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, 2001. ------------------ OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES --- EXCHANGE ACT OF 1934 For the transition period from to ------------ Commission file number 001-13643 ONEOK, Inc. (Exact name of registrant as specified in its charter) Oklahoma 73-1520922 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation of organization) 100 West Fifth Street, Tulsa, OK 74103 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (918) 588-7000 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 --- Common stock, with par value of $0.01 - 59,707,645 shares outstanding at November 5, 2001.
ONEOK, Inc. QUARTERLY REPORT ON FORM 10-Q Part I. Financial Information Page No. Item 1. Financial Statements (Unaudited) Consolidated Statements of Income - Three and Nine Months Ended September 30, 2001 and 2000 3 Consolidated Balance Sheets - September 30, 2001 and December 31, 2000 4-5 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2001 and 2000 6 Notes to Consolidated Financial Statements 7-17 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 18-29 Item 3. Quantitative and Qualitative Disclosures about Market Risk 30 Part II. Other Information Item 1. Legal Proceedings 31-32 Item 6. Exhibits and Reports on Form 8-K 33 Signatures 2
Part I - FINANCIAL INFORMATION Item 1. Financial Statements ONEOK, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF INCOME <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, (Unaudited) 2001 2000 2001 2000 -------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars, except per share amounts) <S> <C> <C> <C> <C> Operating Revenues $1,127,189 $1,753,806 $5,486,019 $3,964,021 Cost of gas 923,940 1,563,953 4,771,447 3,354,992 -------------------------------------------------------------------------------------------------------------------- Net Revenues 203,249 189,853 714,572 609,029 -------------------------------------------------------------------------------------------------------------------- Operating Expenses Operations and maintenance 92,493 91,478 283,466 236,541 Depreciation, depletion, and amortization 39,322 36,068 114,133 107,556 General taxes 15,209 15,239 46,252 39,594 -------------------------------------------------------------------------------------------------------------------- Total Operating Expenses 147,024 142,785 443,851 383,691 -------------------------------------------------------------------------------------------------------------------- Operating Income 56,225 47,068 270,721 225,338 -------------------------------------------------------------------------------------------------------------------- Other income, net (2,406) 384 1,951 18,567 Interest expense 34,731 32,337 108,515 82,665 Income taxes (Note L) 301 5,029 54,752 63,085 -------------------------------------------------------------------------------------------------------------------- Income before cumulative effect of a change in accounting principle 18,787 10,086 109,405 98,155 Cumulative effect of a change in accounting principle, net of tax (Notes I and K) - - (2,151) 2,115 -------------------------------------------------------------------------------------------------------------------- Net Income 18,787 10,086 107,254 100,270 Preferred stock dividends 9,275 9,275 27,825 27,825 -------------------------------------------------------------------------------------------------------------------- Income Available for Common Stock $ 9,512 $ 811 $ 79,429 $ 72,445 ==================================================================================================================== Earnings Per Share of Common Stock (Note E) Basic $ 0.16 $ 0.01 $ 0.90 $ 0.85 ==================================================================================================================== Diluted $ 0.16 $ 0.01 $ 0.90 $ 0.85 ==================================================================================================================== Average Shares of Common Stock (Thousands) Basic 99,521 98,292 99,382 98,320 Diluted 99,633 98,300 99,648 98,326 </TABLE> See accompanying Notes to Consolidated Financial Statements. 3
ONEOK, Inc. and Subsidiaries CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> September 30, December 31, (Unaudited) 2001 2000 --------------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> Assets Current Assets Cash and cash equivalents $ 106 $ 249 Trade accounts and notes receivable 539,456 1,627,714 Materials and supplies 18,161 18,119 Gas in storage 96,070 72,979 Deferred income taxes 8,009 10,425 Unrecovered purchased gas costs 74,465 1,578 Assets from price risk management activities 708,483 1,416,368 Deposits 68,805 120,800 Other current assets 29,736 71,906 --------------------------------------------------------------------------------------------------- Total Current Assets 1,543,291 3,340,138 --------------------------------------------------------------------------------------------------- Property, Plant and Equipment Marketing and Trading 3,218 2,795 Gathering and Processing 1,016,535 1,001,994 Transportation and Storage 784,576 758,019 Distribution 1,946,679 1,860,181 Production 471,808 428,701 Power 116,861 75,891 Other 81,205 64,056 --------------------------------------------------------------------------------------------------- Total Property, Plant and Equipment 4,420,882 4,191,637 Accumulated depreciation, depletion, and amortization 1,205,596 1,110,803 --------------------------------------------------------------------------------------------------- Net Property, Plant and Equipment 3,215,286 3,080,834 --------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets Regulatory assets, net (Note B) 227,631 238,605 Goodwill 117,279 92,909 Assets from price risk management activities 370,667 405,666 Investments and other 217,786 202,193 --------------------------------------------------------------------------------------------------- Total Deferred Charges and Other Assets 933,363 939,373 --------------------------------------------------------------------------------------------------- Total Assets $5,691,940 $7,360,345 =================================================================================================== </TABLE> See accompanying Notes to Consolidated Financial Statements. 4
ONEOK, Inc. and Subsidiaries CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> September 30, December 31, (Unaudited) 2001 2000 ---------------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> Liabilities and Shareholders' Equity Current Liabilities Current maturities of long-term debt $ 250,000 $ 10,767 Notes payable 545,331 824,106 Accounts payable 363,004 1,247,519 Dividends Payable 9,256 - Accrued taxes 59,259 8,735 Accrued interest 26,531 24,161 Customers' deposits 19,604 18,319 Liabilities from price risk management activities 464,182 1,296,041 Other 36,021 96,913 ---------------------------------------------------------------------------------------------------- Total Current Liabilities 1,773,188 3,526,561 ---------------------------------------------------------------------------------------------------- Long-term Debt, excluding current maturities 1,514,153 1,336,082 Deferred Credits and Other Liabilities Deferred income taxes 449,216 382,363 Liabilities from price risk management activities 368,264 543,278 Lease obligation 125,251 137,131 Other deferred credits 179,437 209,973 ---------------------------------------------------------------------------------------------------- Total Deferred Credits and Other Liabilities 1,122,168 1,272,745 ---------------------------------------------------------------------------------------------------- Total Liabilities 4,409,509 6,135,388 ---------------------------------------------------------------------------------------------------- Commitments and Contingencies (Note F) Shareholders' Equity Convertible preferred stock, $0.01 par value: Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at September 30, 2001 and December 31, 2000 199 199 Common stock, $0.01 par value: authorized 300,000,000 shares; issued 63,438,441 shares and outstanding 59,702,698 shares at September 30, 2001; issued 63,198,610 shares and outstanding 59,176,550 shares at December 31, 2000 634 632 Paid in capital (Note H) 901,692 895,352 Unearned compensation (2,212) (1,128) Accumulated other comprehensive income (Note J) 5,623 - Retained earnings 430,348 387,789 Treasury stock at cost: 3,735,743 shares at September 30, 2001; and 4,022,060 shares at December 31, 2000 (53,853) (57,887) ---------------------------------------------------------------------------------------------------- Total Shareholders' Equity 1,282,431 1,224,957 ---------------------------------------------------------------------------------------------------- Total Liabilities and Shareholders' Equity $5,691,940 $7,360,345 ==================================================================================================== </TABLE> 5
ONEOK, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS <TABLE> <CAPTION> Nine Months Ended September 30, (Unaudited) 2001 2000 -------------------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> Operating Activities Net income $ 107,254 $ 100,270 Depreciation, depletion, and amortization 114,133 107,556 Gain on sale of assets (1,120) (27,050) Gain on sale of equity investments (758) - Income from equity investments (8,100) (3,357) Deferred income taxes 65,394 28,633 Amortization of restricted stock 844 492 Changes in assets and liabilities: Accounts and notes receivable 1,088,258 (776,605) Inventories (23,133) (121,935) Unrecovered purchased gas costs (72,887) 2,174 Deposits 51,995 (47,908) Accounts payable and accrued liabilities (781,922) 806,352 Price risk management assets and liabilities (231,768) (38,021) Other assets and liabilities (85,957) (22,305) -------------------------------------------------------------------------------------------------------- Cash Provided by Operating Activities 222,233 8,296 -------------------------------------------------------------------------------------------------------- Investing Activities Changes in other investments, net 756 (111) Acquisitions (15,345) (460,472) Capital expenditures (243,244) (217,904) Proceeds from sale of property 7,911 60,659 Proceeds from sale of equity investment 7,425 - -------------------------------------------------------------------------------------------------------- Cash Used in Investing Activities (242,497) (617,828) -------------------------------------------------------------------------------------------------------- Financing Activities Payments of notes payable, net (278,775) 18,863 Change in bank overdraft (48,414) 89,632 Issuance of debt 401,367 589,429 Payment of debt (7,115) (22,948) Issuance of common stock 5,171 - Issuance (acquisition) of treasury stock, net 3,257 (10,401) Dividends paid (55,370) (54,978) -------------------------------------------------------------------------------------------------------- Cash Provided by Financing Activities 20,121 609,597 -------------------------------------------------------------------------------------------------------- Change in Cash and Cash Equivalents (143) 65 Cash and Cash Equivalents at Beginning of Period 249 72 -------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 106 $ 137 ======================================================================================================== </TABLE> See accompanying Notes to Consolidated Financial Statements. 6
