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 MARCH 31, 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 May 7, 2001: 67,928,033 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. 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. On May 11, 2001, the company announced that the sale of its coal operations to Westmoreland Coal Company has been finalized. For more information on the above sale see Note 7 of Notes to Consolidated Financial Statements and Prospective Information contained in Item 2 -- Management's Discussion and Analysis of Financial Condition and Results of Operations. 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 Holdings Capital Corp. anticipates making investments 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 Months Ended March 31, 2001 and 2000 Consolidated Balance Sheets -- March 31, 2001 and 2000, and December 31, 2000 Consolidated Statements of Cash Flows -- Three Months Ended March 31, 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 Ended March 31, 2001 2000 (In thousands, except per share amounts) Operating revenues $641,248 $371,989 Operating expenses: Fuel and purchased power 13,088 14,399 Purchased natural gas sold 325,771 171,770 Operation and maintenance 195,086 125,918 Depreciation, depletion and amortization 32,096 22,139 Taxes, other than income 11,686 8,333 577,727 342,559 Operating income 63,521 29,430 Other income -- net 2,358 2,368 Interest expense 11,714 10,281 Income before income taxes 54,165 21,517 Income taxes 21,478 8,153 Net income 32,687 13,364 Dividends on preferred stocks 191 192 Earnings on common stock $ 32,496 $ 13,172 Earnings per common share -- basic $ .50 $ .23 Earnings per common share -- diluted $ .49 $ .23 Dividends per common share $ .22 $ .21 Weighted average common shares outstanding -- basic 65,405 57,051 Weighted average common shares outstanding -- diluted 65,979 57,188 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, March 31, December 31, 2001 2000 2000 (In thousands) ASSETS Current assets: Cash and cash equivalents $ 30,978 $ 37,622 $ 36,512 Receivables 312,790 179,585 342,354 Inventories 65,146 57,468 64,017 Deferred income taxes 12,834 16,564 8,048 Prepayments and other current assets 27,193 29,452 29,355 448,941 320,691 480,286 Investments 42,101 42,907 41,380 Property, plant and equipment 2,557,908 2,066,881 2,496,123 Less accumulated depreciation, depletion and amortization 919,627 809,568 895,109 1,638,281 1,257,313 1,601,014 Deferred charges and other assets 198,285 122,959 190,279 $2,327,608 $1,743,870 $2,312,959 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Short-term borrowings $ --- $ --- $ 8,000 Long-term debt and preferred stock due within one year 9,228 3,841 19,695 Accounts payable 148,244 98,245 171,929 Taxes payable 33,127 13,704 10,437 Dividends payable 14,751 12,174 14,423 Other accrued liabilities, including reserved revenues 91,012 80,412 59,989 296,362 208,376 284,473 Long-term debt 679,094 518,164 728,166 Deferred credits and other liabilities: Deferred income taxes 283,982 215,621 281,000 Other liabilities 123,514 114,117 121,860 407,496 329,738 402,860 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, 66,441,325 at March 31, 2001, 57,296,167 at March 31, 2000 and 65,267,567 at December 31, 2000) 66,441 57,296 65,268 Other paid-in capital 547,859 372,661 518,771 Retained earnings 318,585 244,761 300,647 Accumulated other comprehensive loss (1,003) --- --- Treasury stock at cost - 239,521 shares (3,626) (3,626) (3,626) Total common stockholders' equity 928,256 671,092 881,060 Total stockholders' equity 943,256 686,092 896,060 $2,327,608 $1,743,870 $2,312,959 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, 2001 2000 (In thousands) Operating activities: Net income $ 32,687 $ 13,364 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 32,096 22,139 Deferred income taxes and investment tax credit (931) 969 Changes in current assets and liabilities, net of acquisitions: Receivables 53,030 (9,938) Inventories (948) 7,250 Other current assets 6,387 (5,028) Accounts payable (35,054) 16,966 Other current liabilities 49,714 19,346 Other noncurrent changes (4,372) 71 Net cash provided by operating activities 132,609 65,139 Investing activities: Capital expenditures including acquisitions of businesses (87,069) (32,628) Net proceeds from sale or disposition of property 4,194 1,219 Net capital expenditures (82,875) (31,409) Investments 3 221 Additions to notes receivable --- (5,000) Proceeds from notes receivable 4,000 4,000 Net cash used in investing activities (78,872) (32,188) Financing activities: Net change in short-term borrowings (8,000) (14,693) Issuance of long-term debt 60,000 25,400 Repayment of long-term debt (121,971) (71,368) Issuance of common stock 25,449 --- Dividends paid (14,749) (12,172) Net cash used in financing activities (59,271) (72,833) Decrease in cash and cash equivalents (5,534) (39,882) Cash and cash equivalents -- beginning of year 36,512 77,504 Cash and cash equivalents -- end of period $ 30,978 $ 37,622 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS March 31, 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: Three Months Ended March 31, 2001 2000 (In thousands) Interest, net of amount capitalized $7,168 $4,728 Income taxes $ 280 $ 600 4. New accounting pronouncement 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." 