UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended June 30, 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 Identification No.) incorporation or organization) 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 July 30, 1999: 54,054,107 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, South Dakota, Montana and 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, serves the Midwestern, Southern, Central and Rocky Mountain 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. 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 and the Gulf of Mexico. 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 and Six Months Ended June 30, 1999 and 1998 Consolidated Balance Sheets -- June 30, 1999 and 1998, and December 31, 1998 Consolidated Statements of Cash Flows -- Six Months Ended June 30, 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 Six Months Ended Ended June 30, June 30, 1999 1998 1999 1998 (In thousands, except per share amounts) Operating revenues: Electric $ 60,413 $ 48,182 $119,388 $ 92,921 Natural gas 108,105 38,102 237,034 111,646 Construction materials and mining 107,870 80,895 167,908 119,856 Oil and natural gas production 13,879 12,536 24,983 25,414 290,267 179,715 549,313 349,837 Operating expenses: Fuel and purchased power 12,452 12,408 25,955 24,241 Purchased natural gas sold 71,750 11,334 162,455 43,509 Operation and maintenance 143,771 103,844 245,770 173,567 Depreciation, depletion and amortization 19,983 19,365 40,123 37,154 Taxes, other than income 6,663 6,259 13,901 12,652 Write-down of oil and natural gas properties (Note 3) --- 33,100 --- 33,100 254,619 186,310 488,204 324,223 Operating income (loss): Electric 10,894 7,502 22,068 15,950 Natural gas distribution (522) (819) 4,942 5,974 Natural gas transmission 14,938 7,828 24,074 20,724 Construction materials and mining 6,192 9,368 4,953 10,525 Oil and natural gas production 4,146 (30,474) 5,072 (27,559) 35,648 (6,595) 61,109 25,614 Other income -- net 1,065 2,554 4,833 5,156 Interest expense 8,452 7,215 17,258 14,350 Income (loss) before income taxes 28,261 (11,256) 48,684 16,420 Income taxes 10,465 (5,471) 18,167 4,412 Net income (loss) 17,796 (5,785) 30,517 12,008 Dividends on preferred stocks 193 195 386 389 Earnings (loss) on common stock $ 17,603 $ (5,980) $ 30,131 $ 11,619 Earnings (loss) per common share -- basic $ .33 $ (.12) $ .57 $ .24 Earnings (loss) per common share -- diluted $ .33 $ (.12) $ .56 $ .24 Dividends per common share $ .20 $ .1917 $ .40 $ .3833 Weighted average common shares outstanding -- basic 53,373 50,936 53,260 48,171 Weighted average common shares outstanding -- diluted 53,603 50,936 53,512 48,412 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, June 30, December 31, 1999 1998 1998 (In thousands) ASSETS Current assets: Cash and cash equivalents $ 44,534 $ 43,106 $ 39,216 Receivables 145,479 88,059 124,114 Inventories 51,834 40,664 44,865 Deferred income taxes 18,732 16,041 16,918 Prepayments and other current assets 24,470 15,106 15,536 285,049 202,976 240,649 Investments 43,783 20,513 43,029 Property, plant and equipment: Electric 591,510 571,936 583,047 Natural gas distribution 181,182 175,219 178,522 Natural gas transmission 317,397 292,865 304,054 Construction materials and mining 524,046 446,936 484,419 Oil and natural gas production 269,228 218,373 260,758 1,883,363 1,705,329 1,810,800 Less accumulated depreciation, depletion and amortization 758,874 694,878 726,123 1,124,489 1,010,451 1,084,677 Deferred charges and other assets 97,319 74,795 84,420 $1,550,640 $1,308,735 $1,452,775 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Short-term borrowings $ 102 $ 8,439 $ 15,000 Long-term debt and preferred stock due within one year 2,374 5,571 3,292 Accounts payable 84,109 39,880 60,023 Taxes payable 8,178 --- 9,226 Dividends payable 11,004 10,040 10,799 Other accrued liabilities, including reserved revenues 77,374 68,850 71,129 183,141 132,780 169,469 Long-term debt 473,174 332,126 413,264 Deferred credits and other liabilities: Deferred income taxes 177,871 178,995 173,094 Other liabilities 119,490 130,959 129,506 297,361 309,954 302,600 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 -- $1.00 par value, 54,293,628 at June 30, 1999, $3.33 par value, 51,609,444 at June 30, 1998 and 53,272,951 at December 31, 1998) 54,294 171,859 177,399 Other paid-in capital 315,426 143,885 171,486 Retained earnings 214,270 205,057 205,583 Treasury stock at cost - 239,521 shares (3,626) (3,626) (3,626) Total common stockholders' equity 580,364 517,175 550,842 Total stockholders' equity 595,364 532,175 565,842 $1,550,640 $1,308,735 $1,452,775 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Six Months Ended June 30, 1999 1998 (In thousands) Operating activities: Net income $ 30,517 $ 12,008 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 40,123 37,154 Deferred income taxes and investment tax credit (112) (7,242) Write-down of oil and natural gas properties (Note 3) --- 33,100 Changes in current assets and liabilities: Receivables (10,094) 12,691 Inventories (1,414) 4,636 Other current assets (8,860) (637) Accounts payable 20,928 4,440 Other current liabilities 4,594 (30,354) Other noncurrent changes (16,344) (9,074) Net cash provided by operating activities 59,338 56,722 Financing activities: Net change in short-term borrowings (19,098) (1,408) Issuance of long-term debt 80,503 58,501 Repayment of long-term debt (22,408) (40,490) Issuance of common stock 3,184 30,109 Retirement of natural gas repurchase commitment (14,296) (12,374) Dividends paid (21,829) (19,674) Net cash provided by financing activities 6,056 14,664 Investing activities: Capital expenditures including acquisitions of businesses: Electric (10,211) (5,861) Natural gas distribution (4,475) (3,847) Natural gas transmission (14,251) (5,066) Construction materials and mining (27,262) (29,632) Oil and natural gas production (14,817) (19,014) (71,016) (63,420) Net proceeds from sale or disposition of property 10,364 2,557 Net capital expenditures (60,652) (60,863) Sale of natural gas available under repurchase commitment 1,330 5,987 Investments (754) (1,578) Net cash used in investing activities (60,076) (56,454) Increase in cash and cash equivalents 5,318 14,932 Cash and cash equivalents -- beginning of year 39,216 28,174 Cash and cash equivalents -- end of period $ 44,534 $ 43,106 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 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 and six months ended June 30, 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. Write-down of oil and natural gas properties The company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units of production method based on total proved reserves. Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. Future net revenue is estimated based on end-of-quarter prices adjusted for contracted price changes. If capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter. Due to low oil prices, the company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at June 30, 1998. Accordingly, the company was required to write down its oil and natural gas producing properties. This noncash write-down amounted to $33.1 million ($20.0 million after tax) for the three and six months ended June 30, 1998. 4. Cash flow information Cash expenditures for interest and income taxes were as follows: Six Months Ended June 30, 1999 1998 (In thousands) Interest, net of amount capitalized $14,718 $12,408 Income taxes $19,673 $17,489 5. 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. 6. New accounting pronouncement In June 1998, the Financial Accounting Standards Board (FASB) 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. In June 1999, the effective date of SFAS No. 133 was delayed by the FASB to fiscal years beginning after June 15, 2000. The company will adopt SFAS No. 133 on January 1, 2001, and has not yet quantified the impacts of adopting SFAS No. 133 on its financial position or results of operations. 7. 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 wholly owned 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. 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): Six Months Ended June 30, 1999 1998 Oil swap agreement:* Weighted average fixed price per barrel --- $ 20.92 Notional amount (in barrels) --- 109 Natural gas swap agreements:* Weighted average fixed price per MMBtu --- $ 2.04 Notional amount (in MMBtu's) --- 2,353 Oil collar agreements:* Weighted average floor/ceiling price per barrel $14.63/$18.40 --- Notional amount (in barrels) 84 --- Natural gas collar agreements:* Weighted average floor/ceiling price per MMBtu $2.11/$2.53 $2.10/$2.67 Notional amount (in MMBtu's) 1,568 905 Natural gas futures contract:* Weighted average fixed price per MMBtu $2.39 --- Notional amount (in MMBtu's) 400 --- 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 the company's hedge agreements outstanding at June 30, 1999 (notional amounts in thousands): Weighted Average Floor/Ceiling Notional Year of Price Amount Expiration (Per Barrel) (In Barrels) Oil collar agreements* 1999 $14.69/$18.69 368 Weighted Average Floor/Ceiling Notional Year of Price Amount Expiration (Per MMBtu) (In MMBtu's) Natural gas collar agreements* 1999 $2.15/$2.58 2,208 2000 $2.30/$2.65 2,562 Weighted Average Notional Year of Fixed Price Amount Expiration (Per MMBtu) (In MMBtu's) Natural gas futures contracts* 1999 $2.29 400 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 unfavorable position on all hedge agreements outstanding at June 30, 1999, was $192,000. 