ONEOK, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) A. Summary of Significant Accounting Policies Interim Reporting - The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. The interim consolidated financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Due to the seasonal nature of the business, the results of operations for the three and nine months ended September 30, 2001, are not necessarily indicative of the results that may be expected for a twelve-month period. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company's Form 10-K for the year ended December 31, 2000. Derivative Instruments and Hedging Activities - On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (Statement 133), as amended by Statements 137 and 138. See Note I in the Notes to Consolidated Financial Statements. Reclassifications - Certain amounts in the consolidated financial statements have been reclassified to conform to the current presentation. B. Regulatory Assets The following table is a summary of the Company's regulatory assets, net of amortization. September 30, December 31, 2001 2000 ---------------------------------------------------------------------- (Thousands of Dollars) Recoupable take-or-pay $ 75,486 $ 79,324 Pension costs 12,169 15,306 Postretirement costs other than pension 59,993 61,069 Transition costs 21,748 22,199 Reacquired debt costs 22,566 23,209 Income taxes 28,427 30,727 Other 7,242 6,771 ---------------------------------------------------------------------- Regulatory assets, net $ 227,631 $ 238,605 ====================================================================== C. Capital Stock On January 18, 2001, the Company's Board of Directors approved, and on May 17, 2001, the shareholders of the Company voted in favor of, a two-for-one common stock split, which was effected through the issuance of one additional share of common stock for each share of common stock outstanding to holders of record on May 23, 2001, with distribution of the shares on June 11, 2001. The Company retained the current par value of $.01 per share for all shares of common stock. Shareholders' equity reflects the stock split by reclassifying from Paid in Capital to Common Stock an amount equal to the cumulative par value of the additional shares issued to effect the split. All share and per share amounts contained herein for all periods presented reflect this stock split. Outstanding convertible preferred stock is assumed to convert to common stock on a two-for-one basis in the calculations of earnings per share. 7
D. Supplemental Cash Flow Information The following table is supplemental information relative to the Company's cash flows. Nine Months Ended September 30, 2001 2000 ---------------------------------------------------------------------------- (Thousands of Dollars) Cash paid during the period Interest (including amounts capitalized) $106,105 $ 86,124 Income taxes $ 13,047 $ 41,243 Noncash transactions Treasury stock transferred to compensation plans $ - $ 61 Acquisitions Property, plant and equipment $ 845 $ 782,970 Current assets - 74,012 Current liabilities - (20,996) Goodwill 14,500 14,459 Lease obligation - (139,000) Price risk management activities - (239,660) Deferred credits - (11,313) ---------------------------------------------------------------------------- Cash paid - Acquisitions $ 15,345 $ 460,472 ============================================================================ Additions to goodwill are due to purchase price adjustments related to the Kinder Morgan acquisition. E. Earnings per Share Information In accordance with a pronouncement of the Financial Accounting Standards Board's Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95), the Company revised its computation of earnings per common share (EPS). In accordance with Topic D-95, the dilutive effect of the Company's Series A Convertible Preferred Stock is now considered in the computation of basic EPS, utilizing the "if-converted" method. Under the Company's "if-converted" method, the dilutive effect of the Series A Convertible Preferred Stock on EPS cannot be less than the amount that would result from the application of the "two-class" method of computing EPS. The "two-class" method is an earnings allocation formula that determines EPS for the common stock and the participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The Series A Convertible Preferred Stock is a participating instrument with the Company's common stock with respect to the payment of dividends. For all periods presented, except the three months ended September 30, 2000, the "two-class" method resulted in additional dilution. Accordingly, EPS for such periods reflects this further dilution. The Company restated the EPS amounts for the nine months ended September 30, 2000 to be consistent with the revised methodology. 8
The following is a reconciliation of the basic and diluted EPS computations. <TABLE> <CAPTION> Three Months Ended September 30, 2001 Per Share Income Shares Amount -------------------------------------------------------------------------------------------------- (Thousands, except per share amounts) <S> <C> <C> <C> Basic EPS Income available for common stock $ 9,512 $59,629 Convertible preferred stock 9,275 39,892 -------------------------- Income available for common stock and assumed conversion of preferred stock 18,787 99,521 $0.19 ========================== Further dilution from applying the "two- class" method (0.03) ------------ Basic earnings per share $ 0.16 ============ Effect of Other Dilutive Securities Options - 112 -------------------------- Diluted EPS Income available for common stock and assumed exercise of stock options $18,787 $99,633 $ 0.19 ========================== Further dilution from applying the "two- class" method (0.03) ------------ Diluted earnings per share $ 0.16 ================================================================================================== <CAPTION> Three Months Ended September 30, 2000 Per Share Income Shares Amount -------------------------------------------------------------------------------------------------- (Thousands, except per share amounts) <S> <C> <C> <C> Basic EPS Income available for common stock $ 811 58,400 $ 0.01 ============ Effect of Other Dilutive Securities Options - 8 -------------------------- Diluted EPS Income available for common stock and assumed exercise of stock options $ 811 58,408 $ 0.01 ================================================================================================== </TABLE> 9
<TABLE> <CAPTION> Nine Months Ended September 30, 2001 Per Share Income Shares Amount ----------------------------------------------------------------------------------------------------- (Thousands, except per share amounts) <S> <C> <C> <C> Basic EPS Income available for common stock $ 79,429 59,490 Convertible preferred stock 27,825 39,892 --------------------- Income available for common stock and assumed conversion of preferred stock $107,254 99,382 $ 1.08 ===================== Further dilution from applying the "two- class" method (0.18) ----------- Basic earnings per share $ 0.90 =========== Effect of Other Dilutive Securities Options - 266 --------------------- Diluted EPS Income available for common stock and assumed exercise of stock options $107,254 99,648 $ 1.08 ===================== Further dilution from applying the "two- class" method (0.18) ----------- Diluted earnings per share $ 0.90 ===================================================================================================== <CAPTION> Nine Months Ended September 30, 2000 Per Share Income Shares Amount ----------------------------------------------------------------------------------------------------- (Thousands, except per share amounts) <S> <C> <C> <C> Basic EPS Income available for common stock $ 72,445 58,428 Convertible preferred stock 27,825 39,892 --------------------- Income available for common stock and assumed conversion of preferred stock $100,270 98,320 $ 1.02 ===================== Further dilution from applying the "two- class" method (0.17) ----------- Basic earnings per share $ 0.85 =========== Effect of Other Dilutive Securities Options - 6 --------------------- Diluted EPS Income available for common stock and assumed exercise of stock options $100,270 98,326 $ 1.02 ===================== Further dilution from applying the "two- class" method (0.17) ----------- Diluted earnings per share $ 0.85 ===================================================================================================== </TABLE> There were 332,915 and 113,354 option shares excluded from the calculation of diluted EPS for the three months ended September 30, 2001 and 2000, respectively, due to being antidilutive for the periods. There were 39,892,896 common share equivalents relative to the convertible preferred stock excluded from the calculation of diluted EPS due to the assumed conversion effect being antidilutive for the three months ended September 30, 2000. For the nine months ended September 30, 2001 and 2000, there were 121,664 and 307,278 option shares excluded from the calculation of diluted EPS, respectively, due to being antidilutive for the periods. 10
The following is a reconciliation of the basic and diluted EPS computations on income before the cumulative effect of a change in accounting principle to net income. <TABLE> <CAPTION> Nine Months Ended September 30, Basic EPS Diluted EPS 2001 2000 2001 2000 ----------------------------------------------------------------------------------------- (Per share amounts) <S> <C> <C> <C> <C> Income available for common stock before cumulative effect of a change in accounting principle $ 0.92 $ 0.83 $ 0.92 $ 0.83 Cumulative effect of a change in accounting principle, net of tax (0.02) 0.02 (0.02) 0.02 ------- ------- ------- ------- Income available for common stock $ 0.90 $ 0.85 $ 0.90 $ 0.85 ========================================================================================= </TABLE> F. Commitments and Contingencies In connection with the now terminated proposed acquisition of Southwest Gas Corporation (Southwest), the Company is party to various lawsuits. These lawsuits originally contained allegations that included, but were not limited to, federal and state Racketeer Influenced and Corrupt Organizations (RICO) Act violations and improper interference in a contractual or other business relationship between Southwest and Southern Union Corporation (Southern Union). Southern Union's complaint originally asked for $750 million damages to be trebled for alleged RICO violations, compensatory damages of not less than $750 million, punitive damages, and rescission of the Confidentiality and Standstill Agreement. On May 21, 2001, the Court denied Southern Union's motion to reconsider its ruling dismissing the federal RICO claims against the Company or to enter a judgment on the ruling. The Court also applied its ruling to dismiss the state RICO claim asserted by Southern Union against the Company. The Court's ruling on the RICO claims was made applicable to all defendants. On June 21, 2001, the Court dismissed with prejudice Southern Union's claim for fraudulent inducement against the Company, Gene Dubay and John Gaberino. The Court did not dismiss the claim by Southern Union against Southwest and Michael Maffie. The Court also dismissed with prejudice Southern Union's claims for tortious interference with a contractual relationship against the Company, and subsequently dismissed its claims as to Gene Dubay and John Gaberino. This claim remains pending against only James Irvin and Jack Rose. The Court denied the motion to dismiss Southern Union's claim for tortious interference with a prospective relationship against the Company, Gene Dubay and John Gaberino. On June 29, 2001, the Company filed a motion for summary judgment in its favor on the sole remaining claim asserted against it by Southern Union, Gene Dubay and John Gaberino joined in that motion. Various other motions for summary judgment on other claims in the lawsuits were filed by other parties, all of which were heard August 24, 2001 or October 19, 2001. The Court has not yet ruled on the motions heard on October 19, 2001. On September 25, 2001, the Court entered an order that denied the Company's motion for summary judgment on Southern Union's claims for tortious interference with a prospective relationship; however, the Court's ruling limited any recovery by Southern Union to out-of-pocket damages and punitive damages. The Company, as third party beneficiary, filed a lawsuit against Southern Union for, among other things, breach of a confidentiality agreement between Southern Union and Southwest; the Company also asserts that Southern Union tortiously interfered with the Southwest merger agreement. The Company filed suit against Southwest seeking a declaratory judgment determining that it had properly terminated the merger agreement. In response to this suit, Southwest brought a suit against the Company and Southern Union alleging, among other things, fraud and breach of contract. Southwest is seeking damages in excess of $75,000. The lawsuits discussed above have been consolidated into one case with Southwest and ONEOK being designated as the plaintiffs regarding claims against Southern Union. The court has entered an order setting the cases for jury trial on May 28, 2002. 11
