are created. FIN 46 was effective for the first fiscal year or interim period beginning after June 15, 2003, for variable interest entities created before February 1, 2003. However, in October 2003, the FASB issued FASB Staff Position No. FIN 46-6 which defers the required effective date until the end of the first interim or annual period ending after December 15, 2003, for interests held in a variable interest entity or potential variable interest entity that was created before February 1, 2003, provided that financial statements have not been issued reporting that variable interest entity in accordance with FIN 46. The deferral of the effective date of FIN 46 did not have an effect on the Company's financial position or results of operations. The Company evaluated the provisions of FIN 46 for entities created before February 1, 2003. Based on this evaluation, the Company determined that MPX Holdings, Ltda. (MPX) is a variable interest entity. MPX was formed in August 2001, as a result of MDU Brasil Ltda. (MDU Brasil), an indirect wholly owned Brazilian subsidiary of the Company, entering into a joint venture agreement with a Brazilian firm. MDU Brasil has a 49 percent interest in MPX. Although the Company has determined that MPX is a variable interest entity, MDU Brasil is not considered the primary beneficiary of MPX because MDU Brasil does not absorb a majority of MPX's expected losses or receive a majority of MPX's expected residual returns. Therefore, MDU Brasil does not have a controlling financial interest in MPX and is not required to consolidate MPX in its financial statements. MPX is being accounted for under the equity method of accounting. For more information on the equity method investment, see Note 10. The adoption of FIN 46 did not have a material effect on the Company's financial position or results of operations. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 provides clarification on the financial accounting and reporting of derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities; and requires contracts with similar characteristics to be accounted for on a comparable basis. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material effect on the Company's financial position or results of operations. In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within the scope of SFAS No. 150 as a liability (or an asset in some circumstances). SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company will apply SFAS No. 150 to any financial instruments entered into or modified after May 31, 2003. Beginning with the third quarter of 2003, the Company reported its preferred stock subject to mandatory redemption as a liability in accordance with SFAS No. 150. The transition to SFAS No. 150 did not have a material effect on the Company's financial position or results of operations. 9. 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, a minimum pension liability adjustment and foreign currency translation adjustments. The Company's comprehensive income, and the components of other comprehensive income (loss), and their related tax effects, were as follows: Three Months Ended September 30, 2003 2002 (In thousands) Net income $ 65,521 $ 53,931 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 $1,545 and $806 in 2003 and 2002, respectively 2,416 (1,234) Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $2,839 and $789 in 2003 and 2002, respectively (4,522) 1,208 Net unrealized gain (loss) on derivative instruments qualifying as hedges 6,938 (2,442) Foreign currency translation adjustment 1,698 --- 8,636 (2,442) Comprehensive income $ 74,157 $ 51,489 Nine Months Ended September 30, 2003 2002 (In thousands) Net income $129,102 $102,506 Other comprehensive income (loss) -- Net unrealized gain (loss) on derivative instruments qualifying as hedges: Net unrealized loss on derivative instruments arising during the period, net of tax of $983 and $723 in 2003 and 2002, respectively (1,537) (1,107) Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $2,171 and $1,185 in 2003 and 2002, respectively (3,397) 1,815 Net unrealized gain (loss) on derivative instruments qualifying as hedges 1,860 (2,922) Minimum pension liability adjustment, net of tax of $2,781 in 2002 --- (4,340) Foreign currency translation adjustment 942 --- 2,802 (7,262) Comprehensive income $131,904 $ 95,244 10. Equity method investment In August 2001, MDU Brasil entered into a joint venture agreement with a Brazilian firm under which the parties formed MPX. MDU Brasil has a 49 percent interest in MPX which is being accounted for under the equity method of accounting, as discussed in Note 8. MPX, through a wholly owned subsidiary, owns a 220-megawatt natural gas-fired power plant (Project) in the Brazilian state of Ceara. MPX has assets at September 30, 2003, of approximately $101.6 million. Petrobras, the Brazilian state-controlled energy company, has agreed to purchase all of the capacity and market all of the Project's energy. The power purchase agreement with Petrobras expires in May 2008. Petrobras also is under contract for five years to supply natural gas to the Project. This natural gas supply contract is renewable for an additional 13 years. The functional currency for the Project is the Brazilian real. The power purchase agreement with Petrobras contains an embedded derivative, which derives its value from an annual adjustment factor, which largely indexes the contract capacity payments to the U.S. dollar. For the three and nine months ended September 30, 2003, the Company's 49 percent share of the loss from the embedded derivative in the power purchase agreement was $3.0 million (after tax) and $9.0 million (after tax), respectively. The Company's 49 percent share of the foreign currency loss resulting from devaluation of the Brazilian real totaled $476,000 (after tax) for the three months ended September 30, 2003. The Company's 49 percent share of the foreign currency gain resulting from the revaluation of the Brazilian real totaled $2.6 million for the nine months ended September 30, 2003. The Company's investment in the Project has been accounted for under the equity method of accounting, and the Company's share of net income, including the previously mentioned foreign currency gain and loss and the loss from the embedded derivative in the power purchase agreement, for the three months and nine months ended September 30, 2003, of $130,000 and $1.9 million, respectively, was included in other income - net. At September 30, 2003 and 2002, and December 31, 2002, the Company's investment in the Project was approximately $20.6 million, $27.8 million and $27.8 million, respectively. 11. Goodwill and other intangible assets The changes in the carrying amount of goodwill were as follows: Net Goodwill Acquired Balance and Other Balance as of Changes as of Nine Months Ended January 1, During September 30, September 30, 2003 2003 the Year* 2003 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services 62,487 127 62,614 Pipeline and energy services 9,494 --- 9,494 Natural gas and oil production --- --- --- Construction materials and mining 111,887 8,083 119,970 Independent power production and other 7,131 --- 7,131 Total $ 190,999 $ 8,210 $ 199,209 Net Goodwill Acquired Balance and Other Balance as of Changes as of Nine Months Ended January 1, During September 30, September 30, 2002 2002 the Year* 2002 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services 61,909 1,083 62,992 Pipeline and energy services 9,336 158 9,494 Natural gas and oil production --- --- --- Construction materials and mining 102,752 9,967 112,719 Independent power production and other --- --- --- Total $ 173,997 $ 11,208 $ 185,205 Net Goodwill Acquired Balance and Other Balance as of Changes as of Year Ended January 1, During December 31, December 31, 2002 2002 the Year* 2002 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services 61,909 578 62,487 Pipeline and energy services 9,336 158 9,494 Natural gas and oil production --- --- --- Construction materials and mining 102,752 9,135 111,887 Independent power production and other --- 7,131 7,131 Total $ 173,997 $ 17,002 $ 190,999 _________________ * Includes purchase price adjustments related to acquisitions acquired in a prior period. Other intangible assets were as follows: September 30, September 30, December 31, 2003 2002 2002 (In thousands) Amortizable intangible assets: Leasehold rights $184,079 $170,496 $172,496 Accumulated amortization (11,096) (6,141) (7,494) 172,983 164,355 165,002 Noncompete agreements 12,075 12,090 12,075 Accumulated amortization (9,621) (9,234) (9,366) 2,454 2,856 2,709 Other 17,736 5,149 7,224 Accumulated amortization (1,766) (237) (374) 15,970 4,912 6,850 Unamortizable intangible assets 1,603 --- 1,603 Total $193,010 $172,123 $176,164 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 months and nine months ended September 30, 2003, was $1.7 million and $4.5 million, respectively. Amortization expense for amortizable intangible assets for the three months and nine months ended September 30, 2002, and for the year ended December 31, 2002, was $727,000, $1.4 million and $3.4 million, respectively. Estimated amortization expense for amortizable intangible assets is $5.9 million in 2003, $6.2 million in 2004, $6.4 million in 2005, $5.2 million in 2006, $5.1 million in 2007 and $167.1 million thereafter. For more information on goodwill and other intangible assets, see Note 8. 12. 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 2002 Annual Report. As of September 30, 2003, a subsidiary of the Company held derivative instruments designated as cash flow hedging instruments. Hedging activities A subsidiary of the Company 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 the subsidiary's forecasted sales of natural gas and oil production. For the three months and nine months ended September 30, 2003 and 2002, the amount of hedge ineffectiveness recognized, which was included in operating revenues, was immaterial. For the three months and nine months ended September 30, 2003 and 2002, the subsidiary 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 September 30, 2003, the maximum term of the subsidiary's swap and collar agreements, in which the subsidiary of the Company is hedging its exposure to the variability in future cash flows for forecasted transactions, is 15 months. The subsidiary of the Company estimates that over the next twelve months net losses of approximately $2.7 million (after tax) will be reclassified from accumulated other comprehensive loss into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings. 13. Asset retirement obligations The Company adopted SFAS No. 143 on January 1, 2003. The Company recorded obligations related to the plugging and abandonment of natural gas and oil wells; decommissioning of certain electric generating facilities; reclamation of certain aggregate properties and certain other obligations associated with leased properties. Removal costs associated with certain natural gas distribution, transmission, storage and gathering facilities have not been recognized as these facilities have been determined to have indeterminate useful lives. Upon adoption of SFAS No. 143, the Company recorded an additional discounted liability of $22.5 million and a regulatory asset of $493,000, increased net property, plant and equipment by $9.6 million and recognized a one-time cumulative effect charge of $7.6 million (net of deferred income tax benefits of $4.8 million). The Company believes that any expenses under SFAS No. 143 as they relate to regulated operations will be recovered in rates over time and accordingly, deferred such expenses as a regulatory asset upon adoption. The Company will continue to defer those SFAS No. 143 expenses that it believes will be recovered in rates over time. In addition to the $22.5 million liability recorded upon the adoption of SFAS No. 143, the Company had previously recorded a $7.5 million liability related to retirement obligations. A reconciliation of the Company's liability was as follows: For the Nine Months Ended September 30, 2003 (In thousands) January 1, 2003 $ 29,997 Liabilities incurred 1,216 Liabilities acquired 626 Liabilities settled (607) Accretion expense 1,426 $ 32,658 This liability is included in other liabilities. If SFAS No. 143 had been in effect during 2002, the Company's liability would have been approximately $27.0 million and $28.6 million at January 1, 2002, and September 30, 2002, respectively. The fair value of assets that are legally restricted for purposes of settling asset retirement obligations at September 30, 2003, was $5.1 million. 