UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 August 6, 2001: 68,038,592 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 and provides energy- related marketing and management services in the Rocky Mountain, Midwest, Southern and Central regions of the United States. 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. INDEX Part I -- Financial Information Consolidated Statements of Income -- Three and Six Months Ended June 30, 2001 and 2000 Consolidated Balance Sheets -- June 30, 2001 and 2000, and December 31, 2000 Consolidated Statements of Cash Flows -- Six Months Ended June 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 Six Months Ended Ended June 30, June 30, 2001 2000 2001 2000 (In thousands, except per share amounts) Operating revenues $546,418 $362,979 $1,187,665 $734,968 Operating expenses: Fuel and purchased power 14,633 11,805 27,721 26,204 Purchased natural gas sold 139,783 95,004 465,554 266,774 Operation and maintenance 277,758 183,175 472,883 309,093 Depreciation, depletion and amortization 34,476 24,306 66,531 46,445 Taxes, other than income 9,421 7,610 21,108 15,943 476,071 321,900 1,053,797 664,459 Operating income 70,347 41,079 133,868 70,509 Other income -- net 12,202 4,307 14,561 6,676 Interest expense 10,998 10,924 22,712 21,205 Income before income taxes 71,551 34,462 125,717 55,980 Income taxes 28,134 13,336 49,614 21,490 Net income 43,417 21,126 76,103 34,490 Dividends on preferred stocks 191 191 381 383 Earnings on common stock $ 43,226 $ 20,935 $ 75,722 $ 34,107 Earnings per common share -- basic $ .64 $ .35 $ 1.14 $ .58 Earnings per common share -- diluted $ .63 $ .35 $ 1.13 $ .58 Dividends per common share $ .22 $ .21 $ .44 $ .42 Weighted average common shares outstanding -- basic 67,264 59,987 66,339 58,519 Weighted average common shares outstanding -- diluted 68,376 60,212 67,173 58,688 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, June 30, December 31, 2001 2000 2000 (In thousands) ASSETS Current assets: Cash and cash equivalents $ 30,799 $ 39,120 $ 36,512 Receivables 316,640 208,561 342,354 Inventories 81,096 64,448 64,017 Deferred income taxes 12,924 11,252 8,048 Prepayments and other current assets 33,880 37,719 29,355 475,339 361,100 480,286 Investments 37,402 43,274 41,380 Property, plant and equipment 2,623,613 2,294,389 2,496,123 Less accumulated depreciation, depletion and amortization 889,260 829,941 895,109 1,734,353 1,464,448 1,601,014 Deferred charges and other assets 231,564 136,939 190,279 $2,478,658 $2,005,761 $2,312,959 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Short-term borrowings $ --- $ --- $ 8,000 Long-term debt and preferred stock due within one year 9,531 3,856 19,695 Accounts payable 155,857 111,063 171,929 Taxes payable 6,944 3,571 10,437 Dividends payable 15,157 13,033 14,423 Other accrued liabilities, including reserved revenues 77,889 76,265 59,989 265,378 207,788 284,473 Long-term debt 748,646 695,030 728,166 Deferred credits and other liabilities: Deferred income taxes 317,611 220,693 281,000 Other liabilities 114,589 114,147 121,860 432,200 334,840 402,860 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, 68,273,213 at June 30, 2001, 61,519,748 at June 30, 2000 and 65,267,567 at December 31, 2000) 68,273 61,520 65,268 Other paid-in capital 601,527 440,856 518,771 Retained earnings 346,845 252,853 300,647 Accumulated other comprehensive income 3,015 --- --- Treasury stock at cost - 239,521 shares (3,626) (3,626) (3,626) Total common stockholders' equity 1,016,034 751,603 881,060 Total stockholders' equity 1,031,034 766,603 896,060 $2,478,658 $2,005,761 $2,312,959 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Six Months Ended June 30, 2001 2000 (In thousands) Operating activities: Net income $ 76,103 $ 34,490 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 66,531 46,445 Deferred income taxes and investment tax credit 5,185 10,245 Changes in current assets and liabilities, net of acquisitions: Receivables 55,132 (25,989) Inventories (14,446) 4,078 Other current assets 513 (12,602) Accounts payable (31,124) 21,537 Other current liabilities 9,734 4,071 Other noncurrent changes (7,154) (1,437) Net cash provided by operating activities 160,474 80,838 Investing activities: Capital expenditures including acquisitions of businesses (183,011) (208,853) Net proceeds from sale or disposition of property 33,728 2,341 Net capital expenditures (149,283) (206,512) Investments 3,556 64 Additions to notes