Two substantially identical derivative actions were filed by shareholders against the members of the Board of Directors of the Company for alleged violation of their fiduciary duties to the Company by causing or allowing the Company to engage in certain fraudulent and improper schemes designed to "sabotage" Southern Union Company's competitive bid to acquire Southwest and secure regulatory approval for the Company's own planned merger with Southwest. Such conduct allegedly caused the Company to be sued by both Southwest and Southern Union, which exposed the Company to millions of dollars in liabilities. The allegations are used as a basis for causes of action for intentional breach of fiduciary duty, derivative claim for negligent breach of fiduciary duty, class and derivative claims for constructive fraud, and derivative claims for gross mismanagement. Each plaintiff seeks a declaration that the lawsuit is properly maintained as a derivative action, the defendants, and each of them, have breached their fiduciary duties to the Company, an injunction permanently enjoining defendants from further abuse of control and committing of gross mismanagement and constructive fraud, and asks for an award of compensatory and punitive damages and costs, disbursements and reasonable attorney fees. A Joint Motion for Consolidation of both derivative actions was filed on June 6, 2000, and Pretrial Order No. 1 was entered on that date consolidating the actions and establishing a schedule for response to a consolidated petition. On July 21, 2000, the plaintiffs filed their Consolidated Petition. Stephen J. Jatras and J.M. Graves have been eliminated as defendants in the Consolidated Petition, but Eugene Dubay was added as a new defendant. The plaintiffs also dropped their class and derivative claim for constructive fraud, but added a new derivative claim for waste of corporate assets. On September 19, 2000, the Company, the Independent Directors (Anderson, Bell, Cummings, Ford, Fricke, Lake, Mackie, Newsom, Parker, Scott and Young), David Kyle, and Gene Dubay filed Motions to Dismiss the action for failure of the plaintiffs to make a pre-suit demand on the Company's Board of Directors. In addition, the Independent Directors, David Kyle, and Gene Dubay filed Motions to Dismiss the Plaintiffs' Consolidated Petition for failure to state a claim. On January 3, 2001, the Court dismissed the action without prejudice as to its claims against Larry Brummett. On February 26, 2001, the action was stayed until one of the parties notifies the Court that a dissolution of the stay is requested. If any of the plaintiffs should be successful in any of their claims against the Company and substantial damages are awarded, it could have a material adverse effect on the Company's operations, cash flow, and financial position. At the present time, the Company is unable to estimate the possible loss, if any, associated with these matters. The Company is defending itself vigorously against all claims asserted by Southern Union and Southwest and all other matters relating to the now terminated proposed acquisition with Southwest. The Company has responsibility for 12 manufactured gas sites located in Kansas, which may contain coal tar and other potentially harmful materials that are classified as hazardous material. Hazardous materials are subject to control or remediation under various environmental laws and regulations. A consent agreement with the Kansas Department of Health and Environment (KDHE) presently governs all future work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a ten year period. At September 30, 2001, the costs of the investigations and risk analysis have been immaterial. Limited information is available about the sites and no testing has been performed. Management's best estimate of the cost of remediation ranges from $100 thousand to $10 million per site based on a limited comparison of costs incurred to remediate comparable sites. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from third parties. The Kansas Corporation Commission (KCC) has permitted others to recover their remediation costs through rates. It should be noted that additional information and testing could result in costs significantly below or in excess of the amounts estimated above. To the extent that such remediation costs are not recovered, the costs could be material to the Company's results of operations and cash flows depending on the degree of remediation required and number of years over which the remediation must be completed. 12
The OCC staff filed an application on February 1, 2001 to review the gas procurement practices of ONG in acquiring its gas supply for the 2000/2001 heating season to determine if they were consistent with least cost procurement practices and whether the Company's decisions resulted in fair, just and reasonable costs being borne by its customers. In a hearing on October 31, 2001, the OCC issued an oral ruling that ONG not be allowed to recover the balance in the Company's unrecovered purchased gas cost (UPGC) account related to the unrecovered gas costs from the 2000/2001 winter effective with the first billing cycle for the month following the issuance of a final order. Until such time as a final order is issued, the amount at issue is not known, and the oral ruling is not appealable. The Company believes that decisions made by the Company were prudent based upon the facts and circumstances existing at the time the decisions were made, which is the standard applicable to the Proceeding as stated by the OCC. The Company believes that the oral ruling is without merit based upon the evidence presented and will defend itself vigorously; however, the failure to recover the unrecovered purchased gas costs could have a material adverse affect on the financial condition and results of operations. As of September 30, 2001, ONG's total unrecovered purchased gas costs was $47.5 million, not all of which is related to the 2000/2001 heating season. Two separate class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred in Hutchinson, Kansas in January, 2001. Although no assurances can be given, management believes that the ultimate resolution of these matters will not have a material adverse effect on its financial position or results of operations. The Company is vigorously defending itself against all claims. The Company is a party to other litigation matters and claims, which are normal in the course of its operations, and while the results of litigation and claims cannot be predicted with certainty, management believes the final outcome of such matters will not have a materially adverse effect on consolidated results of operations, financial position, or liquidity. G. Segments The Company conducts its operations through seven segments: (1) the Marketing and Trading segment markets natural gas to wholesale and retail customers; (2) the Gathering and Processing segment gathers and processes natural gas and fractionates, stores and markets natural gas liquids; (3) the Transportation and Storage segment transports and stores natural gas for others and buys and sells natural gas; (4) the Distribution segment distributes natural gas to residential, commercial and industrial customers, leases pipeline capacity to others and provides transportation services for end-use customers; (5) the Production segment develops and produces natural gas and oil; (6) the Power segment produces and sells electricity during peak periods to wholesale customers; and (7) the Other segment primarily operates and leases the Company's headquarters building and a related parking facility. Intersegment sales are recorded on the same basis as sales to unaffiliated customers. All corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. The Company's equity method investments do not represent operating segments of the Company. The Company has no single external customer from which it receives ten percent or more of its revenues. 13
<TABLE> <CAPTION> Three Months Marketing Gathering Transportation Ended and and and Other and September 30, 2001 Trading Processing Storage Distribution Production Power Eliminations Total ------------------------------------------------------------------------------------------------------------------------------------ (Thousands of Dollars) <S> <C> <C> <C> <C> <C> <C> <C> <C> Sales to unaffiliated customers $ 732,806 $ 173,377 $ 14,002 $ 166,301 $ 20,143 $17,118 $ 3,442 $1,127,189 Intersegment sales 41,424 95,174 27,033 1,826 3,040 - (168,497) $ - ------------------------------------------------------------------------------------------------------------------------------------ Total Revenues $ 774,230 $ 268,551 $ 41,035 $ 168,127 $ 23,183 $17,118 (165,055) $1,127,189 ------------------------------------------------------------------------------------------------------------------------------------ Net revenues $ 27,500 $ 52,821 $ 30,337 $ 62,579 $ 23,183 $ 5,182 $ 1,647 $ 203,249 Operating costs $ 5,805 $ 28,319 $ 12,599 $ 54,585 $ 5,612 $ 509 $ 273 $ 107,702 Depreciation, depletion and amortization $ 145 $ 7,406 $ 4,843 $ 17,390 $ 8,134 $ 982 $ 422 $ 39,322 Operating income $ 21,550 $ 17,096 $ 12,895 $ (9,396) $ 9,437 $ 3,691 $ 952 $ 56,225 Income from equity investments $ - $ - $ 992 $ - $ 899 $ - $ - $ 1,891 Capital expenditures $ 26 $ 10,369 $ 4,102 $ 32,109 $ 16,587 $ 1,009 $ 5,052 $ 69,254 ------------------------------------------------------------------------------------------------------------------------------------ <CAPTION> Three Months Marketing Gathering Transportation Ended and and and Other and September 30, 2000 Trading Processing Storage Distribution Production Power Eliminations Total ------------------------------------------------------------------------------------------------------------------------------------ (Thousands of Dollars) <S> <C> <C> <C> <C> <C> <C> <C> <C> Sales to unaffiliated customers $1,226,166 $ 307,317 $ 33,033 $ 169,107 $ 11,377 $ - $ 6,806 $1,753,806 Intersegment sales $ 49,892 $ 51,125 $ 12,152 $ 1,021 $ 5,914 $ - $(120,104) $ - ------------------------------------------------------------------------------------------------------------------------------------ Total Revenues $1,276,058 $ 358,442 $ 45,185 $ 170,128 $ 17,291 $ - $(113,298) $1,753,806 ------------------------------------------------------------------------------------------------------------------------------------ Net revenues $ 15,811 $ 70,816 $ 33,006 $ 55,210 $ 17,291 $ - $ (2,281) $ 189,853 Operating costs $ 4,558 $ 31,328 $ 13,321 $ 51,552 $ 6,443 $ - $ (485) $ 106,717 Depreciation, depletion and amortization $ 192 $ 6,839 $ 4,628 $ 16,087 $ 7,701 $ - $ 621 $ 36,068 Operating income $ 11,061 $ 32,649 $ 15,057 $ (12,429) $ 3,147 $ - $ (2,417) $ 47,068 Income from equity investments $ - $ - $ 519 $ - $ 37 $ - $ - $ 556 Capital expenditures $ 36 $ 22,366 $ 10,911 $ 26,482 $ 11,808 $11,890 $ 9,055 $ 92,548 ------------------------------------------------------------------------------------------------------------------------------------ </TABLE> 14