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 March 31, 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 March 31, 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 ended March 31, 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 ended March 31, 2001, the amount of ineffectiveness recognized was immaterial. For the three months ended March 31, 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 March 31, 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 nine months and the company estimates that losses of $1.0 million will be reclassified from accumulated other comprehensive loss into earnings, subject to changes in natural gas and oil market prices and interest rates, within the nine months between April 1, 2001 and December 31, 2001 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 ended March 31, 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 March 31, 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 loss, net of taxes, were as follows: Three Months Ended March 31, 2001 2000 (In thousands) Net income $ 32,687 $ 13,364 Other comprehensive loss - unrealized 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) --- Unrealized gain on derivative instruments arising during the period, net of tax of $1,631 2,498 --- Reclassification adjustment for losses on derivative instruments included in net income, net of tax of $1,684 2,579 --- Net unrealized loss on derivative instruments qualifying as hedges (1,003) --- Comprehensive income $ 31,684 $ 13,364 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. 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. 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 will record a gain from the sale in the second quarter of 2001. The company's estimate of the gain on the sale of the coal operations is in the range of $4 million to $8 million after tax and is subject to various post-closing adjustments. 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 March 31, 2001 Electric $ 42,953 $ --- $ 4,807 Natural gas distribution 140,855 --- 2,674 Utility services 67,319 4 2,044 Pipeline and energy services 248,276 21,374 2,378 Natural gas and oil production 49,215 22,417 28,032 Construction materials and mining 88,787 3,843* (7,439) Intersegment eliminations --- (43,795) --- Total $ 637,405 $ 3,843* $ 32,496 Three Months Ended March 31, 2000 Electric $ 40,320 $ --- $ 3,223 Natural gas distribution 62,417 --- 2,580 Utility services 22,836 --- 453 Pipeline and energy services 147,738 20,497 2,729 Natural gas and oil production 23,043 4,190 6,409 Construction materials and mining 72,050 3,585* (2,222) Intersegment eliminations --- (24,687) --- Total $ 368,404 $ 3,585* $ 13,172 * 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. 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, which is subject to revision by the FERC, on Williston Basin's natural gas rate change application. Williston Basin is evaluating the implications of the Initial Decision. 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. Williston Basin and Montana- Dakota are awaiting a decision from the Federal District Court. 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 and energy marketing and management services. 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 Ended March 31, 2001 2000 Electric $ 4.8 $ 3.2 Natural gas distribution 2.7 2.6 Utility services 2.0 .5 Pipeline and energy services 2.4 2.7 Natural gas and oil production 28.0 6.4 Construction materials and mining (7.4) (2.2) Earnings on common stock $ 32.5 $ 13.2 Earnings per common share - basic $ .50 $ .23 Earnings per common share - diluted $ .49 $ .23 Return on average common equity for the 12 months ended 15.6% 13.4% ________________________________ Three Months Ended March 31, 2001 and 2000 Consolidated earnings for the quarter ended March 31, 2001, increased $19.3 million from the comparable period a year ago due to higher earnings at the natural gas and oil production, utility services, electric, and natural gas distribution businesses, partially offset by lower earnings at the other business segments. 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 Ended March 31, 2001 2000 Operating revenues: Retail sales $ 34.5 $ 34.0 Sales for resale and other 8.5 6.3 43.0 40.3 Operating expenses: Fuel and purchased power 13.1 14.4 Operation and maintenance 12.6 11.3 Depreciation, depletion and amortization 4.9 4.7 Taxes, other than income 2.0 2.1 32.6 32.5 Operating income $ 10.4 $ 7.8 Retail sales (million kWh) 549.7 546.5 Sales for resale (million kWh) 267.6 256.8 Average cost of fuel and purchased power per kWh $ .015 $ .017 Natural Gas Distribution Three Months Ended March 31, 2001 2000 Operating revenues: Sales $ 139.7 $ 61.4 Transportation and other 1.2 1.0 140.9 62.4 Operating expenses: Purchased natural gas sold 120.9 45.8 Operation and maintenance 10.8 8.5 Depreciation, depletion and amortization 2.3 1.9 Taxes, other than income 1.4 1.3 135.4 57.5 Operating income $ 5.5 $ 4.9 Volumes (MMdk): Sales 16.2 13.3 Transportation 4.2 3.4 Total throughput 20.4 16.7 Degree days (% of normal) 98% 87% Average cost of natural gas, including transportation thereon, per dk $ 7.46 $ 3.45 Utility Services Three Months Ended March 31, 2001 2000 Operating revenues $ 67.3 $ 22.8 Operating expenses: Operation and maintenance 59.1 20.0 