14. Long-term debt In 2003, Centennial borrowed an additional $39 million under its long-term master shelf agreement. Under the terms of Centennial's master shelf agreement, $384.6 million was outstanding at September 30, 2003. Williston Basin Interstate Pipeline Company (Williston Basin), an indirect wholly owned subsidiary of the Company, borrowed an additional $25 million in 2003 under its long-term master shelf agreement. Under the terms of Williston Basin's master shelf agreement, $55.0 million was outstanding at September 30, 2003. In addition, Centennial entered into a $125 million note purchase agreement on June 27, 2003. The $125 million in proceeds was used to pay down Centennial commercial paper program borrowings. Borrowings outstanding that were classified as long-term debt under the Company's and Centennial's commercial paper programs totaled $126.6 million at September 30, 2003, compared to $151.9 million at December 31, 2002. 15. Business segment data The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The Company has 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. During the fourth quarter of 2002, the Company separated independent power production and other operations from its reportable segments. The independent power production and other operations do not individually meet the criteria to be considered a reportable segment. 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 largely of an investment in a natural gas-fired electric generation station in Brazil, as discussed in Note 10. 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 consists of a diversified infrastructure company specializing in electric, gas and telecommunication utility construction, as well as industrial and commercial electrical, exterior lighting and traffic signalization throughout most of the United States. Utility services also provides related specialty equipment manufacturing, sales and rental services. 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 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 north central and western United States and in the states of Alaska, Hawaii and Texas. The independent power production and other operations include electric generating facilities in the United States and Brazil and investments in potential new growth opportunities that are not directly being pursued by the Company's other businesses. The information below follows the same accounting policies as described in Note 1 of the Company's 2002 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 September 30, 2003 Electric $ 47,935 $ --- $ 6,279 Natural gas distribution 27,710 --- (2,524) Pipeline and energy services 55,173 6,230 4,662 130,818 6,230 8,417 Utility services 116,091 --- 1,669 Natural gas and oil production 33,381 31,518 16,530 Construction materials and mining 426,470 --- 36,135 Independent power production and other 9,339 740 2,598 585,281 32,258 56,932 Intersegment eliminations --- (38,488) --- Total $ 716,099 $ --- $ 65,349 Three Months Ended September 30, 2002 Electric $ 41,515 $ --- $ 4,463 Natural gas distribution 16,821 --- (2,646) Pipeline and energy services 21,245 6,324 5,846 79,581 6,324 7,663 Utility services 113,419 --- 1,628 Natural gas and oil production 40,785 1,383 6,953 Construction materials and mining 378,613 --- 33,400 Independent power production and other --- 847 4,098 532,817 2,230 46,079 Intersegment eliminations --- (8,554) --- Total $ 612,398 $ --- $ 53,742 Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Nine Months Ended September 30, 2003 Electric $ 131,655 $ --- $ 12,862 Natural gas distribution 181,104 --- 430 Pipeline and energy services 142,103 36,656 14,056 454,862 36,656 27,348 Utility services 328,682 --- 4,294 Natural gas and oil production 111,246 87,334 46,062 Construction materials and mining 811,352 --- 41,498 Independent power production and other 25,929 2,221 9,353 1,277,209 89,555 101,207 Intersegment eliminations --- (126,211) --- Total $1,732,071 $ --- $ 128,555 Nine Months Ended September 30, 2002 Electric $ 117,877 $ --- $ 9,627 Natural gas distribution 122,652 --- 1,057 Pipeline and energy services 77,155 36,647 13,361 317,684 36,647 24,045 Utility services 338,051 --- 3,811 Natural gas and oil production 117,293 31,046 37,363 Construction materials and mining 701,522 --- 34,560 Independent power production and other --- 2,541 2,160 1,156,866 33,587 77,894 Intersegment eliminations --- (70,234) --- Total $1,474,550 $ --- $ 101,939 Earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from utility services, natural gas and oil production, construction materials and mining, and independent power production and other are all from nonregulated operations. 16. Acquisitions During the first nine months of 2003, the Company acquired a number of businesses, none of which was individually material, including construction materials and mining businesses in Montana, North Dakota and Texas and a wind- powered electric generation facility in California. The total purchase consideration for these businesses and adjustments with respect to certain other acquisitions acquired in 2002, including the Company's common stock and cash, was $172.2 million. The above 2003 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 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, results of operations or cash flows. 17. Regulatory matters and revenues subject to refund On May 30, 2003, Montana-Dakota filed an application with the North Dakota Public Service Commission (NDPSC) for an electric rate increase. Montana-Dakota requested a total of $7.8 million annually or 9.1 percent above current rates. The application included an interim request of $2.4 million effective July 1, 2003, related to the recovery of costs for additional investments and costs incurred for new generation resources. On July 23, 2003, Montana-Dakota and the NDPSC Staff filed a Settlement Agreement with the NDPSC agreeing on the issues of rate of return, capital structure and cost of capital components. On August 4, 2003, Montana-Dakota requested that the NDPSC hold its interim rate request in abeyance until the issuance of a final order or until Montana- Dakota renews the motion for interim relief. A final order from the NDPSC is due January 30, 2004. In December 2002, Montana-Dakota filed an application with the South Dakota Public Utilities Commission (SDPUC) for a natural gas rate increase. Montana-Dakota requested a total of $2.2 million annually or 5.8 percent above current rates. On October 27, 2003, Montana-Dakota and the SDPUC Staff filed a Settlement Stipulation with the SDPUC agreeing to an increase of $1.3 million annually. The Settlement Stipulation must be approved by the SDPUC before it can become effective and a final order from the SDPUC is expected in late 2003. In October 2002, Great Plains filed an application with the Minnesota Public Utilities Commission (MPUC) for a natural gas rate increase. Great Plains requested a total of $1.6 million annually or 6.9 percent above current rates. In December 2002, the MPUC issued an Order setting interim rates that approved an interim increase of $1.4 million annually effective December 6, 2002. Great Plains began collecting such rates effective December 6, 2002, subject to refund until the MPUC issues a final order. On May 13, 2003, Great Plains and the Minnesota Department of Commerce (DOC), the only intervener in the proceeding, filed a Stipulation with the MPUC agreeing to an increase of $1.1 million annually. A hearing before the MPUC on the Stipulation was held on June 13, 2003, at which time the MPUC took under advisement the Stipulation agreed upon by Great Plains and the DOC. On October 9, 2003, the MPUC issued a Final Order authorizing an increase of $1.1 million annually as outlined in the Stipulation and requiring Great Plains to file a compliance filing with the MPUC. On November 10, 2003, Great Plains filed a compliance filing with the MPUC. Great Plains is awaiting a decision from the MPUC on the implementation date of the final rates changes. Reserves have been provided for a portion of the revenues that have been collected subject to refund for certain of the above proceedings. The Company believes that such reserves are adequate based on its assessment of the ultimate outcome of the proceedings. In December 1999, Williston Basin 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. On July 3, 2003, the FERC issued its Order on Initial Decision. The Order 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 are other issues as to which FERC differed with the ALJ including return on common equity and the correct level of corporate overhead expense. On August 4, 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 September 3, 2003, the FERC issued an order granting Williston Basin's request for rehearing of the July 3, 2003, Order on Initial Decision. The FERC also indicated in its September 3, 2003, order that it anticipates issuing a decision on the merits of the rehearing request by November 17, 2003. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to Williston Basin's pending regulatory proceeding. Williston Basin believes that such reserves are adequate based on its assessment of the ultimate outcome of the proceeding. 18. Contingencies Litigation In January 2002, Fidelity Oil Co. (FOC), one of the Company's natural gas and oil production subsidiaries, entered into a compromise agreement with the former operator of certain of FOC's oil production properties in southeastern Montana. The compromise agreement resolved litigation involving the interpretation and application of contractual provisions regarding net proceeds interests paid by the former operator to FOC for a number of years prior to 1998. The terms of the compromise agreement are confidential. As a result of the compromise agreement, the natural gas and oil production segment reflected a gain in its financial results for the first quarter of 2002 of approximately $16.6 million after tax. As part of the settlement, FOC gave the former operator a full and complete release, and FOC is not asserting any such claim against the former operator for periods after 1997. In July 1996, Jack J. Grynberg (Grynberg) filed suit in United States District Court for the District of Columbia (U.S. District Court) against Williston Basin and over 70 other natural gas pipeline companies. 