<TABLE> <CAPTION> Nine Months Marketing Gathering Transportation Ended and and and Other and September 30, 2001 Trading Processing Storage Distribution Production Power Eliminations Total ------------------------------------------------------------------------------------------------------------------------------------ (Thousands of Dollars) <S> <C> <C> <C> <C> <C> <C> <C> <C> Sales to unaffiliated customers $3,505,888 $ 665,097 $ 69,936 $1,152,448 $ 64,798 $21,026 $ 6,826 $5,486,019 Intersegment sales 567,272 433,713 71,102 3,331 22,669 - (1,098,087) $ - ------------------------------------------------------------------------------------------------------------------------------------ Total Revenues $4,073,160 $1,098,810 $ 141,038 $1,155,779 $ 87,467 $21,026 $(1,091,261) $5,486,019 ------------------------------------------------------------------------------------------------------------------------------------ Net revenues $ 94,970 $ 145,126 $ 99,517 $ 275,562 $ 87,467 $ 6,082 $ 5,848 $ 714,572 Operating Costs $ 12,308 $ 86,715 $ 37,836 $ 174,279 $ 20,566 $ 811 $ (2,797) $ 329,718 Depreciation, depletion and amortization $ 406 $ 21,212 $ 14,344 $ 51,526 $ 23,878 $ 1,019 $ 1,748 $ 114,133 Operating income $ 82,256 $ 37,199 $ 47,337 $ 49,757 $ 43,023 $ 4,252 $ 6,897 $ 270,721 Cumulative effect of a change in accounting principle, net of tax $ - $ - $ - $ - $ (2,151) $ - $ - $ (2,151) Income from equity investments $ - $ - $ 2,500 $ - $ 5,600 $ - $ - $ 8,100 Total assets $1,206,647 $1,394,147 $ 741,850 $1,641,109 $ 380,067 $ 9,450 $ 318,670 $5,691,940 Capital expenditures $ 423 $ 27,082 $ 22,224 $ 89,503 $ 42,807 $40,970 $ 20,235 $ 243,244 ------------------------------------------------------------------------------------------------------------------------------------ <CAPTION> Nine Months Marketing Gathering Transportation Ended and and and Other and September 30, 2000 Trading Processing Storage Distribution Production Power Eliminations Total ------------------------------------------------------------------------------------------------------------------------------------ (Thousands of Dollars) <S> <C> <C> <C> <C> <C> <C> <C> <C> Sales to unaffiliated customers $2,536,683 $ 556,216 $ 78,036 $ 735,799 $ 42,131 $ - $ 15,156 $3,964,021 Intersegment sales 195,870 94,442 40,873 2,848 11,357 - (345,390) $ - ------------------------------------------------------------------------------------------------------------------------------------ Total Revenues $2,732,553 $ 650,658 $ 118,909 $ 738,647 $ 53,488 $ - $ (330,234) $3,964,021 ------------------------------------------------------------------------------------------------------------------------------------ Net revenues $ 61,133 $ 144,756 $ 89,155 $ 264,194 $ 53,488 $ - $ (3,697) $ 609,029 Operating costs $ 11,258 $ 59,971 $ 32,040 $ 156,555 $ 17,968 $ - $ (1,657) $ 276,135 Depreciation, depletion and amortization $ 697 $ 15,530 $ 13,825 $ 51,460 $ 24,153 $ - $ 1,891 $ 107,556 Operating income $ 49,178 $ 69,255 $ 43,290 $ 56,179 $ 11,367 $ - $ (3,931) $ 225,338 Cumulative effect of a change in accounting principle, net of tax $ 2,115 $ - $ - $ - $ - $ - $ - $ 2,115 Income from equity investments $ - $ - $ 3,291 $ - $ 66 $ - $ - $ 3,357 $ $ Total assets $2,431,465 $1,394,540 $ 631,128 $1,716,326 $ 353,892 $49,740 $ (230,140) $6,346,951 Capital expenditures $ 81 $ 32,663 $ 25,319 $ 78,150 $ 29,730 $31,517 $ 20,444 $ 217,904 ------------------------------------------------------------------------------------------------------------------------------------ </TABLE> H. Paid in Capital Paid in capital is $337.5 million and $331.2 million for common stock at September 30, 2001, and December 31, 2000, respectively. Paid in capital for convertible preferred stock was $564.2 million at September 30, 2001 and December 31, 2000. 15
I. Derivative Instruments and Hedging Activities On January 1, 2001, the Company adopted the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (Statement 133), amended by Statement No. 137 and Statement No. 138. Statement 137 delayed the implementation of Statement 133 until fiscal years beginning after June 15, 2000. Statement 138 amended the accounting and reporting standards of Statement 133 for certain derivative instruments and hedging activities. Statement 138 also amends Statement 133 for decisions made by the Financial Accounting Standards Board (FASB) relating to the Derivatives Implementation Group (DIG) process. The FASB DIG is addressing Statement 133 implementation issues, the ultimate resolution of which may impact the application of Statement 133. Under Statement 133, entities are required to record all derivative instruments in the balance sheet at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, on the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair values, cash flows, or foreign currencies. If the hedged exposure is a fair value exposure, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. If the hedged exposure is a cash flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the hedge, are reported in earnings immediately. In 2000, the Company entered into derivative instruments related to the production of natural gas, most of which will expire by the end of 2001. These derivative instruments are designed to hedge the Production segment's exposure to changes in the price of natural gas. Changes in the fair value of the derivative instruments are reflected initially in other comprehensive income (loss) and subsequently realized in earnings when the forecasted transaction affects earnings. The Company recorded a cumulative effect charge of $2.2 million, net of tax, in the income statement and $28 million, net of tax, in accumulated other comprehensive loss to recognize at fair value the ineffective and effective portions, respectively, of the losses on all derivative instruments that are designated as cash flow hedging instruments, which primarily consist of costless option collars and swaps on natural gas production. The Company recognized $3.6 million in earnings, representing the ineffective portion of the cash flow hedges for the nine months ended September 30, 2001. The Company realized a $25.4 million loss in earnings that was reclassified from accumulated other comprehensive loss resulting from the settlement of contracts when the natural gas was sold. These gains and losses are reported in Operating Revenues. Other comprehensive income of $5.6 million at September 30, 2001 is related to a cash flow exposure and will be realized in earnings within the next three months. The Company is subject to the risk of fluctuation in interest rates in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and at times interest rate swaps. In July 2001, the Company entered into interest rate swaps on a total of $400 million in fixed rate long-term debt. The rate resets periodically based on the three-month LIBOR or the six-month LIBOR at the reset date. The Company recorded a $23.1 million increase in price risk management assets and long-term debt relating to these fair value hedges. 16
J. Comprehensive Income <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, 2001 September 30, 2001 -------------------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> <C> <C> Net Income $18,787 $107,254 Other comprehensive income (loss): Cumulative effect of a change in accounting principle $ - $(45,556) Unrealized gains on derivative instruments 6,604 29,330 Realized losses in net income (620) 25,395 ------- -------- Other comprehensive income before taxes 5,984 9,169 Income tax benefit on other comprehensive income (2,315) (3,546) ------- -------- Other comprehensive income $ 3,669 $ 5,623 ------- -------- Comprehensive income $22,456 $112,877 ======================================================================================================== </TABLE> K. Energy Trading and Risk Management Activities The Company engages in price risk management activities for both trading and non-trading purposes. On January 1, 2000, the Company adopted Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) for its energy trading contracts. EITF 98-10 requires entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Prior to the adoption of EITF 98-10, the Company accounted for its trading activities on the accrual method based on settlement of physical positions. The adoption of EITF 98-10 was accounted for as a change in accounting principle and the cumulative effect at January 1, 2000 of $2.1 million, net of tax, was recognized. Forwards, swaps, options, and energy transportation and storage contracts utilized for trading activities are reflected at fair value as assets and liabilities from price risk management activities in the consolidated balance sheets. The fair value of these assets and liabilities are affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. Changes in fair value are recognized in net revenues in the consolidated statement of income. Market prices used to fair value these assets and liabilities reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility assumptions underlying the commitments. Market prices are adjusted for the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions. L. Income Taxes The reduction in the effective income tax rate in the third quarter is the result of changes in estimates of prior year tax liabilities. 17
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Some of the statements contained and incorporated in this Form 10-Q are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements relate to the anticipated financial performance, management's plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in various circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements. Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of operations and other statements contained or incorporated in this Form 10-Q identified by words such as "anticipate," "estimate," "expect," "intend," "believe," "projection" or "goal." You should not place undue reliance on the forward-looking statements. They are based on known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following: . the effects of weather and other natural phenomena on sales and prices; . increased competition from other energy suppliers as well as alternative forms of energy; . the capital intensive nature of the Company's business; . further deregulation, or "unbundling" of the natural gas business; . competitive changes in the natural gas gathering, transportation and storage business resulting from deregulation, or "unbundling," of the natural gas business; . the profitability of assets or businesses acquired by the Company; . risks of marketing, trading, and hedging activities as a result of changes in energy prices; . economic climate and growth in the geographic areas in which the Company does business; . the uncertainty of gas and oil reserve estimates; . the timing and extent of changes in commodity prices for natural gas, natural gas liquids, electricity, and crude oil; . the effects of changes in governmental policies and regulatory actions, including income taxes, environmental compliance, and authorized rates; . the results of litigation related to the Company's now terminated proposed acquisition of Southwest Gas Corporation (Southwest) or to the termination of the Company's merger agreement with Southwest; and . the other factors listed in the reports the Company has filed and may file with the Securities and Exchange Commission, which are incorporated by reference. Other factors and assumptions not identified above were also involved in the making of the forward-looking statements. The failure of those assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. 18
A. Results of Operations Consolidated Operations The Company is a diversified energy company whose objective is to maximize value for shareholders by vertically integrating its business operations from the wellhead to the burner tip. This strategy has led the Company to focus on acquiring assets that provide synergistic trading and marketing opportunities along the natural gas energy chain. Products and services are provided to its customers through the following segments: . Marketing and Trading . Gathering and Processing . Transportation and Storage . Distribution . Production . Power . Other <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> <C> <C> Financial Results Operating revenues $1,127,189 $1,753,806 $5,486,019 $3,964,021 Cost of gas 923,940 1,563,953 4,771,447 3,354,992 ----------------------------------------------------------------------------------------------------------------------- Net revenues 203,249 189,853 714,572 609,029 Operating costs 107,702 106,717 329,718 276,135 Depreciation, depletion, and amortization 39,322 36,068 114,133 107,556 ----------------------------------------------------------------------------------------------------------------------- Operating income $ 56,225 $ 47,068 $ 270,721 $ 225,338 ======================================================================================================================= Other income, net $ (2,406) $ 384 $ 1,951 $ 18,567 ======================================================================================================================= Cumulative effect of a change in accounting principle $ - $ - $ (3,508) $ 3,449 Income tax - - 1,357 (1,334) ----------------------------------------------------------------------------------------------------------------------- Cumulative effect of a change in accounting principle, net of tax $ - $ - $ (2,151) $ 2,115 ======================================================================================================================= </TABLE> The Company's operating income increased 19 percent for the three months ended September 30, 2001 compared to the same period in 2000. Other income, net includes income from equity investments as well as ongoing litigation costs associated with the terminated acquisition of Southwest. The Company's operating income increased 20 percent for the nine-month period primarily due to the impact of volatility on gas prices on the Marketing segment and higher average hedged prices on the Production segment. Other income, net for the nine months ended September 30, 2001 includes approximately $8.1 million in income from equity investments that was partially offset by a charge of $3.7 million related to ongoing litigation costs associated with the terminated acquisition of Southwest. Other income, net for the nine months ended September 30, 2000 includes a $26.7 million gain on the sale of assets and $3.4 income from equity investments which were partially offset by a charge of $10.6 million of previously deferred costs and ongoing litigation costs associated with the terminated acquisition of Southwest, and other charges. The reduction in the effective income tax rate in the third quarter is the result of changes in estimates of prior year tax liabilities. 19
Marketing and Trading The Marketing and Trading segment purchases, stores, markets and trades natural gas to both wholesale and retail sectors in 28 states. The Company has strong mid-continent region storage positions and transport capacity of 1 Bcf/d (Bcf per day) that allows for trade from the California border, throughout the Rockies, to the Chicago city gate. With total storage capacity of 73 Bcf, withdrawal capability of 2.5 Bcf/d and injection of 1.4 Bcf/d, the Company has direct access to all regions of the country with great flexibility in capturing volatility in the energy markets. <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ---------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> <C> <C> Financial Results Gas sales $773,815 $1,275,568 $4,071,731 $2,731,483 Cost of gas 746,730 1,260,247 3,978,190 2,671,420 ---------------------------------------------------------------------------------------------------------------------- Gross margin on gas sales 27,085 15,321 93,541 60,063 Other revenues 415 490 1,429 1,070 ---------------------------------------------------------------------------------------------------------------------- Net revenues 27,500 15,811 94,970 61,133 Operating costs 5,805 4,558 12,308 11,258 Depreciation, depletion, and amortization 145 192 406 697 ---------------------------------------------------------------------------------------------------------------------- Operating income $ 21,550 $ 11,061 $ 82,256 $ 49,178 ====================================================================================================================== Other income, net $ 39 $ 126 $ 283 $ 524 ====================================================================================================================== Cumulative effect of change in accounting principle, before tax $ - $ - $ - $ 3,449 ====================================================================================================================== </TABLE> Lower gas prices and sales volumes for the three months ended September 30, 2001 compared to the same period in 2000, resulted in decreased gas sales and cost of gas. Sales volumes decreased due to higher storage injections relative to the prior year. The Company continues to expand its storage position and focus on opportunistically securing storage volumes that are then hedged at favorable winter/summer spreads. The Company also benefited from falling prices that positively impacted fuel costs associated with its long-term transportation contracts. For the nine-month period, higher gas prices and increased price volatility in 2001 resulted in increased gas sales and cost of gas compared to the same period in 2000. Increased volumes primarily resulting from acquisitions in 2000 were partially offset by the reduction in gas sales volumes resulting from higher storage injections in 2001. Gross margin and gross margin per Mcf improved for the three and nine-month periods as the Company has now fully integrated its mid-continent marketing and trading base and is successfully executing its transportation and storage arbitrage strategy that focuses on capturing higher margin sales. Operating costs increased for the three months ended September 30, 2001 compared to the same period in 2000 due to an increase in reserves for doubtful accounts. Operating costs increased for the nine months ended September 30, 2001 compared to the same period in 2000 due to an increase in personnel costs resulting from the acquisitions in 2000. Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 -------------------------------------------------------------------------------- Operating Information Natural gas volumes (MMcf) 233,879 285,783 732,225 721,198 Gross margin ($/Mcf) $ 0.116 $ 0.054 $ 0.128 $ 0.083 Capital expenditures (Thousands) $ 26 $ 36 $ 423 $ 81 Total assets (Thousands) $ - $ - $1,206,647 $2,431,465 -------------------------------------------------------------------------------- 20
Total assets at September 30, 2001 compared to September 30, 2000 decreased due to decreases in accounts receivables and assets from price risk management activities. Gathering and Processing The Gathering and Processing segment currently owns and operates 25 gas processing plants and has an ownership interest in four additional gas processing plants which it does not operate. Six operated plants are temporarily idle. The total processing capacity of plants operated and the Company's proportionate interest in plants not operated by the Company is 2.2 Bcf/d, of which 0.331 Bcf/d has been idled temporarily. A total of over 19,300 miles of gathering pipelines support the gas processing plants. <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ---------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> <C> <C> Financial Results Natural gas liquids and condensate sales $134,926 $189,453 $477,613 $333,864 Gas sales 110,942 145,076 550,533 261,774 Gathering, compression, dehydration and processing fees and other revenues 22,683 23,913 70,664 55,020 Cost of sales 215,730 287,626 953,684 505,902 ---------------------------------------------------------------------------------------------------------------------------- Net revenues 52,821 70,816 145,126 144,756 Operating costs 28,319 31,328 86,715 59,971 Depreciation, depletion, and amortization 7,406 6,839 21,212 15,530 ============================================================================================================================ Operating income $ 17,096 $ 32,649 $ 37,199 $ 69,255 ============================================================================================================================ Other income, net $ (119) $ 75 $ (119) $ 26,885 ============================================================================================================================ </TABLE> Lower prices for the three months ended September 30, 2001 compared to the same period in 2000 resulted in decreases in natural gas liquids and condensate sales, gas sales and cost of sales, despite increases in volumes. For the nine-month period, increased volumes resulting from acquisitions in 2000 and higher prices resulted in increased natural gas liquids and condensate sales, gas sales and cost of sales. Fee-based revenues increased for the nine-month period due to the acquisitions in 2000. Decreases in the processing spreads and lower prices resulted in lower net revenues for the three-month period. For the nine-month period, increased volumes associated with the acquisitions in 2000 resulted in increased revenues, cost of sales and net revenues. Operating costs decreased for the three months ended September 30, 2001 compared to the same period in 2000 primarily due to lower general taxes and employee costs. For the nine months, operating costs increased primarily due to increased personnel costs to support the expanded base of operations resulting from the acquisitions. The increase in assets from well connects and system enhancements resulted in increases in depreciation, depletion, and amortization for the three and nine-month periods. Other income, net in 2000 included the $26.7 million gain on the sale of the Company's 42.4 percent interest in the Indian Basin gas processing plant and gathering system. <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 --------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Gas Processing Plants Operating Information Total gas gathered (MMbtu/D) 1,652 1,572 1,552 1,248 Total gas processed (MMBtu/D) 1,525 1,439 1,391 1,124 Natural gas liquids sales (MBbls) 7,229 6,891 19,820 16,742 Natural gas liquids produced (Bbls/d) 82,164 80,947 71,712 65,718 Gas sales (MMMBtu) 40,495 34,808 109,302 79,284 Capital expenditures (Thousands) $10,369 $22,366 $ 27,082 $ 32,663 Total assets (Thousands) $ - $ - $1,394,147 $1,394,540 ---------------------------------------------------------------------------------------------------- </TABLE> 21