Depreciation, depletion and amortization 1.9 .9 Taxes, other than income 1.8 .8 62.8 21.7 Operating income $ 4.5 $ 1.1 Pipeline and Energy Services Three Months Ended March 31, 2001 2000 Operating revenues: Pipeline $ 21.0 $ 15.1 Energy services 248.6 153.2 269.6 168.3 Operating expenses: Purchased natural gas sold 247.0 149.1 Operation and maintenance 11.6 8.9 Depreciation, depletion and amortization 3.4 2.2 Taxes, other than income 1.5 1.4 263.5 161.6 Operating income $ 6.1 $ 6.7 Transportation volumes (MMdk): Montana-Dakota 8.5 8.7 Other 10.4 11.3 18.9 20.0 Gathering volumes (MMdk) 14.6 7.1 Natural Gas and Oil Production Three Months Ended March 31, 2001 2000 Operating revenues: Natural gas $ 54.4 $ 14.0 Oil 13.5 10.4 Other 3.7 2.8 71.6 27.2 Operating expenses: Purchased natural gas sold .7 1.3 Operation and maintenance 11.0 6.9 Depreciation, depletion and amortization 9.5 5.6 Taxes, other than income 3.8 2.0 25.0 15.8 Operating income $ 46.6 $ 11.4 Production: Natural gas (MMcf) 9,689 6,466 Oil (000's of barrels) 494 471 Average realized prices: Natural gas (per Mcf) $ 5.62 $ 2.17 Oil (per barrel) $ 27.33 $ 21.97 Construction Materials and Mining Three Months Ended March 31, 2001 2000 Operating revenues: Construction materials $ 83.2 $ 68.4 Coal 9.4 7.2 92.6 75.6 Operating expenses: Operation and maintenance 90.9 70.5 Depreciation, depletion and amortization 10.1 6.8 Taxes, other than income 1.2 .8 102.2 78.1 Operating loss $ (9.6) $ (2.5) Sales (000's): Aggregates (tons) 2,689 2,126 Asphalt (tons) 124 93 Ready-mixed concrete (cubic yards) 391 288 Coal (tons) 904 678 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: $43.8 million, $42.9 million and $.9 million for the three months ended March 31, 2001; and $24.6 million, $24.4 million and $.2 million for the three months ended March 31, 2000, respectively. Three Months Ended March 31, 2001 and 2000 Electric Electric earnings increased due to increased sales for resale volumes at higher average realized rates, primarily the result of a strong sales for resale market, and lower fuel and purchased power costs, largely due to insurance recovery proceeds related to a 2000 outage at an electric generating station. Higher operation and maintenance expense, primarily increased payroll expense and higher subcontractor costs, partially offset the earnings increase. Natural Gas Distribution Earnings increased at the natural gas distribution business due to higher retail sales volumes resulting from weather that was 12 percent colder than the comparable period last year and earnings from a business acquired in July 2000. This increase was largely offset by higher operation and maintenance expense, primarily increased payroll expense and higher bad debt expense. Lower service and repair margins and lower average realized rates, also partially offset the earnings improvement. Significantly higher natural gas prices also added to the increase in sales revenue and purchased natural gas sold. Utility Services Utility services earnings increased as a result of higher line construction margins in the Rocky Mountain region, primarily related to fiber-optic-cable installation projects, and earnings from businesses acquired since the comparable period last year. Pipeline and Energy Services Earnings at the pipeline and energy services business decreased due to higher operation and maintenance expense, primarily higher compressor-related expenses and outside services, and decreased storage revenues. Higher natural gas throughput at the pipeline partially offset the earnings decline. The increase in energy services revenue and the related increase in purchased natural gas sold resulted from significantly higher natural gas prices. Natural Gas and Oil Production Natural gas and oil production earnings increased largely due to an increase in natural gas and oil production of 50 percent and 5 percent since last year, respectively, combined with higher realized natural gas and oil prices which were 159 percent and 24 percent higher than last year, respectively. The higher production was due to an acquisition since the comparable period last year and ongoing development of existing properties. Higher margins on inventoried natural gas also added to the earnings increase. 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 due primarily to an acquisition. Hedging activities for natural gas for the first three months of 2001 resulted in realized prices that were 93 percent of what otherwise would have been received. Hedging activities for natural gas for the first three months of 2000 resulted in realized prices that were unchanged. In addition, hedging activities for oil for the first three months 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 decreased largely due to lower earnings at the construction materials operations as a result of normal seasonal losses realized in the first quarter of 2001 by businesses acquired since the comparable period last year and higher interest expense resulting from higher acquisition-related borrowings. Also adding to the earnings decline were increased selling, general and administrative costs and decreased construction activity, due to weather-related delays, partially offset by increased aggregate and ready-mixed concrete volumes at existing construction materials operations. Earnings at the coal operations improved mainly due to increased coal volumes. 