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. 8. Common stock 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. 9. 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 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, Central and Rocky Mountain 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 mines 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 and the Gulf of Mexico. 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 June 30, 1999 Electric $ 60,413 $ --- $ 5,064 Natural gas distribution 25,881 --- (550) Natural gas transmission 82,224 6,537 8,027 Construction materials and mining 106,367* 1,503 2,265 Oil and natural gas production 13,879 --- 2,797 Intersegment eliminations --- (6,537) --- Total $ 288,764 $ 1,503 $ 17,603 Three Months Ended June 30, 1998 Electric $ 48,182 $ --- $ 2,993 Natural gas distribution 24,197 --- (910) Natural gas transmission 13,905 8,231 4,319 Construction materials and mining 79,022* 1,873 5,643 Oil and natural gas production 12,536 --- (18,025) Intersegment eliminations --- (8,231) --- Total $ 177,842 $ 1,873 $ (5,980) * Includes sales, for use at the Coyote Station, an electric generating station jointly owned by the company and other utilities, of (in thousands) $1,577 and $1,764 for the three months ended June 30, 1999 and 1998, respectively. Operating Operating Revenues Earnings Revenues Inter- on Common External segment Stock Six Months (In thousands) Ended June 30, 1999 Electric $ 119,388 $ --- $ 10,227 Natural gas distribution 87,005 --- 2,328 Natural gas transmission 150,029 27,120 13,559 Construction materials and mining 164,129* 3,779 891 Oil and natural gas production 24,983 --- 3,126 Intersegment eliminations --- (27,120) --- Total $ 545,534 $ 3,779 $ 30,131 Six Months Ended June 30, 1998 Electric $ 92,921 $ --- $ 6,585 Natural gas distribution 86,834 --- 2,716 Natural gas transmission 24,812 27,036 12,461 Construction materials and mining 116,302* 3,554 5,895 Oil and natural gas production 25,414 --- (16,038) Intersegment eliminations --- (27,036) --- Total $ 346,283 $ 3,554 $ 11,619 * Includes sales, for use at the Coyote Station, an electric generating station jointly owned by the company and other utilities, of (in thousands) $3,363 and $3,538 for the six months ended June 30, 1999 and 1998, respectively. 10. 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. By order dated June 1, 1999, the FERC remanded the return on equity issue to an Administrative Law Judge for further proceedings. Based on the FERC's order, Williston Basin will be allowed to seek reimbursement from its customers of a portion of the refunds made in 1997 relating to the return on equity issue. 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. On June 1, 1999, the FERC issued an order approving and denying various issues addressed in Williston Basin's rehearing request, and also remanded the return on equity issue to an Administrative Law Judge for further proceedings. On July 1, 1999, Williston Basin requested rehearing of certain issues which were contained in the June 1, 1999 FERC order. In addition, on July 29, 1999, Williston Basin appealed to the D.C. Circuit Court certain issues concerning storage cost allocations as decided by the FERC in its June 1, 1999 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. Based on the June 1, 1999 FERC orders referenced above, Williston Basin has determined that reserves previously established exceed its expected refund obligation and has adjusted such reserves accordingly. Williston Basin believes that such remaining reserves are adequate based on its assessment of the ultimate outcome of the various proceedings. 11. Natural gas repurchase commitment As described in Note 15 of its 1998 Annual Report, the company had 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. In May 1999, the company purchased the remaining 5.8 MMdk of natural gas subject to the repurchase commitment thereby extinguishing the repurchase commitment. 12. 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. Apache and Snyder filed a notice of appeal with the North Dakota Supreme Court on May 17, 1999. 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. Based on its assessment of the current proceedings, Knife River has established reserves for anticipated liabilities in connection with the coal pricing issues and related tax matters. Although unable to predict the ultimate outcome of the arbitration, Knife River and the company believe that the Co- owners' claims for past damages are overstated and are currently awaiting a final decision from the arbitration panel. Royalty Interest Owners -- On June 3, 1999, several oil and gas royalty interest owners filed suit in Colorado State District Court, in the City and County of Denver, against WBI Production, Inc. (WBI Production), an indirect wholly owned subsidiary of the company, and several former producers of natural gas with respect to certain gas production properties in the state of Colorado. The complaint arose as a result of the purchase by WBI Production effective January 1, 1999, of certain natural gas producing leaseholds from the former producers. Prior to February 1, 1999, the natural gas produced from the leaseholds was sold at above market prices pursuant to a natural gas contract. Pursuant to the contract, the royalty interest owners were paid royalties based upon the above market prices. The royalty interest owners have alleged that WBI Production took assignment of the rights to the natural gas contract from the former owner of the contract and, with respect to natural gas produced from such leases and sold at market prices thereafter, wrongly ceased paying the higher royalties on such gas. In their complaint, the royalty interest owners have alleged, in part, breach of oil and gas lease obligations and unjust enrichment on the part of WBI Production and the other former producers with respect to the amount of royalties being paid to the royalty interest owners. The royalty interest owners have requested damages for additional royalties and other costs, including pre-judgment interest. No specific amount of damages has been stated. WBI Production intends to vigorously contest the suit. 13. 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 Six Months Ended Ended June 30, June 30, 1999 1998 1999 1998 Electric $ 5.1 $ 3.0 $ 10.2 $ 6.6 Natural gas distribution (.6) (.9) 2.3 2.7 Natural gas transmission 8.0 4.3 13.6 12.4 Construction materials and mining 2.3 5.6 .9 5.9 Oil and natural gas production 2.8 (18.0) 3.1 (16.0) Earnings (loss) on common stock $ 17.6 $ (6.0) $ 30.1 $ 11.6 Earnings (loss) per common share - basic $ .33 $ (.12)* $ .57 $ .24* Earnings (loss) per common share - diluted $ .33 $ (.12)* $ .56 $ .24* Return on average common equity for the 12 months ended 9.3%** 10.0%* * Reflects the effect of a $20 million noncash after-tax write- down of oil and natural gas properties in June 1998. ** Reflects the effect of a $19.9 million noncash after-tax write- down of oil and natural gas properties in December 1998. Three Months Ended June 30, 1999 and 1998 Consolidated earnings for the quarter ended June 30, 1999, were up $23.6 million from the comparable period a year ago due to higher earnings at the oil and natural gas production business, largely resulting from a 1998 $20 million noncash after-tax write-down of oil and natural gas properties. Increased earnings at the natural gas transmission, electric and natural gas distribution businesses also contributed to the earnings improvement. Lower earnings at the construction materials and mining unit somewhat offset the increase in earnings. Six Months Ended June 30, 1999 and 1998 Consolidated earnings for the six months ended June 30, 1999, were up $18.5 million from the comparable period a year ago due to higher earnings at the oil and natural gas production business, largely resulting from the aforementioned write-down of oil and natural gas properties. Higher earnings at the electric and natural gas transmission businesses also added to the increase in earnings. Decreased earnings at the construction materials and mining and natural gas distribution businesses partially offset the earnings improvement. ________________________________ 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 Six Months Ended Ended June 30, June 30, 1999 1998 1999 1998 Operating revenues: Retail sales $ 30.5 $ 29.4 $ 64.5 $ 62.4 Sales for resale and other 6.4 4.7 12.7 8.0 Utility services 23.5 14.1 42.2 22.5 60.4 48.2 119.4 92.9 Operating expenses: Fuel and purchased power 12.4 12.4 26.0 24.2 Operation and maintenance 29.5 21.2 56.0 38.7 Depreciation, depletion and amortization 5.1 4.8 10.3 9.5 Taxes, other than income 2.5 2.3 5.0 4.5 49.5 40.7 97.3 76.9 Operating income $ 10.9 $ 7.5 $ 22.1 $ 16.0 Retail sales (million kWh) 481.5 459.4 1,017.6 982.6 Sales for resale (million kWh) 248.7 180.1 517.3 309.5 Average cost of fuel and purchased power per kWh $ .016 $ .018 $ .016 $ .018 Natural Gas Distribution Operations Three Months Six Months Ended Ended June 30, June 30, 1999 1998 1999 1998 Operating revenues: Sales $ 25.1 $ 23.5 $ 85.2 $ 85.1 Transportation and other .8 .7 1.8 1.7 25.9 24.2 87.0 86.8 Operating expenses: Purchased natural gas sold 16.5 15.3 61.5 60.7 Operation and maintenance 7.0 6.9 14.8 14.5 Depreciation, depletion and amortization 1.8 1.8 3.6 3.5 Taxes, other than income 1.1 1.0 2.2 2.1 26.4 25.0 82.1 80.8 Operating income (loss) $ (.5) $ (.8) $ 4.9 $ 6.0 Volumes (MMdk): Sales 5.0 4.5 18.2 18.5 Transportation 2.2 1.8 5.3 5.0 Total throughput 7.2 6.3 23.5 23.5 Degree days (% of normal) 112% 99% 92% 95% Average cost of gas, including transportation thereon, per dk $ 3.29 $ 3.41 $ 3.37 $ 3.28 Natural Gas Transmission Operations Three Months Six Months Ended Ended June 30, June 30, 1999 1998 1999 1998 Operating revenues: Transportation and storage $ 20.3 $ 13.9 $ 35.7 $ 32.9 Energy marketing and natural gas production 68.4 8.2 141.4 18.9 88.7 22.1 177.1 51.8 Operating expenses: Purchased natural gas sold 61.7 4.2 128.1 9.8 Operation and maintenance 7.9 6.7 16.4 14.3 Depreciation, depletion and amortization 2.6 2.0 5.2 4.1 Taxes, other than income 1.6 1.4 3.3 2.9 73.8 14.3 153.0 31.1 Operating income $ 14.9 $ 7.8 $ 24.1 $ 20.7 Transportation volumes (MMdk): Montana-Dakota 6.9 7.6 15.3 16.0 Other 12.5 15.2 21.6 29.6 19.4 22.8 36.9 45.6 Natural gas production (Mdk) 2,603 1,718 5,271 3,470 Construction Materials and Mining Operations Three Months Six Months Ended Ended June 30, June 30, 1999 1998 1999 1998 Operating revenues: Construction materials $ 99.9 $ 71.9 $ 150.0 $ 101.6 Coal 7.9 9.0 17.9 18.3 107.8 80.9 167.9 119.9 Operating expenses: Operation and maintenance 94.9 65.4 149.7 98.6 Depreciation, depletion and amortization 5.9 5.2 11.6 9.1 Taxes, other than income .8 .9 1.7 1.7 101.6 71.5 163.0 109.4 Operating income $ 6.2 $ 9.4 $ 4.9 $ 10.5 Sales (000's): Aggregates (tons) 3,032 2,560 4,570 3,422 Asphalt (tons) 807 391 911 421 Ready-mixed concrete (cubic yards) 290 259 508 398 Coal (tons) 763 773 1,641 1,561 Oil and Natural Gas Production Operations Three Months Six Months Ended Ended June 30, June 30, 1999 1998 1999 1998 Operating revenues: Oil $ 6.8 $ 6.3 $ 11.7 $ 13.1 Natural gas 7.1 6.2 13.3 12.3 13.9 12.5 25.0 25.4 Operating expenses: Operation and maintenance 4.5 3.6 8.8 7.4 Depreciation, depletion and amortization 4.6 5.6 9.4 11.0 Taxes, other than income .7 .7 1.7 1.5 Write-down of oil and natural gas properties --- 33.1 --- 33.1 9.8 43.0 19.9 53.0 Operating income (loss) $ 4.1 $ (30.5) $ 5.1 $ (27.6) Production: Oil (000's of barrels) 437 490 918 973 Natural gas (MMcf) 3,312 2,942 6,788 5,750 Average sales price: Oil (per barrel) $ 15.44 $ 12.90 $ 12.77 $ 13.47 Natural gas (per Mcf) $ 2.16 $ 2.11 $ 1.95 $ 2.14 Amounts presented in the preceding tables for natural gas operating revenues and purchased natural gas sold for the three and six months ended June 30, 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 June 30, 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 higher volumes and increased average realized rates, both resulting from favorable contracts. Higher retail sales to residential and commercial customers and decreased purchased power demand charges, resulting from the 1998 pass-through of periodic maintenance costs, also added to the earnings improvement. Increased operation and maintenance expense resulting primarily from higher subcontractor costs at the Lewis & Clark station due to boiler and turbine maintenance and higher payroll related costs partially offset the electric utility earnings improvement. Utility services contributed $1.8 million to earnings during the second quarter of 1999 compared to $747,000 a year ago. Natural Gas Distribution Operations Earnings increased at the natural gas distribution business due to higher weather-related sales, the result of 13 percent colder weather. Increased service and repair income and higher returns on gas in storage and prepaid demand balances also added to the increased earnings. Lower average realized rates and a rate reduction implemented in North Dakota somewhat offset the earnings improvement. Natural Gas Transmission Operations Earnings at the natural gas transmission business increased primarily due to a $4.4 million after-tax reserve revenue adjustment associated with FERC orders received in the 1992 and 1995 rate case proceedings. Higher production and increased average prices from company-owned reserves and earnings from new acquisitions also added to the improvement. Decreased transportation to storage and off- system markets at lower average transportation rates and reduced sales of natural gas in inventory somewhat offset the earnings increase. The increase in energy marketing revenue and the related increase in purchased natural gas sold resulted primarily 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 lower earnings at the coal operations resulting from reserve additions of $3.7 million after-tax made relating to anticipated liabilities in connection with the pending coal contract arbitration proceedings and related tax matters, as discussed under Coal Supply Agreement in Note 12 of Notes to Consolidated Financial Statements. Lower average sales prices, reduced tax depletion benefits and higher stripping costs also added to the coal earnings decline. Earnings at the construction materials business increased due to businesses acquired since the comparable period last year and increased earnings at existing construction materials operations. Increased aggregate deliveries, lower cement costs and higher average realized prices on ready-mixed concrete all contributed to the increase in construction materials earnings. Higher selling, general and administrative costs and increased interest expense resulting from increased acquisition- related long-term debt somewhat offset the increased earnings at the construction materials business. Oil and Natural Gas Production Operations Earnings for the oil and natural gas production business increased largely as a result of the 1998 $20 million noncash after-tax write- down of oil and natural gas properties, as discussed in Note 3 of Notes to Consolidated Financial Statements. Increased realized oil prices, which were 20 percent higher than last year and higher natural gas production due to new acquisitions also contributed to the increase in earnings. In addition, decreased depreciation, depletion and amortization due to lower rates resulting from the June 1998 and December 1998 write-downs of oil and natural gas properties also added to the earnings improvement. Lower oil production partially offset the earnings increase. Six Months Ended June 30, 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 volumes improved by 67 percent and margins increased by nearly 15 percent, both resulting from favorable contracts. Higher retail sales to all major customer classes and lower retail fuel and purchased power costs also contributed to the earnings improvement. Increased generation at lower cost versus higher cost generating stations and decreased purchased power demand charges resulting from the 1998 pass-through of periodic maintenance costs contributed to the decline in retail fuel and purchased power costs. Increased operation and maintenance expense resulting largely from higher subcontractor costs at the Lewis & Clark station due to boiler and turbine maintenance partially offset the electric utility earnings improvement. Earnings attributable to utility services were $2.7 million compared to $1.1 million a year ago. Natural Gas Distribution Operations Earnings decreased at the natural gas distribution business due to a rate reduction implemented in North Dakota and lower weather-related sales, the result of warmer weather in the first quarter. Increased operation and maintenance expense also added to the decline in earnings. Higher returns on gas in storage and prepaid demand balances somewhat offset the decrease in earnings. Natural Gas Transmission Operations Earnings at the natural gas transmission business increased largely due to the previously discussed $4.4 million after-tax reserve revenue adjustment. The recognition of $1.7 million in the first quarter resulting from a favorable order received from the D.C. Circuit Court relating to the 1992 general rate proceeding also contributed to the increase in earnings. In addition, higher production from company-owned reserves and earnings from new acquisitions also added to the earnings improvement. Decreased transportation to storage and off-system markets at lower average transportation rates and reduced sales of natural gas in inventory somewhat offset the earnings increase. The $3.1 million after-tax reversal of reserves in the first quarter of 1998 for certain contingencies relating to a FERC order concerning a compliance filing also partially offset the 1999 earnings increase. The increase in energy marketing revenue and the related increase in purchased natural gas sold resulted primarily from the acquisition of a natural gas marketing business in July 1998. Construction Materials and Mining Operations Construction materials and mining earnings decreased primarily due to lower earnings at the coal operations largely resulting from the previously discussed reserve additions of $3.7 million after-tax associated with the coal contract arbitration proceedings and related tax matters, as discussed under Coal Supply Agreement in Note 12 of Notes to Consolidated Financial Statements. Lower average sales prices, reduced tax depletion benefits and higher stripping costs also added to the coal earnings decline. Earnings at the construction materials businesses increased slightly due to businesses acquired since the comparable period last year and increased earnings at existing construction materials operations. Increased aggregate deliveries, lower cement costs and higher ready-mixed concrete volumes all contributed to the increase in construction materials operations. Higher selling, general and administrative costs and increased interest expense resulting from increased acquisition-related long- term debt somewhat offset the increased earnings at the construction materials business. Normal seasonal losses realized in the first quarter of 1999 by construction materials businesses not owned during the full first quarter last year also partially offset the earnings improvement at the construction materials business. Oil and Natural Gas Production Operations Earnings for the oil and natural gas production business increased largely as a result of the 1998 $20 million noncash after-tax write- down of oil and natural gas properties, as discussed in Note 3 of Notes to Consolidated Financial Statements. Higher natural gas production due to new acquisitions and decreased depreciation, depletion and amortization due to lower rates resulting from the June 1998 and December 1998 write-downs of oil and natural gas properties also added to the earnings improvement. Lower average oil and natural gas prices in the first quarter and decreased oil production partially offset the increase 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. The company recently made several acquisitions. During the second quarter, the company acquired two construction materials and mining companies. A construction company specializing in commercial grading as well as asphalt and concrete paving joined the company's northern California operations. In southern Oregon, the company acquired a vertically integrated aggregate mining and construction materials company that performs general contracting work including excavation, site preparation, underground utilities and road construction. In addition, in July 1999, the company acquired a Wyoming pipeline and gathering system. The pipeline connects Williston Basin's existing pipeline and storage facilities to the coal seam gas supplies being developed by various producers in Wyoming's Powder River Basin. A gas storage field in western Kentucky was also acquired. None of the above mentioned acquisitions were individually material. 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 June 30, 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 June 30, 1999, based on contacts with and representations obtained from approximately 64 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. As to those who have not responded, 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 June 30, 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 June 30, 1999. Remediation Testing Implementation Electric and natural gas distribution 87% 81% 86% Natural gas transmission 98% 93% 98% Construction materials and mining 87% 84% 85% Oil and natural gas production 100% 100% 100% The company has established a target date of October 1, 1999, to substantially 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 June 30, 1999, the company has incurred incremental costs of approximately $1 million. 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 are 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 substantially 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 June 30, 1999, the utility division, which includes electric generation and transmission and electric and natural gas distribution, has prepared 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 participated 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 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 substantially in place by October 1, 1999. Liquidity and Capital Commitments The 1999 electric and natural gas distribution capital expenditures are estimated at $31.3 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 $75 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 June 30, 1999, $23 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 acquisitions to date, pipeline expansion projects, routine system improvements and continued development of natural gas reserves are estimated at $50.3 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 acquisitions to date, routine equipment rebuilding and replacement and the building of construction materials handling and transportation facilities, are estimated at $62 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 June 30, 1999, and the issuance of long-term debt and the company's equity securities 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 $68.9 million for 1999. It is anticipated that capital expenditures will be met from internal sources, a commercial paper credit facility at Centennial, as described below, and the issuance of long-term debt and 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, $164 million was outstanding at June 30, 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 June 30, 1999, the company could have issued approximately $280 million of additional first mortgage bonds. The company's coverage of combined fixed charges and preferred stock dividends was 3.2 and 2.5 times for the twelve months ended June 30, 1999, and December 31, 1998, respectively. Additionally, the company's first mortgage bond interest coverage was 6.6 and 6.1 times for the twelve months ended June 30, 1999, and December 31, 1998, respectively. Common stockholders' equity as a percent of total capitalization was 54 percent and 56 percent at June 30, 1999, and December 31, 1998, 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, 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 Apache and Snyder filed a notice of appeal with the North Dakota Supreme Court on May 17, 1999. Based on its assessment of the current coal supply agreement arbitration proceedings, Knife River has established reserves for anticipated liabilities in connection with the coal pricing issues and related tax matters. On June 3, 1999, several oil and gas royalty interest owners filed suit in Colorado State District Court, in the City and County of Denver, against WBI Production, Inc. (WBI Production), an indirect wholly owned subsidiary of the company, and several former producers of natural gas with respect to certain gas production properties in the state of Colorado. For more information on the above legal actions see Note 12 of Notes to Consolidated Financial Statements. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS On June 9, 1999, the company issued to the shareholders of DSS Company, 898,103 shares of Common Stock, $1.00 par value, to acquire all of the issued and outstanding capital stock of DSS Company. The Common Stock issued by the company in this transaction was issued in private sales exempt from registration pursuant to Section 4(2) of the Securities Act of 1933. The shareholders have acknowledged that they are holding the company's Common Stock as an investment and not with a view to distribution. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a) Exhibits 3(a) Restated Certificate of Incorporation of the company, as amended to date 4(a(1)) Indenture of Mortgage, dated as of May 1, 1939, as restated in the Forty-Fifth Supplemental Indenture, dated as of April 21, 1992, and the Forty-Sixth through Forty-Eighth Supplements thereto between the company and the New York Trust Company (The Bank of New York, successor Corporate Trustee) and A. C. Downing (Douglas J. MacInnes, successor Co-Trustee), filed as Exhibit 4(a) in Registration No. 33-66682; and Exhibits 4(e), 4(f) and 4(g) in Registration No. 33-53896 4(a(2)) Instrument Effecting a Change in Individual Trustee dated as of April 30, 1999 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 August 9, 1999 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. 3(a) Restated Certificate of Incorporation of the company, as amended to date 4(a(1)) Indenture of Mortgage, dated as of May 1, 1939, as restated in the Forty-Fifth Supplemental Indenture, dated as of April 21, 1992, and the Forty-Sixth through Forty-Eighth Supplements thereto between the company and the New York Trust Company (The Bank of New York, successor Corporate Trustee) and A. C. Downing (Douglas J. MacInnes, successor Co-Trustee), filed as Exhibit 4(a) in Registration No. 33-66682; and Exhibits 4(e), 4(f) and 4(g) in Registration No. 33-53896 4(a(2)) Instrument Effecting a Change in Individual Trustee dated as of April 30, 1999 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends 27 Financial Data Schedule