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, 1999 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, 1999: 53,156,004 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 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), the public utility division of the company, distributes natural gas and operates electric power generation, transmission and distribution facilities, serving 256 communities in North Dakota, eastern Montana, northern and western South Dakota and northern Wyoming. The company, through its wholly owned subsidiary, Centennial Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI Holdings), Knife River Corporation (Knife River), the Fidelity Oil Group (Fidelity Oil) and Utility Services, Inc. (Utility Services). WBI Holdings, through its wholly owned subsidiaries, provides underground storage, transportation and gathering services through an interstate pipeline system serving Montana, North Dakota, South Dakota and Wyoming, produces natural gas, and seeks new energy markets while continuing to expand present markets for natural gas and propane in the Midwestern, Southern and Central regions of the United States. Knife River, through its wholly owned subsidiary, KRC Holdings, Inc. (KRC Holdings) and its subsidiaries, mines and markets aggregates and construction materials in Alaska, California, Hawaii and Oregon, and operates lignite coal mines in Montana and North Dakota. Fidelity Oil is comprised of Fidelity Oil Co. and Fidelity Oil Holdings, Inc., which own oil and natural gas interests throughout the United States, the Gulf of Mexico and Canada. Utility Services, through its wholly owned subsidiaries, installs and repairs electric transmission and distribution power lines, fiber optic cable and natural gas pipeline and provides related supplies, equipment and engineering services throughout the western United States and Hawaii. INDEX Part I -- Financial Information Consolidated Statements of Income -- Three Months Ended March 31, 1999 and 1998 Consolidated Balance Sheets -- March 31, 1999 and 1998, and December 31, 1998 Consolidated Statements of Cash Flows -- Three Months Ended March 31, 1999 and 1998 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, 1999 1998 (In thousands, except per share amounts) Operating revenues: Electric $ 58,974 $ 44,740 Natural gas 128,931 73,543 Construction materials and mining 60,038 38,961 Oil and natural gas production 11,103 12,878 259,046 170,122 Operating expenses: Fuel and purchased power 13,503 11,833 Purchased natural gas sold 90,705 32,175 Operation and maintenance 101,999 69,723 Depreciation, depletion and amortization 20,140 17,789 Taxes, other than income 7,238 6,393 233,585 137,913 Operating income: Electric 11,175 8,448 Natural gas distribution 5,464 6,793 Natural gas transmission 9,135 12,895 Construction materials and mining (1,239) 1,158 Oil and natural gas production 926 2,915 25,461 32,209 Other income -- net 3,768 2,602 Interest expense 8,806 7,135 Income before income taxes 20,423 27,676 Income taxes 7,702 9,883 Net income 12,721 17,793 Dividends on preferred stocks 193 194 Earnings on common stock $ 12,528 $ 17,599 Earnings per common share -- basic $ .24 $ .39 Earnings per common share -- diluted $ .23 $ .39 Dividends per common share $ .20 $ .1917 Weighted average common shares outstanding -- basic 53,147 45,375 Weighted average common shares outstanding -- diluted 53,420 45,629 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, 1999 1998 1998 (In thousands) ASSETS Current assets: Cash and cash equivalents $ 36,930 $ 50,857 $ 39,216 Receivables 123,639 89,131 124,114 Inventories 43,176 34,549 44,865 Deferred income taxes 20,974 17,896 16,918 Prepayments and other current assets 17,849 18,896 15,536 242,568 211,329 240,649 Investments 40,550 18,131 43,029 Property, plant and equipment: Electric 587,299 567,416 583,047 Natural gas distribution 179,396 173,468 178,522 Natural gas transmission 312,766 289,781 304,054 Construction materials and mining 493,080 414,520 484,419 Oil and natural gas production 264,478 250,341 260,758 1,837,019 1,695,526 1,810,800 Less accumulated depreciation, depletion and amortization 741,392 686,642 726,123 1,095,627 1,008,884 1,084,677 Deferred charges and other assets 95,289 72,933 84,420 $1,474,034 $1,311,277 $1,452,775 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Short-term borrowings $ 122 $ 1,625 $ 15,000 Long-term debt and preferred stock due within one year 2,502 10,436 3,292 Accounts payable 61,326 31,128 60,023 Taxes payable 20,540 16,508 9,226 Dividends payable 10,824 9,633 10,799 Other accrued liabilities, including reserved revenues 85,756 79,701 71,129 181,070 149,031 169,469 Long-term debt 417,778 338,073 413,264 Deferred credits and other liabilities: Deferred income taxes 173,885 178,899 173,094 Other liabilities 128,777 140,664 129,506 302,662 319,563 302,600 Preferred stock subject to mandatory redemption 1,600 1,700 1,600 Commitments and contingencies Stockholders' equity: Preferred stocks 15,000 15,000 15,000 Common stockholders' equity: Common stock (Shares issued -- $3.33 par value, 53,395,525 at March 31, 1999, 32,991,683 at March 31, 1998 and 53,272,951 at December 31, 1998) 177,807 109,862 177,399 Other paid-in capital 174,264 160,792 171,486 Retained earnings 207,479 220,882 205,583 Treasury stock at cost -- 239,521 shares at March 31, 1999 and December 31, 1998 and 159,681 shares at March 31, 1998 (3,626) (3,626) (3,626) Total common stockholders' equity 555,924 487,910 550,842 Total stockholders' equity 570,924 502,910 565,842 $1,474,034 $1,311,277 $1,452,775 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, 1999 1998 (In thousands) Operating activities: Net income $ 12,721 $ 17,793 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 20,140 17,789 Deferred income taxes and investment tax credit (3,352) 450 Changes in current assets and liabilities: Receivables 475 7,785 Inventories 1,689 10,577 Other current assets (2,313) (3,295) Accounts payable 1,303 (3,368) Other current liabilities 25,966 (6,322) Other noncurrent changes (11,453) (4,190) Net cash provided by operating activities 45,176 37,219 Financing activities: Net change in short-term borrowings (14,878) (7,722) Issuance of long-term debt 25,089 37,301 Repayment of long-term debt (21,366) (6,670) Issuance of common stock 3,186 --- Retirement of natural gas repurchase commitment (1,288) (4,786) Dividends paid (10,825) (9,634) Net cash provided by (used in) financing activities (20,082) 8,489 Investing activities: Capital expenditures including acquisitions of businesses: Electric (5,159) (2,779) Natural gas distribution (2,211) (1,617) Natural gas transmission (9,256) (1,117) Construction materials and mining (12,231) (11,054) Oil and natural gas production (8,751) (10,935) (37,608) (27,502) Net proceeds from sale or disposition of property 7,130 946 Net capital expenditures (30,478) (26,556) Sale of natural gas available under repurchase commitment 619 2,727 Investments 2,479 804 Net cash used in investing activities (27,380) (23,025) Increase (decrease) in cash and cash equivalents (2,286) 22,683 Cash and cash equivalents -- beginning of year 39,216 28,174 Cash and cash equivalents -- end of period $ 36,930 $ 50,857 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS March 31, 1999 and 1998 (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, 1998 (1998 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 1998 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. For the three months ended March 31, 1999 and 1998, comprehensive income equaled net income as reported. 