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. * The company anticipates that its earnings per share growth rate from operations for 2001 will be in excess of 25 percent. * Earnings per share, diluted, from operations for 2001 are projected in the $2.30 to $2.50 range, excluding a gain from the sale of the company's coal operations. * The company expects the percentage of 2001 earnings per share from operations for the following quarters to be in the following approximate ranges: - Second Quarter: 20 to 25 percent - Third Quarter: 30 to 35 percent - Fourth Quarter: 20 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. * Based on existing operations and current accounting rules, annual goodwill amortization expense is expected to be approximately $4.7 million. 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 North Dakota Lignite Research Council to determine the feasibility of constructing a 500 megawatt class lignite-fired power plant in western North Dakota. Natural gas distribution * Annual natural gas throughput for 2001 is expected to be approximately 55 million decatherms, with about 39 million decatherms from sales and 16 million from transportation. * The number of natural gas retail customers at existing operations is expected to grow by approximately 1.5 to 2 percent on an annual basis over the next three to five years. * This business segment expects growth in sales of new value- added products and services, such as appliance repair contracts and home security systems. Utility services * This segment is growing both internally and through acquisitions of utility services companies. The company's strategy is to acquire utility services businesses that are well managed, have excellent reputations and are growth-driven. * Revenues for the utility services segment are expected to exceed $300 million in 2001. * This business segment's goal is to achieve compound annual revenue and earnings growth rates of approximately 20 to 25 percent over the next five years. Pipeline and energy services * Two pipeline projects related to the company's coal bed natural gas drilling program in the Powder River Basin of Wyoming and Montana were completed in 2000. The two projects provide the pipeline company the ability to move approximately 40 percent more coal bed natural gas through its system than has historically been transported, as well as enabling additional deliveries to other pipeline systems. The largest project involved building a 75-mile, nonregulated pipeline through the heart of the basin, to move gas produced from throughout the Powder River Basin 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 to 20 percent. * This segment continues business development activities looking for assets and resources or system expansions that add value to existing operations through further vertical integration of its natural gas delivery and storage systems. 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 company operated properties and the emphasis will continue to be on natural gas. The 2001 drilling program is expected to be the single largest drilling program in the company's history. * During the first quarter of 2001, 159 wells were drilled, 98 percent of which were completed. * Combined natural gas and oil production in 2000 totaled 40.5 Bcf equivalents - a daily average of 111,000 Mcf equivalents. For the month of March 2001, combined production averaged 135,500 Mcf equivalents per day, which was 38 percent higher than March 2000. * Currently, there are approximately 165 wells producing in the Powder River Basin of Wyoming and Montana. For the month of March, gross production averaged 19,200 Mcf equivalents per day. * Combined natural gas and oil production at this business 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 April through December 2001 are in the range of $3.15 to $4.15 per Mcf. The company's estimates for natural gas prices on the NYMEX for April through December 2001 are in the range of $3.75 to $4.75 per Mcf. * The company's estimates for NYMEX crude oil prices are in the range of $23 to $27 per barrel for April through December 2001. * This business 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 25 to 30 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 35 to 40 percent of 2001 estimated annual oil production is hedged at NYMEX prices ranging from $27.51 to $29.22 per barrel. * This business segment has entered into a hedging arrangement for 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. This swap agreement represents approximately 8 percent of the company's 2002 estimated annual oil production. At this time, the company has not entered into any natural gas swap agreements for 2002 natural gas production. However, the company has approximately 10 percent of its estimated 2002 annual natural gas production under fixed price forward sales. Construction materials and mining * 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. 