Strong market prices early in 2001 resulted in increases for NGL prices and gas prices for the nine months, despite decreases in market prices during the third quarter of 2001. The Conway OPIS composite NGL price increased 20 percent to $0.551 from $0.461 and the Five Pipe IFERC gas price increased 73 percent to $5.194 from $3.004 over the same nine-month period in 2000. For the three-month period, the Conway OPIS composite NGL price decreased 24 percent to $0.431 from $0.565 and the Five Pipe IFERC gas price decreased 20 percent to $3.224 from $4.024. The volume of natural gas liquids produced increased for the three-month period as decreases in gas prices made it more economical to extract liquids than it had been during 2000. Volumes of natural gas gathered, processed and sold and natural gas liquids produced and sold increased for the nine months ended September 30, 2001 compared to the same period in 2000 primarily due to increased processing and fractionation capacity acquired in acquisitions during 2000. These acquisitions increased the Company's processing and fractionation capacity by 1.6 Bcf/d. Transportation and Storage The Transportation and Storage segment represents the Company's intrastate transmission pipelines and natural gas storage facilities. The Company has four storage facilities in Oklahoma, two in Kansas and three in Texas with a combined working capacity of approximately 58 Bcf. The Company's intrastate transmission pipelines operate in Oklahoma, Kansas and Texas and are regulated by the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), and Texas Railroad Commission (TRC), respectively. <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> <C> <C> Financial Results Transportation and gathering revenues $27,515 $26,906 $92,272 $71,054 Storage revenues 8,812 13,119 30,150 27,066 Gas sales and other 4,708 5,160 18,616 20,789 Cost of fuel and gas 10,698 12,179 41,521 29,754 ----------------------------------------------------------------------------------------------- Net revenues 30,337 33,006 99,517 89,155 Operating costs 12,599 13,321 37,836 32,040 Depreciation, depletion, and amortization 4,843 4,628 14,344 13,825 ----------------------------------------------------------------------------------------------- Operating income $12,895 $15,057 $47,337 $43,290 =============================================================================================== Other income, net $ 989 $ 567 $ 2,076 $ 3,464 =============================================================================================== </TABLE> Transportation and gathering revenues increased for the three and nine months ended September 30, 2001 compared to the same periods in 2000 due to increased transportation rates. A new power plant load for the nine-month period and acquisitions in 2000 also contributed to the increase in revenues. Storage revenues decreased for the three months due to lower storage capacity availability in Kansas and Texas. For the nine months, storage revenues increased primarily due to increased volumes resulting from increased storage capacity acquired in 2000 and the industry's movement to maintain more gas in storage for use during the heating season. Cost of fuel was impacted for the nine months by the effect of higher prices. Operating costs increased for the nine-month period primarily as a result of increased personnel costs to support the expanded base of operations resulting from the acquisitions in 2000 and increased gathering costs. 22
<TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, June 30, 2001 2000 2001 2000 ---------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Operating Information Volumes transported (MMcf) 124,777 160,977 411,562 396,484 Capital expenditures (Thousands) $ 4,102 $ 10,911 $ 22,224 $ 25,319 Total assets (Thousands) $ - $ - $741,850 $631,128 ---------------------------------------------------------------------------------------------------------- </TABLE> For the three-month period, transportation volumes decreased due to a lack of injections into a Kansas gas storage facility and the resulting lack of transportation to that facility. Distribution The Distribution segment provides natural gas distribution services in Oklahoma and Kansas to residential, commercial and industrial customers. The Company's operations in Oklahoma are primarily conducted through Oklahoma Natural Gas (ONG). Operations in Kansas are conducted through Kansas Gas Service (KGS). The Distribution segment serves about 80 percent of Oklahoma and about 72 percent of Kansas. ONG is subject to regulatory oversight by the OCC, and KGS is subject to regulatory oversight by the KCC. An Order received in May 2000 from the OCC provided for a $20 million net revenue reduction in rates which will be offset by an annual reduction in depreciation expense of $11.4 million. Pursuant to this Order, the Oklahoma assets and customers of KGS were transferred to ONG. This Order also adjusted rates for the removal of the gathering and storage assets no longer included in base rates and provided for the recovery of gas purchase, operations and maintenance expenses and line losses through a rider rather than base rates. An Order from the KCC effective in July, 2000 reduced tariff rates. This Order also provided for the recovery of certain costs through a cost of gas rider rather than through tariff rates, which reduces gross margin and operating costs by a like amount. The OCC staff filed an application on February 1, 2001 to review the gas procurement practices of ONG in acquiring its gas supply for the 2000/2001 heating season to determine if they were consistent with least cost procurement practices and whether the Company's decisions resulted in fair, just and reasonable costs being borne by its customers. In a hearing on October 31, 2001, the OCC issued an oral ruling that ONG not be allowed to recover the balance in the Company's unrecovered purchased gas cost account related to the unrecovered gas costs from the 2000/2001 winter effective with the first billing cycle for the month following the issuance of a final order. Until such time as a final order is issued, the amount at issue is not known, and the oral ruling is not appealable. The Company believes that decisions made by the Company were prudent based upon the facts and circumstances existing at the time the decisions were made, which is the standard applicable to the Proceeding as stated by the OCC. The Company believes that the oral ruling is without merit based upon the evidence presented and will defend itself vigorously; however, the failure to recover the unrecovered purchased gas costs could have a material adverse affect on the financial condition and results of operations. As of September 30, 2001, ONG's total unrecovered purchased gas costs was $47.5 million, not all of which is related to the 2000/2001 heating season. 23
<TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ---------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> <C> <C> Financial Results Gas sales $150,464 $154,130 $1,099,047 $684,236 Cost of gas 105,548 114,918 880,217 474,453 ---------------------------------------------------------------------------------------------- Gross margin 44,916 39,212 218,830 209,783 PCL and ECT Revenues 12,012 12,382 40,794 42,953 Other revenues 5,651 3,616 15,938 11,458 ---------------------------------------------------------------------------------------------- Net revenues 62,579 55,210 275,562 264,194 Operating costs 54,585 51,552 174,279 156,555 Depreciation, depletion, and amortization 17,390 16,087 51,526 51,460 ---------------------------------------------------------------------------------------------- Operating income (loss) $ (9,396) $(12,429) $ 49,757 $ 56,179 ============================================================================================== Other income, net $ (726) $ 172 $ (647) $ 962 ============================================================================================== </TABLE> Gas sales and cost of gas decreased for the three months ended September 30, 2001 compared to the same period in 2000 due to decreased gas costs. Higher gas prices in the early part of 2001 resulted in an increase in gas sales and cost of gas for the nine months ended September 30, 2001 compared to the same period in 2000. Increased customer participation in the WeatherProof rate program, a Kansas program which provides for a levelized bill each month, and colder weather contributed to higher gross margins for the three and nine-month period. Increased revenue from a line loss and gathering rider and increased customer service revenue positively impacted gross margin. Increased late payment charges contributed to the increase in Other revenues. Increased bad debts due to the high natural gas prices resulted in an increase in operating costs of $6.0 million and $18.0 million for the three and nine months, respectively. Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 -------------------------------------------------------------------------------- Gross Margin per Mcf Oklahoma Residential $7.02 $6.50 $2.95 $2.99 Commercial $3.75 $2.71 $2.23 $2.30 Industrial $1.65 $1.38 $1.30 $1.20 Pipeline capacity leases (PCL) $0.32 $0.25 $0.31 $0.26 Kansas Residential $6.17 $5.71 $2.43 $2.53 Commercial $2.36 $2.96 $1.71 $1.93 Industrial $1.48 $1.96 $1.45 $1.86 End-use customer transportation (ECT) $0.48 $0.46 $0.59 $0.55 -------------------------------------------------------------------------------- Residential, commercial and industrial gross margins per Mcf for the Oklahoma customers increased for the three months ended September 30, 2001 compared to the same period in 2000 due to reduced volumes which resulted in customer-based fees being spread over less volumes. Gross margin per Mcf for the Kansas residential customers increased for the three-month period compared to the same period in 2000 due to increased participation in the WeatherProof rate program. Commercial and industrial margins in Kansas were lower for the three and nine-month periods due to the tariff reductions. 24
<TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 --------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Operating Information Average Number of Customers 1,409,034 1,409,349 1,429,311 1,437,737 Capital expenditures (Thousands) $ 32,109 $ 26,482 $ 89,503 $ 78,150 Total Assets (Thousands) $ - $ - $1,641,109 $1,716,326 Customers per employee 592 555 594 554 --------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 --------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Volumes (MMcf) Gas sales Residential 6,721 6,937 71,151 72,568 Commercial 3,447 3,915 28,704 28,209 Industrial 524 1,003 2,993 4,015 Wholesale 12,133 10,078 19,891 27,556 -------------------------------------------------------------------------------------------------------------- Total volumes sold 22,825 21,933 122,739 132,348 PCL and ECT 31,836 37,674 100,611 119,971 -------------------------------------------------------------------------------------------------------------- Total volumes delivered 54,661 59,607 223,350 252,319 ============================================================================================================== </TABLE> Total residential and commercial volumes decreased for the three months due to warmer weather and fewer customers in the third quarter of 2001 compared to the same period in 2000. The decrease in customers is due to more customers staying off the system for longer periods primarily due to the increased payments required to reconnect service. For the nine months, the decrease during the third quarter was generally offset by the effect of colder than normal weather during the first quarter of 2001 compared to warmer than normal weather during the first quarter of 2000. Wholesale, PCL and ECT volumes decreased for the three and nine-month periods due to the loss of a large customer to an affiliate in June 2001 and certain customers curtailing manufacturing due to the high natural gas prices. These decreases in volumes were partially offset by more customers qualifying for PCL and ECT rates due to a reduction in the minimum capacity requirements pursuant to regulatory orders. Certain costs to be recovered through the rate making process have been recorded as regulatory assets in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation". As services continue to unbundle, certain of these assets may no longer meet the criteria of a regulatory asset, and accordingly, a write-off of regulatory assets and stranded costs may be required. The Company's most recent Orders did not change the recoverability of regulatory assets. The Company has been authorized to recover transition costs incurred due to natural gas industry restructuring. The current annual recovery level is set at $2.1 million. This recovery level will be updated annually. Accordingly, the Company does not anticipate that write-off of costs, if any, will be material. 25
