10-Q 1 mdur3rdqtr10q.txt 2002 3RD QUARTER FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002 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 November 6, 2002: 71,672,380 shares. INTRODUCTION This Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 -- Management's Discussion and Analysis of Financial Condition and Results of Operations -- Safe Harbor for Forward-looking Statements. Forward-looking statements are all statements other than statements of historical fact, including without limitation, those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions. MDU Resources Group, Inc. (Company) is a diversified natural resource company which was incorporated under the laws of the State of Delaware in 1924. Its principal executive offices are at the Schuchart Building, 918 East Divide Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 222-7900. Montana-Dakota Utilities Co. (Montana-Dakota), a public utility division of the Company, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in the northern Great Plains. Great Plains Natural Gas Co. (Great Plains), another public utility division of the Company, distributes natural gas in southeastern North Dakota and western Minnesota. These operations also supply related value-added products and services. The Company, through its wholly owned subsidiary, Centennial Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI Holdings), Knife River Corporation (Knife River), Utility Services, Inc. (Utility Services) and Centennial Holdings Capital Corp. (Centennial Capital). WBI Holdings is comprised of the pipeline and energy services and the natural gas and oil production segments. The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States and provides energy- related management services, as well as cable and pipeline locating services. The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration and production activities primarily in the Rocky Mountain region of the United States and in the Gulf of Mexico. Knife River mines aggregates and markets crushed stone, sand, gravel and other related construction materials, including ready-mixed concrete, cement and asphalt, as well as value-added products and services in the north central and western United States, including Alaska and Hawaii. Utility Services is a diversified infrastructure company specializing in engineering, design and build capability for electric, gas and telecommunication utility construction, as well as industrial and commercial electrical, exterior lighting and traffic signalization throughout most of the United States. Utility Services also provides related specialty equipment manufacturing, sales and rental services. Centennial Capital invests in new growth and synergistic opportunities, including independent power production, which are not directly being pursued by the existing business units but which are consistent with the Company's philosophy and growth strategy. These activities are reflected in the pipeline and energy services segment. The Company, through its wholly owned subsidiary, MDU Resources International, Inc. (MDU International), invests in projects outside the United States which are consistent with the Company's philosophy, growth strategy and areas of expertise. These activities are reflected in the pipeline and energy services segment. INDEX Part I -- Financial Information Consolidated Statements of Income -- Three and Nine Months Ended September 30, 2002 and 2001 Consolidated Balance Sheets -- September 30, 2002 and 2001, and December 31, 2001 Consolidated Statements of Cash Flows -- Nine Months Ended September 30, 2002 and 2001 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 Form 10-Q Certifications Exhibit Index Exhibits PART I -- FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Nine Months Ended Ended September 30, September 30, 2002 2001 2002 2001 (In thousands, except per share amounts) Operating revenues $612,398 $551,680 $1,474,550 $1,739,345 Operating expenses: Fuel and purchased power 14,500 14,982 41,568 42,703 Purchased natural gas sold 4,644 36,840 60,120 502,394 Operation and maintenance 445,672 356,677 1,023,562 823,052 Depreciation, depletion and amortization 40,589 36,205 114,536 102,737 Taxes, other than income 16,822 13,737 47,601 41,352 522,227 458,441 1,287,387 1,512,238 Operating income 90,171 93,239 187,163 227,107 Other income -- net 6,910 1,855 11,729 16,416 Interest expense 11,731 11,459 33,253 34,171 Income before income taxes 85,350 83,635 165,639 209,352 Income taxes 31,419 32,889 63,133 82,502 Net income 53,931 50,746 102,506 126,850 Dividends on preferred stocks 189 190 567 571 Earnings on common stock $ 53,742 $ 50,556 $ 101,939 $ 126,279 Earnings per common share -- basic $ .76 $ .75 $ 1.45 $ 1.89 Earnings per common share -- diluted $ .75 $ .74 $ 1.44 $ 1.87 Dividends per common share $ .24 $ .23 $ .70 $ .67 Weighted average common shares outstanding -- basic 70,923 67,650 70,288 66,781 Weighted average common shares outstanding -- diluted 71,344 68,127 70,756 67,519 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, September 30, December 31, 2002 2001 2001 (In thousands, except shares and per share amount) ASSETS Current assets: Cash and cash equivalents $ 42,806 $ 57,817 $ 41,811 Receivables, net 363,568 357,027 285,081 Inventories 102,130 95,669 95,341 Deferred income taxes 15,020 14,839 18,973 Prepayments and other current assets 39,482 27,722 40,286 563,006 553,074 481,492 Investments 43,339 37,917 38,198 Property, plant and equipment 2,979,495 2,699,796 2,738,612 Less accumulated depreciation, depletion and amortization 1,046,987 918,468 946,470 1,932,508 1,781,328 1,792,142 Deferred charges and other assets: Goodwill 185,205 158,619 173,997 Other intangible assets, net 84,682 76,410 76,234 Other 60,889 65,123 61,008 330,776 300,152 311,239 $2,869,629 $2,672,471 $2,623,071 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Short-term borrowings $ 10,000 $ --- $ --- Long-term debt and preferred stock due within one year 22,606 11,131 11,185 Accounts payable 148,312 141,950 110,649 Taxes payable 17,960 28,984 11,826 Dividends payable 17,335 15,840 16,108 Other accrued liabilities 104,720 91,191 95,559 320,933 289,096 245,327 Long-term debt 832,533 843,915 783,709 Deferred credits and other liabilities: Deferred income taxes 360,872 327,560 342,412 Other liabilities 139,021 118,013 125,552 499,893 445,573 467,964 Preferred stock subject to mandatory redemption 1,300 1,400 1,300 Commitments and contingencies Stockholders' equity: Preferred stocks 15,000 15,000 15,000 Common stockholders' equity: Common stock (Shares issued -- $1.00 par value, 71,681,396 at September 30, 2002, 69,386,316 at September 30, 2001 and 70,016,851 at December 31, 2001) 71,681 69,386 70,017 Other paid-in capital 690,139 626,655 646,521 Retained earnings 446,820 381,752 394,641 Accumulated other comprehensive income (loss) (5,044) 3,320 2,218 Treasury stock at cost - 239,521 shares (3,626) (3,626) (3,626) Total common stockholders' equity 1,199,970 1,077,487 1,109,771 Total stockholders' equity 1,214,970 1,092,487 1,124,771 $2,869,629 $2,672,471 $2,623,071 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended September 30, 2002 2001 (In thousands) Operating activities: Net income $102,506 $126,850 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 114,536 102,737 Deferred income taxes and investment tax credit 12,686 8,448 Changes in current assets and liabilities, net of acquisitions: Receivables (64,437) 54,776 Inventories (4,585) (26,844) Other current assets (2,743) 7,460 Accounts payable 27,941 (55,426) Other current liabilities 14,142 43,667 Other noncurrent changes 1,594 (2,867) Net cash provided by operating activities 201,640 258,801 Investing activities: Capital expenditures (212,584) (227,829) Acquisitions, net of cash acquired (14,802) (112,743) Net proceeds from sale or disposition of property 5,699 34,847 Investments (2,827) 3,041 Proceeds from notes receivable 4,000 4,000 Net cash used in investing activities (220,514) (298,684) Financing activities: Net change in short-term borrowings 10,000 (8,000) Issuance of long-term debt 68,039 158,807 Repayment of long-term debt (8,043) (96,031) Proceeds from issuance of common stock, net 200 52,157 Dividends paid (50,327) (45,745) Net cash provided by financing activities 19,869 61,188 Increase in cash and cash equivalents 995 21,305 Cash and cash equivalents -- beginning of year 41,811 36,512 Cash and cash equivalents -- end of period $ 42,806 $ 57,817 The accompanying notes are an integral part of these consolidated statements. MDU RESOURCES GROUP, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 2002 and 2001 (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, 2001 (2001 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 2001 Annual Report. The information is unaudited but includes all adjustments which are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements. 2. Allowance for doubtful accounts The Company's allowance for doubtful accounts as of September 30, 2002 and 2001, and December 31, 2001 was $8.0 million, $5.7 million and $5.8 million, respectively. 3. 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 for particular segments, and for the Company as a whole, may not be indicative of results for the full fiscal year. 4. Cash flow information Cash expenditures for interest and income taxes were as follows: Nine Months Ended September 30, 2002 2001 (In thousands) Interest, net of amount capitalized $ 27,434 $28,158 Income taxes $ 42,421 $57,528 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 stockholders' equity as previously reported. 6. New accounting standards In June 2001, the Financial Accounting Standards Board (FASB) approved Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for the recorded amount or incurs a gain or loss upon settlement. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company will adopt SFAS No. 143 on January 1, 2003, but has not yet quantified the effects of adopting SFAS No. 143 on its financial position or results of operations. In April 2002, the FASB approved Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). FASB No. 4 required all gains or losses from extinguishment of debt to be classified as extraordinary items net of income taxes. SFAS No. 145 requires that gains and losses from extinguishment of debt be evaluated under the provisions of Accounting Principles Board Opinion No. 30, and be classified as ordinary items unless they are unusual or infrequent or meet the specific criteria for treatment as an extraordinary item. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. The Company believes the adoption of SFAS No. 145 will not have a material effect on its financial position or results of operations. In June 2002, the Emerging Issues Task Force (EITF) adopted the position in EITF Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, 'Accounting for Contracts Involved in Energy Trading and Risk Management Activities' (EITF No. 98-10), and No. 00- 17, 'Measuring the Fair Value of Energy-related Contracts in Applying Issue No. 98-10'" (EITF No. 02-3) that mark-to-market gains and losses on energy trading contracts should be reported on a net basis in the income statement whether or not settled physically in financial statements issued for periods ending after July 15, 2002. However, at the October 25, 2002 EITF meeting, the EITF reached a consensus to rescind EITF No. 98-10, the impact of which is to preclude mark-to- market accounting for all energy trading contracts not within the scope of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). In addition, the EITF reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensuses reached effectively supersede the consensuses reached on this issue at the June, 2002 EITF meeting. The rescission of EITF No. 98-10 is effective for fiscal periods beginning after December 15, 2002. Energy trading contracts not within the scope of SFAS No. 133 purchased after October 25, 2002, but prior to the implementation of the consensus are not permitted to apply mark-to-market accounting. The Company has not yet determined the financial statement effect, if any, of the adoption of the October 25, 2002, EITF positions. In June 2002, the FASB approved Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)" (EITF No. 94-3). SFAS No. 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company believes the adoption of SFAS No. 146 will not have a material effect on its financial position or results of operations. 