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 will record a gain from the sale in the second quarter of 2001. The company's estimate of the gain on the sale of the coal operations is in the range of $4 million to $8 million after tax and is subject to various post-closing adjustments. While the sale will add to the company's 2001 earnings, future earnings will be decreased as a result of the loss of earnings from the coal operations. Earnings from coal operations would normally be expected to contribute less than 10 percent of annual earnings of the construction materials and mining segment. * The construction materials and mining business estimates that it currently has nearly one billion tons of economically recoverable aggregate reserves. These reserves are strategically located and represent more than a 40-year supply at current consumption levels. * Including the effects of acquisitions completed in 2000 and 2001, aggregate, asphalt and ready-mixed concrete volumes are expected to increase by approximately 35 to 45 percent, 80 to 90 percent and 35 to 45 percent, respectively, in 2001. * As of mid-April, the construction materials and mining unit had approximately $197 million in backlog. * This segment expects to achieve compound annual revenue and earnings growth rates of approximately 10 to 20 percent over the next five years. * Earnings are expected to increase from a combination of acquisitions and by optimizing both synergies and improvements at existing operations. Liquidity and Capital Commitments Net capital expenditures for the year 2001 are estimated at $354.1 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. The company continues to evaluate potential future acquisitions; however, these acquisitions 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 March 31, 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 two completed 2001 acquisitions including a construction materials and mining company based in Minnesota that was acquired in mid-April 2001 and a utility services company based in Missouri that was acquired in early 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, $192.9 million was outstanding at March 31, 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 due September 29, 2003. 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 March 31, 2001. On March 6, 2001, the company reported the sale of 358,429 shares of the company's Common Stock to Paul Revere Capital Partners Ltd. (Paul Revere), pursuant to a purchase agreement by and between the company and Paul Revere. The company received proceeds from this sale of $10 million. These proceeds were 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 March 31, 2001, the company could have issued approximately $297 million of additional first mortgage bonds. The company's coverage of fixed charges including preferred dividends was 4.5 times and 4.1 times for the twelve months ended March 31, 2001, and December 31, 2000, respectively. Additionally, the company's first mortgage bond interest coverage was 9.0 times and 8.3 times for the twelve months ended March 31, 2001, and December 31, 2000, respectively. Common stockholders' equity as a percent of total capitalization was 57 percent and 54 percent at March 31, 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 March 5, 2001, the North Dakota District Court entered a final judgment on the July 2000 order granting the motions for summary judgment to dismiss the claims of the 11 natural gas producers. 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. Upon motion of plaintiffs, the Quinque case has been remanded to State District Court for Stevens County, Kansas. For more information on the above legal actions see Note 9 of Notes to Consolidated Financial Statements. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS Between January 1, 2001 and March 31, 2001, the company issued 264,728 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The company's Annual Meeting of Stockholders was held on April 24, 2001. Two proposals were submitted to stockholders as described in the company's Proxy Statement dated March 9, 2001, and were voted upon and approved by stockholders at the meeting. The table below briefly describes the proposals and the results of the stockholder votes. Shares Shares Against or Broker For Withheld Abstentions Non-Votes Proposal to amend the 1997 Executive Long-Term Incentive Plan 31,528,117 8,272,505 1,038,761 12,770,086 Proposal to elect five directors: For terms expiring in 2004 -- Dennis W. Johnson 51,899,581 1,709,888 --- --- John L. Olson 53,240,868 368,601 --- --- Joseph T. Simmons 53,221,546 387,923 --- --- Martin A. White 53,269,790 339,679 --- --- For a term expiring in 2002 -- Douglas C. Kane 53,212,205 397,264 --- --- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a) Exhibits 10(a) 1997 Executive Long-Term Incentive Plan, as amended to date 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 March 8, 2001. Under Item 5 -- Other Events, the company reported the sale of 358,429 shares of company Common Stock to Paul Revere Capital Partners Ltd. Form 8-K was filed on March 20, 2001. Under Item 5 -- Other Events, the company reported the press release issued March 14, 2001 regarding revised earnings forecast for 2001. Form 8-K was filed on April 25, 2001. Under Item 5 -- Other Events, the company reported the press release issued April 24, 2001 regarding earnings for the quarter ended March 31, 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 May 14, 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. 10(a) 1997 Executive Long-Term Incentive Plan, as amended to date 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends