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, 2001 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 the number of shares outstanding of each of the issuer's classes of common stock, as of October 19, 2001: 69,147,245 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 should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 -- Management's Discussion and Analysis of Financial Condition and Results of Operations -- Safe Harbor for Forward-looking Statements. 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. MDU Resources Group, Inc. (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, distributes natural gas and provides related value- added products and services in Montana, North Dakota, South Dakota and Wyoming. Great Plains Natural Gas Co. (Great Plains), another public utility division of the company, distributes natural gas in southeastern North Dakota and western Minnesota. 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) and Centennial Holdings Capital Corp. (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 in the Rocky Mountain, Midwest, Southern and Central regions of the United States and provides energy- related marketing and management services. The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration and production primarily in the Rocky Mountain region of the United States and in the Gulf of Mexico. Knife River mines and markets aggregates and related value- added construction materials products and services in Alaska, California, Hawaii, Minnesota, Montana, Oregon, Washington and Wyoming. Utility Services is a diversified infrastructure construction company specializing in electric, natural gas and telecommunication utility construction as well as interior industrial electrical, exterior lighting and traffic signalization. Utility Services has engineering, design and build capability and provides related specialty equipment sales and rental services throughout most of the United States. Centennial Capital invests in new growth and synergistic opportunities which are not directly being pursued by the existing business units but which are consistent with the company's philosophy and growth strategy. The company, through its wholly owned subsidiary, MDU Resources International, Inc., invests in projects outside the United States which are consistent with the company's philosophy, growth strategy and areas of expertise. INDEX Part I -- Financial Information Consolidated Statements of Income -- Three and Nine Months Ended September 30, 2001 and 2000 Consolidated Balance Sheets -- September 30, 2001 and 2000, and December 31, 2000 Consolidated Statements of Cash Flows -- Nine Months Ended September 30, 2001 and 2000 Notes to Consolidated Financial Statements Management's Discussion and Analysis of Financial Condition and Results of Operations Quantitative and Qualitative Disclosures About Market Risk 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, 2001 2000 2001 2000 (In thousands, except per share amounts) Operating revenues $551,680 $530,834 $1,739,345 $1,265,802 Operating expenses: Fuel and purchased power 14,982 13,399 42,703 39,603 Purchased natural gas sold 36,840 123,132 502,394 389,906 Operation and maintenance 356,677 277,512 823,052 582,511 Depreciation, depletion and amortization 36,205 28,686 102,737 75,130 Taxes, other than income 13,737 12,082 41,352 32,121 458,441 454,811 1,512,238 1,119,271 Operating income 93,239 76,023 227,107 146,531 Other income -- net 1,855 1,947 16,416 8,624 Interest expense 11,459 13,333 34,171 34,539 Income before income taxes 83,635 64,637 209,352 120,616 Income taxes 32,889 24,645 82,502 46,133 Net income 50,746 39,992 126,850 74,483 Dividends on preferred stocks 190 191 571 575 Earnings on common stock $ 50,556 $ 39,801 $ 126,279 $ 73,908 Earnings per common share -- basic $ .75 $ .63 $ 1.89 $ 1.23 Earnings per common share -- diluted $ .74 $ .63 $ 1.87 $ 1.23 Dividends per common share $ .23 $ .22 $ .67 $ .64 Weighted average common shares outstanding -- basic 67,650 62,975 66,781 60,015 Weighted average common shares outstanding -- diluted 68,127 63,345 67,519 60,238 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, 2001 2000 2000 (In thousands) ASSETS Current assets: Cash and cash equivalents $ 57,817 $ 47,267 $ 36,512 Receivables 357,027 284,491 342,354 Inventories 95,669 76,065 64,017 Deferred income taxes 14,839 7,043 8,048 Prepayments and other current assets 27,722 43,992 29,355 553,074 458,858 480,286 Investments 37,917 41,480 41,380 Property, plant and equipment 2,718,035 2,424,888 2,496,123 Less accumulated depreciation, depletion and amortization 919,212 862,148 895,109 1,798,823 1,562,740 1,601,014 Deferred charges and other assets 282,657 182,791 190,279 $2,672,471 $2,245,869 $2,312,959 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Short-term borrowings $ --- $ 12,000 $ 8,000 Long-term debt and preferred stock due within one year 11,131 6,407 19,695 Accounts payable 141,950 131,003 171,929 Taxes payable 28,984 9,372 10,437 Dividends payable 15,840 14,385 14,423 Other accrued liabilities, including reserved revenues 91,191 79,135 59,989 289,096 252,302 284,473 Long-term debt 843,915 758,170 728,166 Deferred credits and other liabilities: Deferred income taxes 327,560 262,034 281,000 Other liabilities 118,013 119,926 121,860 445,573 381,960 402,860 Preferred stock subject to mandatory redemption 1,400 1,500 1,400 Commitments and contingencies Stockholders' equity: Preferred stocks 15,000 15,000 15,000 Common stockholders' equity: Common stock (Shares issued -- $1.00 par value, 69,386,316 at September 30, 2001, 64,466,401 at September 30, 2000 and 65,267,567 at December 31, 2000) 69,386 64,466 65,268 Other paid-in capital 626,655 497,572 518,771 Retained earnings 381,752 278,525 300,647 Accumulated other comprehensive income 3,320 --- --- Treasury stock at cost - 239,521 shares (3,626) (3,626) (3,626) Total common stockholders' equity 1,077,487 836,937 881,060 Total stockholders' equity 1,092,487 851,937 896,060 $2,672,471 $2,245,869 $2,312,959 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, 2001 2000 (In thousands) Operating activities: Net income $126,850 $74,483 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 102,737 75,130 Deferred income taxes and investment tax credit 8,448 20,627 Changes in current assets and liabilities, net of acquisitions: Receivables 54,776 (63,224) Inventories (26,844) (2,563) Other current assets 7,460 (18,584) Accounts payable (55,426) 19,695 Other current liabilities 43,667 14,792 Other noncurrent changes (2,867) 676 Net cash provided by operating activities 258,801 121,032 Investing activities: Capital expenditures including acquisitions of businesses (340,572) (323,225) Net proceeds from sale or disposition of property 34,847 5,092 Net capital expenditures (305,725) (318,133) Investments 3,041 2,001 Additions to notes receivable --- (5,000) Proceeds from notes receivable 4,000 4,000 Net cash used in investing activities (298,684) (317,132) Financing activities: Net change in short-term borrowings (8,000) (3,242) Issuance of long-term debt 158,807 201,815 Repayment of long-term debt (96,031) (20,461) Issuance of common stock 52,157 27,278 Dividends paid (45,745) (39,527) Net cash provided by financing activities 61,188 165,863 Increase (decrease) in cash and cash equivalents 21,305 (30,237) Cash and cash equivalents -- beginning of year 36,512 77,504 Cash and cash equivalents -- end of period $ 57,817 $ 47,267 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 2001 and 2000 (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, 2000 (2000 Annual Report), and the standards of accounting measurement set forth in Accounting Principles Board Opinion No. 28 and any amendments thereto adopted by the Financial Accounting Standards Board. 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 2000 Annual Report. The information is unaudited but includes all adjustments which 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 may not be indicative of results for the full fiscal year. 3. Cash flow information Cash expenditures for interest and income taxes were as follows: Nine Months Ended September 30, 2001 2000 (In thousands) Interest, net of amount capitalized $28,158 $28,520 Income taxes $57,528 $25,946 4. 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 common stockholders' equity as previously reported. 5. Impairment testing of natural gas and oil properties The company uses the full-cost method of accounting for its natural gas and oil production activities. Under this method, all costs incurred in the acquisition, exploration and development of natural gas and oil properties are capitalized and amortized on the units of production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized. Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net revenues of proved reserves based on single point in time spot market prices, as mandated under the rules of the Securities and Exchange Commission, and the lower of cost or fair value of unproved properties. Future net revenue is estimated based on end-of-quarter spot market prices adjusted for contracted price changes. If capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter unless subsequent price changes eliminate or reduce an indicated write-down. Due to aberrantly low spot natural gas prices that existed on the last trading day of the quarter, the company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at September 30, 2001. The lower natural gas prices were largely attributable to a sharp decline in nationwide spot market prices, especially natural gas prices in the Rocky Mountain region, over a relatively short period of time following the terrorist attacks on New York and Washington, D.C. on September 11, 2001, and prior to October 1, 2001. Oil prices likewise experienced a sharp drop during this same period. The company believes the decline in natural gas prices does not reflect the economics of its production assets in that natural gas prices actually being received by the company at the end of the quarter were significantly higher than the spot market prices at that time. In addition, historic natural gas prices have also generally been much higher and only a small portion of the company's natural gas is sold using spot market pricing. As of September 30, 2001, the capitalized costs exceeded the full-cost ceiling and would have resulted in a write-down of the company's natural gas and oil properties in the amount of approximately $32 million after tax. However, subsequent to September 30, 2001, natural gas prices both nationwide and in the Rocky Mountain region increased significantly, thereby eliminating the need for a write-down of the company's natural gas and oil producing properties. 6. New accounting pronouncements In June 2001, the Financial Accounting Standards Board (FASB) approved Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS No. 141). SFAS No. 141 requires that all business combinations be accounted for using the purchase method of accounting. The use of the pooling-of- interest method of accounting for business combinations is prohibited. The provisions of SFAS No. 141 apply to all business combinations initiated after June 30, 2001. The company is accounting for business combinations after June 30, 2001, in accordance with SFAS No. 141. In June 2001, the FASB approved Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). SFAS No. 142 changes the accounting for goodwill and intangible assets and requires that goodwill no longer be amortized but be tested for impairment at least annually at the reporting unit level in accordance with SFAS No. 142. Recognized intangible assets should be amortized over their useful life and reviewed for impairment in accordance with FASB Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The provisions of SFAS No. 142 are effective for fiscal years beginning after December 15, 2001, except for provisions related to the nonamortization and amortization of goodwill and intangible assets acquired after June 30, 2001, which will be subject immediately to the provisions of SFAS No. 142. The company will adopt SFAS No. 142 on January 1, 2002. The company will cease amortization of its recorded goodwill in place at June 30, 2001, on January 1, 2002. The company has not yet quantified the effects of adopting SFAS No. 142 on its financial position or results of operations. In June 2001, the FASB approved Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). 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. The company will adopt SFAS No. 143 on January 1, 2003, but has not yet quantified the effects of adopting SFAS No. 143 on its financial position or results of operations. In August 2001, the FASB approved Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144 supersedes FASB Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121). SFAS No. 121 did not address the accounting for a segment of a business accounted for as a discontinued operation which resulted in two accounting models for long-lived assets to be disposed of. SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The company will adopt SFAS No. 144 on January 1, 2002, but has not yet quantified the effects of adopting SFAS No. 144 on its financial position or results of operations. The company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), amended by Statement of Financial Accounting Standards No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133" and Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" (all such statements hereinafter referred to as SFAS No. 133) on January 1, 2001. SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset the related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. SFAS No. 133 requires that as of the date of initial adoption, the difference between the fair market value of derivative instruments recorded on the balance sheet and the previous carrying amount of those derivative instruments be reported in net income or other comprehensive income (loss), as appropriate, as the cumulative effect of a change in accounting principle in accordance with APB 20, "Accounting Changes." On January 1, 2001, the company reported a net-of-tax cumulative- effect adjustment of $6.1 million in accumulated other comprehensive loss to recognize at fair value all derivative instruments that are designated as cash-flow hedging instruments, which the company expects to reflect in earnings, subject to changes in natural gas and oil market prices, over the twelve months ending December 31, 2001. The transition to SFAS No. 133 did not have an effect on the company's net income at adoption. 