7. Derivative instruments The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties. The Company's policy requires settlement of natural gas and oil price derivative instruments monthly, settlement of foreign currency derivative transactions yearly and settlement of interest rate derivative instruments within 90 days. The Company has policies and procedures, which management believes minimize credit-risk exposure. These policies and procedures include an evaluation of potential counterparties' credit ratings and credit exposure limitations. Accordingly, the Company does not anticipate any material effect to its financial position or results of operations as a result of nonperformance by counterparties. In the event a derivative instrument does not qualify for hedge accounting because it is no longer highly effective in offsetting changes in cash flows of a hedged item; or if the derivative instrument expires or is sold, terminated, or exercised; or if management determines that designation of the derivative instrument as a hedge instrument is no longer appropriate, hedge accounting will be discontinued, and the derivative instrument would continue to be carried at fair value with changes in its fair value recognized in earnings. In these circumstances, the net gain or loss at the time of discontinuance of hedge accounting would remain in other comprehensive income (loss) until the period or periods during which the hedged forecasted transaction affects earnings, at which time the net gain or loss would be reclassified into earnings. In the event a cash flow hedge is discontinued because it is unlikely that a forecasted transaction will occur, the derivative instrument would continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income (loss) would be recognized immediately in earnings. In the event of a sale, termination or extinguishment of a foreign currency derivative, the resulting gain or loss would be recognized immediately in earnings. The Company's policy requires approval to terminate a derivative instrument prior to its original maturity. Certain subsidiaries of the Company held derivative instruments designated as cash flow hedging instruments as well as a foreign currency derivative which was not designated as a hedge. Hedging activities Certain subsidiaries of the Company utilize natural gas and oil price swap and natural gas collar agreements, to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on the subsidiaries' forecasted sales of natural gas and oil production. Centennial entered into an interest rate swap agreement which expired in the fourth quarter of 2001. The objective for holding the interest rate swap agreement was to manage a portion of Centennial's interest rate risk on the forecasted issuance of fixed-rate debt under Centennial's commercial paper program. Such subsidiaries designated each of the natural gas and oil price swap and collar agreements as a hedge of the forecasted sale of natural gas and oil production and designated the interest rate swap agreement as a hedge of the risk of changes in interest rates on Centennial's forecasted issuances of fixed- rate debt under Centennial's commercial paper program. On an ongoing basis, such subsidiaries of the Company adjust their Consolidated Balance Sheets to reflect the current fair market value of their swap and collar agreements. The related gains or losses on these agreements are recorded in common stockholders' equity as a component of other comprehensive income (loss). At the date the underlying transaction occurs, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. For the three months and nine months ended September 30, 2002 and 2001, such subsidiaries of the Company recognized the ineffectiveness of cash flow hedges, which is included in operating revenues and interest expense for the natural gas and oil price swap and collar agreements and the interest rate swap agreement, respectively. For the three months and nine months ended September 30, 2002 and 2001, the amount of hedge ineffectiveness recognized was immaterial. For the three months and nine months ended September 30, 2002 and 2001, such subsidiaries did not exclude any components of the derivative instruments' gain or loss from the assessment of hedge effectiveness and there were no reclassifications into earnings as a result of the discontinuance of hedges. Gains and losses on derivative instruments that are reclassified from accumulated other comprehensive income (loss) to current-period earnings are included in the line item in which the hedged item is recorded. As of September 30, 2002, the maximum term of the subsidiaries' swap and collar agreements, in which the subsidiaries of the Company are hedging their exposure to the variability in future cash flows for forecasted transactions is 15 months. The subsidiaries of the Company estimate that over the next twelve months net losses of approximately $450,000 will be reclassified from accumulated other comprehensive income (loss) into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings. Foreign currency derivative On August 12, 2002, a subsidiary of the Company entered into a foreign currency collar agreement for a notional amount of $21.3 million with a fixed price floor of R$3.10 and a fixed price ceiling of R$3.40 to manage a portion of its foreign currency risk. This subsidiary has a 49 percent equity investment in a 200 megawatt natural gas fired electric generation project in Brazil which has a portion of its borrowings and payables denominated in U.S. dollars. This subsidiary has exposure to currency exchange risk as a result of fluctuations in currency exchange rates between the U.S. dollar and the Brazilian real. The term of the collar agreement is from August 12, 2002 through February 3, 2003, and the collar agreement settles on February 3, 2003. The foreign currency collar agreement has not been designated as a hedge and is recorded at fair value on the Consolidated Balance Sheets. Gains or losses on this derivative instrument are recorded in other income -- net on the Consolidated Statements of Income. 8. Comprehensive income On January 1, 2001, the Company recorded a cumulative- effect adjustment in accumulated other comprehensive loss to recognize all derivative instruments designated as hedges at fair value. As of September 30, 2002 and 2001, the Company has recorded unrealized gains and losses on natural gas and oil price swap and collar agreements and an interest rate swap agreement which qualify for hedge accounting. As of September 30, 2002, the Company also recorded a minimum pension liability adjustment. These amounts are reflected in the following table. The Company's comprehensive income, and the components of other comprehensive income (loss), net of taxes, were as follows: Three Months Ended September 30, 2002 2001 (In thousands) Net income $ 53,931 $ 50,746 Other comprehensive income (loss) -- Net unrealized gain (loss) on derivative instruments qualifying as hedges: Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $806 and $1,191 in 2002 and 2001, respectively (1,234) 1,824 Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $789 and $992 in 2002 and 2001, respectively 1,208 1,519 Net unrealized gain (loss) on derivative instruments qualifying as hedges (2,442) 305 Comprehensive income $ 51,489 $ 51,051 Nine Months Ended September 30, 2002 2001 (In thousands) Net income $102,506 $126,850 Other comprehensive income (loss) -- Net unrealized gain (loss) on derivative instruments qualifying as hedges: Unrealized loss on derivative instruments at January 1, 2001, due to cumulative effect of a change in accounting principle, net of tax of $3,970 --- (6,080) Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $723 and $2,782 in 2002 and 2001, respectively (1,107) 4,262 Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $1,185 and $3,355 in 2002 and 2001, respectively 1,815 (5,138) Net unrealized gain (loss) on derivative instruments qualifying as hedges (2,922) 3,320 Minimum pension liability adjustment, net of tax of $2,781 (4,340) --- (7,262) 3,320 Comprehensive income $ 95,244 $130,170 9. Goodwill and other intangible assets In June 2001, the FASB approved Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). SFAS No. 142 changes the accounting for goodwill and intangible assets and requires that goodwill no longer be amortized but be tested for impairment at least annually at the reporting unit level in accordance with SFAS No. 142. Recognized intangible assets with determinable useful lives should be amortized over their useful life and reviewed for impairment in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). The Company adopted SFAS No. 142 on January 1, 2002. The Company completed its transitional goodwill impairment testing and determined that no impairment existed as of January 1, 2002. Therefore, no impairment loss has been recorded for the three months and nine months ended September 30, 2002, in connection with the adoption of SFAS No. 142. On January 1, 2002, in accordance with SFAS No. 142, the Company ceased amortization of its goodwill recorded in business combinations which occurred on or before June 30, 2001. The following information is presented as if SFAS No. 142 was adopted as of January 1, 2001. The reconciliation of previously reported earnings and earnings per share to the amounts adjusted for the exclusion of goodwill amortization net of the related income tax effect is as follows: Three Months Ended September 30, 2002 2001 (In thousands, except per share amounts) Reported earnings on common stock $ 53,742 $50,556 Add: Goodwill amortization, net of tax --- 1,502 Adjusted earnings on common stock $ 53,742 $52,058 Reported earnings per common share -- basic $ .76 $ .75 Add: Goodwill amortization, net of tax --- .02 Adjusted earnings per common share -- basic $ .76 $ .77 Reported earnings per common share -- diluted $ .75 $ .74 Add: Goodwill amortization, net of tax --- .02 Adjusted earnings per common share -- diluted $ .75 $ .76 Nine Months Ended September 30, 2002 2001 (In thousands, except per share amounts) Reported earnings on common stock $101,939 $126,279 Add: Goodwill amortization, net of tax --- 3,294 Adjusted earnings on common stock $101,939 $129,573 Reported earnings per common share -- basic $ 1.45 $ 1.89 Add: Goodwill amortization, net of tax --- .05 Adjusted earnings per common share -- basic $ 1.45 $ 1.94 Reported earnings per common share -- diluted $ 1.44 $ 1.87 Add: Goodwill amortization, net of tax --- .05 Adjusted earnings per common share -- diluted $ 1.44 $ 1.92 The changes in the carrying amount of goodwill for the nine months ended September 30, 2002, by business segment are as follows: Net Balance Goodwill Balance as of Acquired as of January 1, During September 30, 2002 the Year 2002 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services 61,909 1,083 62,992 Pipeline and energy services 9,336 158 9,494 Natural gas and oil production --- --- --- Construction materials and mining 102,752 9,967 112,719 Total $ 173,997 $ 11,208 $ 185,205 Included in other intangible assets on the Company's Consolidated Balance Sheets are the following: September 30,September 30,December 31, 2002 2001 2001 (In thousands) Amortizable intangible assets: Leasehold rights $ 79,005 $ 72,780 $ 72,955 Accumulated amortization (2,091) (964) (1,149) 76,914 71,816 71,806 Noncompete agreements 12,090 12,030 12,034 Accumulated amortization (9,234) (8,655) (8,811) 2,856 3,375 3,223 Other 5,149 1,371 1,377 Accumulated amortization (237) (152) (172) 4,912 1,219 1,205 Total $ 84,682 $ 76,410 $ 76,234 Amortization expense for intangible assets for the three months and nine months ended September 30, 2002, was approximately $727,000 and $1.4 million, respectively. Estimated amortization expense for intangible assets is $2.7 million in 2002, $3.1 million in 2003, $3.0 million in 2004, $3.3 million in 2005, $2.6 million in 2006 and $71.4 million thereafter. 10. Common stock At the Annual Meeting of Stockholders held on April 23, 2002, the Company's common stockholders approved an amendment to the Certificate of Incorporation increasing the authorized number of common shares from 150 million shares to 250 million shares with a par value of $1.00 per share. 11. Business segment data The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The Company's operations are conducted through six business segments. The vast majority of the Company's operations are located within the United States. The Company also has investments in foreign countries, which largely consists of an investment in a natural gas fired electric generation station in Brazil. The electric segment generates, transmits and distributes electricity and the natural gas distribution segment distributes natural gas. These operations also supply related value-added products and services in the northern Great Plains. The utility services segment consists of a diversified infrastructure company specializing in engineering, design and build capability for electric, gas and telecommunication utility construction, as well as industrial and commercial electrical, exterior lighting and traffic signalization throughout most of the United States. Utility services provides related specialty equipment manufacturing sales and rental services. The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. Energy- related management services as well as cable and pipeline locating services also are provided. The pipeline and energy services segment includes investments in domestic and international growth opportunities, including 213 megawatts of natural gas fired electric generating facilities in Colorado, and a 49 percent equity interest in a natural gas fired electric generation station in Brazil. The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration and production activities primarily in the Rocky Mountain region of the United States and in the Gulf of Mexico. The construction materials and mining segment mines aggregates and markets crushed stone, sand, gravel and other related construction materials, including ready-mixed concrete, cement and asphalt, as well as value-added products and services in the north central and western United States, including Alaska and Hawaii. In 2001, the Company sold its coal operations to Westmoreland Coal Company for $28.2 million in cash, including final settlement cost adjustments. The sale of the coal operations was effective April 30, 2001. Included in the sale were active coal mines in North Dakota and Montana, coal sales agreements, reserves and mining equipment, and certain development rights at the former Gascoyne Mine site in North Dakota. The Company retains ownership of coal reserves and leases at its former Gascoyne Mine site. The Company recorded a gain of $11.0 million ($6.6 million after tax) included in other income - net on the Company's Consolidated Statements of Income from the sale in the second quarter of 2001. Segment information follows the same accounting policies as described in Note 1 of the Company's 2001 Annual Report. Segment information included in the accompanying Consolidated Statements of Income is as follows: Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Three Months Ended September 30, 2002 Electric $ 41,515 $ --- $ 4,463 Natural gas distribution 16,821 --- (2,646) Utility services 113,419 --- 1,628 Pipeline and energy services 21,245 7,171 9,944 Natural gas and oil production 40,785 1,383 6,953 Construction materials and mining 378,613 --- 33,400 Intersegment eliminations --- (8,554) --- Total $ 612,398 $ --- $ 53,742 Three Months Ended September 30, 2001 Electric $ 48,154 $ --- $ 8,265 Natural gas distribution 18,710 --- (2,747) Utility services 92,208 --- 3,405 Pipeline and energy services 59,430 5,391 3,895 Natural gas and oil production 31,579 10,891 10,519 Construction materials and mining 301,599 --- 27,219 Intersegment eliminations --- (16,282) --- Total $ 551,680 $ --- $ 50,556 Inter- External segment Earnings Operating Operating on Common Revenues Revenues Stock (In thousands) Nine Months Ended September 30, 2002 Electric $ 117,877 $ --- $ 9,627 Natural gas distribution 122,652 --- 1,057 Utility services 338,051 --- 3,811 Pipeline and energy services 77,155 39,188 15,521 Natural gas and oil production 117,293 31,046 37,363 Construction materials and mining 701,522 --- 34,560 Intersegment eliminations --- (70,234) --- Total $1,474,550 $ --- $ 101,939 Nine Months Ended September 30, 2001 Electric $ 129,143 $ --- $ 15,224 Natural gas distribution 200,809 --- (1,620) Utility services 236,710 4 9,321 Pipeline and energy services 454,819 34,197 9,656 Natural gas and oil production 121,310 48,192 56,440 Construction materials and mining 591,538 5,016* 37,258 Intersegment eliminations --- (82,393) --- Total $1,734,329 $ 5,016* $ 126,279 * In accordance with the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Regulation", intercompany coal sales are not eliminated. On April 1, 2000, Fidelity Exploration & Production Company (Fidelity), an indirect wholly owned subsidiary of the Company, purchased substantially all of the assets of Preston Reynolds & Co., Inc. (Preston), a coalbed natural gas development operation based in Colorado with related oil and gas leases and properties in Montana and Wyoming. Pursuant to the asset purchase and sale agreement, Preston could, but was not obligated to purchase, acquire and own an undivided 25 percent working interest (Seller's Option Interest) in certain oil and gas leases or properties acquired and/or generated by Fidelity. Fidelity had the right, but not the obligation, to purchase Seller's Option Interest for an amount as specified in the agreement. On July 10, 2002, Fidelity purchased the Seller's Option Interest. 12. Equity Method Investment As reported in the Company's Form 8-K which was filed on October 23, 2002, the Company reported the press release issued October 22, 2002, regarding earnings for the quarter ended September 30, 2002. In this press release, the Company reported earnings from its subsidiary's 49 percent owned Brazilian operations in the amount of $4.0 million, largely attributable to foreign currency gains on Brazilian real- denominated obligations. The press release reported that while the matter has not been finally resolved, the Company's management has initially determined the functional currency for the 200-megawatt natural gas fired electric generation project to be the U.S. dollar. The Company's determination is based on the fact that the contract revenues for the project are largely indexed to the U.S. dollar. In addition, the majority of expected operation and maintenance expenses as well as actual equipment purchases are in U.S. dollars. The press release also reported that if, however, the Brazilian real is ultimately deemed to be the functional currency, rather than recording a $4.0 million gain, the Company would be required to restate earnings for the three months ended September 30, 2002 to reflect a net loss from Brazilian operations for the third quarter of approximately $7.5 million, largely from foreign currency losses related to U.S. dollar-denominated obligations. This change from a gain to a loss on the equity method investment would result in earnings and earnings per common share, diluted, for the three months ended September 30, 2002 of $42.2 million and $.59, respectively and for the nine months ended September 30, 2002 of $90.4 million and $1.28, respectively. At the time of filing this quarterly report on Form 10-Q, the above matter has not been finally resolved. This matter is expected to be resolved in the fourth quarter. 13. Acquisitions During the first nine months of 2002, the Company acquired construction materials and mining businesses in Minnesota and Montana, an energy development company in Montana, and utility services companies in California and Ohio, none of which was individually material. The total purchase consideration for these businesses, including the Company's common stock and cash, was $60.8 million. On November 1, 2002, the Company's independent power production subsidiary announced the acquisition of 213 megawatts of natural gas fired electric generating facilities. Ninety-five percent of the facilities' output is sold to a non- affiliated utility under long-term power purchase contracts. The above acquisitions were accounted for under the purchase method of accounting and accordingly, the acquired assets and liabilities assumed have been preliminarily recorded at their respective fair values as of the date of acquisition. Final fair market values are pending the completion of the review of the relevant assets, liabilities and issues identified as of the acquisition date. The results of operations of the acquired businesses are included in the financial statements since the date of each acquisition. Pro forma financial amounts reflecting the effects of the above acquisitions are not presented as such acquisitions were not material to the Company's financial position or results of operations. 14. Regulatory matters and revenues subject to refund On October 7, 2002, Great Plains filed with the Minnesota Public Utilities Commission (MPUC) for a natural gas rate increase. The Company is requesting a total of $1.6 million annually or 6.9 percent above current rates. The Company requested an interim increase of $1.4 million or 6.1 percent to be effective within 60 days of the filing of the natural gas rate increase. A final order from the MPUC is due August 22, 2003. On June 10, 2002, Montana-Dakota filed with the Wyoming Public Service Commission (WYPSC) for a natural gas rate increase. The Company is requesting a total of $662,000 annually or 5.6 percent above current rates. A hearing before the WYPSC is scheduled for December 10, 2002 and a final order from the WYPSC is due April 10, 2003. On May 20, 2002, Montana-Dakota filed with the Montana Public Service Commission (MTPSC) for a natural gas rate increase. The Company is requesting a total of $3.6 million annually or 6.5 percent above current rates. On September 5, 2002, the MTPSC approved an interim increase of $2.1 million effective with service rendered on and after September 5, 2002. Montana-Dakota began collecting such rates effective September 5, 2002, which are subject to refund until the MTPSC issues a final order. On November 7, 2002, the MTPSC approved an additional interim increase of $300,000 annually effective November 15, 2002. The additional interim increase is the result of a Stipulation reached between the Company and the Montana Consumer Counsel, the only intervener in the proceeding. Under the terms of the Stipulation, the total interim relief granted ($2.4 million) will be the final increase in the proceeding. Reserves have not been provided for the revenues that have been collected subject to refund. A hearing before the MTPSC is scheduled for December 6, 2002 and the final order from the MTPSC is due February 20, 2003. On April 12, 2002, Montana-Dakota filed with the North Dakota Public Service Commission (NDPSC) for a natural gas rate increase. The Company is requesting a total of $2.8 million annually or 4.1 percent above current rates. A hearing before the NDPSC was held on October 7-8, 2002 and the final order from the NDPSC is due December 12, 2002. The NDPSC authorized its Staff to initiate an investigation into the earnings levels of Montana-Dakota's North Dakota electric operations based on Montana-Dakota's 2000 Annual Report to the NDPSC. The investigation was based on a complaint filed with the NDPSC on September 7, 2001, by the NDPSC Staff. On April 24, 2002, the NDPSC issued an Order requiring Montana-Dakota to reduce its North Dakota electric rates by $4.3 million annually, effective May 8, 2002. On April 25, 2002, Montana-Dakota filed an appeal of the NDPSC Order in the North Dakota South Central Judicial District Court (District Court). The filing also requested a stay of the effectiveness of the NDPSC Order while the appeal is pending. Montana-Dakota is challenging the NDPSC's determination of the level of electricity sales to other utilities and the resulting revenues expected to be received by Montana-Dakota. On May 2, 2002, the District Court granted Montana-Dakota's request for a stay of a portion of the $4.3 million annual rate reduction ordered by the NDPSC. Accordingly, Montana-Dakota implemented an annual rate reduction of $800,000 effective with service rendered on and after May 8, 2002, rather than the $4.3 million annual reduction ordered by the NDPSC. The remaining $3.5 million is subject to refund if Montana-Dakota does not prevail in this proceeding. Oral arguments before the District Court were held on October 9, 2002, and a ruling is expected in the near future. Reserves have been provided for the revenues that have been collected subject to refund with respect to Montana- Dakota's pending electric rate reduction. In December 1999, Williston Basin Interstate Pipeline Company (Williston Basin), an indirect wholly owned subsidiary of the Company, filed a general natural gas rate change application with the Federal Energy Regulatory Commission (FERC). Williston Basin began collecting such rates effective June 1, 2000, subject to refund. In May 2001, the Administrative Law Judge issued an initial decision on Williston Basin's natural gas rate change application, which matter is currently pending before and subject to revision by the FERC. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to Williston Basin's pending regulatory proceeding. Williston Basin believes that such reserves are adequate based on its assessment of the ultimate outcome of the proceeding. 15. Contingencies Litigation In January 2002, Fidelity Oil Co. (FOC), one of the Company's natural gas and oil production subsidiaries, entered into a compromise agreement with the former operator of certain of FOC's oil production properties in southeastern Montana. The compromise agreement resolved litigation involving the interpretation and application of contractual provisions regarding net proceeds interests paid by the former operator to FOC for a number of years prior to 1998. The terms of the compromise agreement are confidential. As a result of the compromise agreement, the natural gas and oil production segment reflected a nonrecurring gain in its financial results for the first quarter of 2002 of approximately $16.6 million after-tax. As part of the settlement, FOC gave the former operator a full and complete release, and FOC is not asserting any such claim against the former operator for periods after 1997. In March 1997, 11 natural gas producers filed suit in North Dakota Southwest Judicial District Court (North Dakota District Court) against Williston Basin and the Company. The natural gas producers had processing agreements with Koch Hydrocarbon Company (Koch). Williston Basin and the Company had natural gas purchase contracts with Koch. The natural gas producers alleged they were entitled to damages for the breach of Williston Basin's and the Company's contracts with Koch although no specific damages were stated. A similar suit was filed by Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) in North Dakota Northwest Judicial District Court in December 1993. The North Dakota Supreme Court in December 1999 affirmed the North Dakota Northwest Judicial District Court decision dismissing Apache's and Snyder's claims against Williston Basin and the Company. Based in part upon the decision of the North Dakota Supreme Court affirming the dismissal of the claims brought by Apache and Snyder, Williston Basin and the Company filed motions for summary judgment to dismiss the claims of the 11 natural gas producers. The motions for summary judgment were granted by the North Dakota District Court in July 2000. In March 2001, the North Dakota District Court entered a final judgment on the July 2000 order granting the motions for summary judgment. In May 2001, the 11 natural gas producers appealed the North Dakota District Court's decision by filing a Notice of Appeal with the North Dakota Supreme Court. On April 16, 2002, the North Dakota Supreme Court affirmed the summary judgment entered by the North Dakota District Court. On April 30, 2002, the 11 natural gas producers filed a petition for rehearing by the North Dakota Supreme Court. On May 17, 2002, the North Dakota Supreme Court denied the 11 natural gas producers petition for rehearing. The 11 natural gas producers filed a petition for a writ of certiorari with the Supreme Court of the United States, which was docketed on August 21, 2002. On October 21, 2002, the Supreme Court of the United States denied the petition for the writ of certiorari. In July 1996, Jack J. Grynberg (Grynberg) filed suit in United States District Court for the District of Columbia (U.S. District Court) against Williston Basin and over 70 other natural gas pipeline companies. Grynberg, acting on behalf of the United States under the Federal False Claims Act, alleged improper measurement of the heating content and volume of natural gas purchased by the defendants resulting in the underpayment of royalties to the United States. In March 1997, the U.S. District Court dismissed the suit without prejudice and the dismissal was affirmed by the United States Court of Appeals for the D.C. Circuit in October 1998. In June 1997, Grynberg filed a similar Federal False Claims Act suit against Williston Basin and Montana-Dakota and filed over 70 other separate similar suits against natural gas transmission companies and producers, gatherers, and processors of natural gas. In April 1999, the United States Department of Justice decided not to intervene in these cases. In response to a motion filed by Grynberg, the Judicial Panel on Multidistrict Litigation consolidated all of these cases in the Federal District Court of Wyoming (Federal District Court). Oral argument on motions to dismiss was held before the Federal District Court in March 2000. In May 2001, the Federal District Court denied Williston Basin's and Montana-Dakota's motion to dismiss. The matter is currently pending. The Quinque Operating Company (Quinque), on behalf of itself and subclasses of gas producers, royalty owners and state taxing authorities, instituted a legal proceeding in State District Court for Stevens County, Kansas, (State District Court) against over 200 natural gas transmission companies and producers, gatherers, and processors of natural gas, including Williston Basin and Montana-Dakota. The complaint, which was served on Williston Basin and Montana- Dakota in September 1999, contains allegations of improper measurement of the heating content and volume of all natural gas measured by the defendants other than natural gas produced from federal lands. In response to a motion filed by the defendants in this suit, the Judicial Panel on Multidistrict Litigation transferred the suit to the Federal District Court for inclusion in the pretrial proceedings of the Grynberg suit. Upon motion of plaintiffs, the case has been remanded to State District Court. In September 2001, the defendants in this suit filed a motion to dismiss with the State District Court. The motion to dismiss was denied by the State District Court on August 19, 2002. The matter is currently pending. Williston Basin and Montana-Dakota believe the claims of Grynberg and Quinque are without merit and intend to vigorously contest these suits. Williston Basin and Montana-Dakota believe it is not probable that Grynberg and Quinque will ultimately succeed given the current status of the litigation. Environmental matters In December 2000, Morse Bros., Inc. (MBI), an indirect wholly owned subsidiary of the Company, was named by the United States Environmental Protection Agency (EPA) as a Potentially Responsible Party in connection with the cleanup of a commercial property site, now owned by MBI, and part of the Portland, Oregon, Harbor Superfund Site. Sixty-eight other parties were also named in this administrative action. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon State Department of Environmental Quality and other information available, MBI does not believe it is a Responsible Party. In addition, MBI intends to seek indemnity for any and all liabilities incurred in relation to the above matters from Georgia-Pacific West, Inc., the seller of the commercial property site to MBI, pursuant to the terms of their sale agreement. The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above administrative action. Guarantees Certain subsidiaries of the Company have financial guarantees outstanding at September 30, 2002. These guarantees as of September 30, 2002, are approximately $31.2 million, of which approximately $27.8 million pertain to Centennial's guarantee of certain obligations in connection with the natural gas fired electric generation station in Brazil, as discussed in Notes 10 and 15 of Notes to Consolidated Financial Statements in the 2001 Annual Report and Items 2 and 3 of Part I of this Quarterly Report on Form 10-Q. As of September 30, 2002, with respect to these guarantees, there were approximately $27.8 million outstanding through 2003, $1.4 million outstanding through 2004 and $2.0 million outstanding thereafter. These guarantees are not reflected in the consolidated financial statements. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For purposes of segment financial reporting and discussion of results of operations, electric and natural gas distribution include the electric and natural gas distribution operations of Montana- Dakota and the natural gas distribution operations of Great Plains Natural Gas Co. Utility services includes all the operations of Utility Services, Inc. Pipeline and energy services includes WBI Holdings' natural gas transportation, underground storage, gathering services, and energy-related management services; Centennial Capital, which invests in domestic growth opportunities; and MDU International, which invests in international growth opportunities. Natural gas and oil production includes the natural gas and oil acquisition, exploration and production operations of WBI Holdings, while construction materials and mining includes the results of Knife River's operations. Reference should be made to Notes to Consolidated Financial Statements for information pertinent to various commitments and contingencies. Overview The following table (dollars in millions, where applicable) summarizes the contribution to consolidated earnings by each of the Company's business segments. Three Months Nine Months Ended Ended September 30, September 30, 2002 2001 2002 2001 Electric $ 4.5 $ 8.3 $ 9.6 $15.2 Natural gas distribution (2.6) (2.7) 1.0 (1.6) Utility services 1.6 3.4 3.8 9.3 Pipeline and energy services 9.9 3.9 15.5 9.7 Natural gas and oil production 6.9 10.5 37.4 56.4 Construction materials and mining 33.4 27.2 34.6 37.3 Earnings on common stock $ 53.7 $ 50.6 $101.9 $126.3 Earnings per common share - basic $ .76 $ .75 $ 1.45 $ 1.89 Earnings per common share - diluted $ .75 $ .74 $ 1.44 $ 1.87 Return on average common equity for the 12 months ended 11.5% 17.0% ________________________________ Three Months Ended September 30, 2002 and 2001 Consolidated earnings for the quarter ended September 30, 2002, increased $3.1 million from the comparable period a year ago due to higher earnings at the construction materials and mining, and pipeline and energy services businesses, along with a slightly lower seasonal loss at the natural gas distribution business. Decreased earnings at the electric, natural gas and oil production, and utility services businesses partially offset the earnings increase. Nine Months Ended September 30, 2002 and 2001 Consolidated earnings for the nine months ended September 30, 2002, decreased $24.4 million from the comparable period a year ago due to lower earnings at the natural gas and oil production, electric, utility services, and construction materials and mining businesses. Increased earnings at the pipeline and energy services, and natural gas distribution businesses partially offset the earnings decline. Equity Method Investment As reported in the Company's Form 8-K which was filed on October 23, 2002, the Company reported the press release issued October 22, 2002, regarding earnings for the quarter ended September 30, 2002. In this press release, the Company reported earnings from its subsidiary's 49 percent owned Brazilian operations in the amount of $4.0 million, largely attributable to foreign currency gains on Brazilian real- denominated obligations. The press release reported that while the matter has not been finally resolved, the Company's management has initially determined the functional currency for the 200-megawatt natural gas fired electric generation project to be the U.S. dollar. The Company's determination is based on the fact that the contract revenues for the project are largely indexed to the U.S. dollar. In addition, the majority of expected operation and maintenance expenses as well as actual equipment purchases are in U.S. dollars. The press release also reported that if, however, the Brazilian real is ultimately deemed to be the functional currency, rather than recording a $4.0 million gain, the Company would be required to restate earnings for the three months ended September 30, 2002 to reflect a net loss from Brazilian operations for the third quarter of approximately $7.5 million, largely from foreign currency losses related to U.S. dollar-denominated obligations. This change from a gain to a loss on the equity method investment would result in earnings and earnings per common share, diluted, for the three months ended September 30, 2002 of $42.2 million and $.59, respectively and for the nine months ended September 30, 2002 of $90.4 million and $1.28, respectively. At the time of filing this quarterly report on Form 10-Q, the above matter has not been finally resolved. This matter is expected to be resolved in the fourth quarter. ________________________________ Financial and operating data The following tables (dollars in millions, where applicable) are key financial and operating statistics for each of the Company's business segments. Electric Three Months Nine Months Ended Ended September 30, September 30, 2002 2001 2002 2001 Operating revenues: Retail sales $ 37.1 $ 37.9 $ 103.3 $ 103.5 Sales for resale and other 4.4 10.3 14.6 25.6 41.5 48.2 117.9 129.1 Operating expenses: Fuel and purchased power 14.5 15.0 41.6 42.7 Operation and maintenance 10.8 10.5 33.7 34.0 Depreciation, depletion and amortization 4.8 4.9 14.6 14.5 Taxes, other than income 1.8 1.8 5.6 5.6 31.9 32.2 95.5 96.8 Operating income $ 9.6 $ 16.0 $ 22.4 $ 32.3 Retail sales (million kWh) 609.9 597.3 1,669.6 1,640.4 Sales for resale (million kWh) 153.6 201.0 580.0 649.0 Average cost of fuel and purchased power per kWh $ .018 $ .018 $ .018 $ .018 Natural Gas Distribution Three Months Nine Months Ended Ended September 30, September 30, 2002 2001 2002 2001 Operating revenues: Sales $ 16.0 $ 17.8 $ 119.9 $ 197.9 Transportation and other .8 .9 2.8 2.9 16.8 18.7 122.7 200.8 Operating expenses: Purchased natural gas sold 8.6 10.7 82.4 162.6 Operation and maintenance 8.5 8.3 27.0 27.8 Depreciation, depletion and amortization 2.4 2.3 7.2 7.0 Taxes, other than income 1.2 1.2 3.8 3.8 20.7 22.5 120.4 201.2 Operating income (loss) $ (3.9) $ (3.8) $ 2.3 $ (0.4) Volumes (MMdk): Sales 3.1 3.0 26.2 24.6 Transportation 2.5 2.9 8.9 9.8 Total throughput 5.6 5.9 35.1 34.4 Degree days (% of normal) 82% 88% 104% 98% Average cost of natural gas, including transportation thereon, per dk $ 2.73 $ 3.53 $ 3.14 $ 6.61 Utility Services Three Months Nine Months Ended Ended September 30, September 30, 2002 2001 2002 2001 Operating revenues $ 113.4 $ 92.2 $ 338.1 $ 236.7 Operating expenses: Operation and maintenance 104.3 80.7 311.7 206.4 Depreciation, depletion and amortization 2.4 2.1 6.8 5.8 Taxes, other than income 3.1 2.6 10.8 6.2 109.8 85.4 329.3 218.4 Operating income $ 3.6 $ 6.8 $ 8.8 $ 18.3 Pipeline and Energy Services Three Months Nine Months Ended Ended September 30, September 30, 2002 2001 2002 2001 Operating revenues: Pipeline $ 26.4 $ 22.7 $ 71.4 $ 64.9 Energy services and other 2.0 42.1 44.9 424.1 28.4 64.8 116.3 489.0 Operating expenses: Purchased natural gas sold .7 40.2 36.8 416.4 Operation and maintenance 12.1 10.4 38.8 33.9 Depreciation, depletion and amortization 3.8 3.9 11.2 10.7 Taxes, other than income 1.3 1.6 4.4 4.6 17.9 56.1 91.2 465.6 Operating income $ 10.5 $ 8.7 $ 25.1 $ 23.4 Transportation volumes (MMdk): Montana-Dakota 9.4 8.9 24.6 26.4 Other 20.5 19.2 52.4 46.8 29.9 28.1 77.0 73.2 Gathering volumes (MMdk) 18.8 15.2 52.4 44.0 Natural Gas and Oil Production Three Months Nine Months Ended Ended September 30, September 30, 2002 2001 2002 2001 Operating revenues: Natural gas $ 30.2 $ 29.2 $ 87.8 $ 124.8 Oil 11.9 12.4 33.1 38.9 Other .1 .9 27.4* 5.8 42.2 42.5 148.3 169.5 Operating expenses: Purchased natural gas sold --- .7 --- 2.4 Operation and maintenance 14.7 11.9 41.8 34.7 Depreciation, depletion and amortization 12.3 10.3 35.2 30.4 Taxes, other than income 3.1 2.3 8.8 8.7 30.1 25.2 85.8 76.2 Operating income $ 12.1 $ 17.3 $ 62.5 $ 93.3 Production: Natural gas (MMcf) 12,219 9,921 34,571 29,641 Oil (000's of barrels) 486 510 1,469 1,492 Average realized prices: Natural gas (per Mcf) $ 2.48 $ 2.94 $ 2.54 $ 4.21 Oil (per barrel) $ 24.44 $ 24.33 $ 22.54 $ 26.04 * Includes the effects of a nonrecurring compromise agreement of $27.4 million ($16.6 million after tax) in the first quarter of 2002. Construction Materials and Mining Three Months Nine Months Ended Ended September 30, September 30, 2002 2001 2002 2001 Operating revenues: Construction materials $ 378.6 $ 301.6 $ 701.5 $ 584.3 Coal ---** ---** ---** 12.3 378.6 301.6 701.5 596.6 Operating expenses: Operation and maintenance 299.1 236.5 581.7 489.7 Depreciation, depletion and amortization 14.9 12.7 39.5 34.3 Taxes, other than income 6.3 4.2 14.2 12.4 320.3 253.4 635.4 536.4 Operating income $ 58.3 $ 48.2 $ 66.1 $ 60.2 Sales (000's): Aggregates (tons) 13,155 11,023 25,600 19,951 Asphalt (tons) 3,745 3,310 5,732 4,732 Ready-mixed concrete (cubic yards) 951 804 2,145 1,916 Coal (tons) ---** ---** ---** 1,171 ** Coal operations were sold effective April 30, 2001. Amounts presented in the preceding tables for operating revenues, purchased natural gas sold and operation and maintenance expenses will not agree with the Consolidated Statements of Income due to the elimination of intercompany transactions between the pipeline and energy services segment and the natural gas distribution, utility services, construction materials and mining, and natural gas and oil production segments. The amounts relating to the elimination of intercompany transactions for operating revenues, purchased natural gas sold, and operation and maintenance expenses are as follows: $8.5 million, $4.7 million and $3.8 million for the three months ended September 30, 2002; $16.3 million, $14.7 million and $1.6 million for the three months ended September 30, 2001; $70.2 million, $59.1 million and $11.1 million for the nine months ended September 30, 2002; and $82.4 million, $79.0 million and $3.4 million for the nine months ended September 30, 2001, respectively. Three Months Ended September 30, 2002 and 2001 Electric Electric earnings decreased as a result of lower average realized sales for resale prices, which were 55 percent lower than last year, due to a weaker demand in the sales for resale markets, and a North Dakota retail rate reduction. Slightly offsetting the earnings decline were increased retail sales, primarily to large industrial and commercial customers. For further information on the North Dakota retail rate reduction, see Prospective Information. Natural Gas Distribution Normal seasonal losses at the natural gas distribution business decreased slightly as a result of somewhat higher retail sales volumes, primarily to commercial customers, along with an interim rate increase in Montana of $2.1 million annually, effective with service rendered on and after September 5, 2002. Utility Services Utility services earnings decreased due to a slowdown in telecommunications work and the impact of the weak economy on the technology sector, which resulted in lower construction revenues and margins in the Rocky Mountain and Northwest regions, as well as lower revenues and margins in the engineering services business. Lower equipment sales revenues and margins also added to the earnings decrease. Partially offsetting the earnings decline were increased workloads in the utility sector. The increase in revenues and the related increase in operation and maintenance expense resulted largely from businesses acquired since the comparable period last year. Pipeline and Energy Services The results of the pipeline and energy services segment could vary significantly from those discussed below, depending on the ultimate outcome of the determination of the functional currency of the Company's equity method investment in a natural gas fired electric generation project in Brazil as previously discussed. Earnings at the pipeline and energy services business increased largely as a result of earnings of $4.0 million from a 49 percent equity investment in a Brazilian natural gas fired electric generation project, largely attributable to foreign currency gains on Brazilian real-denominated obligations, partially offset by interest expense due to high local short-term interest rates. For further information on the Brazilian natural gas fired electric generation project, see Note 12 of Notes to Consolidated Financial Statements. Also adding to the earnings increase were higher natural gas volumes transported and gathered at higher average rates, increased storage revenues and the absence in 2002 of the 2001 loss on the sale of the Company's energy marketing operations. Lower technology services revenues, largely due to the depressed telecommunications sector, partially offset the earnings increase. The $40.1 million decrease in energy services revenue and the related decrease in purchased natural gas sold were due primarily to decreased energy marketing volumes resulting from the sale of the vast majority of the Company's low-margin energy marketing operations in the third quarter of 2001. Natural Gas and Oil Production Natural gas and oil production earnings decreased due to lower realized natural gas prices which were 16 percent lower than last year, largely the result of significantly lower natural gas prices in the Rocky Mountain area; higher lease operating costs resulting from the expansion of coalbed natural gas production; increased depreciation, depletion and amortization expense due to higher natural gas production volumes and slightly higher rates; increased interest expense due to higher average debt balances; and decreased oil production of 5 percent. Increased natural gas production of 23 percent, largely from operated properties in the Rocky Mountain area, partially offset the earnings decrease. Hedging activities for natural gas for the third quarter of 2002 and 2001 resulted in realized prices that were 116 and 111 percent, respectively, of what otherwise would have been received. In addition, hedging activities for oil for the third quarter of 2002 and 2001 resulted in realized prices that were 95 and 102 percent, respectively, of what otherwise would have been received. Construction Materials and Mining Earnings for the construction materials and mining business increased as a result of earnings from companies acquired since the comparable period a year ago, and higher aggregate, cement, and ready-mixed concrete sales volumes combined with higher construction revenues at existing operations. Existing operations accounted for nearly 30 percent of the earnings increase. Partially offsetting the earnings increase were higher insurance costs and higher depreciation, depletion and amortization expense due primarily to higher property, plant and equipment balances. Nine Months Ended September 30, 2002 and 2001 Electric Electric earnings decreased as a result of lower average realized sales for resale prices, which were 44 percent lower than last year, due to weaker demand in the sales for resale markets, a North Dakota retail rate reduction, the absence in 2002 of 2001 insurance recovery proceeds related to a 2000 outage at an electric generating station and lower sales for resale volumes. Partially offsetting the earnings decline were decreased purchased power costs, increased retail sales volumes, primarily to residential and large industrial customers, and decreased interest expense. For further information on the North Dakota retail rate reduction, see Prospective Information. Natural Gas Distribution Earnings at the natural gas distribution business increased as a result of higher retail sales volumes, which were 7 percent higher than last year, increased return on natural gas storage, demand and prepaid commodity balances, decreased operation and maintenance expense due primarily to decreased bad debt expense, and higher service and repair margins. The pass-through of lower natural gas prices resulted in the decrease in sales revenues and purchased natural gas sold. Utility Services Utility services earnings decreased as a result of lower line construction margins in the Rocky Mountain region related primarily to decreased fiber optic construction work; decreased equipment sales and margins; the write-off of receivables of $1.4 million (after tax) associated with a company in the telecommunications industry; lower construction margins in the Central region, partially due to an unfavorable settlement of a billing dispute of $724,000 (after tax); and decreased margins at the engineering segment. Partially offsetting the earnings decline were increased workloads in the Southwest and Northwest regions, and the discontinuance of the amortization of goodwill in 2002 ($1.1 million after tax in 2001). The increase in revenues and the related increase in operation and maintenance expense resulted largely from businesses acquired since the comparable period last year. Pipeline and Energy Services The results of the pipeline and energy services segment could vary significantly from those discussed below, depending on the ultimate outcome of the determination of the functional currency of the Company's equity method investment in a natural gas fired electric generation project in Brazil as previously discussed. Earnings at the pipeline and energy services business increased as a result of higher gathering volumes at higher average rates, increased volumes transported into storage at slightly higher average rates and higher storage revenues. Also contributing to the earnings improvement was the absence in 2002 of a 2001 write-off of an investment in a software development company of $699,000 (after tax). Partially offsetting the earnings increase were higher operation and maintenance expense, largely related to the expansion of the gathering system to accommodate increasing natural gas volumes, higher depreciation, depletion and amortization expense resulting from increased property, plant and equipment balances, and lower technology services revenues, as previously described. Also adding to the earnings increase were earnings of $2.2 million in connection with domestic and international energy projects, largely attributable to currency gains on Brazilian real-denominated obligations. Partially offsetting the foreign currency gain were ongoing development costs due, in part, to delays in commercial production of power from the second 100 megawatts of installed capacity of the natural gas fired electric generation project in Brazil due to a delay until early 2003 in the third party delivery of natural gas supply, and interest expense, as previously described. The $379.2 million decrease in energy services revenue and the related decrease in purchased natural gas sold were due primarily to decreased energy marketing volumes resulting from the sale of the vast majority of the Company's low-margin energy marketing operations in the third quarter of 2001. Natural Gas and Oil Production Natural gas and oil production earnings decreased largely due to lower realized natural gas and oil prices which were 40 percent and 13 percent lower than last year, respectively, partially offset by higher natural gas production of 17 percent, largely from operated properties in the Rocky Mountain area. Also adding to the earnings decline were increased operation and maintenance expense, mainly higher lease operating expenses resulting from the expansion of coalbed natural gas production; increased depreciation, depletion and amortization expense due to higher natural gas production volumes and higher rates; and lower sales volumes of inventoried natural gas. Partially offsetting the earnings decline were the effects of the nonrecurring compromise agreement of $27.4 million ($16.6 million after tax), included in operating revenue, as discussed in Note 15 of Notes to Consolidated Financial Statements. Hedging activities for natural gas for the nine months ended September 30, 2002 and 2001 resulted in realized prices that were 109 and 99 percent, respectively, of what otherwise would have been received. In addition, hedging activities for oil for the nine months ended September 30, 2002 and 2001 resulted in realized prices that were 99 and 102 percent, respectively, of what otherwise would have been received. Construction Materials and Mining Earnings for the construction materials and mining business decreased as a result of the one-time gain in 2001 from the sale of the Company's coal operations of $11.0 million ($6.6 million after tax), included in other income - net, as previously discussed in Note 11 of Notes to Consolidated Financial Statements. Higher selling, general and administrative costs, mainly due to higher insurance and payroll costs, and higher depreciation, depletion and amortization expense due to higher property, plant and equipment balances, partially offset by the discontinuance of the amortization of goodwill in 2002 ($1.2 million after tax in 2001), also added to the earnings decline. Partially offsetting the decrease in earnings were earnings from businesses acquired since the comparable period last year, higher aggregate and asphalt sales volumes, and decreased interest expense due to lower interest rates and lower average borrowings. Safe Harbor for Forward-looking Statements The Company is including the following cautionary statement in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Prospective Information. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation management's examination of historical operating trends, data contained in the Company's records and other data available from third parties, but there can be no assurance that the Company's expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the effect of each such factor on the Company's business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in forward-looking statements include: natural gas and oil commodity prices; prevailing governmental policies and regulatory actions with respect to allowed rates of return, financings, or industry and rate structures; acquisition and disposal of assets or facilities; operation and construction of plant facilities; recovery of purchased power and purchased gas costs; present or prospective generation; and availability of economic supplies of natural gas. Other important factors include the level of governmental expenditures on public projects and the timing of such projects, changes in anticipated tourism levels, the effects of competition (including but not limited to electric retail wheeling and transmission costs and prices of alternate fuels and system deliverability costs), drilling successes in natural gas and oil operations, the ability to contract for or to secure necessary drilling rig contracts and to retain employees to drill for and develop reserves, ability to acquire natural gas and oil properties, the availability of economic expansion or development opportunities, and political, regulatory and economic conditions and changes in currency rates in foreign countries where the Company does business. The business and profitability of the Company are also influenced by economic and geographic factors, including political and economic risks, economic disruptions caused by terrorist activities, changes in and compliance with environmental and safety laws and policies, weather conditions, population growth rates and demographic patterns, market demand for energy from plants or facilities, changes in tax rates or policies, unanticipated project delays or changes in project costs, unanticipated changes in operating expenses or capital expenditures, labor negotiations or disputes, changes in credit ratings or capital market conditions, inflation rates, inability of the various counterparties to meet their contractual obligations, changes in accounting principles and/or the application of such principles to the Company, changes in technology and legal proceedings, and the ability to effectively integrate the operations of acquired companies. Prospective Information The following information includes highlights of the key growth strategies, projections and certain assumptions for the Company and its subsidiaries over the next few years and other matters for each of the Company's six business segments. Many of these highlighted points are forward-looking statements. There is no assurance that the Company's projections, including estimates for growth and increases in revenues and earnings, will in fact be achieved. Reference should be made to assumptions contained in this section as well as the various important factors listed under the heading Safe Harbor for Forward-looking Statements. Changes in such assumptions and factors could cause actual future results to differ materially from targeted growth, revenue and earnings projections. MDU Resources Group, Inc. - Earnings per share, diluted, for 2002 are projected in the $1.80 to $2.00 range. Excluding the benefit of the compromise agreement discussed in Note 15 of Notes to Consolidated Financial Statements, 2002 earnings per share from operations are projected to be in the approximate range of $1.60 to $1.80. Earnings per share, diluted, for 2002 could vary significantly from the amounts discussed above, depending on the ultimate outcome of the determination of the functional currency of the Company's equity method investment in a natural gas fired electric generation project in Brazil as previously discussed. - Earnings per share, diluted, for 2003 are projected in the $1.80 to $2.05 range. - Weighted average diluted common shares outstanding for the twelve months ended December 31, 2001, were 67.9 million. The Company anticipates a 3 percent to 7 percent increase in weighted average diluted shares outstanding by 2002 year end. - The Company will examine issuing equity from time to time to keep debt at the nonregulated businesses at no more than 40 percent of total capitalization. - The Company estimates that the benefit resulting solely from the discontinuance of goodwill amortization would be 5 cents to 6 cents per common share in 2002. - The Company's long-term compound annual growth goals on earnings per share from operations are in the range of 6 percent to 9 percent. Electric - Montana-Dakota has obtained and holds valid and existing franchises authorizing it to conduct its electric and natural gas operations in all of the municipalities it serves where such franchises are required. As franchises expire, Montana-Dakota may face increasing competition in its service areas, particularly its service to smaller towns, from rural electric cooperatives. 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. - On May 2, 2002, the District Court granted Montana-Dakota's request for a stay of a portion of the $4.3 million annual rate reduction ordered by the NDPSC. Accordingly, Montana-Dakota implemented an annual rate reduction of $800,000 effective with service rendered on and after May 8, 2002, rather than the $4.3 million annual reduction ordered by the NDPSC. The remaining $3.5 million is subject to refund if Montana-Dakota does not prevail in this proceeding. Reserves have been provided for the revenues that have been collected subject to refund with respect to this pending electric rate reduction. Oral arguments before the District Court were held on October 9, 2002, and a ruling is expected in the near future. For more information on this proceeding see Note 14 of Notes to Consolidated Financial Statements. - A 40-megawatt natural gas fired peaking unit is scheduled to be constructed for operation by June 1, 2003. This project is expected to be recovered in rates and will be used to meet the utility's need for additional generating capacity. - Pending regulatory approval, the Company plans to purchase energy from a 20-megawatt, wind energy farm in North Dakota. Rate recovery is expected. - Montana-Dakota is working with the State of North Dakota to determine the feasibility of constructing a 500-megawatt lignite- fired power plant in western North Dakota. The first preliminary decision is expected in December 2002. Natural gas distribution - Annual natural gas throughput for 2002 is expected to be approximately 53 million decatherms, with about 40 million decatherms from sales and 13 million decatherms from transportation, which compares to 37 million decatherms from sales and 14 million decatherms from transportation in 2001. - Montana-Dakota and Great Plains have filed applications with state regulatory authorities in four states (Minnesota, Wyoming, Montana and North Dakota) seeking increases in natural gas retail rates that are in the range of 4.1 percent to 6.9 percent above current rates. While Montana-Dakota and Great Plains believe that they should be authorized to increase retail rates in the respective amounts requested, there is no assurance that the increases ultimately allowed will be for the full amounts requested in each jurisdiction. For further information on the natural gas rate increase applications, see Note 14 of Notes to Consolidated Financial Statements. Utility services - Revenues for this segment are expected to be approximately $450 million in 2002, a 23 percent increase over 2001. However, earnings are estimated to decrease by approximately 50 percent from the 2001 level due to lower margins resulting from current economic conditions combined with the second quarter 2002 write-off of receivables and an unfavorable billing dispute settlement. Earnings from this segment accounted for approximately 8 percent of consolidated 2001 earnings. Pipeline and energy services - In 2002, natural gas throughput from this segment, including both transportation and gathering, is expected to increase by more than 5 percent over the 2001 record level throughput. - A 247-mile pipeline to transport additional natural gas to market and enhance the use of this segment's storage facilities is currently under regulatory review. An application has been filed to modify the proposed construction of this pipeline. The amended plan seeks to reroute a portion of the line and modifies facility construction to reduce the proposed initial maximum firm daily design delivery capacity and revises the original construction schedule. Depending upon the timing of the receipt of the necessary regulatory approval, construction completion could occur as early as late 2003. - MDU International continues its efforts to complete the financing for a 200-megawatt natural gas fired electric generation project in Brazil. The first 100 megawatts have begun commercial production and the second 100 megawatts are scheduled to begin commercial production early in 2003. Petrobras, the purchaser of the output from the project, commenced making capacity payments in the third quarter. Earnings for 2002 from the natural gas fired electric generation project in Brazil could vary significantly depending on the ultimate outcome of the determination of the functional currency of the Company's equity method investment in this project as previously discussed. - On November 1, 2002, the Company's independent power production group purchased 213 megawatts of natural gas fired electric generating facilities. Ninety-five percent of the facilities' output is sold to a non-affiliated utility under long-term power purchase contracts. The acquisition is expected to be funded with long-term debt and equity. - The Company's plans to construct a 113-megawatt coal-fired electric generation station in Montana are pending. The Company purchased plant equipment and obtained all permits necessary to begin construction. NorthWestern Energy terminated the power purchase agreement for the energy from this plant in July 2002; however, the Company is pursuing other markets for the energy and is studying its options regarding this project. The Company has suspended construction activities except for those items of a critical nature. At September 30, 2002, the Company's investment in this project was approximately $22.4 million. Natural gas and oil production - This segment anticipates combined natural gas and oil production in 2002 to be approximately 10 percent to 15 percent higher than in 2001. - In 2003, this segment expects a combined production increase in excess of 20 percent over 2002 levels. - This segment expects to drill approximately 250 wells in 2002. - Natural gas prices in the Rocky Mountain Region for November and December 2002 reflected in the Company's 2002 earnings guidance are in the range of $2.00 to $2.50 per Mcf. The Company's estimates for natural gas prices on the NYMEX for November and December 2002 reflected in the Company's 2002 earnings guidance are in the range of $3.50 to $4.00 per Mcf. During the first nine months of 2002, more than half of this segment's natural gas production was priced using Rocky Mountain or other non-NYMEX prices. - NYMEX crude oil prices for November and December 2002 reflected in the Company's 2002 earnings guidance are in the range of $28 to $30 per barrel. - This segment has hedged a portion of its 2002 production. The Company has entered into swap agreements and fixed price forward sales representing approximately 35 percent to 40 percent of 2002 estimated annual natural gas production. These natural gas swaps are at various indices and range from a low CIG index of $2.73 to a high NYMEX price of $4.34. The Company has also entered into oil swap agreements at average NYMEX prices in the range of $24.80 to $25.90 per barrel, representing approximately 30 percent to 35 percent of the Company's 2002 estimated annual oil production. - The Company has hedged a portion of its 2003 production. The Company has entered into costless collars, a natural gas swap and fixed price forward sales, representing approximately 35 percent to 40 percent of 2003 estimated annual natural gas production. The costless collars and swap are at various indices and range from a low CIG index of $2.94 to a high Ventura index of $4.30 per Mcf. - For 2003, the Company's estimates for natural gas prices in the Rocky Mountain Region are in the range of $2.50 to $3.00 per Mcf and estimates for natural gas prices on the NYMEX are in the range of $3.00 to $3.50. - The Company's estimates for NYMEX crude oil prices are in the range of $20 to $25 per barrel for 2003. - The Company has hedged a portion of its 2003 oil production. The Company has entered into a costless collar at NYMEX prices with a floor of $24.50 and a cap of $27.15 representing approximately 15 percent to 20 percent of 2003 estimated annual oil production. Construction materials and mining - Excluding the effects of potential future acquisitions, aggregate volumes are expected to increase by approximately 18 percent to 23 percent in 2002 and asphalt and ready-mixed concrete volumes are expected to increase by 15 percent to 20 percent and 5 percent to 10 percent, respectively, in 2002. - Work has begun on a $167 million joint venture harbor deepening project in Los Angeles. One of the Company's subsidiaries is responsible for approximately one-half of this project and will be supplying rock from its Catalina Island quarry. Another subsidiary has begun work on a multi-year resort project in the State of Washington. - Revenues for this segment are expected to exceed $900 million in 2002. - Revenues are expected to grow by 5 percent to 10 percent in 2003. New Accounting Standards In June 2001, the FASB approved SFAS No. 143. For further information on SFAS No. 143, see Note 6 of Notes to Consolidated Financial Statements. In June 2001, the FASB approved SFAS No. 142. Under SFAS No. 142, goodwill and other intangible assets with indefinite lives are no longer amortized but are reviewed annually, or more frequently if impairment issues arise, for impairment. As of December 31, 2001, the Company had unamortized goodwill of $174.0 million that was subject to the provisions of SFAS No. 142. Had SFAS No. 142 been in effect for 2001, earnings would have been $4.2 million higher. For further information on SFAS No. 142, see Note 9 of Notes to Consolidated Financial Statements. In April 2002, the FASB approved SFAS No. 145. For further information on SFAS No. 145, see Note 6 of Notes to Consolidated Financial Statements. In June 2002, the EITF adopted the position in EITF No. 02-3. For further information on EITF No. 02-3, see Note 6 of Notes to Consolidated Financial Statements. In June 2002, the FASB approved SFAS No. 146. For further information on SFAS No. 146, see Note 6 of Notes to Consolidated Financial Statements. Critical Accounting Policies The Company's critical accounting policies include impairment of long-lived assets and intangibles, impairment testing of natural gas and oil production properties, revenue recognition, derivatives, purchase accounting and accounting for the effects of regulation. There are no material changes in the Company's critical accounting policies from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. For more information on critical accounting policies, see Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. Liquidity and Capital Commitments Cash flows Operating activities -- Cash flows from operating activities in the first nine months of 2002 decreased $57.2 million from the comparable 2001 period, primarily due to a decrease in cash from changes in working capital items of $53.3 million and the decrease in net income of $24.3 million. The working capital decrease was primarily due to lower natural gas prices compared to the same period last year. Higher depreciation, depletion and amortization expense of $11.8 million resulting largely from increased property, plant and equipment balances partially offset the decrease in cash flows from operating activities. Investing activities -- Cash flows used in investing activities in the first nine months of 2002 decreased $78.2 million compared to the comparable period in 2001, the result of a decrease in net capital expenditures (capital expenditures, acquisitions, net of cash acquired, and net proceeds from the sale or disposition of property). Net capital expenditures exclude the noncash transactions related to acquisitions, including the issuance of the Company's equity securities. The noncash transactions were $46.0 million and $57.3 million in the first nine months of 2002 and 2001, respectively. Financing activities -- Financing activities resulted in a decrease in cash flows for the first nine months of 2002 of $41.3 million compared to the comparable 2001 period. This decrease was largely due to the decrease in issuance of long-term debt of $90.8 million and the decrease in proceeds from issuance of common stock of $52 million. This decrease was partially offset by a decrease in the repayment of long-term debt of $88 million. Capital expenditures Net capital expenditures, including the issuance of the Company's equity securities, for the first nine months of 2002 were $267.6 million and are estimated to be approximately $420 million for the year 2002, including those for acquisitions, system upgrades, routine replacements, service extensions, routine equipment maintenance and replacements, land and building improvements, pipeline and gathering expansion projects, the further enhancement of natural gas and oil production and reserve growth, power generation opportunities and other growth opportunities. Approximately 30 percent to 35 percent of estimated net capital expenditures for 2002 are for completed acquisitions. The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, actual acquisitions and capital expenditures may vary significantly from the estimated 2002 capital expenditures referred to above. It is anticipated that the funds required for capital expenditures will be met from various sources. These sources include internally generated funds, a revolving credit and term loan agreement, a commercial paper credit facility at Centennial, as described below, and through the issuance of long-term debt and the Company's equity securities. The estimated 2002 capital expenditures referred to above include completed 2002 acquisitions involving construction materials and mining businesses in Minnesota and Montana, an energy development company in Montana, utility services companies in California and Ohio, and natural gas fired electric generation facilities in Colorado. Pro forma financial amounts reflecting the effects of the above acquisitions are not presented as such acquisitions were not material to the Company's financial position or results of operations. Capital resources MDU Resources Group, Inc. The Company has a revolving credit and term loan agreement with various banks that allows for borrowings of up to $40 million. In addition, the Company has unsecured bank lines of credit aggregating $60 million. Under the credit and term loan agreement, $23 million was outstanding at September 30, 2002. There were no outstanding borrowings under the Company's bank lines of credit at September 30, 2002. The borrowings by the Company under the credit and term loan agreement, which allows for subsequent borrowings up to a term of one year, are classified as long term as the Company intends to refinance these borrowings on a long-term basis. The Company intends to renew or replace the existing credit and term loan agreement, which expires on December 31, 2002. The Company also has arrangements with commercial paper dealers to sell commercial paper from time to time, and has recently requested regulatory authority to incur indebtedness in the form of bank loans and commercial paper up to $125 million in total. The Company's goal is to maintain acceptable credit ratings under its credit agreements and individual bank lines of credit in order to access the capital markets through the issuance of commercial paper. If the Company were to experience a minor downgrade of its credit rating, the Company would not anticipate any change in its ability to access the capital markets. However, in such event, the Company would expect a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If the Company were to experience a significant downgrade of its credit ratings, which the Company does not currently anticipate, it may need to borrow under its committed bank lines. To the extent the Company needs to borrow under its committed bank lines, it would be expected to incur increased annualized interest expense on its variable rate debt. This was not applicable for the calendar year 2002 as there were no variable rate borrowings at September 30, 2002. On an annual basis, the Company negotiates the placement of its individual bank lines of credit that provide credit support to access the capital markets. In the event the Company were unable to successfully negotiate the bank credit facilities, or in the event the fees on such facilities became too expensive, which the Company does not currently anticipate, the Company would seek alternative funding. One source of alternative funding might involve the securitization of certain Company assets. Currently, there are no credit facilities that contain cross- default provisions between the Company and any of its subsidiaries. The Company's issuance of first mortgage debt is subject to certain restrictions imposed under the terms and conditions of its Indenture of Mortgage. Generally, those restrictions require the Company to pledge $1.43 of unfunded property to the Trustee for each dollar of indebtedness incurred under the Indenture and that annual earnings (pretax and before interest charges), as defined in the Indenture, equal at least two times its annualized first mortgage bond interest costs. Under the more restrictive of the two tests, as of September 30, 2002, the Company could have issued approximately $319 million of additional first mortgage bonds. The Company's coverage of fixed charges including preferred dividends was 4.5 times and 5.3 times for the twelve months ended September 30, 2002 and December 31, 2001, respectively. Additionally, the Company's first mortgage bond interest coverage was 7.3 times and 8.5 times for the twelve months ended September 30, 2002 and December 31, 2001, respectively. Common stockholders' equity as a percent of total capitalization was 58 percent at September 30, 2002 and December 31, 2001. Centennial Energy Holdings, Inc. Centennial has a revolving credit agreement (Centennial credit agreement) with various banks that supports $305 million of Centennial's $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreement at September 30, 2002. Under the Centennial commercial paper program, $233.6 million was outstanding at September 30, 2002. The Centennial commercial paper borrowings are classified as long term as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings and as further supported by the Centennial credit agreement, which allows for subsequent borrowings up to a term of one year. Centennial intends to renew the Centennial credit agreement, which expires September 26, 2003, on an annual basis. Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $400 million. Under the terms of the master shelf agreement, $261.2 million was outstanding at September 30, 2002. On October 22, 2002, Centennial borrowed an additional $50 million under the terms of this agreement. The $50 million in proceeds were used for partial payment of an acquisition and to pay down Centennial commercial paper program borrowings. Centennial's goal is to maintain acceptable credit ratings under its credit agreement in order to access the capital markets through the issuance of commercial paper. If Centennial were to experience a minor downgrade of its credit rating, it would not anticipate any change in its ability to access the capital markets. However, in such event, Centennial would expect a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If Centennial were to experience a significant downgrade of its credit ratings, which it does not currently anticipate, it may need to borrow under its committed bank lines. To the extent Centennial needs to borrow under its committed bank lines, it would be expected to incur increased annualized interest expense on its variable rate debt by approximately $350,000 (after tax) for the calendar year 2002 based on September 30, 2002 variable rate borrowings. Based on Centennial's overall interest rate exposure at September 30, 2002, this change would not have a material affect on the Company's results of operations. On an annual basis, Centennial negotiates the placement of the Centennial credit agreement that provides credit support to access the capital markets. In the event Centennial was unable to successfully negotiate the credit agreement, or in the event the fees on such facility became too expensive, which Centennial does not currently anticipate, it would seek alternative funding. One source of alternative funding might involve the securitization of certain Centennial assets. In order to borrow under Centennial's credit agreement and the Centennial uncommitted long-term master shelf agreement, Centennial and certain of its subsidiaries must be in compliance with the applicable covenants and certain other conditions. The significant covenants include maximum capitalization ratios, minimum interest coverage ratios, minimum consolidated net worth, limitations on priority debt, limitations on sale of assets and limitations on loans and investments. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at September 30, 2002. In the event Centennial or such subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued as previously described. The Centennial credit agreement and the Centennial uncommitted long-term master shelf agreement contain cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement which causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the Centennial credit agreement and the Centennial uncommitted long-term master shelf agreement will be in default. The Centennial credit agreement, the Centennial uncommitted long- term master shelf agreement and Centennial's practice limit the amount of subsidiary indebtedness. MDU Resources International, Inc. MDU International has a credit agreement that allows for borrowings of up to $25 million. Under this agreement, $10 million was outstanding at September 30, 2002. MDU International intends to renew this credit agreement, which expires June 30, 2003, on an annual basis. In order to borrow under MDU International's credit facilities, MDU International must be in compliance with the applicable covenants and certain other conditions. The significant covenants include limitations on sale of assets and limitations on loans and investments. MDU International was in compliance with these covenants and met the required conditions at September 30, 2002. In the event MDU International does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. Contractual obligations and commercial commitments There are no material changes in the Company's contractual obligations on long-term debt, operating leases and purchase commitments from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. For more information on contractual obligations and commercial commitments, see Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. Certain subsidiaries of the Company have financial guarantees outstanding at September 30, 2002. These guarantees as of September 30, 2002, are approximately $31.2 million, of which approximately $27.8 million pertain to Centennial's guarantee of certain obligations in connection with the natural gas fired electric generation station in Brazil, as discussed in Notes 10 and 15 of Notes to Consolidated Financial Statements in the 2001 Annual Report and Items 2 and 3 of this Quarterly Report on Form 10-Q. As of September 30, 2002, with respect to these guarantees, there were approximately $27.8 million outstanding through 2003, $1.4 million outstanding through 2004 and $2.0 million outstanding thereafter. Approval of audit and non-audit services On November 12, 2002, the Company's audit committee pre- approved certain audit services relating to comfort letters and consents in connection with registration statements and other Securities and Exchange Commission required filings and audit reviews in connection with such filings, audit reviews in connection with business combinations, and additional audit services required in connection with quarterly reviews and annual audits. The audit committee also approved certain non-audit services, relating to tax services in connection with domestic and international operations, and training on accounting and Securities and Exchange Commission compliance. The approved services, to be performed by the Company's auditor, Deloitte & Touche LLP, for the period November 12, 2002 to December 31, 2003, are expected to result in total fees of up to $100,000. Also on that date, the audit committee, in compliance with the "de minimus" exception in the Sarbanes-Oxley Act, approved certain other non-audit services relating to tax services in connection with domestic and international operations of approximately $5,000 that had been performed by the Company's auditors. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to the impact of market fluctuations associated with commodity prices, interest rates, and foreign currency. The Company has policies and procedures to assist in controlling these market risks and utilizes derivatives to manage a portion of its risk. Commodity price risk -- The Company utilizes derivative instruments, including natural gas and oil price swap and natural gas collar agreements, to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on the Company's forecasted sales of natural gas and oil production. For more information on commodity price risk, see Part II, Item 7A in the Company's Annual Report on Form 10-K for the year ended December 31, 2001, and Notes to Consolidated Financial Statements in this Form 10-Q. The following table summarizes hedge agreements entered into by certain wholly owned subsidiaries of the Company, as of September 30, 2002. These agreements call for the subsidiaries to receive fixed prices and pay variable prices. (Notional amount and fair value in thousands) Weighted Average Notional Fixed Price Amount (Per MMBtu) (In MMBtu's) Fair Value Natural gas swap agreements maturing in 2002 $ 3.73 4,225 $1,548 Weighted Average Notional Fixed Price Amount (Per barrel) (In barrels) Fair Value Oil swap agreements maturing in 2002 $ 24.52 194 $(1,061) Weighted Average Floor/Ceiling Notional Price Amount (Per MMBtu) (In MMBtu's) Fair Value Natural gas collar agreements maturing in 2003 $3.24/$3.90 12,118 $(1,651) Interest rate risk -- There are no material changes to interest rate risk faced by the Company from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. For more information on interest rate risk, see Part II, Item 7A in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. Foreign currency risk -- A subsidiary of the Company has a 49 percent equity investment in a 200 megawatt natural gas fired electric generation project (Project) in Brazil which has a portion of its borrowings and payables denominated in Brazilian real. The subsidiary has exposure to currency exchange risk as a result of fluctuations in currency exchange rates between the U.S. dollar and the Brazilian real. For further information on this investment, see Note 12 of Notes to Consolidated Financial Statements. The effects of changes in currency exchange rates with respect to the Project's Brazilian real denominated obligations are reflected in net income. At September 30, 2002, the Project had Brazilian real obligations of approximately US$20.5 million. If, for example, the value of the Brazilian real increased in relation to the U.S. Dollar by 10 percent, the subsidiary, with respect to its interest in the Project, would record a foreign currency translation loss in net income of approximately $1.2 million based on the Brazilian real denominated obligations at September 30, 2002. In addition to the Brazilian real denominated obligations, the Project had $44.1 million of third party U.S. dollar denominated obligations at September 30, 2002. The subsidiary's investment in this Project at September 30, 2002 was $27.8 million. In addition to the subsidiary's investment, Centennial has guaranteed Project obligations and loans of approximately $27.8 million as of September 30, 2002. The subsidiary is managing a portion of its foreign currency exchange risk through contractual provisions that are largely indexed to the U.S. dollar contained in the Project's power purchase agreement with Petrobras. On August 12, 2002, the subsidiary entered into a foreign currency collar agreement for a notional amount of $21.3 million with a fixed price floor of R$3.10 and a fixed price ceiling of R$3.40 to manage a portion of its foreign currency risk. The term of the collar agreement is from August 12, 2002 through February 3, 2003, and the collar agreement settles on February 3, 2003. Gains or losses on this derivative instrument are recorded in earnings each period. The fair value of the foreign currency collar agreement at September 30, 2002 was $415,000 ($260,000 after tax). ITEM 4. CONTROLS AND PROCEDURES The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company. Evaluation of disclosure controls and procedures The term "disclosure controls and procedures" is defined in Rules 13a-14(c) and 15d-14(c) of the Securities Exchange Act of 1934 (Exchange Act). These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. The Company's chief executive officer and chief financial officer have evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days before the filing of this Quarterly Report on Form 10-Q (Evaluation Date), and, they have concluded that, as of the Evaluation Date, such controls and procedures were effective to accomplish those tasks. Changes in internal controls The Company maintains a system of internal accounting controls that are designed to provide reasonable assurance that the Company's transactions are properly authorized, the Company's assets are safeguarded against unauthorized or improper use, and the Company's transactions are properly recorded and reported to permit preparation of the Company's financial statements in conformity with generally accepted accounting principles in the United States. There were no significant changes in the Company's internal controls or in other factors that could significantly affect the Company's internal controls subsequent to the Evaluation Date, nor were there any significant deficiencies or material weaknesses in the Company's internal controls. PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The 11 natural gas producers filed a petition for writ of certiorari with the Supreme Court of the United States, which was docketed on August 21, 2002. On October 21, 2002, the Supreme Court of the United States denied the writ of certiorari. For more information on the above legal action see Note 15 of Notes to Consolidated Financial Statements. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS Between July 1, 2002 and September 30, 2002, the Company issued 15,495 shares of Common Stock, $1.00 par value, as part of final adjustments with respect to acquisitions in a prior period. The Common Stock issued by the Company in these transactions was issued in private sales exempt from registration pursuant to Section 4(2) of the Securities Act of 1933. The former owners of the businesses acquired, and now shareholders of the Company, are accredited investors and have acknowledged that they would hold the Company's Common Stock as an investment and not with a view to distribution. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a) Exhibits 3(a) Certificate of Designations of Series B Preference Stock of MDU Resources Group, Inc. 10(a) Change of Control Employment Agreement between the Company and John K. Castleberry 10(b) Change of Control Employment Agreement between the Company and Cathleen M. Christopherson 10(c) Change of Control Employment Agreement between the Company and Richard A. Espeland 10(d) Change of Control Employment Agreement between the Company and Terry D. Hildestad 10(e) Change of Control Employment Agreement between the Company and Lester H. Loble, II 10(f) Change of Control Employment Agreement between the Company and Vernon A. Raile 10(g) Change of Control Employment Agreement between the Company and Warren L. Robinson 10(h) Change of Control Employment Agreement between the Company and William E. Schneider 10(i) Change of Control Employment Agreement between the Company and Ronald D. Tipton 10(j) Change of Control Employment Agreement between the Company and Martin A. White 10(k) Change of Control Employment Agreement between the Company and Robert E. Wood 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends 99 Statement Pursuant to Section 906 of Sarbanes - Oxley Act of 2002 b) Reports on Form 8-K Form 8-K was filed on August 14, 2002. Under Item 7 -- Financial Statements and Exhibits and Item 9 -- Regulation FD Disclosure, the Company reported the sworn statements of the Principal Executive Officer and Principal Financial Officer, in compliance with the Securities and Exchange Commission's Order No. 4-460. Form 8-K was filed on October 23, 2002. Under Item 5 -- Other Events, the Company reported the press release issued October 22, 2002, regarding earnings for the quarter ended September 30, 2002. Form 8-K was filed on November 5, 2002. Under Item 5 -- Other Events and Item 7 -- Financial Statements and Exhibits, the Company reported the purchase of 213 megawatts of natural gas fired electric generating facilities. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. MDU RESOURCES GROUP, INC. DATE: November 14, 2002 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 FORM 10-Q CERTIFICATION I, Martin A. White, certify that: 1. I have reviewed this quarterly report on Form 10-Q of MDU Resources Group, Inc.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a- 14 and 15d-14) for the registrant and we have: a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 14, 2002 /s/ Martin A. White Martin A. White Chairman of the Board, President and Chief Executive Officer FORM 10-Q CERTIFICATION I, Warren L. Robinson, certify that: 1. I have reviewed this quarterly report on Form 10-Q of MDU Resources Group, Inc.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a- 14 and 15d-14) for the registrant and we have: a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 14, 2002 /s/ Warren L. Robinson Warren L. Robinson Executive Vice President, Treasurer and Chief Financial Officer EXHIBIT INDEX Exhibit No. 3(a) Certificate of Designations of Series B Preference Stock of MDU Resources Group, Inc. 10(a) Change of Control Employment Agreement between the Company and John K. Castleberry 10(b) Change of Control Employment Agreement between the Company and Cathleen M. Christopherson 10(c) Change of Control Employment Agreement between the Company and Richard A. Espeland 10(d) Change of Control Employment Agreement between the Company and Terry D. Hildestad 10(e) Change of Control Employment Agreement between the Company and Lester H. Loble, II 10(f) Change of Control Employment Agreement between the Company and Vernon A. Raile 10(g) Change of Control Employment Agreement between the Company and Warren L. Robinson 10(h) Change of Control Employment Agreement between the Company and William E. Schneider 10(i) Change of Control Employment Agreement between the Company and Ronald D. Tipton 10(j) Change of Control Employment Agreement between the Company and Martin A. White 10(k) Change of Control Employment Agreement between the Company and Robert E. Wood 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends 99 Statement Pursuant to Section 906 of Sarbanes - Oxley Act of 2002