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 March 1997, the U.S. District Court dismissed the suit without prejudice and the dismissal was affirmed by the United States Court of Appeals for the D.C. Circuit in October 1998. In June 1997, Grynberg filed a similar Federal False Claims Act suit against Williston Basin and Montana-Dakota and filed over 70 other separate similar suits against natural gas transmission companies and producers, gatherers, and processors of natural gas. 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 Federal District Court of Wyoming (Federal District Court). Oral argument on motions to dismiss was held before the Federal District Court in March 2000. In May 2001, the Federal District Court denied Williston Basin's and Montana-Dakota's motion to dismiss. The matter is currently in the discovery stage. 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. Williston Basin and Montana-Dakota believe that the Grynberg case will ultimately be dismissed because Grynberg is not, as is required by the Federal False Claims Act, the original source of the information underlying the action. Failing this, Williston Basin and Montana-Dakota believe Grynberg will not recover damages from Williston Basin and Montana-Dakota because insufficient facts exist to support the allegations. Williston Basin and Montana-Dakota intend to vigorously contest this suit. 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 United States Environmental Protection Agency (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 ten 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. Guarantees Centennial has unconditionally guaranteed a portion of certain bank borrowings of MPX and a foreign currency swap agreement of MPX in connection with the Company's equity method investment in the natural gas-fired electric generation station in Brazil, as discussed in Note 10. The Company, through MDU Brasil, owns 49 percent of MPX. At September 30, 2003, the amount of the obligation of the foreign currency swap agreement, which expires in 2003, was $47,000. At September 30, 2003, the aggregate amount of borrowings outstanding subject to these guarantees was $64.4 million and the scheduled repayment of these borrowings was $19.1 million in 2006 and $45.3 million in 2008. Centennial guarantees of approximately $19.1 million will terminate upon MPX meeting certain financial covenants. The individual investor, who through EBX Empreendimentos Ltda. (EBX), a Brazilian company, owns 51 percent of MPX, has also guaranteed a portion of these loans. Centennial and the individual investor have entered into reimbursement agreements under which they have agreed to reimburse each other to the extent they may be required to make any guarantee payments in excess of their proportionate ownership share in MPX. These guarantees are not reflected on the Consolidated Balance Sheets. In addition, WBI Holdings has guaranteed certain of its subsidiary's natural gas and oil price collar agreement obligations. The amount of the subsidiary's obligations at September 30, 2003, was $2.2 million. There is no fixed maximum amount guaranteed in relation to the natural gas and oil price collar agreements; however, the amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the natural gas and oil price collar agreements at September 30, 2003, expire in December 2003; however, the subsidiary 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 amounts outstanding under the natural gas and oil price collar agreements were reflected on the Consolidated Balance Sheets. In the event the above subsidiary 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 that are related to natural gas transportation and sales agreements, electric power supply agreements, insurance policies and certain other guarantees. At September 30, 2003, the fixed maximum amounts guaranteed under these agreements aggregated $43.7 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $6.5 million in 2003; $12.5 million in 2004; $5.0 million in 2005; $3.3 million in 2006; $900,000 in 2009; $12.0 million in 2012; $500,000, which is subject to expiration 30 days after the receipt of written notice and $3.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $202,000 and was reflected on the Consolidated Balance Sheets at September 30, 2003. 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 Exploration & Production Company (Fidelity), an indirect wholly owned subsidiary of the Company, 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 September 30, 2003, the fixed maximum amounts guaranteed under these agreements aggregated $22.0 million. Scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $2.0 million in 2005 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 $650,000, which was not reflected on the Consolidated Balance Sheets at September 30, 2003, because these intercompany transactions are eliminated in consolidation. In addition, Centennial has issued guarantees related to the Company's purchase of maintenance items to third parties 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 Sheets at September 30, 2003. As of September 30, 2003, Centennial was contingently liable for performance of certain of its subsidiaries under approximately $325 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. A large portion of these contingent commitments are expected to expire within the next twelve 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. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Company has 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. During the fourth quarter of 2002, the Company separated independent power production and other operations from its reportable segments. The independent power production and other operations do not individually meet the criteria to be considered a reportable segment. All prior period information has been restated to reflect this change. The electric and natural gas distribution segments include the electric and natural gas distribution operations of Montana-Dakota and the natural gas distribution operations of Great Plains Natural Gas Co. The utility services segment includes all the operations of Utility Services, Inc. The pipeline and energy services segment includes WBI Holdings' natural gas transportation, underground storage, gathering services, and energy related management services. The natural gas and oil production segment includes the natural gas and oil acquisition, exploration and production operations of WBI Holdings. The construction materials and mining segment includes the results of Knife River's operations, while independent power production and other operations include electric generating facilities in the United States and Brazil and investments in potential new growth opportunities that are not directly being pursued by the Company's other businesses. Earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from utility services, natural gas and oil production, construction materials and mining, and independent power production and other are all from nonregulated operations. On August 14, 2003, the Company's Board of Directors approved a three-for-two common stock split. For more information on the common stock split see Note 3 of Notes to Consolidated Financial Statements. Reference should be made to Notes to Consolidated Financial Statements for information pertinent to various commitments and contingencies. Overview The following table (dollars in millions, where applicable) summarizes the contribution to consolidated earnings by each of the Company's businesses. Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Electric $ 6.3 $ 4.5 $ 12.9 $ 9.6 Natural gas distribution (2.5) (2.6) .4 1.0 Utility services 1.7 1.6 4.3 3.8 Pipeline and energy services 4.6 5.8 14.1 13.3 Natural gas and oil production 16.5 6.9 46.1 37.4 Construction materials and mining 36.1 33.4 41.5 34.6 Independent power production and other 2.6 4.1 9.3 2.2 Earnings on common stock $ 65.3 $ 53.7 $128.6 $101.9 Earnings per common share - basic $ .58 $ .51 $ 1.16 $ .97 Earnings per common share - diluted $ .58 $ .50 $ 1.15 $ .96 Return on average common equity for the 12 months ended 13.4% 11.5% ________________________________ Three Months Ended September 30, 2003 and 2002 Consolidated earnings for the quarter ended September 30, 2003, increased $11.6 million from the comparable period a year ago due to higher earnings at the natural gas and oil production, construction materials and mining, electric, natural gas distribution and utility services businesses. Decreased earnings at the independent power production and other and pipeline and energy services businesses slightly offset the earnings increase. Nine Months Ended September 30, 2003 and 2002 Consolidated earnings for the nine months ended September 30, 2003, increased $26.7 million from the comparable period a year ago due to higher earnings at the natural gas and oil production, independent power production and other, construction materials and mining, electric, pipeline and energy services, and utility services businesses. Decreased earnings at the natural gas distribution business slightly offset the earnings increase. ________________________________ Financial and operating data The following tables (dollars in millions, where applicable) are key financial and operating statistics for each of the Company's businesses. Electric Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Operating revenues: Retail sales $ 40.0 $ 37.1 $ 110.7 $ 103.3 Sales for resale and other 7.9 4.4 21.0 14.6 47.9 41.5 131.7 117.9 Operating expenses: Fuel and purchased power 16.1 14.5 44.8 41.6 Operation and maintenance 12.6 10.8 38.9 33.7 Depreciation, depletion and amortization 5.1 4.8 15.0 14.6 Taxes, other than income 1.9 1.8 5.8 5.6 35.7 31.9 104.5 95.5 Operating income $ 12.2 $ 9.6 $ 27.2 $ 22.4 Retail sales (million kWh) 630.2 609.9 1,760.0 1,669.6 Sales for resale (million kWh) 212.7 153.6 587.1 580.0 Average cost of fuel and purchased power per kWh $ .018 $ .018 $ .018 $ .018 Natural Gas Distribution Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Operating revenues: Sales $ 26.8 $ 16.0 $ 178.1 $ 119.9 Transportation and other .9 .8 3.0 2.8 27.7 16.8 181.1 122.7 Operating expenses: Purchased natural gas sold 18.1 8.6 136.6 82.4 Operation and maintenance 9.7 8.5 31.4 27.0 Depreciation, depletion and amortization 2.4 2.4 7.6 7.2 Taxes, other than income 1.3 1.2 3.9 3.8 31.5 20.7 179.5 120.4 Operating income (loss) $ (3.8) $ (3.9)$ 1.6 $ 2.3 Volumes (MMdk): Sales 3.1 3.1 25.9 26.2 Transportation 2.8 2.5 8.8 8.9 Total throughput 5.9 5.6 34.7 35.1 Degree days (% of normal)* 92% 82% 100% 104% Average cost of natural gas, including transportation thereon, per dk $ 5.80 $ 2.73 $ 5.27 $ 3.14 _____________________ * Degree days are a measure of the daily temperature-related demand for energy for heating. Utility Services Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Operating revenues $116.1 $113.4 $ 328.7 $ 338.1 Operating expenses: Operation and maintenance 106.5 104.3 300.4 311.7 Depreciation, depletion and amortization 2.6 2.4 7.7 6.8 Taxes, other than income 3.6 3.1 11.4 10.8 112.7 109.8 319.5 329.3 Operating income $ 3.4 $ 3.6 $ 9.2 $ 8.8 Pipeline and Energy