receivable --- (5,000) Proceeds from notes receivable 4,000 4,000 Net cash used in investing activities (141,727) (207,448) Financing activities: Net change in short-term borrowings (8,000) (15,242) Issuance of long-term debt 62,109 147,476 Repayment of long-term debt (75,673) (18,802) Issuance of common stock 27,009 --- Dividends paid (29,905) (25,206) Net cash provided by (used in) financing activities (24,460) 88,226 Decrease in cash and cash equivalents (5,713) (38,384) Cash and cash equivalents -- beginning of year 36,512 77,504 Cash and cash equivalents -- end of period $ 30,799 $ 39,120 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 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: Six Months Ended June 30, 2001 2000 (In thousands) Interest, net of amount capitalized $ 20,399 $ 17,362 Income taxes $ 45,754 $ 13,844 4. New accounting pronouncements In June 2001, the Financial Accounting Standards Board (FASB) issued 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 will account for any future business combinations in accordance with SFAS No. 141. In June 2001, the FASB issued 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 has not yet quantified the effects of adopting SFAS No. 142 on its financial position or results of operations. In June 2001, the FASB issued 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. 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. 5. Derivative instruments As of June 30, 2001, the company held derivative instruments designated as cash flow hedging instruments and other derivative instruments in relation to its energy marketing operations which have not been designated as hedges. All derivative instruments are recognized on the Consolidated Balance Sheets at fair value. Hedging activities The cash flow hedging instruments in place at June 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 six months ended June 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 six months ended June 30, 2001, the amount of ineffectiveness recognized was immaterial. For the three months and six months ended June 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 June 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 18 months and the company estimates that net gains of $2.8 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 July 1, 2001 and June 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 In its energy marketing operations, the company enters into other derivative instruments that have not been designated as hedges. These derivative instruments are natural gas forward purchase and sale commitments. These commitments involve the purchase and sale of natural gas and related delivery of such commodity. The energy marketing operations seek to match natural gas purchases and sales on specific derivative instruments so that a margin is obtained on the transportation of such commodity as distinguished from earning a margin on changes in market prices. In addition, the energy marketing derivative instruments are generally entered into on a seasonal basis with a duration generally not exceeding 12 months. The net change in fair value representing unrealized gains and losses resulting from changes in market prices on these derivative instruments is 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 six months ended June 30, 2001 and 2000. The company is exposed to credit risk in relation to derivative instruments entered into at the company's energy marketing operations in the event of nonperformance by counterparties. The company maintains credit procedures, which management believes minimize credit-risk exposure. These procedures include applying specific eligibility criteria to prospective counterparties and may require letters of credit or similar security to secure payment on such sales contracts. However, despite mitigation efforts, defaults by counterparties may occur. To date, no such defaults have had a material effect on the company's financial position or results of operations. 6. 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 June 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 4 and 5 of the Notes to the Consolidated Financial Statements in this Form 10-Q. The company's comprehensive income, and the components of other comprehensive income, net of taxes, were as follows: Three Months Ended June 30, 2001 2000 (In thousands) Net income $ 43,417 $ 21,126 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 $2,413 3,755 --- Reclassification adjustment for losses on derivative instruments included in net income, net of tax of $172 263 --- Net unrealized gain on derivative instruments qualifying as hedges 4,018 --- Comprehensive income $ 47,435 $ 21,126 Six Months Ended June 30, 2001 2000 (In thousands) Net income $ 76,103 $ 34,490 Other comprehensive income - Net unrealized gain (loss) 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 $3,428 5,309 --- Reclassification adjustment for losses on derivative instruments included in net income, net of tax of $2,472 3,786 --- Net unrealized gain on derivative instruments qualifying as hedges 3,015 --- Comprehensive income $ 79,118 $ 34,490 7. 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's operations are conducted through six business 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 business 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 and provides energy-related marketing and management services in the Rocky Mountain, Midwest, Southern and Central regions of the United States 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, has 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 June 30, 2001 Electric $ 38,036 $ --- $ 2,152 Natural gas distribution 41,246 --- (1,547) Utility services 77,183 --- 3,873 Pipeline and energy services 147,111 7,432 3,383 Natural gas and oil production 40,517 14,884 17,888 Construction materials and mining 201,153 1,172* 17,477 Intersegment eliminations --- (22,316) --- Total $ 545,246 $ 1,172* $ 43,226 Three Months Ended June 30, 2000 Electric $ 36,401 $ --- $ 3,035 Natural gas distribution 29,038 --- (669) Utility services 24,352 --- 1,074 Pipeline and energy services 97,574 9,616 919 Natural gas and oil production 21,805 7,555 7,089 Construction materials and mining 150,984 2,825* 9,487 Intersegment eliminations --- (17,171) --- Total $ 360,154 $ 2,825* $ 20,935 * 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) Six Months Ended June 30, 2001 Electric $ 80,989 $ --- $ 6,959 Natural gas distribution 182,100 --- 1,127 Utility services 144,502 4 5,917 Pipeline and energy services 395,387 28,806 5,761 Natural gas and oil production 89,732 37,301 45,920 Construction materials and mining 289,939 5,016* 10,038 Intersegment eliminations --- (66,111) --- Total $1,182,649 $ 5,016* $ 75,722 Six Months Ended June 30, 2000 Electric $ 76,721 $ --- $ 6,259 Natural gas distribution 91,455 --- 1,910 Utility services 47,188 --- 1,527 Pipeline and energy services 245,312 30,113 3,648 Natural gas and oil production 44,848 11,745 13,498 Construction materials and mining 223,034 6,410* 7,265 Intersegment eliminations --- (41,858) --- Total $ 728,558 $ 6,410* $ 34,107 * In accordance with the provisions of SFAS No. 71, intercompany coal sales are not eliminated. The company acquired a construction materials and mining business in Minnesota and a utility services business based in Missouri during the first six months of 2001, neither of which was individually material. The total purchase consideration, consisting of the company's common stock and cash, for these businesses was $95.6 million. 8. 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. 9. 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, 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 for Stevens County, Kansas. Williston Basin and Montana-Dakota believe the claims of Grynberg and Quinque are without merit and intend to vigorously contest these suits. 10. 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 Six Months Ended Ended June 30, June 30, 2001 2000 2001 2000 Electric $ 2.1 $ 3.0 $ 7.0 $ 6.3 Natural gas distribution (1.5) (.7) 1.1 1.9 Utility services 3.9 1.1 5.9 1.5 Pipeline and energy services 3.3 .9 5.8 3.6 Natural gas and oil production 17.9 7.1 45.9 13.5 Construction materials and mining 17.5 9.5 10.0 7.3 Earnings on common stock $ 43.2 $ 20.9 $ 75.7 $ 34.1 Earnings per common share - basic $ .64 $ .35 $ 1.14 $ .58 Earnings per common share - diluted $ .63 $ .35 $ 1.13 $ .58 Return on average common equity for the 12 months ended 16.9% 13.0% ________________________________ Three Months Ended June 30, 2001 and 2000 Consolidated earnings for the quarter ended June 30, 2001, increased $22.3 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 and pipeline and energy services businesses, partially offset by lower earnings at the other business segments. Six Months Ended June 30, 2001 and 2000 Consolidated earnings for the six months ended June 30, 2001, increased $41.6 million from the comparable period a year ago due to higher earnings at the natural gas and oil production, utility services, construction materials and mining, 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 Six Months Ended Ended June 30, June 30, 2001 2000 2001 2000 Operating revenues: Retail sales $ 31.1 $ 30.5 $ 65.6 $ 64.5 Sales for resale and other 6.9 5.9 15.4 12.2 38.0 36.4 81.0 76.7 Operating expenses: Fuel and purchased power 14.6 11.8 27.7 26.2 Operation and maintenance 10.9 10.6 23.5 21.8 Depreciation, depletion and amortization 4.9 4.8 9.7 9.5 Taxes, other than income 1.8 1.9 3.8 4.0 32.2 29.1 64.7 61.5 Operating income $ 5.8 $ 7.3 $ 16.3 $ 15.2 Retail sales (million kWh) 493.4 483.9 1,043.1 1,030.4 Sales for resale (million kWh) 180.4 201.4 448.0 458.2 Average cost of fuel and purchased power per kWh $ .020 $ .016 $ .018 $ .017 Natural Gas Distribution Three Months Six Months Ended Ended June 30, June 30, 2001 2000 2001 2000 Operating revenues: Sales $ 40.4 $ 28.2 $180.1 $ 89.6 Transportation and other .9 .8 2.0 1.9 41.3 29.0 182.1 91.5 Operating expenses: Purchased natural gas sold 31.0 19.6 151.9 65.3 Operation and maintenance 8.8 7.2 19.5 15.9 Depreciation, depletion and amortization 2.4 1.9 4.7 3.8 Taxes, other than income 1.2 1.1 2.6 2.4 43.4 29.8 178.7 87.4 Operating income (loss) $ (2.1) $ (.8) $ 3.4 $ 4.1 Volumes (MMdk): Sales 5.4 4.7 21.6 18.0 Transportation 2.7 2.5 6.9 5.9 Total throughput 8.1 7.2 28.5 23.9 Degree days (% of normal) 99% 106% 98% 91% Average cost of natural gas, including transportation thereon, per dk $ 5.78 $ 4.13 $ 7.04 $ 3.63 Utility Services Three Months Six Months Ended Ended June 30, June 30, 2001 2000 2001 2000 Operating revenues $ 77.2 $ 24.4 $144.5 $ 47.2 Operating expenses: Operation and maintenance 66.7 20.6 125.7 40.5 Depreciation, depletion and amortization 1.7 .9 3.7 1.9 Taxes, other than income 1.8 .8 3.6 1.6 70.2 22.3 133.0 44.0 Operating income $ 7.0 $ 2.1 $ 11.5 $ 3.2 Pipeline and Energy Services Three Months Six Months Ended Ended June 30, June 30, 2001 2000 2001 2000 Operating revenues: Pipeline $ 21.2 $ 14.4 $ 42.3 $ 29.4 Energy services 133.3 92.8 381.9 246.0 154.5 107.2 424.2 275.4 Operating expenses: Purchased natural gas sold 129.1 91.3 376.2 240.3 Operation and maintenance 11.9 8.7 23.6 17.6 Depreciation, depletion and amortization 3.4 2.4 6.7 4.6 Taxes, other than income 1.5 1.0 3.0 2.4 145.9 103.4 409.5 264.9 Operating income $ 8.6 $ 3.8 $ 14.7 $ 10.5 Transportation volumes (MMdk): Montana-Dakota 9.0 6.9 17.5 15.7 Other 17.2 15.6 27.6 26.8 26.2 22.5 45.1 42.5 Gathering volumes (MMdk) 14.2 7.8 28.8 14.8 Natural Gas and Oil Production Three Months Six Months Ended Ended June 30, June 30, 2001 2000 2001 2000 Operating revenues: Natural gas $ 41.2 $ 15.6 $ 95.6 $ 29.6 Oil 12.9 10.6 26.4 21.0 Other 1.3 3.2 5.0 6.0 55.4 29.4 127.0 56.6 Operating expenses: Purchased natural gas sold 1.1 1.1 1.8 2.5 Operation and maintenance 11.7 7.9 22.7 14.8 Depreciation, depletion and amortization 10.6 5.7 20.1 11.2 Taxes, other than income 2.6 2.0 6.4 4.0 26.0 16.7 51.0 32.5 Operating income $ 29.4 $ 12.7 $ 76.0 $ 24.1 Production: Natural gas (MMcf) 10,031 6,371 19,720 12,837 Oil (000's of barrels) 488 471 982 942 Average realized prices: Natural gas (per Mcf) $ 4.10 $ 2.45 $ 4.85 $ 2.31 Oil (per barrel) $26.52 $22.51 $26.93 $22.24 Construction Materials and Mining Three Months Six Months Ended Ended June 30, June 30, 2001 2000 2001 2000 Operating revenues: Construction materials $199.4 $146.1 $282.7 $214.4 Coal 2.9 7.7 12.3 15.0 202.3 153.8 295.0 229.4 Operating expenses: Operation and maintenance 168.7 128.4 259.7 199.0 Depreciation, depletion and amortization 11.5 8.6 21.6 15.4 Taxes, other than income .5 .8 1.7 1.6 180.7 137.8 283.0 216.0 Operating income $ 21.6 $ 16.0 $ 12.0 $ 13.4 Sales (000's): Aggregates (tons) 6,239 4,683 8,928 6,810 Asphalt (tons) 1,298 863 1,422 956 Ready-mixed concrete (cubic yards) 721 419 1,112 707 Coal (tons) 268 694 1,171 1,372 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: $22.3 million, $21.4 million and $.9 million for the three months ended June 30, 2001; $17.2 million, $17.0 million and $.2 million for the three months ended June 30, 2000; $66.1 million, $64.3 million and $1.8 million for the six months ended June 30, 2001; and $41.8 million, $41.3 million and $.5 million for the six months ended June 30, 2000, respectively. Three Months Ended June 30, 2001 and 2000 Electric Electric earnings decreased due to higher fuel and purchased power costs, largely due to an extended maintenance outage at an electric power supplier's generating station, and lower sales for resale volumes. Due to the maintenance conducted at this station during the quarter, plant availability was diminished with resulting higher purchased power costs. Higher average sales for resale prices partially offset the earnings decrease. Natural Gas Distribution Normal seasonal losses at the natural gas distribution business increased, largely as a result of a normal seasonal loss at a natural gas utility business acquired in July 2000. Higher operation and maintenance expense, primarily increased bad debt expense, offset, in part, by decreased employee benefit costs, also added to the earnings decline. 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 at existing operations. Pipeline and Energy Services Earnings at the pipeline and energy services business increased due to higher transportation volumes at the pipeline combined with higher average rates, higher natural gas sales margins at energy services, increased pipeline and cable magnetization and locating services revenues and earnings from a pipeline acquisition in June 2000. Partially offsetting these results was a write-off of an investment in a software development company of $699,000 (after tax), higher operation and maintenance expense, primarily higher compressor-related expenses, and increased depreciation, depletion and amortization expense as a result of higher property, plant and equipment balances. Higher natural gas prices added to the increase in energy services revenue and the related increase in purchased natural gas sold. Natural Gas and Oil Production Natural gas and oil production earnings increased largely due to an increase in natural gas and oil production of 57 percent and 4 percent since last year, respectively, combined with higher realized natural gas and oil prices which were 67 percent and 18 percent higher than last year, respectively. 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 second quarter of 2001 and 2000 resulted in realized prices that were unchanged and 87 percent, respectively, of what otherwise would have been received. In addition, hedging activities for oil for the second quarter of 2001 and 2000 resulted in realized prices that were 102 and 84 percent, respectively, of what otherwise would have been received. Construction Materials and Mining Earnings for the construction materials and mining business increased 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 in Note 7 of Notes to Consolidated Financial Statements, partially offset by lower coal sales volumes due primarily to one month of operations in 2001 compared to three months in 2000. Earnings from existing operations at the construction materials business and from businesses acquired since the comparable period last year also added to the earnings improvement. Partially offsetting the earnings increase was the absence of last year's gain of $1.2 million after tax on the sale of nonstrategic property and increased interest expense, the result of higher acquisition-related borrowings. Six Months Ended June 30, 2001 and 2000 Electric Electric earnings increased due to higher average realized sales for resale prices, insurance recovery proceeds related to a 2000 outage at an electric generating station, and increased retail sales volumes, primarily to residential, commercial and large industrial customers. Increased fuel and purchased power costs, as previously described, higher operation and maintenance expense, primarily payroll and subcontractor costs, and decreased sales for resale volumes, partially offset the earnings increase. 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 increased 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. Partially offsetting the decline were increased sales due to weather that was 8 percent colder than 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 at existing operations. Pipeline and Energy Services Earnings at the pipeline and energy services business increased due to higher transportation volumes at the pipeline combined with higher average rates, higher natural gas sales margins at energy services, increased pipeline and cable magnetization and locating services revenues and earnings from a pipeline acquisition in June 2000. Partially offsetting the earnings increase were higher operation and maintenance expense, primarily higher compressor- related expenses, increased professional services and higher employee-benefit costs. The previously mentioned write-off of an investment, and increased depreciation, depletion and amortization expense as a result of higher property, plant and equipment balances also partially offset the earnings improvement. The increase in energy services revenue and the related increase in purchased natural gas sold resulted from higher natural gas prices. Natural Gas and Oil Production Natural gas and oil production earnings increased largely due to increased realized natural gas and oil prices which were 110 percent and 21 percent higher than last year, respectively, combined with higher natural gas and oil production of 54 percent and 4 percent since last year, respectively. The higher production was the result of a natural gas property acquisition in April 2000 and 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 rates. Partially offsetting the earnings improvement were increased depreciation, depletion and amortization expense, due to higher production volumes and higher rates, and increased operation and maintenance expense, mainly higher lease operating expenses and higher general and administrative costs. Hedging activities for natural gas for the six months ended June 30, 2001 and 2000 resulted in realized prices that were 96 and 93 percent, respectively, of what otherwise would have been received. In addition, hedging activities for oil for the six months ended June 30, 2001 and 2000 resulted in realized prices that were 102 and 84 percent, respectively, of what otherwise would have been received. Construction Materials and Mining Earnings for the construction materials and mining business increased due to the previously mentioned gain from the sale of the coal operations, partially offset by lower coal sales volumes due primarily to four months of operations in 2001 compared to six months in 2000. Earnings from existing operations at the construction materials business also added to the earnings improvement. Partially offsetting the earnings increase was the absence of the previously mentioned gain on the sale of nonstrategic property last year, increased interest expense, the result of higher acquisition-related borrowings, and normal seasonal losses realized in the first quarter of 2001 by businesses acquired since the comparable period last year. 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, 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 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 year will be in excess of 25 percent, excluding the gain on the sale of the company's coal operations and the write-off of an investment. * Earnings per share, diluted, for 2001 are projected in the $2.30 to $2.50 range, excluding the gain on the sale of the company's coal operations and the write-off of an investment. * The company expects the percentage of 2001 earnings per share for the remaining quarters to be in the following approximate ranges: - Third Quarter: 30 percent to 35 percent - Fourth Quarter: 20 percent to 25 percent * 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. * Goodwill amortization expense is expected to be approximately $4.5 million in 2001. 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. Currently, a smaller town in western North Dakota is considering municipalization of Montana-Dakota's electric facilities. Montana- Dakota is vigorously contesting any such proposal but is currently unable to determine the ultimate outcome of any such proceeding. 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 to 2 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. * 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. 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 for this segment is expected to increase by approximately 10 percent to 20 percent. Natural gas and oil production * The 2001 drilling program is projected to include over 500 wells, 90 percent of which are expected to be drilled on operated properties and the emphasis will continue to be on natural gas. During the six-month period ended June 30, 2001, 295 wells have been drilled. The 2001 drilling program is expected to be the single largest drilling program in the company's history. * Combined natural gas and oil production at this segment is expected to be approximately 30 percent higher in 2001 than in 2000. * The company's estimates for natural gas prices in the Rocky Mountain region for August through December 2001 are in the range of $2 to $3 per Mcf. The company's estimates for natural gas prices on the NYMEX for August through December 2001 are in the range of $3 to $4 per Mcf. * The company's estimates for NYMEX crude oil prices are in the range of $23 to $27 per barrel for August through December 2001. * 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 an oil swap agreement at an average NYMEX price of $25.25 per barrel, representing approximately 5 percent to 10 percent of the company's 2002 estimated annual oil production. The company has also 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. Construction materials and mining * Aggregate, asphalt and ready-mixed concrete volumes are expected to increase by approximately 40 percent to 50 percent, 80 percent to 90 percent and 45 percent to 55 percent, respectively, in 2001. * This segment expects to achieve compound annual revenue and earnings growth rates of approximately 10 percent to 20 percent over the next five years. * As of mid-July, the construction materials and mining unit had approximately $260 million in backlog. * This segment estimates it currently has approximately one billion tons of strategically located economically recoverable aggregate reserves. New Accounting Standards In June 2001, the Financial Accounting Standards Board (FASB) issued 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). For more information on SFAS No. 141, SFAS No. 142 and SFAS No. 143, see Note 4 of Notes to Consolidated Financial Statements. Liquidity and Capital Commitments Net capital expenditures for the year 2001 are estimated at $499.3 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 June 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 three completed 2001 acquisitions including a construction materials and mining company based in Hawaii that was acquired in July 2001, a construction materials and mining company based in Minnesota that was acquired in April 2001 and a utility services company based in Missouri that was acquired in January 2001. 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 on behalf of its subsidiaries that supports $315 million of Centennial's $325 million commercial paper program. Under the commercial paper program, $251.9 million was outstanding at June 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 on behalf of its subsidiaries that allows for borrowings of up to $200 million. Under the master shelf agreement, $150 million was outstanding at June 30, 2001. 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 June 30, 2001, the company could have issued approximately $301 million of additional first mortgage bonds. The company's coverage of fixed charges including preferred dividends was 5.0 times and 4.1 times for the twelve months ended June 30, 2001, and December 31, 2000, respectively. Additionally, the company's first mortgage bond interest coverage was 9.1 times and 8.3 times for the twelve months ended June 30, 2001, and December 31, 2000, respectively. Common stockholders' equity as a percent of total capitalization was 57 percent and 54 percent at June 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 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. On May 18, 2001, the Federal District Court denied Williston Basin's and Montana-Dakota's motion to dismiss in the Grynberg legal proceeding. For more information on these legal actions, see Note 9 of Notes to Consolidated Financial Statements. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS Between April 1, 2001 and June 30, 2001, the company issued 1,651,486 shares of Common Stock, $1.00 par value, as part of the consideration 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 issued by the company in these transactions was issued in private sales exempt from registration pursuant to Section 4(2) of the Securities Act of 1933. The former owners of the businesses acquired, and now shareholders of the company, are accredited investors and have acknowledged that they would hold the company's Common Stock as an investment and not with a view to distribution. 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 July 26, 2001. Under Item 5 -- Other Events, the company reported the press release issued July 25, 2001, regarding earnings for the quarter ended June 30, 2001. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. MDU RESOURCES GROUP, INC. DATE August 13, 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