7. Derivative instruments As of September 30, 2001, the company held derivative instruments designated as cash flow hedging instruments. All derivative instruments are recognized on the Consolidated Balance Sheets at fair value. Hedging activities The cash flow hedging instruments in place at September 30, 2001, are comprised of natural gas and oil price swap agreements and an interest rate swap agreement. The objective for holding the natural gas and oil price swap agreements is to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on the company's forecasted sales of natural gas and oil production. The objective for holding the interest rate swap agreement is to manage a portion of the company's interest rate risk on the forecasted issuances of fixed-rate debt under the company's commercial paper program. The company designated each of the natural gas and oil price swap agreements as a hedge of the forecasted sale of natural gas and oil production and designated the interest rate swap agreement as a hedge of the risk of changes in interest rates on the company's forecasted issuances of fixed-rate debt under the company's commercial paper program. The company's policy allows the use of derivative instruments as part of an overall energy price and interest rate risk management program to efficiently manage and minimize commodity price and interest rate risk. The company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions and the company has procedures in place to monitor compliance with its policies. The company is exposed to credit-related losses in relation to hedged derivative instruments in the event of nonperformance by counterparties. The company has policies and procedures, which management believes minimize credit-risk exposure. These policies and procedures include an evaluation of potential counterparties' credit ratings, credit exposure limitations, settlement of natural gas and oil price swap agreements monthly and settlement of interest rate swap agreements within 90 days. Accordingly, the company does not anticipate any material effect to its financial position or results of operations as a result of nonperformance by counterparties. Upon the adoption of SFAS No. 133, the company recorded the fair market value of the natural gas and oil price swap agreements on the company's Consolidated Balance Sheets. On an ongoing basis, the company adjusts its balance sheet to reflect the current fair market value of the natural gas and oil price swap agreements and the interest rate swap agreement. The related gains or losses on these agreements are recorded in common stockholders' equity as a component of other comprehensive income (loss). At the date the underlying transaction occurs, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. For the three months and nine months ended September 30, 2001, the company recognized the ineffectiveness of all cash- flow hedges, which is included in operating revenues and interest expense on the Consolidated Statements of Income for the natural gas and oil price swap agreements and the interest rate swap agreement, respectively. For the three months and nine months ended September 30, 2001, the amount of ineffectiveness recognized was immaterial. For the three months and nine months ended September 30, 2001, the company did not exclude any components of the derivative instruments' 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, 2001, the maximum length of time over which the company is hedging its exposure to the variability in future cash flows for forecasted transactions is 15 months and the company estimates that net gains of approximately $3.0 million will be reclassified from accumulated other comprehensive income into earnings, subject to changes in natural gas and oil market prices and interest rates, within the twelve months between October 1, 2001 and September 30, 2002 as the hedged transactions affect earnings. In the event a derivative instrument does not qualify for hedge accounting because it is no longer highly effective in offsetting changes in cash flows of a hedged item; or if the derivative instrument expires or is sold, terminated, or exercised; or if management determines that designation of the derivative instrument as a hedge instrument is no longer appropriate, hedge accounting will be discontinued, and the derivative instrument would continue to be carried at fair value with changes in its fair value recognized in earnings. In these circumstances, the net gain or loss at the time of discontinuance of hedge accounting would remain in other comprehensive income (loss) until the period or periods during which the hedged forecasted transaction affects earnings, at which time the net gain or loss would be reclassified into earnings. In the event a cash flow hedge is discontinued because it is unlikely that a forecasted transaction will occur, the derivative instrument would continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income (loss) would be recognized immediately in earnings. The company's policy requires approval to terminate a hedge agreement prior to its original maturity. Energy marketing The company had entered into other derivative instruments that were not designated as hedges in its energy marketing operations. In the third quarter of 2001, the company sold the vast majority of its energy marketing operations. The derivative instruments entered into by these operations prior to the sale in the third quarter of 2001 were natural gas forward purchase and sale commitments. These commitments involved the purchase and sale of natural gas and related delivery of such commodity. These operations sought to match natural gas purchases and sales on specific derivative instruments so that a margin was obtained on the transportation of such commodity as distinguished from earning a margin on changes in market prices. The net change in fair value representing unrealized gains and losses resulting from changes in market prices on these derivative instruments was reflected as operating revenues or purchased natural gas sold on the company's Consolidated Statements of Income. Net unrealized gains and losses on these derivative instruments were not material for the three months and nine months ended September 30, 2001 and 2000. 8. Comprehensive income Upon the adoption of SFAS No. 133 on January 1, 2001, the company recorded a cumulative-effect adjustment in accumulated other comprehensive loss to recognize all derivative instruments designated as hedges at fair value. As of September 30, 2001, the company has recorded unrealized gains and losses on natural gas and oil price swap and interest rate swap agreements in accordance with SFAS No. 133. These amounts are reflected in the following table. For additional information on the adoption of SFAS No. 133, see Notes 6 and 7 of the Notes to the Consolidated Financial Statements. The company's comprehensive income, and the components of other comprehensive income, net of taxes, were as follows: Three Months Ended September 30, 2001 2000 (In thousands) Net income $ 50,746 $ 39,992 Other comprehensive income - Net unrealized gain on derivative instruments qualifying as hedges: Net unrealized gain on derivative instruments arising during the period, net of tax of $1,191 1,824 --- Reclassification adjustment for gains on derivative instruments included in net income, net of tax of $992 (1,519) --- Net unrealized gain on derivative instruments qualifying as hedges 305 --- Comprehensive income $ 51,051 $ 39,992 Nine Months Ended September 30, 2001 2000 (In thousands) Net income $126,850 $ 74,483 Other comprehensive income - Net unrealized gain on derivative instruments qualifying as hedges: Unrealized loss on derivative instruments at January 1, 2001, due to cumulative effect of a change in accounting principle, net of tax of $3,970 (6,080) --- Net unrealized gain on derivative instruments arising during the period, net of tax of $2,782 4,262 --- Reclassification adjustment for losses on derivative instruments included in net income, net of tax of $3,355 5,138 --- Net unrealized gain on derivative instruments qualifying as hedges 3,320 --- Comprehensive income $130,170 $ 74,483 9. Business segment data The company's reportable business 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's operations are conducted through six segments. Substantially all of the company's operations are located within the United States. 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 construction company specializing in electric, natural gas and telecommunication utility construction as well as interior industrial electrical, exterior lighting and traffic signalization. Utility services has engineering, design and build capability and provides related specialty equipment sales and rental services throughout most of the United States. The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems in the Rocky Mountain, Midwest, Southern and Central regions of the United States, provides energy-related marketing and management services and invests in new growth and synergistic opportunities. 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 the Gulf of Mexico. The construction materials and mining segment mines and markets aggregates and related value-added construction materials products and services in Alaska, California, Hawaii, Minnesota, Montana, Oregon, Washington and Wyoming. On May 11, 2001, the company announced that the sale of its coal operations to Westmoreland Coal Company for $28.8 million in cash, excluding final settlement cost adjustments, had been finalized. The sale of the coal operations was effective April 30, 2001. Included in the sale were active coal mines in North Dakota and Montana, coal sales agreements, reserves and mining equipment and certain development rights at the former Gascoyne Mine site in North Dakota. The company retains ownership of coal reserves and leases at its former Gascoyne Mine site. The company recorded a gain of $11.0 million ($6.6 million after tax) included in other income - net on the company's Consolidated Statements of Income from the sale in the second quarter of 2001. Segment information follows the same accounting policies as described in Note 1 of the company's 2000 Annual Report. Segment information included in the accompanying Consolidated Statements of Income is as follows: Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Three Months Ended September 30, 2001 Electric $ 48,154 $ --- $ 8,265 Natural gas distribution 18,710 --- (2,747) Utility services 92,208 --- 3,405 Pipeline and energy services 59,430 5,391 3,895 Natural gas and oil production 31,579 10,891 10,519 Construction materials and mining 301,599 --- 27,219 Intersegment eliminations --- (16,282) --- Total $ 551,680 $ --- $ 50,556 Three Months Ended September 30, 2000 Electric $ 42,078 $ --- $ 5,920 Natural gas distribution 24,912 --- (2,180) Utility services 60,056 --- 3,860 Pipeline and energy services 136,679 7,508 2,997 Natural gas and oil production 25,012 10,241 10,001 Construction materials and mining 238,647 3,450* 19,203 Intersegment eliminations --- (17,749) --- Total $ 527,384 $ 3,450* $ 39,801 * In accordance with the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Regulation" (SFAS No. 71), intercompany coal sales are not eliminated. Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Nine Months Ended September 30, 2001 Electric $ 129,143 $ --- $ 15,224 Natural gas distribution 200,809 --- (1,620) Utility services 236,710 4 9,321 Pipeline and energy services 454,819 34,197 9,656 Natural gas and oil production 121,310 48,192 56,440 Construction materials and mining 591,538 5,016* 37,258 Intersegment eliminations --- (82,393) --- Total $1,734,329 $ 5,016* $ 126,279 Nine Months Ended September 30, 2000 Electric $ 118,799 $ --- $ 12,179 Natural gas distribution 116,370 --- (270) Utility services 107,243 --- 5,387 Pipeline and energy services 381,989 37,622 6,645 Natural gas and oil production 69,861 21,985 23,499 Construction materials and mining 461,680 9,860* 26,468 Intersegment eliminations --- (59,607) --- Total $1,255,942 $ 9,860* $ 73,908 * In accordance with the provisions of SFAS No. 71, intercompany coal sales are not eliminated. During the first nine months of 2001, the company acquired a number of businesses, none of which was individually material, including construction materials and mining businesses in Hawaii, Minnesota and Oregon, utility services businesses based in Missouri and Oregon and an energy services company specializing in cable and pipeline locating and tracking systems. The total purchase consideration, consisting of the company's common stock and cash, for these businesses was $165.4 million. 10. Regulatory matters and revenues subject to refund In December 1999, Williston Basin Interstate Pipeline Company (Williston Basin), an indirect wholly owned subsidiary of the company, filed a general natural gas rate change application with the Federal Energy Regulatory Commission (FERC). Williston Basin began collecting such rates effective June 1, 2000, subject to refund. On May 9, 2001, the Administrative Law Judge issued an Initial Decision on Williston Basin's natural gas rate change application, which matter is currently pending before and subject to revision by the FERC. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to the pending regulatory proceeding. Williston Basin believes that such reserves are adequate based on its assessment of the ultimate outcome of the proceeding. 11. Litigation In March 1997, 11 natural gas producers filed suit in North Dakota Southwest Judicial District Court (North Dakota District Court) against Williston Basin and the company. The natural gas producers had processing agreements with Koch Hydrocarbon Company (Koch). Williston Basin and the company had natural gas purchase contracts with Koch. The natural gas producers alleged they were entitled to damages for the breach of Williston Basin's and the company's contracts with Koch although no specific damages were stated. A similar suit was filed by Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) in North Dakota Northwest Judicial District Court in December 1993. The North Dakota Supreme Court in December 1999 affirmed the North Dakota Northwest Judicial District Court decision dismissing Apache's and Snyder's claims against Williston Basin and the company. Based in part upon the decision of the North Dakota Supreme Court affirming the dismissal of the claims brought by Apache and Snyder, Williston Basin and the company filed motions for summary judgment to dismiss the claims of the 11 natural gas producers. The motions for summary judgment were granted by the North Dakota District Court in July 2000. On March 5, 2001, the North Dakota District Court entered a final judgment on the July 2000 order granting the motions for summary judgment. On May 4, 2001, the 11 natural gas producers appealed the North Dakota District Court's decision by filing a Notice of Appeal with the North Dakota Supreme Court. 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 or 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. On May 18, 2001, the Federal District Court denied Williston Basin's and Montana-Dakota's motion to dismiss. The matter is currently pending. The Quinque Operating Company (Quinque), on behalf of itself and subclasses of gas producers, royalty owners and state taxing authorities, instituted a legal proceeding in State District Court for Stevens County, Kansas,(State District Court) against over 200 natural gas transmission companies and producers, gatherers, and processors of natural gas, including Williston Basin and Montana-Dakota. The complaint, which was served on Williston Basin and Montana-Dakota in September 1999, contains allegations of improper measurement of the heating content and volume of all natural gas measured by the defendants other than natural gas produced from federal lands. In response to a motion filed by the defendants in this suit, the Judicial Panel on Multidistrict Litigation transferred the suit to the Federal District Court for inclusion in the pretrial proceedings of the Grynberg suit. Upon motion of plaintiffs, the case has been remanded to State District Court. On September 12, 2001, the defendants in this suit filed a motion to dismiss with the State District Court. Williston Basin and Montana-Dakota believe the claims of Grynberg and Quinque are without merit and intend to vigorously contest these suits. 12. 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, now owned by MBI, 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. Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon State Department of Environmental Quality and other information available, MBI does not believe it is a Responsible Party. In addition, MBI intends to seek indemnity for any and all liabilities incurred in relation to the above matters from Georgia-Pacific West, Inc., the seller of the commercial property site to MBI, pursuant to the terms of their sale agreement. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For purposes of segment financial reporting and discussion of results of operations, electric and natural gas distribution include the electric and natural gas distribution operations of Montana- Dakota and the natural gas distribution operations of Great Plains Natural Gas Co. Utility services includes all the operations of Utility Services, Inc. Pipeline and energy services includes WBI Holdings' natural gas transportation, underground storage, gathering services, energy marketing and management services and Centennial Capital. Natural gas and oil production includes the natural gas and oil acquisition, exploration and production operations of WBI Holdings, while construction materials and mining includes the results of Knife River's operations. 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 business segments. Three Months Nine Months Ended Ended September 30, September 30, 2001 2000 2001 2000 Electric $ 8.3 $ 5.9 $ 15.2 $12.2 Natural gas distribution (2.7) (2.2) (1.6) (.3) Utility services 3.4 3.9 9.3 5.4 Pipeline and energy services 3.9 3.0 9.7 6.6 Natural gas and oil production 10.5 10.0 56.4 23.5 Construction materials and mining 27.2 19.2 37.3 26.5 Earnings on common stock $50.6 $ 39.8 $126.3 $73.9 Earnings per common share - basic $ .75 $ .63 $ 1.89 $1.23 Earnings per common share - diluted $ .74 $ .63 $ 1.87 $1.23 Return on average common equity for the 12 months ended 17.0% 13.7% ________________________________ Three Months Ended September 30, 2001 and 2000 Consolidated earnings for the quarter ended September 30, 2001, increased $10.8 million from the comparable period a year ago due to higher earnings at the construction materials and mining, electric, pipeline and energy services, and natural gas and oil production businesses, partially offset by lower earnings at the other business segments. Nine Months Ended September 30, 2001 and 2000 Consolidated earnings for the nine months ended September 30, 2001, increased $52.4 million from the comparable period a year ago due to higher earnings at the natural gas and oil production, construction materials and mining, utility services, pipeline and energy services and electric businesses, partially offset by lower earnings at the natural gas distribution business segment. ________________________________ Financial and operating data The following tables (dollars in millions, where applicable) are key financial and operating statistics for each of the company's business segments. Electric Three Months Nine Months Ended Ended September 30, September 30, 2001 2000 2001 2000 Operating revenues: Retail sales $ 37.9 $ 34.4 $ 103.5 $ 98.9 Sales for resale and other 10.3 7.7 25.6 19.9 48.2 42.1 129.1 118.8 Operating expenses: Fuel and purchased power 15.0 13.4 42.7 39.6 Operation and maintenance 10.5 10.0 34.0 31.9 Depreciation, depletion and amortization 4.9 4.8 14.5 14.3 Taxes, other than income 1.8 1.7 5.6 5.6 32.2 29.9 96.8 91.4 Operating income $ 16.0 $ 12.2 $ 32.3 $ 27.4 Retail sales (million kWh) 597.3 561.7 1,640.4 1,592.1 Sales for resale (million kWh) 201.0 222.4 649.0 680.6 Average cost of fuel and purchased power per kWh $ .018 $ .016 $ .018 $ .016 Natural Gas Distribution Three Months Nine Months Ended Ended September 30, September 30, 2001 2000 2001 2000 Operating revenues: Sales $ 17.8 $ 24.1 $ 197.9 $ 113.7 Transportation and other .9 .8 2.9 2.7 18.7 24.9 200.8 116.4 Operating expenses: Purchased natural gas sold 10.7 16.8 162.6 82.2 Operation and maintenance 8.3 7.7 27.8 23.6 Depreciation, depletion and amortization 2.3 2.3 7.0 6.1 Taxes, other than income 1.2 1.1 3.8 3.5 22.5 27.9 201.2 115.4 Operating income (loss) $ (3.8) $ (3.0) $ (0.4)$ 1.0 Volumes (MMdk): Sales 3.0 3.2 24.6 21.2 Transportation 2.9 3.1 9.8 9.0 Total throughput 5.9 6.3 34.4 30.2 Degree days (% of normal) 88% 118% 98% 92% Average cost of natural gas, including transportation thereon, per dk $ 3.53 $ 5.28 $ 6.61 $ 3.88 Utility Services Three Months Nine Months Ended Ended September 30, September 30, 2001 2000 2001 2000 Operating revenues $ 92.2 $ 60.1 $ 236.7 $ 107.2 Operating expenses: Operation and maintenance 80.7 49.5 206.4 89.9 Depreciation, depletion and amortization 2.1 1.4 5.8 3.3 Taxes, other than income 2.6 1.9 6.2 3.5 85.4 52.8 218.4 96.7 Operating income $ 6.8 $ 7.3 $ 18.3 $ 10.5 Pipeline and Energy Services Three Months Nine Months Ended Ended September 30, September 30, 2001 2000 2001 2000 Operating revenues: Pipeline $ 22.7 $ 19.2 $ 64.9 $ 48.6 Energy services 42.1 125.0 424.1 371.0 64.8 144.2 489.0 419.6 Operating expenses: Purchased natural gas sold 40.2 123.3 416.4 363.6 Operation and maintenance 10.4 9.0 33.9 26.6 Depreciation, depletion and amortization 3.9 3.2 10.7 7.9 Taxes, other than income 1.6 1.4 4.6 3.7 56.1 136.9 465.6 401.8 Operating income $ 8.7 $ 7.3 $ 23.4 $ 17.8 Transportation volumes (MMdk): Montana-Dakota 8.9 6.7 26.4 22.4 Other 19.2 15.5 46.8 42.3 28.1 22.2 73.2 64.7 Gathering volumes (MMdk) 15.2 13.2 44.0 28.0 Natural Gas and Oil Production Three Months Nine Months Ended Ended September 30, September 30, 2001 2000 2001 2000 Operating revenues: Natural gas $ 29.2 $ 21.3 $ 124.8 $ 51.0 Oil 12.4 11.6 38.9 32.5 Other .9 2.3 5.8 8.4 42.5 35.2 169.5 91.9 Operating expenses: Purchased natural gas sold .7 .6 2.4 3.0 Operation and maintenance 11.9 8.5 34.7 23.4 Depreciation, depletion and amortization 10.3 6.5 30.4 17.7 Taxes, other than income 2.3 2.1 8.7 6.1 25.2 17.7 76.2 50.2 Operating income $ 17.3 $ 17.5 $ 93.3 $ 41.7 Production: Natural gas (MMcf) 9,921 7,361 29,641 20,198 Oil (000's of barrels) 510 486 1,492 1,428 Average realized prices: Natural gas (per Mcf) $ 2.94 $ 2.90 $ 4.21 $ 2.52 Oil (per barrel) $ 24.33 $ 23.86 $ 26.04 $ 22.79 Construction Materials and Mining Three Months Nine Months Ended Ended September 30, September 30, 2001 2000 2001 2000 Operating revenues: Construction materials $ 301.6 $ 233.2 $ 584.3 $ 447.7 Coal --- 8.9 12.3 23.8 301.6 242.1 596.6 471.5 Operating expenses: Operation and maintenance 236.5 193.0 489.7 387.8 Depreciation, depletion and amortization 12.7 10.5 34.3 25.9 Taxes, other than income 4.2 3.9 12.4 9.7 253.4 207.4 536.4 423.4 Operating income $ 48.2 $ 34.7 $ 60.2 $ 48.1 Sales (000's): Aggregates (tons) 11,023 6,700 19,951 13,510 Asphalt (tons) 3,310 1,627 4,732 2,583 Ready-mixed concrete (cubic yards) 804 516 1,916 1,223 Coal (tons) --- 818 1,171 2,190 Amounts presented in the preceding tables for operating revenues, purchased natural gas sold and operation and maintenance expenses will not agree with the Consolidated Statements of Income due to the elimination of intercompany transactions between the pipeline and energy services segment and the natural gas distribution and natural gas and oil production segments. The amounts relating to the elimination of intercompany transactions for operating revenues, purchased natural gas sold and operation and maintenance expenses are as follows: $16.3 million, $14.7 million and $1.6 million for the three months ended September 30, 2001; $17.8 million, $17.6 million and $.2 million for the three months ended September 30, 2000; $82.4 million, $79.0 million and $3.4 million for the nine months ended September 30, 2001; and $59.6 million, $58.9 million and $.7 million for the nine months ended September 30, 2000, respectively. Three Months Ended September 30, 2001 and 2000 Electric Electric earnings increased due to higher average realized sales for resale prices, and increased retail sales volumes due largely to an increased summer cooling load resulting from warmer weather compared to the same period a year ago. Higher operation and maintenance expense, primarily increased payroll costs, partially offset the earnings increase. Natural Gas Distribution Earnings at the natural gas distribution business decreased due to higher operation and maintenance expense, primarily increased payroll costs and higher bad debt expense, and reduced operating revenue caused by lower weather-related sales, the result of 24 percent warmer weather than the same period last year. The pass- through of lower natural gas prices added to the decline in sales revenue and purchased natural gas sold. Utility Services Utility services earnings declined largely due to lower construction margins due, in part, to a slow down in the economy. Higher selling, general and administrative expenses also added to the earnings decline. Partially offsetting the earnings decrease were higher equipment sales at existing operations and earnings from businesses acquired since the comparable period last year. Pipeline and Energy Services Earnings at the pipeline and energy services business increased due to higher transportation volumes moved to storage, higher average rates and increased gathering volumes at the pipeline. Higher operation and maintenance expense, primarily increased material costs, higher contract services, and increased payroll costs, the sale of the company's Kentucky energy services operations and higher depreciation, depletion and amortization expense partially offset the earnings increase. The decrease in energy services revenue and the related decrease in purchased natural gas sold resulted primarily from decreased energy marketing volumes, largely at certain energy services operations which were sold, as previously discussed. Natural Gas and Oil Production Natural gas and oil production earnings increased largely due to an increase in natural gas and oil production of 35 percent and 5 percent since last year, respectively, combined with slightly higher realized natural gas and oil prices. Higher realized prices were the result of gains on hedging activities. The higher production was the result of the ongoing development of existing properties. Also adding to the earnings increase was lower interest expense, a result of lower debt balances combined with lower average interest rates. Partially offsetting the earnings improvement were increased depreciation, depletion and amortization expense due to higher production volumes and higher rates, increased operation and maintenance expense, mainly higher lease operating expenses and higher general and administrative costs, and lower sales volumes of inventoried natural gas. Hedging activities for natural gas for the third quarter of 2001 and 2000 resulted in realized prices that were 111 and 86 percent, respectively, of what otherwise would have been received. In addition, hedging activities for oil for the third quarter of 2001 and 2000 resulted in realized prices that were 102 and 81 percent, respectively, of what otherwise would have been received. Construction Materials and Mining Earnings for the construction materials and mining business increased largely as a result of earnings from businesses acquired since the comparable period last year and from increases at existing aggregate, asphalt and cement operations. Partially offsetting the earnings increase were lower construction workloads and margins, largely increased competition and less available work, due, in part, to a slow down in the economy, and the timing of projects, at certain West Coast operations. The absence of coal volumes due to the sale of the coal operations, as previously discussed in Note 9 of Notes to the Consolidated Financial Statements, also partially offset the earnings increase. Nine Months Ended September 30, 2001 and 2000 Electric Electric earnings increased due to higher average realized sales for resale prices, increased retail sales volumes, as previously discussed, and insurance recovery proceeds related to a 2000 outage at an electric generating station. Increased fuel and purchased power costs, largely due to an extended maintenance outage at an electric power supplier's generating station, partially offset the earnings increase. Also partially offsetting the earnings increase were higher operation and maintenance expense, primarily higher payroll costs. Natural Gas Distribution Earnings at the natural gas distribution business decreased as a result of higher operation and maintenance expenses, primarily increased bad debt expense and higher payroll costs. Decreased return on natural gas storage, demand and prepaid commodity balances, decreased service and repair margins, and lower average realized rates, also added to the earnings decline. Slightly offsetting the decline were increased sales, partially due to weather that was 7 percent colder than the same period last year, and earnings from a natural gas utility business acquired in July 2000. The pass-through of higher natural gas prices added to the increase in sales revenue and purchased natural gas sold. Utility Services Utility services earnings increased as a result of earnings from businesses acquired since the comparable period last year, as well as increased workloads and equipment sales at existing operations. The earnings improvement was partially offset by higher selling, general and administrative costs. Pipeline and Energy Services Earnings at the pipeline and energy services business increased due to higher transportation volumes combined with higher average rates, increased gathering volumes and increased earnings from an acquisition in June 2000 at the pipeline. Also contributing to the earnings increase were higher natural gas sales margins, increased pipeline and cable magnetization and locating services revenues at energy services. Partially offsetting the earnings increase were higher operation and maintenance expense, the write-off of an investment in a software development company of $699,000 (after tax), and increased depreciation, depletion and amortization expense. The higher operations and maintenance expense was due primarily to increased compressor-related expenses, higher payroll expenses and increased contract services. The increase in energy services revenue and the related increase in purchased natural gas sold resulted from higher natural gas prices, partially offset by decreased energy marketing volumes, as previously discussed. Natural Gas and Oil Production Natural gas and oil production earnings increased largely due to increased realized natural gas and oil prices which were 67 percent and 14 percent higher than last year, respectively, combined with higher natural gas and oil production of 47 percent and 4 percent since last year, respectively. The higher production was largely the result of a natural gas property acquisition in April 2000 and the ongoing development of that property as well as existing properties. Also adding to the earnings increase was lower interest expense, a result of lower debt balances combined with lower average rates. Partially offsetting the earnings improvement were increased depreciation, depletion and amortization expense, due to higher production volumes and higher rates, increased operation and maintenance expense, mainly higher lease operating expenses and higher general and administrative costs, and lower sales volumes of inventoried natural gas. Hedging activities for natural gas for the nine months ended September 30, 2001 and 2000 resulted in realized prices that were 99 and 89 percent, respectively, of what otherwise would have been received. In addition, hedging activities for oil for the nine months ended September 30, 2001 and 2000 resulted in realized prices that were 102 and 83 percent, respectively, of what otherwise would have been received. Construction Materials and Mining Earnings for the construction materials and mining business increased largely due to a gain from the sale of the coal operations of $11.0 million ($6.6 million after tax), included in other income - net, as previously discussed, partially offset by lower coal sales volumes due primarily to four months of operations in 2001 compared to nine months in 2000. At the construction materials business, earnings from businesses acquired since the comparable period last year and increases largely from existing asphalt and aggregate operations, also added to the earnings improvement. Partially offsetting the earnings increase were lower construction workloads and margins, as previously described, the absence of last year's gain of $1.2 million after tax on the sale of nonstrategic property, increased interest expense, the result of higher acquisition-related borrowings, higher depreciation, depletion and amortization due to increased plant balances, and higher selling, general and administrative costs. Safe Harbor for Forward-looking Statements The company is including the following cautionary statement 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 which 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 such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the company, are also expressly qualified by these 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, but there can be no assurance that the company's expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such 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 such 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 such factors, nor can it assess the effect of each such factor on the company's business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include prevailing governmental policies and regulatory actions with respect to allowed rates of return, financings, or industry and rate structures, acquisition and disposal of assets or facilities, operation and construction of plant facilities, recovery of purchased power and purchased gas costs, present or prospective generation and availability of economic supplies of natural gas. Other important factors include the level of governmental expenditures on public projects and the timing of such projects, changes in anticipated tourism levels, the effects of competition (including but not limited to electric retail wheeling and transmission costs and prices of alternate fuels and system deliverability costs), natural gas and oil commodity prices, 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, ability to acquire natural gas and oil properties, and the availability of economic expansion or development opportunities. The business and profitability of the company are also influenced by economic and geographic factors, including political and economic risks, economic disruptions caused by terrorist activities, changes in and compliance with environmental and safety laws and policies, weather conditions, 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, changes in credit ratings or capital market conditions, inflation rates, inability of the various 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, and the ability to effectively integrate the operations of acquired companies. Prospective Information The following information includes highlights of the key growth strategies, projections and certain assumptions for the company over the next few years and other matters for the company for each of its six major business segments. 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 Safe Harbor for Forward-looking Statements. Changes in such assumptions and factors could cause actual future results to differ materially from the company's targeted growth, revenue and earnings projections. MDU Resources Group, Inc. - Over the past five years, the company has experienced a compound annual earnings per share growth rate of approximately 14 percent. Currently, the company anticipates that its earnings per share growth rate for this single year will be approximately 17 percent to 28 percent, excluding the one-time gain from the sale of the company's coal operations and the write-off of an investment taken in the second quarter. - Earnings per share, diluted, for 2001 are projected in the $2.10 to $2.30 range, excluding the gain on the sale of the company's coal operations and the write-off of an investment. - Earnings per share, diluted, for 2002 are projected in the $1.90 to $2.10 range. - The company's long-term growth goals on compound annual earnings per share from operations are in the range of 10 percent to 12 percent. However, the general weakening of the economy combined with the recent terrorist events have added uncertainty in the ability of the company to achieve this goal in the early years of the planning cycle. - The company expects to issue and sell equity from time to time to keep its debt at the nonregulated businesses at no more than 40 percent of total capitalization. - The company estimates that the benefit resulting solely from the discontinuance of goodwill amortization would be five to six cents per common share in 2002. Electric - Montana-Dakota has obtained and holds valid and existing franchises authorizing it to conduct its electric and natural gas 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. Previously, a smaller town in western North Dakota was considering municipalization of Montana-Dakota's electric facilities. In August 2001, the voters of this town in a special election turned down the opportunity to pursue municipalization of the electric system. Montana-Dakota is currently negotiating the terms of a new franchise with this town. 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. - Due to growing electric demand, a gas-fired 40-megawatt electric plant may be added in the three to five year planning horizon. - Currently, the company is working with the state of North Dakota to determine the feasibility of constructing a 500-megawatt lignite-fired power plant in western North Dakota. Natural Gas Distribution - Annual natural gas throughput for 2001 is expected to be approximately 54 million decatherms, with about 38 million decatherms from sales and 16 million decatherms from transportation. - The number of natural gas retail customers at existing operations is expected to grow by approximately 1.5 percent on an annual basis over the next three to five years. Utility Services - Revenues for this segment are expected to exceed $300 million in 2001 and be approximately $500 million in 2002. - This segment's goal is to achieve compound annual revenue and earnings growth rates of approximately 20 percent to 25 percent over the next five years. However, the general weakening of the economy combined with the recent terrorist events have added uncertainty in the ability of the company to achieve this goal in the early years of the planning cycle. Pipeline and Energy Services - Two pipeline projects completed in 2000, are providing the pipeline company the ability to move approximately 40 percent more coalbed natural gas through its system than has historically been transported, as well as enabling additional deliveries to interconnecting pipeline systems, including the company's own transmission system. - In 2001, natural gas throughput, including transportation and gathering, for this segment is expected to increase by approximately 10 percent to 20 percent. - A 250-mile pipeline to transport additional gas to market and enhance the use of the company's storage facilities is in the planning stages and regulatory approval is expected to be sought later this year. Natural Gas and Oil Production - During the first nine months of 2001, the company drilled 514 new wells in its coalbed fields and in other operated fields in Montana and Colorado. - Combined natural gas and oil production at this segment is expected to be approximately 30 percent higher in 2001 than in 2000. In 2002, this segment expects a combined production increase of approximately 30 percent over 2001 levels. - The company's estimates for natural gas prices in the Rocky Mountain