Services Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Operating revenues: Pipeline $ 24.2 $ 26.4 $ 74.7 $ 71.4 Energy services 37.2 1.2 104.1 42.4 61.4 27.6 178.8 113.8 Operating expenses: Purchased natural gas sold 36.5 .7 101.3 36.8 Operation and maintenance 11.0 10.4 34.8 34.4 Depreciation, depletion and amortization 3.8 3.7 11.2 11.0 Taxes, other than income 1.4 1.3 4.3 4.4 52.7 16.1 151.6 86.6 Operating income $ 8.7 $ 11.5 $ 27.2 $ 27.2 Transportation volumes (MMdk): Montana-Dakota 9.2 9.4 25.6 24.6 Other 13.7 20.5 44.3 52.4 22.9 29.9 69.9 77.0 Gathering volumes (MMdk) 18.8 18.8 56.4 52.4 Natural Gas and Oil Production Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Operating revenues: Natural gas $ 52.7 $ 30.2 $160.5 $ 87.8 Oil 12.2 11.9 37.9 33.1 Other --- .1 .2 27.4* 64.9 42.2 198.6 148.3 Operating expenses: Purchased natural gas sold --- --- .1 --- Operation and maintenance: Lease operating costs 8.4 7.5 22.9 20.2 Gathering and transportation 4.0 3.1 11.1 8.9 Other 3.7 4.1 12.5 12.7 Depreciation, depletion and amortization 15.3 12.3 44.6 35.2 Taxes, other than income: Production and property taxes 5.4 2.9 16.0 8.2 Other .1 .2 .4 .6 36.9 30.1 107.6 85.8 Operating income $ 28.0 $ 12.1 $ 91.0 $ 62.5 Production: Natural gas (MMcf) 13,470 12,219 40,367 34,571 Oil (000's of barrels) 453 486 1,380 1,469 Average realized prices (including hedges): Natural gas (per Mcf) $ 3.91 $ 2.48 $ 3.98 $ 2.54 Oil (per barrel) $26.86 $24.44 $27.48 $ 22.54 Average realized prices (excluding hedges): Natural gas (per Mcf) $ 4.26 $ 2.13 $ 4.42 $ 2.34 Oil (per barrel) $27.78 $25.63 $28.64 $ 22.68 Production costs, including taxes, per net equivalent Mcf $ 1.10 $ .89 $ 1.03 $ .86 _____________________ * Includes the effects of a compromise agreement gain of $27.4 million ($16.6 million after tax). Construction Materials and Mining Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Operating revenues $426.5 $378.6 $811.3 $ 701.5 Operating expenses: Operation and maintenance 338.3 299.1 668.9 581.7 Depreciation, depletion and amortization 16.4 14.9 46.6 39.5 Taxes, other than income 8.5 6.3 19.5 14.2 363.2 320.3 735.0 635.4 Operating income $ 63.3 $ 58.3 $ 76.3 $ 66.1 Sales (000's): Aggregates (tons) 14,119 13,155 28,738 25,600 Asphalt (tons) 3,647 3,745 5,510 5,732 Ready-mixed concrete (cubic yards) 1,161 951 2,588 2,145 Independent Power Production and Other Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Operating revenues $ 10.1 $ .8 $ 28.1 $ 2.5 Operating expenses: Operation and maintenance 4.1 1.7 11.3 4.4 Depreciation, depletion and amortization 2.1 .1 6.0 .2 6.2 1.8 17.3 4.6 Operating income (loss) $ 3.9* $ (1.0) $ 10.8*$ (2.1) Net generation capacity - kW** 279,600 --- 279,600 --- Electricity produced and sold (thousand kWh)** 103,816 --- 242,410 --- _____________________ * Reflects international operations for 2003 and domestic operations acquired on November 1, 2002 and January 31, 2003. ** Reflects domestic independent power production operations. NOTE: The earnings from the Company's equity method investment in Brazil were included in other income - net and, thus, are not reflected in the above table. Amounts presented in the preceding tables for operating revenues, purchased natural gas sold and operation and maintenance expense will not agree with the Consolidated Statements of Income due to the elimination of intersegment transactions. The amounts (dollars in millions) relating to the elimination of intersegment transactions are as follows: Three Months Nine Months Ended Ended September 30, September 30, 2003 2002 2003 2002 Operating revenues $ 38.5 $ 8.5 $ 126.2 $ 70.2 Purchased natural gas sold $ 34.7 $ 4.7 $ 114.4 $ 59.1 Operation and maintenance $ 3.8 $ 3.8 $ 11.8 $ 11.1 For further information on intersegment eliminations, see Note 15 of Notes to Consolidated Financial Statements. Three Months Ended September 30, 2003 and 2002 Electric Electric earnings increased as a result of higher sales for resale revenues due to higher average realized prices of 46 percent and higher volumes of 39 percent, both resulting from stronger sales for resale markets. Also contributing to the earnings increase were higher retail sales prices and higher retail sales volumes, primarily to residential and small commercial customers. Partially offsetting the earnings increase was higher operation and maintenance expense, primarily due to higher pension, medical, and payroll costs, and higher power plant maintenance costs. Natural Gas Distribution Normal seasonal losses at the natural gas distribution business decreased slightly as a result of higher retail sales rates, the result of increases in Minnesota, Montana, North Dakota and Wyoming. Largely offsetting the earnings increase was higher operation and maintenance expense, primarily due to higher pension, medical and payroll costs. The pass-through of higher natural gas prices is reflected in the increase in both sales revenues and purchased natural gas sold. For further information on the retail rate increases, see Note 17 of Notes to Consolidated Financial Statements in this Form 10-Q and Note 17 of Notes to Consolidated Financial Statements in the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003. Utility Services Utility services earnings increased slightly as a result of higher inside electrical margins in the Northwest and Central regions and higher line construction margins in the Northwest and Rocky Mountain regions, all at existing operations. Earnings from a company acquired since the comparable period last year also added to the earnings increase. Largely offsetting the earnings increase were lower line construction margins at existing operations in the Southwest and Central regions and higher selling, general and administrative expenses. Lower margins are a reflection of the continuing effects of the soft economy in this sector and the downturn in the telecommunications market. Pipeline and Energy Services Earnings at the pipeline and energy services business decreased as a result of lower transportation volumes, largely resulting from lower volumes transported to storage, and higher operation and maintenance costs due in part to higher compressor-related materials costs and property insurance costs. Partially offsetting the earnings decrease were higher transportation reservation fees resulting from an increase in firm services, lower financing-related costs and higher transportation and gathering rates. The increase in energy services revenues and the related increase in purchased natural gas sold include the effect of increases in natural gas prices since the comparable period last year. Natural Gas and Oil Production Natural gas and oil production earnings increased due to higher realized natural gas prices of 58 percent, higher natural gas production of 10 percent, largely resulting from enhanced natural gas production in the Rocky Mountain area, and higher average realized oil prices of 10 percent. Partially offsetting the earnings increase were increased depreciation, depletion and amortization expense due to higher natural gas production volumes and higher rates and increased operation and maintenance expense, primarily higher lease operating expenses due in part to increased natural gas production. Decreased oil production of 7 percent also partially offset the earnings increase. Construction Materials and Mining Construction materials and mining earnings increased due to earnings from companies acquired since the comparable period last year. Increased ready-mixed concrete volumes and margins and higher aggregate volumes, all at existing operations, also added to the increase in earnings. Partially offsetting the earnings increase were higher selling, general and administrative costs, lower asphalt volumes and margins, due in part to higher asphalt oil costs, and higher depreciation, depletion and amortization expense due to higher property, plant and equipment balances. Independent Power Production and Other Earnings for the independent power production business decreased due to lower net income at the Brazilian operations and higher interest expense resulting from higher debt balances related to domestic businesses acquired since the comparable period last year. Lower net income of $3.6 million from the Company's share of its equity investment in Brazil was due primarily to the effects of foreign currency exchange fluctuations, including their effect on the value of the embedded derivative in the electric power contract, offset in part by higher margins due to higher capacity revenues resulting from all four units being in operation compared to only two operational units (effective July 2002) for the same period in 2002. Partially offsetting the earnings decrease were earnings from domestic businesses acquired since the comparable period last year. Nine Months Ended September 30, 2003 and 2002 Electric Electric earnings increased as a result of higher retail sales revenues, due in part to higher retail sales volumes, largely to residential, commercial and large industrial customers. Higher average sales for resale prices of 48 percent and higher sales for resale volumes, both due to stronger sales for resale markets, also added to the increase in earnings. Partially offsetting the earnings increase was higher operation and maintenance expense, largely higher payroll costs, higher costs related to planned maintenance outages at two generating stations, and higher pension and medical costs. Increased fuel and purchased power costs also partially offset the earnings increase. Natural Gas Distribution Earnings at the natural gas distribution business decreased as a result of higher operation and maintenance expense, primarily due to higher payroll, pension and medical costs, and decreased returns on natural gas held in storage. Partially offsetting the earnings decline were higher retail sales rates, the result of increases in Minnesota, Montana, North Dakota and Wyoming, as previously discussed. The pass-through of higher natural gas prices is reflected in the increase in both sales revenues and purchased natural gas sold. Utility Services Utility services earnings increased as a result of the absence in 2003 of a 2002 write-off of receivables of $1.4 million (after tax) associated with a company in the telecommunications industry and the absence in 2003 of a 2002 unfavorable settlement of a billing dispute of $724,000 (after tax) in the Central Region. Higher line construction margins in the Northwest and Rocky Mountain regions and higher equipment sale margins also added to the increase in earnings. Partially offsetting the earnings increase were lower line construction margins in the Southwest and Central regions, lower margins in the telecommunications industry in the Rocky Mountain region and lower inside electrical margins in the Northwest and Central regions. Lower margins are a reflection of the continuing effects of the soft economy in this sector and the downturn in the telecommunications market. Pipeline and Energy Services Earnings at the pipeline and energy services business increased as a result of higher gathering volumes of 8 percent, lower financing-related costs and increased storage revenues. Partially offsetting the earnings increase was higher operation and maintenance costs, primarily higher payroll and property insurance costs. The increase in energy services revenues and the related increase in purchased natural gas sold include the effect of increases in natural gas prices since the comparable period last year. Natural Gas and Oil Production Natural gas and oil production earnings increased due to higher realized natural gas prices of 57 percent, higher natural gas production of 17 percent, largely resulting from enhanced natural gas production in the Rocky Mountain area, and higher average realized oil prices of 22 percent. Largely offsetting the earnings increase were the 2002 compromise agreement gain of $27.4 million ($16.6 million after tax) which was included in 2002 operating revenues, and the $12.7 million ($7.7 million after tax) noncash transition charge in 2003, reflecting the cumulative effect of an accounting change, as discussed in Note 18 and Note 8 of Notes to Consolidated Financial Statements, respectively. Also partially offsetting the earnings increase were increased depreciation, depletion and amortization expense due to higher natural gas production volumes and higher rates, and increased operation and maintenance expense, primarily higher lease operating expenses resulting largely from the expansion of coalbed natural gas production. Decreased oil production of 6 percent, higher interest expense, due primarily to higher average debt balances, and higher general and administrative costs, also partially offset the earnings increase. Construction Materials and Mining Construction materials and mining earnings increased due to increased aggregate volumes and margins, increased ready-mix concrete volumes and margins, and higher construction activity primarily due to a large harbor-deepening project in southern California, all at existing operations. Earnings from companies acquired since the comparable period last year also added to the earnings increase. Partially offsetting the increase in earnings were higher selling, general and administrative costs and lower asphalt volumes and margins due in part to higher asphalt oil costs. Higher depreciation, depletion and amortization expense primarily due to higher aggregate volumes produced and higher property, plant and equipment balances also partially offset the earnings increase. Independent Power Production and Other Earnings for the independent power production business increased largely from the domestic businesses acquired since the comparable period last year, partially offset by higher interest expense, resulting from higher average debt balances relating to these acquisitions. Partially offsetting the earnings increase was lower net income of $477,000 from the Company's share of its equity investment in Brazil due primarily to the mark-to-market loss on an embedded derivative in the electric power contract and higher interest expense due to a full nine months of debt in 2003, offset by higher margins due to higher capacity revenues, as previously discussed. 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 recent events leading to the current adverse economic environment may have a general negative impact on the Company's future revenues and may result in a goodwill impairment for Innovatum, Inc., an indirect wholly owned subsidiary of the Company (Innovatum). In response to the occurrence of several recent events, including the September 11, 2001, terrorist attack on the United States, the ongoing war against terrorism by the United States and the bankruptcy of several large energy and telecommunications companies and other large enterprises, the financial markets have been highly volatile. An adverse economy could negatively affect the level of governmental expenditures on public projects and the timing of these projects which, in turn, would negatively affect the demand for the Company's products and services. Innovatum, which specializes in cable and pipeline magnetization and locating, is subject to the economic conditions within the telecommunications and energy industries. Innovatum could face a future goodwill impairment if there is a continued downturn in these sectors. At September 30, 2003, the goodwill amount at Innovatum was approximately $8.3 million. The determination of whether an impairment will occur is dependent on a number of factors, including the level of spending in the telecommunications and energy industries, the success of a newly developed hand-held locating device at Innovatum, rapid changes in technology, competitors and potential new customers. The Company relies on financing sources and capital markets. The Company's inability to access financing may impair 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. 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 the 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 - Capital market conditions generally - Volatility in commodity prices - Terrorist attacks - Global events The Company's natural gas and oil production business is dependent on factors, including commodity prices, which cannot be predicted or controlled. These factors include: price fluctuations in natural gas and crude oil prices; availability of economic supplies of natural gas; drilling successes in natural gas and oil operations; 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. Environmental and Regulatory Risks Some of the Company's operations are subject to extensive environmental laws and regulations that may increase its costs of operations, impact or limit its business plans, or expose the Company to environmental liabilities. One of the Company's subsidiaries has been sued in connection with its coalbed natural gas development activities. 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, as a result of 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. Both public officials and private individuals may seek 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. Fidelity has been named as a defendant in, and/or certain of its operations are the subject of, several lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material effect on Fidelity's existing coalbed natural gas operations and/or its future development of its coalbed natural gas properties. The Company is subject to extensive government regulations that may 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 the Company's Independent Power Production Business The 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 or other material agreements, as well as the risk of performance below expected levels of output or efficiency. The Company is finalizing plans for the construction of a 113- megawatt coal-fired development project in Hardin, Montana. Based on demand and power pricing in the Northwest, the plant will be built on a merchant basis. Unanticipated events could delay completion of construction, start-up and/or operation of the project. Changes in the market price for power from the Company's projections could also negatively impact earnings to be derived from the project. Risks Relating to Foreign Operations The value of the Company's investment in foreign operations may diminish due to political, regulatory and economic conditions and changes in currency exchange rates in countries where the Company does business. The Company is subject to political, regulatory and economic conditions and changes in currency exchange rates in foreign countries where the Company does business. Significant changes in the political, regulatory or economic environment in these countries could negatively affect the value of the Company's investments located in these countries. Also, since the Company is unable to predict the fluctuations in the foreign currency exchange rates, these fluctuations may have an adverse impact on the Company's results of operations. The Company's 49 percent equity method investment in a 220- megawatt natural gas-fired electric generation project in Brazil includes a power purchase agreement that contains an embedded derivative. This embedded derivative derives its value from an annual adjustment factor that largely indexes the contract capacity payments to the U.S. dollar. In addition, from time to time, other derivative instruments may be utilized. The valuation of these financial instruments, including the embedded derivative, can involve judgments, uncertainties and the use of estimates. As a result, changes in the underlying assumptions could affect the reported fair value of these instruments. These instruments could recognize financial losses as a result of volatility in the underlying fair values, or if a counterparty fails to perform. 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 industry includes numerous strong and capable competitors, many 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. 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 generation 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 activities for the pipeline and energy services and natural gas and oil production businesses. In addition, severe weather can be destructive, causing outages 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 over the next few years 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 should be 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 the other factors 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 2003, diluted, before the cumulative effect of the change in accounting for asset retirement obligations as required by the adoption of SFAS No. 143, are projected in the range of $1.46 to $1.63. Including the $7.6 million after-tax cumulative effect of the accounting change, 2003 earnings per common share, diluted, are projected to be in the range of $1.40 to $1.57. - Earnings per common share for 2004, diluted, are projected in the range of $1.50 to $1.63. - The Company will consider issuing equity from time to time to keep debt at the nonregulated businesses at no more than 40 percent of total capitalization. - Excluding unidentified future acquisitions, the Company anticipates investing approximately $375 million in capital expenditures during 2004. - The Company's long-term compound annual growth goals on earnings per share from operations are in the range of 6 percent to 9 percent. Electric - 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. As franchises expire, Montana-Dakota may face increasing competition in its service areas, particularly its service to smaller towns, from rural electric cooperatives. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises and will continue to take steps to effectively operate in an increasingly competitive environment. - Montana-Dakota filed an application with the NDPSC seeking an increase in electric retail rates of 9.1 percent above current rates. While Montana-Dakota believes that it should be authorized to increase retail rates in the amount requested, there is no assurance that the increase ultimately allowed will be for the full amount requested in the jurisdiction. For further information on the electric rate increase application, see Note 17 of Notes to Consolidated Financial Statements. - In August 2003, an electric rate case was filed with the Montana Public Service Commission (MTPSC) requesting an increase of $3.3 million annually, or 10.7 percent. This case was recently withdrawn due to concerns expressed by the MTPSC and the Montana Consumer Council related to the case test period. It is the Company's intent to file a new case. - Regulatory approval has been received from the North Dakota Public Service Commission and the South Dakota Public Utilities Commission on the Company's plans to purchase energy from a 20- megawatt wind energy farm in North Dakota. This wind energy farm is expected to be on line early to mid 2004. - The Company expects to build or acquire an additional 80 megawatts of capacity in the 2007 through 2009 timeframe. The costs of these projects are expected to be recovered in rates and will be used to meet the utility's need for additional generating capacity. - The Company is working with the state of North Dakota to determine the feasibility of constructing a 250-megawatt to 500- megawatt lignite-fired power plant in western North Dakota. The next preliminary decision on this matter is expected later this year. - Montana-Dakota has joined with two electric generators in appealing a finding by the North Dakota Department of Health (Department) in September 2003 that the 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 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 on October 8, 2003, in the Burleigh County District Court in Bismarck, North Dakota. In a related case, the Dakota Resource Council filed an action in Federal District Court in Denver, Colorado on September 30, 2003, to require the Environmental Protection Agency (EPA) to enforce certain air quality standards in North Dakota. If successful, the action could require the curtailment of discharges of sulfur dioxide into the atmosphere by existing electric generating facilities and could preclude or hinder the construction of future generating facilities in North Dakota. The Company is currently assessing the merits of this lawsuit and may file a motion to intervene. The Company cannot predict the outcome of these matters or their ultimate impact on its operations. Natural gas distribution - 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. As franchises expire, Montana-Dakota and Great Plains may face increasing competition in their service areas. Montana-Dakota and Great Plains intend to protect their service areas and seek renewal of all expiring franchises and will continue to take steps to effectively operate in an increasingly competitive environment. - Annual natural gas throughput for 2003 and 2004 is expected to be approximately 52 million decatherms per year. - Montana-Dakota filed an application with the SDPUC seeking an increase in natural gas retail rates of $2.2 million annually or 5.8 percent above current rates. On October 27, 2003, Montana-Dakota and the SDPUC staff filed a Settlement Stipulation with the SDPUC agreeing to an increase of $1.3 million annually. Great Plains filed an application with the MPUC seeking an increase in natural gas retail rates of $1.6 million or 6.9 percent above current rates. On October 9, 2003, the MPUC issued a Final Order authorizing an increase of $1.1 million annually. For further information on the natural gas rate increase applications, see Note 17 of Notes to Consolidated Financial Statements. Utility services - Revenues for this segment are expected to be in the range of $425 million to $475 million in 2003 and $450 million to $500 million in 2004. - This segment anticipates margins in 2003 to decrease from 2002 levels; however, margins are anticipated to increase in 2004 as compared to projected 2003 levels. Pipeline and energy services - In 2003, natural gas throughput from this segment, including both transportation and gathering, is expected to be comparable to 2002 record levels. In 2004, total throughput is expected to increase approximately 25 percent over projected 2003 levels largely due to the Grasslands Pipeline being in service. Transportation rates are expected to decline due to the estimated effects of a FERC rate order received in July 2003. - Pipeline construction began in mid-August on the 253-mile Grasslands Pipeline project. The in-service date for this project is expected to be in the late-November to December 1, 2003, timeframe. - Innovatum could face a future goodwill impairment based on certain economic conditions, as previously discussed in Risk Factors and Cautionary Statements that May Affect Future Results. Innovatum recently developed a hand-held locating device that can detect both magnetic and plastic materials. One of the possible uses for this product would be in the detection of unexploded ordnance (land mines). Innovatum is in the preliminary stages of working with and demonstrating the device to a Department of Defense contractor and has met with individuals from the Department of Defense. This potential new market may mitigate the possibility of a goodwill impairment. Natural gas and oil production - In 2003, this segment expects a combined natural gas and oil production increase of approximately 10 percent to 12 percent over record 2002 levels. In 2004, the Company expects a combined production increase of approximately 10 percent over projected 2003 levels. Currently, this segment's gross daily operated natural gas production is approximately 130,000 to 140,000 Mcf per day. - This segment continues to expand its operated production. Natural gas production from operated properties was 73 percent and 67 percent of total production for the nine months ended September 30, 2003 and 2002, respectively. - This segment expects to drill more than 400 wells in 2003 and approximately 400 wells in 2004. - This segment had approximately 185 wells in process related to its coalbed natural gas development in the Powder River Basin in Montana and Wyoming that were not producing natural gas or water at September 30, 2003, but may begin producing either natural gas or water in the future. - Estimates for average natural gas prices in the Rocky Mountain region for November and December 2003, reflected in the Company's 2003 earnings guidance, are in the range of $3.50 to $4.00 per Mcf. The Company's estimates for natural gas prices on the NYMEX for November and December 2003, reflected in the Company's 2003 earnings guidance, are in the range of $4.25 to $4.75 per Mcf. During 2002, more than half of this segment's natural gas production was priced using Rocky Mountain or other non-NYMEX prices. - For 2004, the Company's estimate for natural gas prices in the Rocky Mountain region are in the range of $3.00 to $3.50 per Mcf, and estimates for natural gas prices on the NYMEX are in the range of $4.00 to $4.25 per Mcf. - Estimates of NYMEX crude oil prices for October through December 2003, reflected in the Company's 2003 earnings guidance, are in the range of $22 to $27 per barrel. - Estimates of NYMEX crude oil prices for 2004 are projected in the range of $24 to $28 per barrel. - The Company has hedged a portion of its 2003 production primarily using collars that establish both a floor and a cap. The Company has entered into agreements representing approximately 45 percent to 50 percent of 2003 estimated annual natural gas production. The agreements are at various indices and range from a low CIG index of $2.94 to a high Ventura index of $4.76 per Mcf. CIG is an index pricing point related to Colorado Interstate Gas Co.'s system and Ventura is an index pricing point related to Northern Natural Gas Co.'s system. - The Company has hedged a portion of its 2003 oil production. The Company has entered into agreements at NYMEX prices with floors of $24.50 and caps as high as $28.12, representing approximately 30 percent to 35 percent of 2003 estimated annual oil production. - The Company has hedged a portion of its 2004 estimated annual natural gas production. The Company has entered into agreements representing approximately 10 percent to 15 percent of 2004 estimated annual natural gas production. The agreements are at various indices and range from a low CIG index of $3.75 to a high NYMEX index of $5.20 per Mcf. - Fidelity has been named as a defendant in, and/or certain of its operations are the subject of, several lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. In one such case, the United States District Court in Billings, Montana (U.S. District Court) held that water produced in association with coalbed natural gas and discharged into rivers and streams was not a pollutant under the Federal Clean Water Act and that state statutes exempt such unaltered groundwater from Montana Pollution Discharge Elimination System permit requirements. On April 10, 2003, the United States Circuit Court of Appeals for the Ninth Circuit (Circuit Court) reversed the U.S. District Court's decision. Fidelity filed a petition for a writ of certiorari with the United States Supreme Court (Supreme Court) on August 8, 2003. The Supreme Court denied Fidelity's petition for certiorari on October 20, 2003. The Supreme Court's decision has the effect of remanding the case to the U.S. District Court for trial on the remaining issues. Fidelity believes the ultimate outcome of the proceeding will not have a material effect on its existing coalbed natural gas operations or on the future development of its coalbed natural gas properties. In the event a penalty is ultimately imposed in that proceeding, Fidelity believes it will be minimal because any unpermitted discharges were of small amounts, were for a short duration and are now fully permitted. Fidelity believes the ultimate outcome of other lawsuits filed in connection with its coalbed natural gas development could have a material effect on its existing coalbed natural gas operations and/or its future development of its coalbed natural gas properties. For further information on these proceedings, see Risk Factors and Cautionary Statements that May Affect Future Results in this Form 10-Q. Construction materials and mining - Excluding the effects of unidentified future acquisitions, aggregate and ready-mixed concrete volumes in 2003 are expected to increase over record levels achieved in 2002, while asphalt volumes are expected to be comparable to 2002 levels. Ready-mixed concrete and aggregate volumes in 2004 are expected to be comparable to projected 2003 levels, while asphalt volumes are expected to increase over those projected for 2003. - Revenues for this segment in 2003 are expected to increase by approximately 10 percent to 15 percent as compared to 2002 record levels. Revenues in 2004 are expected to increase by approximately 5 percent to 10 percent over projected 2003 levels. - Four of the five labor contracts that Knife River was negotiating, as reported in Items 1 and 2 - Business and Properties - General in the Company's 2002 Form 10-K, have been ratified and the one remaining contract is being negotiated. The Company considers its relations with its employees to be satisfactory. Independent power production and other - Earnings projections in 2003 and 2004 for independent power production and other operations include the estimated results from the wind-powered electric generation facility in California, the natural gas-fired generating facilities in Colorado, and the Company's 49-percent ownership in a 220-megawatt natural gas-fired generation project in Brazil. Earnings are expected to be in the range of $9 million to $14 million in 2003 and $18 million to $23 million in 2004. - The Company is finalizing plans for the construction of a 113- megawatt coal-fired development project in Hardin, Montana, as previously discussed in Risk Factors and Cautionary Statements that May Affect Future Results. Efforts will continue towards securing a contract for the off-take of the plant. The Company is optimistic that this plant will be under contract by the time of plant completion. The projected plant on-line date for this project is late 2005. New Accounting Standards In the third quarter of 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 three months and nine months ended September 30, 2003, was $53,000 (after tax). In June 2001, the FASB approved SFAS No. 141, "Business Combinations," which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In June 2001, the FASB also approved SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS No. 141 and SFAS No. 142 clarify that more assets should be distinguished and classified between tangible and intangible. The Company did not change or reclassify contractual mineral rights included in property, plant and equipment related to its natural gas and oil production business upon adoption of SFAS No. 142. The Company has included such mineral rights as part of property, plant and equipment under the full cost method of accounting for natural gas and oil properties. An issue has arisen within the natural gas and oil industry as to whether contractual mineral rights under SFAS No. 142 should be classified as intangible rather than as part of property, plant and equipment. This accounting matter is anticipated to be addressed by the FASB's Emerging Issues Task Force. The resolution of this matter may result in certain reclassifications of amounts in the Company's Consolidated Balance Sheets, as well as changes to the Company's Notes to Consolidated Financial Statements in the future. The applicable provisions of SFAS No. 141 and SFAS No. 142 only affect the balance sheet and associated footnote disclosure, so any reclassifications that might be required in the future will not affect the Company's cash flows or results of operations. The Company believes that the resolution of this matter will not have a material effect on the Company's financial position because the mineral rights acquired by its natural gas and oil production business after the June 30, 2001, effective date of SFAS No. 142 are not material. In June 2001, the FASB approved SFAS No. 143, "Accounting for Asset Retirement Obligations." Upon adoption of SFAS No. 143, the Company recorded an additional discounted liability of $22.5 million and a regulatory asset of $493,000, increased net property, plant and equipment by $9.6 million and recognized a one-time cumulative effect charge of $7.6 million (net of deferred tax benefit of $4.8 million). In April 2002, the FASB approved SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." The adoption of SFAS No. 145 did not have a material effect on the Company's financial position or results of operations. In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including indirect Guarantees of Indebtedness of Others" (FIN 45). The Company is applying the initial recognition and initial measurement provisions of FIN 45 to guarantees issued or modified after December 31, 2002. In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 was effective for the first fiscal year or interim period beginning after June 15, 2003, for variable interest entities created before February 1, 2003. However, in October 2003, the FASB issued FASB Staff Position No. FIN 46-6 which defers the required effective date until the end of the first interim or annual period ending after December 15, 2003, for interests held in a variable interest entity or potential variable interest entity that was created before February 1, 2003, provided that financial statements have not been issued reporting that variable interest entity in accordance with FIN 46. The deferral of the effective date of FIN 46 did not have an effect on the Company's financial position or results of operations. The adoption of FIN 46 did not have a material effect on the Company's financial position or results of operations. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material effect on the Company's financial position or results of operations. In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." The Company will apply SFAS No. 150 to any financial instruments entered into or modified after May 31, 2003. Beginning with the third quarter of 2003, the Company reported its preferred stock subject to mandatory redemption as a liability in accordance with SFAS No. 150. The transition to SFAS No. 150 did not have a material effect on the Company's financial position or results of operations. For further information on SFAS No. 123, SFAS No. 143, SFAS No. 145, FIN 45, FIN 46, SFAS No. 149 and SFAS No. 150, see Note 8 of Notes to Consolidated Financial Statements. Critical Accounting Policies The Company's critical accounting policies include impairment of long-lived assets and intangibles, impairment testing of natural gas and oil properties, revenue recognition, derivatives, purchase accounting, accounting for the effects of regulation and use of estimates. There are no material changes in the Company's critical accounting policies from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. For more information on critical accounting policies, see Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. Liquidity and Capital Commitments Cash flows Operating activities -- Cash flows provided by operating activities in the first nine months of 2003 increased $76.6 million from the comparable 2002 period, the result of an increase in cash from net income of $26.6 million and higher depreciation, depletion and amortization expense of $24.2 million, resulting largely from increased property, plant and equipment balances and higher mineral production volumes. Higher deferred income taxes and investment tax credits of $11.7 million and the cumulative effect of an accounting change of $7.6 million also added to the increase in cash flows provided by operating activities. Investing activities -- Cash flows used in investing activities in the first nine months of 2003 increased $103.5 million compared to the comparable 2002 period, the result of an increase in net capital expenditures (capital expenditures; acquisitions, net of cash acquired; and net proceeds from the sale or disposition of property) of $114.4 million, slightly offset by an increase in investments of $7.1 million and proceeds from notes receivable of $3.8 million. Net capital expenditures exclude the noncash transactions related to acquisitions, including the issuance of the Company's equity securities. The noncash transactions were $40.1 million and $46.0 million for the first nine months of 2003 and 2002, respectively. Financing activities -- Cash flows provided by financing activities in the first nine months of 2003 increased $50.3 million compared to the comparable 2002 period, due to an increase in the issuance of long-term debt of $175.0 million. The increase in the repayment of long-term debt of $91.3 million and the net decrease of short-term borrowings of $30.0 million, partially offset the increase in cash provided by financing activities. 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. Pretax pension income reflected in the years ended December 31, 2002 and 2001 was $2.4 million and $4.4 million, respectively. The Company's pension expense is expected to be less than $1.0 million in 2003 and is currently projected to be approximately $4.0 million to $5.0 million in 2004. Persistent declines in the equity markets and a reduction in the Company's assumed discount rate for Pension Plans have combined to largely produce the increase in these costs. Funding for the Pension Plans is actuarially determined. The minimum required contributions for 2002 and 2001 were approximately $1.2 million and $440,000, respectively. The minimum required contribution for 2003 is approximately $1.6 million and is currently projected to be approximately $2.5 million to $3.0 million for 2004. For further information on the Company's Pension Plans, see Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. Capital expenditures Net capital expenditures, including the issuance of the Company's equity securities, for the first nine months of 2003 were $376.3 million and are estimated to be approximately $510 million for the year 2003. Estimated capital expenditures include those for: - Completed acquisitions - System upgrades, including a 40-megawatt natural gas-fired peaking unit - Routine replacements - Service extensions - Routine equipment maintenance and replacements - Land and building improvements - Pipeline and gathering expansion projects, including a 253-mile pipeline, as previously discussed - The further enhancement of natural gas and oil production and reserve growth - Power generation opportunities, including certain construction costs for a 113-megawatt coal-fired development project, as previously discussed - Other growth opportunities Approximately 34 percent of estimated 2003 net capital expenditures are for completed acquisitions. The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, actual acquisitions and capital expenditures may vary significantly from the estimated 2003 capital expenditures referred to above. It is anticipated that the funds required for capital expenditures will be met from various sources. These sources include internally generated funds, commercial paper credit facilities at Centennial and MDU Resources, as described below, and through the issuance of long-term debt and the Company's equity securities. The estimated 2003 capital expenditures referred to above include completed 2003 acquisitions involving construction materials and mining businesses in Montana, North Dakota and Texas and a wind- powered electric generation facility in California. 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. Capital resources Certain debt instruments of the Company and its subsidiaries, including those discussed below, contain restrictive covenants, all of which the Company and its subsidiaries were in compliance with at September 30, 2003. MDU Resources Group, Inc. The Company has a revolving credit agreement with various banks totaling $90 million at September 30, 2003. There were no amounts outstanding under the credit agreement at September 30, 2003. The credit agreement supports the Company's $75 million commercial paper program. Under the Company's commercial paper program, $50.0 million was outstanding at September 30, 2003. The commercial paper borrowings are classified as long-term debt as the Company intends to refinance these borrowings on a long-term basis through continued commercial paper borrowings and as further supported by the credit agreement, which expires on July 18, 2006. 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 of approximately $75,000 (after tax) based on September 30, 2003, variable rate borrowings. Based on the Company's overall interest rate exposure at September 30, 2003, this change would not have a material effect on the Company's results of operations or cash flows. Prior to the maturity of the credit agreement, the Company plans to negotiate the extension or replacement of this agreement that provides credit support to access the capital markets. In the event the Company was 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. The significant covenants include maximum leverage ratios, minimum interest coverage ratio, limitation on sale of assets and limitation on investments. The Company was in compliance with these covenants and met the required conditions at September 30, 2003. 