Production The Production segment owns, develops and produces natural gas and oil reserves primarily in Oklahoma and Kansas. <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 -------------------------------------------------------------------------------------------------- (Thousands of Dollars) <S> <C> <C> <C> <C> Financial Results Natural gas sales $19,869 $15,279 $78,610 $46,944 Oil sales 3,276 1,548 8,716 5,722 Other revenues 38 464 141 822 -------------------------------------------------------------------------------------------------- Net revenues 23,183 17,291 87,467 53,488 Operating costs 5,612 6,443 20,566 17,968 Depreciation, depletion, and amortization 8,134 7,701 23,878 24,153 -------------------------------------------------------------------------------------------------- Operating income $ 9,437 $ 3,147 $43,023 $11,367 ================================================================================================== Other income, net $ 165 $ 1,138 $ 5,518 $ 3,608 ================================================================================================== Cumulative effect of change in accounting principle, before tax $ - $ - $(3,508) $ - ================================================================================================== </TABLE> For the three and nine months ended September 30, 2001 compared to the same periods in 2000, natural gas sales and oil sales increased due to substantially higher realized prices which were partially offset by the reduction in natural gas sales volumes due to normal production declines. New wells added in the third quarter of 2001 resulted in increased oil production volumes. For the three-month period, operating costs decreased primarily due to decreased production taxes and overhead costs. Production taxes are calculated based on wellhead price, which was lower for the three-month period, rather than realized price, which was higher as a result of hedging activities. For the nine-month period, operating costs increased primarily due to increased production taxes resulting from the higher wellhead prices. <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ------------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> Operating Information Proved reserves Gas (MMcf) - - 252,349 258,310 Oil (MBbls) - - 4,724 4,151 Production Gas (MMcf) 6,419 6,705 19,069 20,573 Oil (MBbls) 127 88 328 314 Average realized price Gas (MMcf) $ 3.10 $ 2.28 $ 4.12 $ 2.28 Oil (MBbls) $ 25.80 $ 17.59 $ 26.57 $ 18.20 Capital expenditures (Thousands) $16,587 $11,808 $ 42,807 $ 29,730 Total assets (Thousands) $ - $ - $380,067 $353,892 ----------------------------------------------------------------------------------------------------------------------------- </TABLE> Average realized price, above, reflects the impact of hedging activities. 26
Power The Company created the Power segment on January 1, 2001, to include the operating results of the peak electric generating plant constructed by the Company. The Company's strategy is to capture the spark spread premium primarily during peak demand periods. The plant was capable of operation in May 2001. Operating income for three and nine months ended September 30, 2001, was $3.7 million and $4.3 million, respectively. Prior to January 1, 2001, capital expenditures for the construction of the plant had been included in the Marketing and Trading segment. These capital expenditures have been reclassified and included in the Power segment for the periods shown in this report. For the three and nine months ended September 30, 2001, capital expenditures relating to the construction of the electric generating plant were $1.0 million and $41.0 million, respectively, compared to $11.9 million and $31.5 million for the same periods in 2000, respectively. B. Financial Flexibility and Liquidity Operating Cash Flows Operating cash flows for the nine months ended September 30, 2001, as compared to the same period one year ago, were $222.2 million compared to $8.3 million. Cash flow from operating activities was positively impacted in the current year due to the collection of increased accounts receivables and reduced deposits, which were partially offset by increased cash used for payment of accounts payable and gas in storage and reduced recovery of unrecovered purchased gas costs. Receivables are typically higher during the heating season, however they were higher than normal at December 31, 2000 due to the higher gas prices and the integration of the businesses acquired in 2000. Consistent with receivables, accounts payable are typically higher during the heating season resulting in payments being made during the first six months of the year. Although receivables and payables would normally have been expected to decrease from December 31, 1999 to September 30, 2000 due to seasonality as discussed above, receivables and payables increased during this period due to the acquisitions. A reduction in margin deposits required on futures and options contracts for the Marketing and Trading segment is due to the drop in gas prices at September 30, 2001 compared to December 31, 2000. The increase in gas in storage during the nine months ended September 30, 2001 is a result of increased volumes in storage as well as higher gas prices as the Company focused on opportunistically securing volumes that are then hedged at favorable winter/summer spreads. The increase in gas in storage during the nine months ended September 30, 2000 is due to the acquisitions. For the nine months ended September 30, 2001, the increase in the unrecovered purchased gas costs is due to higher gas prices and the OCC's extending the recovery of the costs to mitigate the impact on customers. See "Liquidity", page 28. Investing Cash Flows Cash paid for capital expenditures for the nine months ended September 30, 2001, was $243.2 million. Capital expenditures include $41.0 million for construction of an electric generating plant. For the same period one year ago, capital expenditures were $217.9 million which included $31.5 million for the construction of the electric generating plant. The increase in capital expenditures for the nine months ended September 30, 2001 compared to the same period in 2000 is primarily attributable to increased cost of sustaining a higher asset base due to the acquisitions and the costs related to construction of the electric generating plant. Acquisitions for 2001 included $14.5 million of purchase price adjustments related to the Kinder Morgan acquisition. 27
Financing Cash Flows The Company's capitalization structure is 36 percent equity and 64 percent debt at September 30, 2001, compared to 48 percent equity and 52 percent debt at December 31, 2000. At September 30, 2001, $1.7 billion of long-term debt was outstanding. As of that date, the Company could have issued $702.9 million of additional long-term debt under the most restrictive provisions contained in its various borrowing agreements. The increase in debt, incurred to finance acquisitions, resulted in the increase in interest costs for the nine months ended September 30, 2001 compared to the same period in 2000. In April 2001, the Company issued $400 million of ten year, 7.125 percent, fixed rate notes to pay off short-term debt. In July 2001, the Company entered into interest rate swaps on this debt. In October 2001, the Company fixed the interest rate on this debt at 3.63% through 2002. On July 18, 2001, the Company filed a "shelf" registration statement on Form S-3 pursuant to which the Company may offer debt securities and shares of the Company's Common Stock in one or more offerings with a total initial offering price of up to $500 million. The Board of Directors has authorized up to $1.2 billion of short term financing to be obtained as necessary for the operation of the corporation and its subsidiaries. The Company has an $850 million revolving credit facility with a maturity date of June 27, 2002. This credit facility is primarily used to support the commercial paper program. At September 30, 2001, $545.3 million of commercial paper was outstanding. Although cash provided by operating activities continues as the primary source for meeting day-to-day cash requirements, due to seasonal fluctuations, acquisitions, and additional capital requirements, the Company accesses funds through commercial paper, and short-term credit agreements and, if necessary, through long-term borrowing. Liquidity Competition continues to increase in all segments of the Company's business. The loss of major customers without recoupment of those revenues and lower spreads in the Gathering and Processing segment are events that could have a material adverse effect on the Company's financial condition. However, strategies such as aggressive negotiations to reduce keep whole contract exposure, weather normalization in Kansas and Oklahoma, and increased use of storage in the day trading market are expected to reduce other risks to the Company. Additionally, rates in the Distribution segment are structured to reduce the Company's risk in serving its large customers. The OCC staff filed an application on February 1, 2001 to review the gas procurement practices of ONG in acquiring its gas supply for the 2000/2001 heating season to determine if they were consistent with least cost procurement practices and whether the Company's decisions resulted in fair, just and reasonable costs being borne by its customers. In a hearing on October 31, 2001, the OCC issued an oral ruling that ONG not be allowed to recover the balance in the Company's unrecovered purchased gas cost account related to the unrecovered gas costs from the 2000/2001 winter effective with the first billing cycle for the month following the issuance of a final order. Until such time as a final order is issued, the amount at issue is not known, and the oral ruling is not appealable. The Company believes that decisions made by the Company were prudent based upon the facts and circumstances existing at the time the decisions were made, which is the standard applicable to the Proceeding as stated by the OCC. The Company believes that the oral ruling is without merit based upon the evidence presented and will defend itself vigorously; however, the failure to recover the unrecovered purchased gas costs could have a material adverse affect on the financial condition and results of operations. As of September 30, 2001, ONG's total unrecovered purchased gas costs was $47.5 million, not all of which is related to the 2000/2001 heating season. The Company believes that internally generated funds and access to financial markets will be sufficient to meet its normal debt services, dividend requirements, and capital expenditures. 28