Region for November and December 2001 are in the range of $2.00 to $2.50 per Mcf. The company's estimates for natural gas prices on the NYMEX for November and December 2001 are in the range of $2.50 to $3.25 per Mcf. - During the first nine months of 2001, more than half of this segment's natural gas production was priced using Mid-Continent or Rocky Mountain prices. - For 2002, the company's estimates for natural gas prices in the Rocky Mountain Region are in the range of $2.25 to $2.75 per Mcf and estimates for natural gas prices on the NYMEX are in the range of $2.75 to $3.50. - The company's estimates for NYMEX crude oil prices are in the range of $20 to $25 per barrel for the remainder of 2001 and for 2002. - This segment has entered into hedging arrangements for a portion of its 2001 production. The company has entered into swap agreements and fixed price forward sales representing approximately 30 percent to 35 percent of 2001 estimated annual natural gas production. Natural gas swap prices range from $4.57 to $5.39 per Mcf based on NYMEX and $4.04 to $4.44 per Mcf for Rocky Mountain gas sales. In addition, approximately 30 percent to 35 percent of 2001 estimated annual oil production is hedged at NYMEX prices ranging from $27.51 to $29.22 per barrel. - This segment has hedged a portion of its 2002 production. The company has entered into a swap agreement and fixed price forward sales representing approximately 10 percent to 15 percent of 2002 estimated annual natural gas production. The natural gas swap is at an average NYMEX price of $4.34 per Mcf. The company has also entered into oil swap agreements at average NYMEX prices in the range of $24.80 to $25.25 per barrel, representing approximately 20 percent to 25 percent of the company's 2002 estimated annual oil production. Construction Materials and Mining - Aggregate, asphalt and ready-mixed concrete volumes are expected to increase by approximately 35 percent to 45 percent, 75 percent to 85 percent and 40 percent to 50 percent, respectively, in 2001. - This segment's goal is to achieve compound annual revenue and earnings growth rates of approximately 10 percent to 20 percent over the next five years. However, the general weakening of the economy combined with the recent terrorist events have added uncertainty in the ability of the company to achieve this goal in the early years of the planning cycle. - With the acquisitions made this year, aggregate reserves now total more than 1 billion tons. - With the acquisitions made this year and strong performance in existing markets, 2001 revenues at this segment are expected to exceed $750 million. New Accounting Standards In June 2001, the Financial Accounting Standards Board (FASB) approved Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS No. 141), Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), and Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). In August 2001, the FASB approved Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets" (SFAS No. 144). For more information on SFAS No. 141, SFAS No. 142, SFAS No. 143, and SFAS No. 144 see Note 6 of Notes to Consolidated Financial Statements. Liquidity and Capital Commitments Net capital expenditures for the year 2001 are estimated at $424.2 million, including those for acquisitions to date, system upgrades, routine replacements, service extensions, routine equipment maintenance and replacements, pipeline and gathering expansion projects, the building of construction materials handling and transportation facilities, the further enhancement of natural gas and oil production and reserve growth, and for potential future acquisitions and other growth opportunities. 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 2001 capital expenditures referred to above. It is anticipated that all of the funds required for capital expenditures will be met from various sources. These sources include internally generated funds, the company's $40 million revolving credit and term loan agreement, none of which is outstanding at September 30, 2001, a commercial paper credit facility at Centennial, as described below, and through the issuance of long-term debt and the company's equity securities. The estimated 2001 capital expenditures referred to above include completed 2001 acquisitions including construction materials and mining businesses based in Hawaii, Minnesota, and Oregon, utility services businesses based in Missouri and Oregon, and an energy services company specializing in cable and pipeline locating and tracking systems. 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. Centennial, a direct wholly owned subsidiary of the company, has a revolving credit agreement with various banks that supports Centennial's $350 million commercial paper program. Under the commercial paper program, $299.4 million was outstanding at September 30, 2001. The commercial paper borrowings are classified as long term as Centennial intends to refinance these borrowings on a long-term basis through continued commercial paper borrowings supported by the revolving credit agreement. Centennial intends to renew this existing credit agreement on an annual basis. Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $300 million. Under the master shelf agreement, $210 million was outstanding at September 30, 2001. On September 28, 2001, the company reported the sale of 1,105,353 shares of the company's Common Stock to Acqua Wellington North American Equities Fund, Ltd. (Acqua Wellington), pursuant to a purchase agreement by and between the company and Acqua Wellington. The company received proceeds from this sale of $25 million. These proceeds are anticipated to be used for refunding of outstanding debt obligations and for other general corporate purposes. 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, 2001, the company could have issued approximately $300 million of additional first mortgage bonds. The company's coverage of fixed charges including preferred dividends was 5.4 times and 4.1 times for the twelve months ended September 30, 2001, and December 31, 2000, respectively. Additionally, the company's first mortgage bond interest coverage was 9.6 times and 8.3 times for the twelve months ended September 30, 2001, and December 31, 2000, respectively. Common stockholders' equity as a percent of total capitalization was 56 percent and 54 percent at September 30, 2001, and December 31, 2000, respectively. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK There are no material changes in market risk faced by the company from those reported in the company's Annual Report on Form 10-K for the year ended December 31, 2000. For more information on market risk, see Part II, Item 7A in the company's Annual Report on Form 10- K for the year ended December 31, 2000, and Notes to Consolidated Financial Statements in this form 10-Q. PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS On September 12, 2001, the defendants in the Quinque legal proceeding filed a motion to dismiss with the State District Court. For more information on this legal action, see Note 11 of Notes to Consolidated Financial Statements. 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 b) Reports on Form 8-K Form 8-K was filed on September 21, 2001. Under Item 5 -- Other Events, the company reported the press release issued September 20, 2001, regarding natural gas price volatility. Form 8-K was filed on September 28, 2001. Under Item 5 -- Other Events, the company reported the sale of 1,105,353 shares of company Common Stock to Acqua Wellington North American Equities Fund, Ltd. 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 October 26, 2001 BY /s/ Warren L. Robinson Warren L. Robinson Executive Vice President, Treasurer and Chief Financial Officer BY /s/ Vernon A. Raile Vernon A. Raile Vice President, Controller 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