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, 1999 1998 (In thousands) Interest, net of amount capitalized $3,131 $3,033 Income taxes $ 130 $ 437 4. Reclassifications Certain reclassifications have been made in the financial statements for the prior period to conform to the current presentation. Such reclassifications had no effect on net income or common stockholders' equity as previously reported. 5. New accounting pronouncement In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's 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 is effective for fiscal years beginning after June 15, 1999. SFAS No. 133 must be applied to derivative instruments and certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997. The company will adopt SFAS No. 133 on January 1, 2000, and has not yet quantified the impacts of adopting SFAS No. 133 on the company's financial position or results of operations. 6. Derivatives Williston Basin Interstate Pipeline Company (Williston Basin), a wholly owned subsidiary of WBI Holdings, and Fidelity Oil have entered into certain price swap and collar agreements to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas. These swap and collar agreements are not held for trading purposes. The swap and collar agreements call for Williston Basin and Fidelity Oil to receive monthly payments from or make payments to counterparties based upon the difference between a fixed and a variable price as specified by the agreements. The variable price is either an oil price quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural gas price on the NYMEX or Colorado Interstate Gas Index. The company believes that there is a high degree of correlation because the timing of purchases and production and the swap and collar agreements are closely matched, and hedge prices are established in the areas of operations. Amounts payable or receivable on the swap and collar agreements are matched and reported in operating revenues on the Consolidated Statements of Income as a component of the related commodity transaction at the time of settlement with the counterparty. The amounts payable or receivable are generally offset by corresponding increases and decreases in the value of the underlying commodity transactions. Innovative Gas Services, Incorporated, an indirect energy marketing subsidiary of WBI Holdings, participates in the natural gas futures market to hedge a portion of the price risk associated with natural gas purchase and sale commitments. These futures are not held for trading purposes. Gains or losses on the futures contracts are deferred until the transaction occurs, at which point they are reported in "Purchased natural gas sold" on the Consolidated Statements of Income. The gains or losses on the futures contracts are generally offset by corresponding increases and decreases in the value of the underlying commodity transactions. Knife River had entered into an interest rate swap agreement, which expired in August 1998, to manage a portion of its interest rate exposure on long-term debt. This interest rate swap agreement was not held for trading purposes. The interest rate swap agreement called for Knife River to receive quarterly payments from or make payments to counterparties based upon the difference between fixed and variable rates as specified by the interest rate swap agreement. The variable prices were based on the three-month floating London Interbank Offered Rate. Settlement amounts payable or receivable under this interest rate swap agreement were recorded in "Interest expense" on the Consolidated Statements of Income in the accounting period they were incurred. The amounts payable or receivable were generally offset by interest on the related debt instrument. The company's policy prohibits the use of derivative instruments for trading purposes and the company has procedures in place to monitor compliance with its policies. The company is exposed to credit-related losses in relation to financial instruments in the event of nonperformance by counterparties, but does not expect any counterparties to fail to meet their obligations given their existing credit ratings. The following table summarizes the company's hedging activity (notional amounts in thousands): Three Months Ended March 31, 1999 1998 Oil swap agreement:* Weighted average fixed price per barrel --- $ 20.92 Notional amount (in barrels) --- 54 Natural gas swap agreements:* Weighted average fixed price per MMBtu --- $ 2.23 Notional amount (in MMBtu's) --- 1,170 Natural gas collar agreements:* Weighted average floor/ceiling price per MMBtu $2.10/$2.51 $2.10/$2.67 Notional amount (in MMBtu's) 720 450 Interest rate swap agreement:** Range of fixed interest rates --- 5.50%-6.50% Notional amount (in dollars) --- $10,000 *Receive fixed -- pay variable **Receive variable -- pay fixed The following table summarizes hedge agreements outstanding at March 31, 1999 (notional amounts in thousands): Weighted Average Floor/Ceiling Notional Year of Price Amount Expiration (Per MMBtu) (In MMBtu's) Natural gas collar agreements* 1999 $2.10/$2.51 2,200 Weighted Average Notional Year of Fixed Price Amount Expiration (Per MMBtu) (In MMBtu's) Natural gas futures contracts* 2000 $2.38 1,000 * Receive fixed -- pay variable The fair value of these derivative financial instruments reflects the estimated amounts that the company would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current favorable or unfavorable position on open contracts. The favorable or unfavorable position is currently not recorded on the company's financial statements. Favorable and unfavorable positions related to commodity hedge agreements are expected to be generally offset by corresponding increases and decreases in the value of the underlying commodity transactions. The company's net favorable position on all hedge agreements outstanding at March 31, 1999, was $457,000. In the event a hedge agreement does not qualify for hedge accounting or when the underlying commodity transaction or related debt instrument matures, is sold, is extinguished, or is terminated, the current favorable or unfavorable position on the open contract would be included in results of operations. The company's policy requires approval to terminate a hedge agreement prior to its original maturity. In the event a hedge agreement is terminated, the realized gain or loss at the time of termination would be deferred until the underlying commodity transaction or related debt instrument is sold or matures and is expected to generally offset the corresponding increases or decreases in the value of the underlying commodity transaction or interest on the related debt instrument. 