C. Impact of Recently Issued Accounting Pronouncements In July 2001, the FASB issued Statement of Financial Accounting Standards No. 141, "Business Combinations" (Statement 141), Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (Statement 142), and Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (Statement 143). In October, 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (Statement 144). Statement 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. Statement 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of Statement 142. The Company is required to adopt the provisions of Statement 141 immediately, and Statement 142 effective January 1, 2002. Goodwill acquired in business combinations completed before July 1, 2001 will continue to be amortized prior to the adoption of Statement 142. In connection with the Company's adoption of Statement 142, the Company will be required to perform an assessment of whether there is an indication that goodwill, including equity-method goodwill, is impaired as of the date of adoption. Any transitional impairment loss will be recognized as a cumulative effect of a change in accounting principle in the Company's statement of earnings. As of September 30, 2001, the Company has unamortized goodwill in the amount of $147.9 million, which will be subject to the transition provisions of Statement 142. Amortization expense related to goodwill was $3.2 million and $3.3 million for the year ended December 31, 2000 and the nine months ended September 30, 2001, respectively. Because of the extensive effort needed to comply with adopting Statements 141 and 142, no estimate is available of the impact of adopting these Statements. The Company will discontinue amortization of goodwill effective January 1, 2002, with the adoption of Statement 142. Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Statement 143 is effective for fiscal years beginning after June 15, 2002. Statement 144 retains the requirement to report separately discontinued operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. Statement 144 is effective for fiscal years beginning after December 15, 2001, and for interim periods within those fiscal years. The Company is currently assessing the impact of Statements 143 and 144 on its financial condition and results of operations. D. Other Southwest Gas Corporation Information related to the terminated proposed acquisition of Southwest Gas Corporation is presented in Note F in the Notes to the Consolidated Financial Statements and Part II, Item 1 of this Form 10-Q. 29
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Risk Management - The Company, substantially through its non-utility segments, is exposed to market risk in the normal course of its business operations and to the impact of market fluctuations in the price of natural gas, NGLs and crude oil. Market risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity energy prices. The Company's primary exposure arises from fixed price purchase or sale agreements which extend for periods of up to 48 months, gas in storage inventories utilized by the gas marketing and trading operation, and anticipated sales of natural gas and oil production. To a lesser extent, the Company is exposed to risk of changing prices or the cost of intervening transportation resulting from purchasing gas at one location and selling it at another (hereinafter referred to as basis risk). To minimize the risk from market fluctuations in the price of natural gas, NGLs and crude oil, the Company uses commodity derivative instruments such as futures contracts, swaps and options to manage market risk of existing or anticipated purchase and sale agreements, existing physical gas in storage, and basis risk. The Company adheres to policies and procedures that limit its exposure to market risk from open positions and monitors its exposure to market risk. Interest Rate Risk - The Company is subject to the risk of fluctuation in interest rates in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and at times interest rate swaps. In July 2001, the Company entered into interest rate swaps on a total of $400 million in long-term debt. In October 2001, the Company fixed the interest rates through 2002. A hypothetical 10 percent change in interest rates would result in an annual $1.8 million change in interest costs related to short-term, floating rate debt, and interest rate swaps based on principal balances outstanding at September 30, 2001. Value-at-Risk Disclosure of Market Risk - ONEOK measures entity-wide market risk in its trading, price risk management, and its non-trading portfolios using value-at-risk. The quantification of market risk using value-at-risk provides a consistent measure of risk across diverse energy markets and products with different risk factors in order to set overall risk tolerance, to determine risk targets and set position limits. The use of this methodology requires a number of key assumptions including the selection of a confidence level and the holding period to liquidation. ONEOK relies on value-at-risk to determine the potential reduction in the trading and price risk management portfolio values arising from changes in market conditions over a defined period. ONEOK's value-at-risk exposure represents an estimate of potential losses that would be recognized for its trading and price risk management portfolio of derivative financial instruments, physical contracts and gas in storage assuming hypothetical movements in commodity market assumptions with no change in positions and are not necessarily indicative of actual results that may occur. Value-at-risk does not represent the maximum possible loss nor any expected loss that may occur because actual future gains and losses will differ from those estimated based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in the Company's trading and price risk management portfolio of derivative financial instruments and physical contracts. At September 30, 2001, the Company's estimated potential one-day favorable or unfavorable impact on future earnings, as measured by value-at-risk, using a 95 percent confidence level and diversified correlation assuming one day to liquidate positions was $2.2 million for its non-trading portfolio and $2.3 million for its trading portfolio. 30
PART II - OTHER INFORMATION Item 1. Legal Proceedings ONEOK, Inc. v. Southern Union Company, No. 99-CV-0345-H(M), United States ------------------------------------- District Court for the Northern District of Oklahoma, transferred, No. CV-00-1812-PHX-ROS, in the United States District Court for the District of Arizona, on appeal of preliminary injunction, United States Court of Appeals for the Tenth Circuit, Case Number 99-5103. On June 29, 2001, Southern Union filed a motion for summary judgment in its favor on the claims asserted against it by the Company in this action. A hearing on the motion was held on October 19, 2001. No decision has been rendered by the Court concerning Southern Union's motion for summary judgment. Southern Union Company v. Southwest Gas Corporation, et al., No. ----------------------------------------------------------- CIV-99-1294-PHX-ROS, United States District Court for the District of Arizona. On June 29, 2001, the Company filed a motion for summary judgment in its favor on the sole remaining claim asserted against it by Southern Union. On August 24, 2001, the Court heard 10 motions for summary judgment and related motions asserted by the corporate and individual parties. On September 25, 2001, the Court granted in part and denied in part the motions of ONEOK and Messrs. Dubay and Gaberino. The Court's rulings struck the damages of $750 million asserted by Southern Union, holding that any recovery in this action by Southern Union would be limited to out-of-pocket expenses and punitive damages relating to the failed merger. The Court determined that Southern Union's sole remaining liability claim, interference with a prospective economic advantage, would be set for a jury trial scheduled to commence on May 28, 2002. ONEOK, Inc. v. Southwest Gas Corporation, No. 00-CV-063-H(E), United States ---------------------------------------- District Court for the Northern District of Oklahoma, transferred, No. CIV-00-1775-PHX-ROS, United States District Court for the District of Arizona. On June 29, 2001, Southwest filed a motion for summary judgment on the claims asserted against it by the Company in this action. A hearing on the motion was held on October 19, 2001. No decision has been rendered by the Court concerning Southwest's motion for summary judgment. Southwest Gas Corporation v. ONEOK, Inc., No. CIV-00-0119-PHX-ROS, United States ---------------------------------------- District Court for the District of Arizona. On June 29, 2001, the Company filed a motion for partial summary judgment on the claims asserted against it by Southwest in this action. A hearing on the motion was held on October 19, 2001. No decision has been rendered by the Court on the Company's motion for summary judgment. Quinque Operating Company, et al. v. Gas Pipelines, et al., 26th Judicial ----------------------------------------------------------- District, Stevens County, Kansas, Civil Department, Case No. 99C30. On June 8, 2001, a Second Amended Petition was filed as a purported class action against 225 defendants, including ONEOK, Inc., one of its divisions and five of its subsidiaries. The Second Amended Petition was purportedly filed on behalf of all producers and royalty owners who have lost money as the result of mismeasurement of gas since 1974 from any of the 225 defendants. The Second Amended Petition alleges that each of the 225 defendants engaged in one or more specific "mismeasurement techniques" and conspired with one another to undermeasure the gas sold by the alleged class members. Discovery, except on class certification and personal jurisdictional grounds, has been stayed. The jurisdictional discovery sought by the plaintiffs has been limited by the Court. The response of ONEOK Gas Transportation, LLC, the only ONEOK subsidiary named as a defendant that is seeking dismissal on grounds of personal jurisdiction, was served on the plaintiff on October 29, 2001. Cause PUD 01-57, Oklahoma Corporation Commission. On October 31, 2001, by a 2-1 --------------- vote, the Commission orally ruled that ONG should not be allowed to recover the balance in the UPGC account related to last winter's gas costs, effective with the first billing period after the order is issued. The Commission directed Staff to conduct an audit of the UPGC account to determine the amount. The Company then expects that a final written order will be entered by the Commission, which will be subject to appeal by the Company. 31
For additional information regarding the Company's legal proceedings, see the Company's Form 10-K for the period ended December 31, 2000 and the Company's Form 10-Q for the periods ending March 31, 2001 and June 30, 2001. 32
Item 6. Exhibits and Reports of Form 8-K (A) Documents Filed as Part of this Report (12) Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the nine months ended September 30, 2001 and 2000 (12)(a) Computation of Ratio of Earnings to Fixed Charges for the nine months ended September 30, 2001 and 2000 (B) Reports on Form 8-K August 9, 2001 - Reported a clarification in the second quarter earnings release August 9, 2001 - Reported a conference call with financial analysts to discuss second quarter earnings September 27, 2001 - Announced that ONEOK was granted a motion for summary judgment on a claim against ONEOK by Southern Union Company for tortious interference with Southern Union's prospective relationship with Southwest Gas Corporation September 27, 2001 - Announced ONEOK's stock repurchase plan 33
Signatures Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 7th day of November 2001. ONEOK, Inc. Registrant By: /s/ Jim Kneale ------------------------------------------- Jim Kneale Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer) 34