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. Currently, 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 pledge $1.43 of unfunded property to the trustee for each dollar of indebtedness incurred under the Indenture and 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 two tests, as of September 30, 2003, the Company could have issued approximately $338 million of additional first mortgage bonds. The Company's coverage of fixed charges including preferred dividends was 4.9 times and 4.8 times for the twelve months ended September 30, 2003 and December 31, 2002, respectively. Additionally, the Company's first mortgage bond interest coverage was 8.6 times and 7.7 times for the twelve months ended September 30, 2003 and December 31, 2002, respectively. Common stockholders' equity as a percent of total capitalization was 58 percent and 60 percent at September 30, 2003 and December 31, 2002, respectively. Centennial Energy Holdings, Inc. Centennial has two revolving credit agreements with various banks that support $275 million of Centennial's $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at September 30, 2003. Under the Centennial commercial paper program, $76.6 million was outstanding at September 30, 2003. 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. The Centennial credit agreements are for $137.5 million each. One of these agreements expires on September 3, 2004, and allows for subsequent borrowings up to a term of one year. The other agreement expires on September 5, 2006. Centennial intends to negotiate the extension or replacement of these agreements prior to their maturities. Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $400 million. Under the terms of the master shelf agreement, $384.6 million was outstanding at September 30, 2003. 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 $115,000 (after tax) based on September 30, 2003, variable rate borrowings. Based on Centennial's overall interest rate exposure at September 30, 2003, 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 that 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. The significant covenants include maximum capitalization ratios, minimum interest coverage ratios, 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 September 30, 2003. 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 September 30, 2003. 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. The significant covenants include limitation on consolidated indebtedness, 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 September 30, 2003. In the event Williston Basin does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. Contractual obligations and commercial commitments There are no material changes in the Company's contractual obligations on operating leases and purchase commitments from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. The Company's contractual obligations on long-term debt at September 30, 2003, increased $155.1 million or 18 percent from December 31, 2002, primarily due to acquisitions and other corporate purposes. At September 30, 2003, the Company's commitments under these obligations for the twelve months ended September 30, were as follows: 2004 2005 2006 2007 2008 Thereafter Total (In millions) Long-term debt $7.9 $91.7 $212.1 $120.7 $130.2 $434.1 $996.7 For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. Centennial has financial guarantees outstanding at September 30, 2003. These guarantees pertain to Centennial's guarantee of certain obligations in connection with the natural gas-fired electric generation station in Brazil and as of September 30, 2003, are approximately $64.5 million. As of September 30, 2003, with respect to these guarantees, there was approximately $47,000 outstanding through 2003, $19.1 million outstanding through 2006 and $45.3 million outstanding through 2008. These guarantees are not reflected on the Consolidated Balance Sheets. For more information on these guarantees, see Note 18 of Notes to Consolidated Financial Statements. As of September 30, 2003, Centennial was contingently liable for performance of certain of its subsidiaries under approximately $325 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. A large portion of these contingent commitments are expected to expire within the next twelve 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. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to the impact of market fluctuations associated with commodity prices, interest rates and foreign currency. The Company has policies and procedures to assist in controlling these market risks and utilizes derivatives to manage a portion of its risk. Commodity price risk -- A subsidiary of the Company 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 the subsidiary's forecasted sales of natural gas and oil production. For more information on commodity price risk, see Part II, Item 7A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, and Note 12 of Notes to Consolidated Financial Statements in this Form 10-Q. The following table summarizes hedge agreements entered into by a subsidiary of the Company, as of September 30, 2003. These agreements call for the subsidiary to receive fixed prices and pay variable prices. (Notional amount and fair value in thousands) Weighted Average Notional Fixed Price Amount (Per MMBtu) (In MMBtu's) Fair Value Natural gas swap agreements maturing in 2003 $ 4.14 559 $ (209) Natural gas swap agreements maturing in 2004 $ 4.96 3,660 $ 762 Weighted Average Floor/Ceiling Notional Price Amount (Per MMBtu) (In MMBtu's) Fair Value Natural gas collar agreements maturing in 2003 $3.33/$3.89 5,637 $ (4,075) Natural gas collar agreements maturing in 2004 $4.04/$4.48 3,111 $ (597) Weighted Average Floor/Ceiling Notional Price Amount (Per barrel) (In barrels) Fair Value Oil collar agreements maturing in 2003 $24.50/$27.62 161 $ (277) Interest rate risk -- There are no material changes to interest rate risk faced by the Company from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. For more information on interest rate risk, see Part II, Item 7A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. Foreign currency risk -- MDU Brasil has a 49 percent equity investment in a 220-megawatt natural gas-fired electric generation project (Project) in Brazil, which has a portion of its borrowings and payables denominated in U.S. dollars. MDU Brasil has exposure to currency exchange risk as a result of fluctuations in currency exchange rates between the U.S. dollar and the Brazilian real. The functional currency for the Project is the Brazilian real. For further information on this investment, see Note 10 of Notes to Consolidated Financial Statements. MDU Brasil's equity income from this Brazilian investment is impacted by fluctuations in currency exchange rates on transactions denominated in a currency other than the Brazilian real, including the effects of changes in currency exchange rates with respect to the Project's U.S. dollar denominated obligations, excluding a U.S. dollar denominated loan from Centennial Energy Resources International Inc. (Centennial International), an indirect wholly owned subsidiary of the Company, as discussed below. At September 30, 2003, these U.S. dollar denominated obligations approximated $71.8 million. If, for example, the value of the Brazilian real decreased in relation to the U.S. dollar by 10 percent, MDU Brasil, with respect to its interest in the Project, would record a foreign currency transaction loss in net income of approximately $3.2 million (after tax) based on the above U.S. dollar denominated obligations at September 30, 2003. The Project also had US$7.4 million of Brazilian real denominated obligations at September 30, 2003. Adjustments attributable to the translation from the Brazilian real to the U.S. dollar for assets, liabilities, revenues and expenses were recorded in accumulated other comprehensive income (loss) at September 30, 2003. Foreign currency translation adjustments on the Project's U.S. dollar denominated borrowings payable to the subsidiary of $20.0 million at September 30, 2003, are recorded in accumulated other comprehensive income (loss). The investment of Centennial International in this Project at September 30, 2003, was $20.6 million. Centennial has guaranteed Project obligations and loans of approximately $64.5 million as of September 30, 2003. A portion of the Project's foreign currency exchange risk is being managed through contractual provisions, which are largely indexed to the U.S. dollar, contained in the Project's power purchase agreement with Petrobras. In addition, the Project is utilizing foreign currency derivatives. At September 30, 2003, the Project had foreign currency forward contracts with a notional amount of approximately $2.3 million at a weighted average rate of R$3.115, which expired on October 15, 2003, and approximately $4.5 million at a weighted average rate of R$3.125, which expire on November 17, 2003. The Company's 49 percent share of the fair value of these forward contracts at September 30, 2003, was approximately $162,000. 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 that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. The Company's chief executive officer and chief financial officer have evaluated the effectiveness of the Company's disclosure controls and procedures as of the period covered by this report, and, they have concluded that, as of this period, such controls and procedures were effective to accomplish those tasks. Changes in internal controls The Company maintains a system of internal accounting controls that are 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 reasonable likely to materially affect, the Company's internal control over financial reporting. PART II -- OTHER INFORMATION ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS Between July 1, 2003 and September 30, 2003, and prior to the common stock split, the Company issued 1,234,357 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 a business acquired during this period and as a final adjustment with respect to an acquisition in a prior 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. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a) Exhibits 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 b) Reports on Form 8-K Form 8-K was filed on September 10, 2003. Under Item 5 -- Other Events and Regulation FD Disclosure and Item 7 -- Financial Statements and Exhibits, the Company reported the press release issued September 9, 2003, regarding earnings guidance for 2003 and 2004. Form 8-K was filed on July 24, 2003. Under Item 7 -- Financial Statements, Pro Forma Financial Information and Exhibits and Item 9 -- Regulation FD Disclosure, the Company reported the press release issued July 24, 2003, regarding earnings for the quarter ended June 30, 2003. 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: November 13, 2003 BY: /s/ Warren L. Robinson Warren L. Robinson Executive Vice President, Treasurer and Chief Financial Officer BY: /s/ Vernon A. Raile Vernon A. Raile Senior Vice President and Chief Accounting Officer EXHIBIT INDEX Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends 31(a) Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes - Oxley Act of 2002 31(b) Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes - Oxley Act of 2002 32 Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002