7. Common stock On May 14, 1998, the company's Board of Directors approved a three-for-two common stock split effected in the form of a 50 percent common stock dividend. The additional shares of common stock were distributed on July 13, 1998, to common stockholders of record on July 3, 1998. Common stock information appearing in the accompanying Consolidated Statements of Income has been restated to give retroactive effect to the stock split. At the Annual Meeting of Stockholders held on April 27, 1999, the company's common stockholders approved an amendment to the Certificate of Incorporation increasing the authorized number of common shares from 75 million shares to 150 million shares and reducing the par value of the common stock from $3.33 per share to $1.00 per share. 8. Business segment data The company's operations are conducted through five business segments. 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 electric, natural gas distribution, natural gas transmission, construction materials and mining, and oil and natural gas production businesses are substantially all located within the United States. The electric business operates electric power generation, transmission and distribution facilities in North Dakota, South Dakota, Montana and Wyoming and installs and repairs electric transmission and distribution power lines and provides related supplies, equipment and engineering services throughout the western United States and Hawaii. The natural gas distribution business provides natural gas distribution services in North Dakota, South Dakota, Montana and Wyoming. The natural gas transmission business serves the Midwestern, Southern and Central regions of the United States providing natural gas transmission and related services including storage and production along with energy marketing and management, wholesale/retail propane and energy facility construction. The construction materials and mining business produces and markets aggregates and construction materials in Alaska, California, Hawaii and Oregon, and operates lignite coal mines in Montana and North Dakota. The oil and natural gas production business is engaged in oil and natural gas acquisition, exploration and production activities throughout the United States, the Gulf of Mexico and Canada. Segment information follows the same accounting policies as described in Note 1 of the company's 1998 Annual Report. Segment information included in the accompanying Consolidated Statements of Income is as follows: Operating Operating Revenues Earnings Revenues Inter- on Common External segment Stock Three Months (In thousands) Ended March 31, 1999 Electric $ 58,974 $ --- $ 5,163 Natural gas distribution 61,126 --- 2,878 Natural gas transmission 67,805 20,583 5,531 Construction materials and mining 57,762* 2,276 (1,373) Oil and natural gas production 11,103 --- 329 Intersegment eliminations --- (20,583) --- Total $ 256,770 $ 2,276 $12,528 Three Months Ended March 31, 1998 Electric $ 44,740 $ --- $ 3,592 Natural gas distribution 62,635 --- 3,627 Natural gas transmission 10,908 18,805 8,142 Construction materials and mining 37,280* 1,681 252 Oil and natural gas production 12,878 --- 1,986 Intersegment eliminations --- (18,805) --- Total $ 168,441 $ 1,681 $17,599 * Includes sales, for use at the Coyote Station, an electric generating station jointly owned by the company and other utilities, of (in thousands) $1,786 and $1,774 for the three months ended March 31, 1999 and 1998, respectively. 9. Regulatory matters and revenues subject to refund Williston Basin had pending with the Federal Energy Regulatory Commission (FERC) a general natural gas rate change application implemented in 1992. In October 1997, Williston Basin appealed to the United States Court of Appeals for the D.C. Circuit (D.C. Circuit Court) certain issues decided by the FERC in prior orders concerning the 1992 proceeding. On January 22, 1999, the D.C. Circuit Court issued its opinion remanding the issues of return on equity, ad valorem taxes and throughput to the FERC for further explanation and justification. The mandate was issued by the D.C. Circuit Court to the FERC on March 11, 1999. Based on the D.C. Circuit Court's opinion, Williston Basin anticipates that the FERC will modify its prior order thereby allowing Williston Basin to seek reimbursement from its customers of a portion of the refunds made in 1997 relating to certain of these remanded issues. In June 1995, Williston Basin filed a general rate increase application with the FERC. As a result of FERC orders issued after Williston Basin's application was filed, Williston Basin filed revised base rates in December 1995 with the FERC resulting in an increase of $8.9 million or 19.1 percent over the then current effective rates. Williston Basin began collecting such increase effective January 1, 1996, subject to refund. In July 1998, the FERC issued an order which addressed various issues including storage cost allocations, return on equity and throughput. In August 1998, Williston Basin requested rehearing of such order. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to pending regulatory proceedings and to reflect future resolution of certain issues with the FERC. Williston Basin believes that such reserves are adequate based on its assessment of the ultimate outcome of the various proceedings. 10. Natural gas repurchase commitment As described in Note 15 of its 1998 Annual Report, the company has offered for sale since 1984 the inventoried natural gas available under a repurchase commitment with Frontier Gas Storage Company. As a part of the corporate realignment effected January 1, 1985, the company agreed, pursuant to the settlement approved by the FERC, to remove from rates the financing costs associated with this natural gas. The FERC has issued orders that have held that storage costs should be allocated to this gas, prospectively beginning May 1992, as opposed to being included in rates applicable to Williston Basin's customers. These storage costs, as initially allocated to the Frontier gas, approximated $2.1 million annually, for which Williston Basin has provided reserves. Williston Basin appealed these orders to the D.C. Circuit Court which in December 1996 issued its order ruling that the FERC's actions in allocating storage capacity costs to the Frontier gas were appropriate. In August 1998, Williston Basin requested rehearing on the July 1998 FERC order which addressed various issues, including a requirement that storage deliverability costs be allocated to the Frontier gas. 11. Pending litigation W. A. Moncrief -- In November 1993, the estate of W.A. Moncrief (Moncrief), a producer from whom Williston Basin purchased a portion of its natural gas supply, filed suit in Federal District Court for the District of Wyoming (Federal District Court) against Williston Basin and the company disputing certain price and volume issues under the contract. Through the course of this action Moncrief submitted damage calculations which totaled approximately $19 million or, under its alternative pricing theory, approximately $39 million. In June 1997, the Federal District Court issued its order awarding Moncrief damages of approximately $15.6 million. In July 1997, the Federal District Court issued an order limiting Moncrief's reimbursable costs to post-judgment interest, instead of both pre- and post-judgment interest as Moncrief had sought. In August 1997, Moncrief filed a notice of appeal with the United States Court of Appeals for the Tenth Circuit (U.S. Court of Appeals) related to the Federal District Court's orders. In September 1997, Williston Basin and the company filed a notice of cross-appeal. On April 20, 1999, the U.S. Court of Appeals issued its order which affirmed in part and reversed in part the Federal District Court's June 1997 decision. Additionally, the U.S. Court of Appeals remanded the case to the Federal District Court for further determination of the prices and volumes to be used for determination of damages. The U.S. Court of Appeals also remanded to the lower court for further consideration the issue of whether pre-judgment interest on damages is applicable. As a result of the decision by the U.S. Court of Appeals, and in the absence of rehearing, the prior judgment of $15.6 million by the Federal District Court will be vacated. Based on the decision by the U.S. Court of Appeals, Williston Basin estimates its liability for damages on the remanded issues will be less than $5 million. Williston Basin believes that it is entitled to recover from customers virtually all of the costs which might ultimately be incurred as a result of this litigation as gas supply realignment transition costs pursuant to the provisions of the FERC's Order 636. However, the amount of costs that can ultimately be recovered is subject to approval by the FERC and market conditions. Apache Corporation/Snyder Oil Corporation -- In December 1993, Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) filed suit in North Dakota Northwest Judicial District Court (North Dakota District Court), against Williston Basin and the company. Apache and Snyder are oil and natural gas producers which had processing agreements with Koch Hydrocarbon Company (Koch). Williston Basin and the company had a natural gas purchase contract with Koch. Apache and Snyder have alleged they are entitled to damages for the breach of Williston Basin's and the company's contract with Koch. Williston Basin and the company believe that if Apache and Snyder have any legal claims, such claims are with Koch, not with Williston Basin or the company as Williston Basin, the company and Koch have settled their disputes. Apache and Snyder have submitted damage estimates under differing theories aggregating up to $4.8 million without interest. A motion to intervene in the case by several other producers, all of which had contracts with Koch but not with Williston Basin, was denied in December 1996. In November 1998, the North Dakota District Court entered an order directing the entry of judgment in favor of Williston Basin and the company. In December 1998, Apache and Snyder filed a motion for relief asking the North Dakota District Court to reconsider its November 1998 order. On February 4, 1999, the North Dakota District Court denied the motion for relief filed by Apache and Snyder. On March 31, 1999, judgment was entered, thereby dismissing Apache and Snyder's claims against the company. In a related matter, in March 1997, a suit was filed by nine other producers, several of which had unsuccessfully tried to intervene in the Apache and Snyder litigation, against Koch, Williston Basin and the company. The parties to this suit are making claims similar to those in the Apache and Snyder litigation, although no specific damages have been stated. In Williston Basin's opinion, the claims of the nine other producers are without merit. If any amounts are ultimately found to be due, Williston Basin plans to file with the FERC for recovery from customers. However, the amount of costs that can ultimately be recovered is subject to approval by the FERC and market conditions. Coal Supply Agreement -- In November 1995, a suit was filed in District Court, County of Burleigh, State of North Dakota (State District Court) by Minnkota Power Cooperative, Inc., Otter Tail Power Company, Northwestern Public Service Company and Northern Municipal Power Agency (Co-owners), the owners of an aggregate 75 percent interest in the Coyote electric generating station (Coyote Station), against the company (an owner of a 25 percent interest in the Coyote Station) and Knife River. In its complaint, the Co-owners have alleged a breach of contract against Knife River with respect to the long-term coal supply agreement (Agreement) between the owners of the Coyote Station and Knife River. The Co-owners have requested a determination by the State District Court of the pricing mechanism to be applied to the Agreement and have further requested damages during the term of such alleged breach on the difference between the prices charged by Knife River and the prices that may ultimately be determined by the State District Court. The Co-owners also alleged a breach of fiduciary duties by the company as operating agent of the Coyote Station, asserting essentially that the company was unable to cause Knife River to reduce its coal price sufficiently under the Agreement, and the Co-owners are seeking damages in an unspecified amount. In May 1996, the State District Court stayed the suit filed by the Co-owners pending arbitration, as provided for in the Agreement. In September 1996, the Co-owners notified the company and Knife River of their demand for arbitration of the pricing dispute that had arisen under the Agreement. The demand for arbitration, filed with the American Arbitration Association (AAA), did not make any direct claim against the company in its capacity as operator of the Coyote Station. The Co-owners requested that the arbitrators make a determination that the pricing dispute is not a proper subject for arbitration. By an April 1997 order, the arbitration panel concluded that the claims raised by the Co-owners are arbitrable. The Co-owners have requested the arbitrators to make a determination that the prices charged by Knife River were excessive and that the Co- owners should be awarded damages, based upon the difference between the prices that Knife River charged and a "fair and equitable" price. Upon application by the company and Knife River, the AAA administratively determined that the company was not a proper party defendant to the arbitration, and the arbitration is proceeding against Knife River. In October 1998, a hearing before the arbitration panel was completed. At the hearing the Co-owners requested damages of approximately $24 million, including interest, plus a reduction in the future price of coal under the Agreement. The company is currently awaiting a final decision from the arbitration panel. Although unable to predict the ultimate outcome of the arbitration, Knife River and the company believe that the Co-owners' claims for past damages (if any) are substantially overstated and intend to vigorously defend the prices going forward. 12. Environmental matters Montana-Dakota and Williston Basin discovered polychlorinated biphenyls (PCBs) in portions of their natural gas systems and informed the United States Environmental Protection Agency (EPA) in January 1991. Montana-Dakota and Williston Basin believe the PCBs entered the system from a valve sealant. In January 1994, Montana-Dakota, Williston Basin and Rockwell International Corporation (Rockwell), manufacturer of the valve sealant, reached an agreement under which Rockwell has reimbursed and will continue to reimburse Montana-Dakota and Williston Basin for a portion of certain remediation costs. On the basis of findings to date, Montana- Dakota and Williston Basin estimate future environmental assessment and remediation costs will aggregate $3 million to $15 million. Based on such estimated cost, the expected recovery from Rockwell and the ability of Montana-Dakota and Williston Basin to recover their portions of such costs from ratepayers, Montana-Dakota and Williston Basin believe that the ultimate costs related to these matters will not be material to each of their respective financial positions or results of operations. 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 includes the electric operations of Montana-Dakota, as well as the operations of Utility Services. Natural gas distribution includes Montana- Dakota's natural gas distribution operations. Natural gas transmission includes WBI Holdings' storage, transportation, gathering, natural gas production and energy marketing operations. Construction materials and mining includes the results of Knife River's operations, while oil and natural gas production includes the operations of Fidelity Oil. Overview The following table (dollars in millions, where applicable) summarizes the contribution to consolidated earnings by each of the company's businesses. Three Months Ended March 31, 1999 1998 Electric $ 5.2 $ 3.6 Natural gas distribution 2.9 3.6 Natural gas transmission 5.5 8.1 Construction materials and mining (1.4) .3 Oil and natural gas production .3 2.0 Earnings on common stock $ 12.5 $ 17.6 Earnings per common share - basic $ .24 $ .39* Earnings per common share - diluted $ .23 $ .39* Return on average common equity for the 12 months ended 5.1%** 14.8% ________________________________ * Reflects the company's three-for-two common stock split effected in July 1998. **Reflects $39.9 million in noncash after-tax write-downs of oil and natural gas properties in 1998. Three Months Ended March 31, 1999 and 1998 Consolidated earnings for the quarter ended March 31, 1999, decreased $5.1 million from the comparable period a year ago due to lower earnings at the natural gas transmission, construction materials and mining, oil and natural gas production and natural gas distribution businesses. Increased earnings at the electric business somewhat offset the earnings decline. ________________________________ Reference should be made to Notes to Consolidated Financial Statements for information pertinent to various commitments and contingencies. 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 units. Electric Operations Three Months Ended March 31, 1999 1998 Operating revenues: Retail sales $ 34.0 $ 33.0 Sales for resale and other 6.2 3.3 Utility services 18.8 8.4 59.0 44.7 Operating expenses: Fuel and purchased power 13.5 11.8 Operation and maintenance 26.6 17.6 Depreciation, depletion and amortization 5.1 4.7 Taxes, other than income 2.6 2.1 47.8 36.2 Operating income 11.2 8.5 Retail sales (million kWh) 536.1 523.2 Sales for resale (million kWh) 268.6 129.4 Average cost of fuel and purchased power per kWh $ .016 $ .017 Natural Gas Distribution Operations Three Months Ended March 31, 1999 1998 Operating revenues: Sales $ 60.1 $ 61.5 Transportation and other 1.0 1.1 61.1 62.6 Operating expenses: Purchased natural gas sold 44.9 45.4 Operation and maintenance 7.8 7.5 Depreciation, depletion and amortization 1.8 1.8 Taxes, other than income 1.1 1.1 55.6 55.8 Operating income 5.5 6.8 Volumes (MMdk): Sales 13.2 14.0 Transportation 3.1 3.2 Total throughput 16.3 17.2 Degree days (% of normal) 87% 94% Average cost of natural gas, including transportation, per dk $ 3.40 $ 3.24 Natural Gas Transmission Operations Three Months Ended March 31, 1999 1998 Operating revenues: Transportation and storage $ 15.4 $ 19.0 Energy marketing and natural gas production 73.0 10.7 88.4 29.7 Operating expenses: Purchased natural gas sold 66.4 5.6 Operation and maintenance 8.6 7.7 Depreciation, depletion and amortization 2.7 2.0 Taxes, other than income 1.6 1.5 79.3 16.8 Operating income 9.1 12.9 Transportation volumes (MMdk): Montana-Dakota 8.3 8.4 Other 8.8 14.4 17.1 22.8 Produced (Mdk) 2,668 1,751 Construction Materials and Mining Operations Three Months Ended March 31, 1999 1998 Operating revenues: Construction materials $ 50.1 $ 29.7 Coal 10.0 9.3 60.1 39.0 Operating expenses: Operation and maintenance 54.7 33.1 Depreciation, depletion and amortization 5.7 3.9 Taxes, other than income .9 .9 61.3 37.9 Operating income (loss) (1.2) 1.1 Sales (000's): Aggregates (tons) 1,538 863 Asphalt (tons) 104 30 Ready-mixed concrete (cubic yards) 217 139 Coal (tons) 879 788 Oil and Natural Gas Production Operations Three Months Ended March 31, 1999 1998 Operating revenues: Oil $ 5.0 $ 6.8 Natural gas 6.1 6.1 11.1 12.9 Operating expenses: Operation and maintenance 4.3 3.8 Depreciation, depletion and amortization 4.9 5.4 Taxes, other than income 1.0 .8 10.2 10.0 Operating income .9 2.9 Production: Oil (000's of barrels) 481 483 Natural gas (MMcf) 3,476 2,808 Average sales price: Oil (per barrel) $ 10.35 $ 14.05 Natural gas (per Mcf) 1.76 2.17 Amounts presented in the preceding tables for natural gas operating revenues and purchased natural gas sold for the three months ended March 31, 1999 and 1998, will not agree with the Consolidated Statements of Income due to the elimination of intercompany transactions between Montana-Dakota's natural gas distribution business and WBI Holdings' natural gas transmission business. Three Months Ended March 31, 1999 and 1998 Electric Operations Electric earnings increased due to increased electric utility earnings and earnings at the utility services companies acquired since the comparable period last year. Sales for resale revenue improved due to 108 percent higher volumes resulting from increased generating station availability, favorable contracts and reduced line load constraints and higher average rates due to favorable contracts. Higher retail sales to residential, commercial and industrial customers also contributed to the earnings improvement. Increased operation and maintenance expense resulting primarily from higher materials and subcontractor costs at the Heskett and Big Stone stations partially offset the electric utility earnings improvement. Utility services contributed $897,000 to earnings during the first quarter of 1999 compared to $352,000 a year ago. Natural Gas Distribution Operations Earnings decreased at the natural gas distribution business due to reduced weather-related sales, the result of 8 percent warmer weather. A rate reduction implemented in North Dakota and increased operation and maintenance expense also contributed to the earnings decline. Increased return on gas in storage and prepaid demand balances partially offset the decrease in earnings. Natural Gas Transmission Operations Earnings at the natural gas transmission business decreased due to lower transportation revenues resulting from a $5.0 million ($3.1 million after tax) reversal of reserves in 1998 relating to a FERC order concerning a compliance filing and decreased transportation to off-system markets at lower average transportation rates. Reduced sales of natural gas held under the repurchase commitment and lower average prices received on company-owned production also added to the decline in earnings. Earnings from new acquisitions, the recognition of $1.7 million resulting from a favorable 1999 order received from the D.C. Circuit Court relating to the 1992 general rate proceeding, increased storage revenues and higher production from company-owned reserves partially offset the earnings decline. The increase in energy marketing revenue and the related increase in purchased natural gas sold resulted from the acquisition of a natural gas marketing business in July 1998. Construction Materials and Mining Operations Construction materials and mining earnings decreased largely due to normal seasonal losses realized in 1999 by construction materials businesses not owned during the full quarter last year and wet weather experienced at the larger construction materials markets. Increased ready-mixed concrete volumes, a transportation volume- related credit and lower cement costs were largely offset by higher selling, general and administrative costs and increased aggregate costs due to higher off-season maintenance at the existing construction materials operations. Higher interest expense resulting mainly from increased acquisition-related long-term debt also added to the decline in earnings. Earnings at the coal operations increased slightly due to higher demand-related sales. Oil and Natural Gas Production Operations Earnings for the oil and natural gas production business decreased largely as a result of decreased operating revenues resulting from realized oil and natural gas prices which were 26 percent and 19 percent lower than last year, respectively. Increased natural gas production due to new acquisitions somewhat offset the operating revenue decline. Operation and maintenance expenses increased due largely to the previously mentioned acquisitions. Decreased depreciation, depletion and amortization due to lower rates resulting from the 1998 write- downs of oil and natural gas properties partially offset the decrease in earnings. 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. 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. Regulated Operations -- In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for the company and its regulated operations 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, wholesale and retail competition (including but not limited to electric retail wheeling and transmission costs), availability of economic supplies of natural gas, and present or prospective natural gas distribution or transmission competition (including but not limited to prices of alternate fuels and system deliverability costs). Nonregulated Operations -- Certain important factors which could cause actual results or outcomes for the company and all or certain of its nonregulated operations to differ materially from those discussed in forward-looking statements include the level of governmental expenditures on public projects and project schedules, changes in anticipated tourism levels, competition from other suppliers, oil and natural gas commodity prices, drilling successes in oil and natural gas operations, ability to acquire oil and natural gas properties, and the availability of economic expansion or development opportunities. Factors Common to Regulated and Nonregulated Operations -- 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 obligations with respect to the company's financial instruments, changes in accounting principles and/or the application of such principles to the company, changes in technology and legal proceedings, and the ability of the company and third parties, including suppliers and vendors, to identify and address year 2000 issues in a timely manner. Prospective Information Montana-Dakota has obtained and holds valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. As franchises expire, Montana-Dakota may face increasing competition in its service areas, particularly its service to smaller towns, from rural electric cooperatives. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises and will continue to take steps to effectively operate in an increasingly competitive environment. Year 2000 Compliance The year 2000 issue is the result of computer programs having been written using two digits rather than four digits to define the applicable year. In 1997, the company established a task force with coordinators in each of its major operating units to address the year 2000 issue. The scope of the year 2000 readiness effort includes information technology (IT) and non-IT systems, including computer hardware, software, networking, communications, embedded and micro-processor controlled systems, building controls and office equipment. The company's year 2000 plan is based upon a six-phase approach involving awareness, inventory, assessment, remediation, testing and implementation. State of Readiness -- The company is conducting a corporate-wide awareness program, compiling an inventory of IT and non-IT systems, and assigning priorities to such systems. As of March 31, 1999, the awareness and inventory phases, including assigning priorities to IT and non-IT systems, have been substantially completed. The assessment phase involves the review of each inventory item for year 2000 compliance and efforts to obtain representations and assurances from third parties, including suppliers, vendors and major customers, that such entities are year 2000 compliant. The company has identified key suppliers, vendors and customers and as of March 31, 1999, based on contacts with and representations obtained from approximately 63 percent of these third parties, the company is not aware of any material third party year 2000 problems. The company will continue to contact those material third parties that have not responded seeking written verification of year 2000 readiness. Thus, the company is presently unable to determine the potential adverse consequences, if any, that could result from each such entities' failure to effectively address the year 2000 issue. As of March 31, 1999, the assessment phase, as it relates to the company's review of its inventory items, has been substantially completed. The remediation, testing and implementation phases of the company's year 2000 plan are currently in various stages of completion. The remediation phase includes replacements, modifications and/or upgrades necessary for year 2000 compliance that were identified in the assessment phase. The testing phase involves testing systems to confirm year 2000 readiness. The implementation phase is the process of moving a remediated item into production status. The table below represents the approximate percentage of completion by business segment for the remediation, testing and implementation phases as of March 31, 1999. Remediation Testing Implementation Electric and Natural Gas Distribution 87% 62% 89% Natural Gas Transmission 93% 61% 95% Construction Materials and Mining 40% 20% 35% Oil and Natural Gas Production 95% 90% 90% The company has established a target date of October 1, 1999, to complete the remediation, testing and implementation phases. Costs -- The estimated total incremental cost to the company of the year 2000 issue is approximately $1 million to $3 million during the 1998 through 2000 time periods. As of March 31, 1999, the company has incurred incremental costs of less than $750,000. These costs are being funded through cash flows from operations. The company has not established a formal process to track internal year 2000 costs but such costs would be principally related to payroll and benefits. The company's current estimate of costs of the year 2000 issue is based on the facts and circumstances existing at this time, which were derived utilizing numerous assumptions of future events. Risks -- The failure to correct a material year 2000 problem, including failures on the part of third parties, could result in a temporary interruption in, or failure of, certain critical business operations, including electric distribution, generation and transmission; natural gas distribution, transmission, storage and gathering; energy marketing; mining and marketing of coal, aggregates and related construction materials; oil and natural gas exploration, production, and development; and utility line construction and repair services. Although the company believes the project will be completed by October 1, 1999, unforeseen and other factors could cause delays in the project, the results of which could have a material effect on the results of operations and the company's ability to conduct its business. Contingency Planning -- Due to the general uncertainty inherent in the year 2000 issue, including the uncertainty of the year 2000 readiness of third parties, the company is developing contingency plans for its mission-critical operations. As of March 31, 1999, the utility division, which includes electric generation and transmission and electric and natural gas distribution, has prepared preliminary contingency plans in accordance with guidelines and schedules set forth by the North American Electric Reliability Council (NERC) working in conjunction with the Mid-Continent Area Power Pool, the utility's regional reliability council. Such plans are in addition to existing business recovery and emergency plans established to restore electric and natural gas service following an interruption caused by weather or equipment failure. In addition, the company has and will continue to participate with the NERC in national drills to assess industry preparation. The natural gas transmission business has adopted the guidelines used at the utility and has materially completed plans for its administrative and accounting systems. The contingency plans for its other business operations are in the development stage. The oil and natural gas production and the construction materials and mining businesses are in various stages of their contingency planning efforts. Some of the additional contingency plans under consideration include but are not limited to: stockpiling inventories, increasing staffing at critical times, identifying alternative suppliers for critical products and services, using the company's radio system in the event there is a partial loss of voice and data communications and developing manual workarounds and backup procedures. Contingency plans will continue to be developed and finalized and the company anticipates having all such contingency plans in place by October 1, 1999. Liquidity and Capital Commitments The 1999 electric and natural gas distribution capital expenditures are estimated at $30.8 million, including those for system upgrades, routine replacements, service extensions and routine equipment maintenance and replacements. It is anticipated that all of the funds required for these capital expenditures will be met from internally generated funds, the company's $40 million revolving credit and term loan agreement, existing short-term lines of credit aggregating $50 million, a commercial paper credit facility at Centennial, as described below, and through the issuance of long-term debt, the amount and timing of which will depend upon needs, internal cash generation and market conditions. At March 31, 1999, $22 million under the revolving credit and term loan agreement and none of the commercial paper supported by the short-term lines of credit were outstanding. Capital expenditures in 1999 for the natural gas transmission business, including those for pipeline expansion projects, routine system improvements and continued development of natural gas reserves are estimated at $37.4 million. Capital expenditures are expected to be met with a combination of internally generated funds, a commercial paper credit facility at Centennial, as described below, and through the issuance of long-term debt, the amount and timing of which will depend upon needs, internal cash generation and market conditions. The 1999 capital expenditures for the construction materials and mining business, including those for routine equipment rebuilding and replacement and the building of construction materials handling and transportation facilities, are estimated at $48.3 million. It is anticipated that funds generated from internal sources, a commercial paper credit facility at Centennial, as described below, a $10 million line of credit, $5.2 million of which was outstanding at March 31, 1999, and the issuance of long-term debt will meet the needs of this business segment. Capital expenditures for the oil and natural gas production business related to its oil and natural gas acquisition, development and exploration program are estimated at $63.6 million for 1999. It is anticipated that capital expenditures will be met from internal sources, a $30 million note shelf facility, $13 million of which was outstanding at March 31, 1999, a commercial paper credit facility at Centennial, as described below, and the issuance of the company's equity securities. Centennial, a direct subsidiary of the company, has a revolving credit agreement with various banks on behalf of its subsidiaries that allows for borrowings of up to $200 million. This facility supports the Centennial commercial paper program. Under the commercial paper program, $109.7 million was outstanding at March 31, 1999. The estimated 1999 capital expenditures set forth above for the electric, natural gas distribution, natural gas transmission and construction materials and mining operations do not include potential future acquisitions. The company continues to seek additional growth opportunities, including investing in the development of related lines of business. To the extent that acquisitions occur, the company anticipates that such acquisitions would be financed with existing credit facilities and the issuance of long-term debt and the company's equity securities. 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, 1999, the company could have issued approximately $276 million of additional first mortgage bonds. The company's coverage of combined fixed charges and preferred stock dividends was 2.2 and 2.5 times for the twelve months ended March 31, 1999, and December 31, 1998, respectively. Additionally, the company's first mortgage bond interest coverage was 6.1 times for the twelve months ended March 31, 1999, and December 31, 1998. Common stockholders' equity as a percent of total capitalization was 56 percent at March 31, 1999, and December 31, 1998. 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, 1998. 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, 1998, and Notes to Consolidated Financial Statements in this Form 10-Q. PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS On April 20, 1999, the U.S. Court of Appeals issued its order which affirmed in part and reversed in part the Federal District Court's June 1997 decision relating to a suit filed by the estate of W. A. Moncrief. Based on the decision by the U.S. Court of Appeals, Williston Basin estimates its liability for damages on the remanded issues will be less than $5 million. For more information on this legal action, see Note 11 of Notes to Consolidated Financial Statements. On March 31, 1999, judgment was entered, dismissing Apache and Snyder's claims against the company. For more information on this legal action, see Note 11 of Notes to Consolidated Financial Statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The company's Annual Meeting of Stockholders was held on April 27, 1999. Two proposals were submitted to stockholders as described in the company's Proxy Statement dated March 15, 1999, 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 Certificate of Incorporation to increase the number of authorized shares of Common Stock and reduce the par value 41,759,552 3,737,799 773,805 --- Proposal to elect three directors: For terms expiring in 2002 -- Thomas Everist 45,613,261 657,895 --- --- Robert L. Nance 45,568,619 702,537 --- --- John A. Schuchart 45,339,288 931,868 --- --- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a) Exhibits 3(a(1))Composite Certificate of Incorporation of the company, as amended to date, filed as Exhibit 3(a) to Form 10-K for the year ended December 31, 1994, in File No. 1-3480 3(a(2))Amendment to Article FOURTH of the Certificate of Incorporation 10(a) Key Employee Stock Option Plan, as amended to date 10(b) Non-Employee Director Stock Compensation Plan, as amended to date 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends 27 Financial Data Schedule b) Reports on Form 8-K None. 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 13, 1999 BY /s/ Warren L. Robinson Warren L. Robinson 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. 3(a(1)) Composite Certificate of Incorporation of the company, as amended to date, filed as Exhibit 3(a) to Form 10-K for the year ended December 31, 1994, in File No. 1-3480 3(a(2)) Amendment to Article FOURTH of the Certificate of Incorporation 10(a) Key Employee Stock Option Plan, as amended to date 10(b) Non-Employee Director Stock Compensation Plan, as amended to date 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends 27 Financial Data Schedule