UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the quarterly period ended September 30, 2003
OR
For the transition period from to .
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
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 ¨
Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x No ¨.
On October 31, 2003, the Company had 81,271,122 shares of common stock outstanding.
QUARTERLY REPORT ON FORM 10-Q
Part I.
Financial Information
Item 1.
Financial Statements (Unaudited)
Consolidated Statements of Income - Three and Nine Months Ended September 30, 2003 and 2002
Consolidated Balance Sheets - September 30, 2003 and December 31, 2002
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2003 and 2002
Notes to Consolidated Financial Statements
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
Part II.
Other Information
Legal Proceedings
Changes in Securities and Use of Proceeds
Defaults Upon Senior Securities
Submission of Matters to a Vote of Security Holders
Item 5.
Item 6.
Exhibits and Reports on Form 8-K
Signatures
As used in this Quarterly Report on Form 10-Q, the terms “we”, “our” or “us” mean ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.
2
Part I - FINANCIAL INFORMATION
Item 1. Financial Statements
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Revenues
Operating revenues, excluding energy trading revenues
Energy trading revenues, net
Cost of sales
Net Revenues
Operating Expenses
Operations and maintenance
Depreciation, depletion, and amortization
General taxes
Total Operating Expenses
Operating Income
Other income
Other expense
Interest expense
Income taxes
Income from continuing operations
Discontinued operations, net of taxes (Note C)
Income from operations of discontinued component
Gain on sale of discontinued component
Cumulative effect of changes in accounting principle, net of tax (Note A)
Net Income
Preferred stock dividends
Income Available for Common Stock
Earnings Per Share of Common Stock (Note M)
Basic:
Earnings per share from continuing operations
Earnings per share from operations of discontinued component
Earnings per share from gain on sale of discontinued component
Earnings per share from cumulative effect of changes in accounting principle
Net earnings per share, basic
Diluted:
Net earnings per share, diluted
Average Shares of Common Stock (Thousands)
Basic
Diluted
See accompanying Notes to Consolidated Financial Statements.
3
CONSOLIDATED BALANCE SHEETS
Assets
Current Assets
Cash and cash equivalents
Trade accounts and notes receivable, net
Materials and supplies
Gas in storage
Unrecovered purchased gas costs
Assets from price risk management activities
Deposits
Other current assets
Assets of discontinued component
Total Current Assets
Property, Plant and Equipment
Production
Gathering and Processing
Transportation and Storage
Distribution
Marketing and Trading
Other
Total Property, Plant and Equipment
Accumulated depreciation, depletion, and amortization
Net Property, Plant and Equipment
Deferred Charges and Other Assets
Regulatory assets, net (Note E)
Goodwill
Prepaid Pensions
Investments and other
Total Deferred Charges and Other Assets
Non-current Assets of Discontinued Component
Total Assets
4
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt
Notes payable
Accounts payable
Dividends payable
Accrued taxes
Accrued interest
Customers’ deposits
Liabilities from price risk management activities
Deferred income taxes
Liabilities of discontinued component
Total Current Liabilities
Long-term Debt, excluding current maturities
Deferred Credits and Other Liabilities
Lease obligation
Other deferred credits
Total Deferred Credits and Other Liabilities
Non-current Liabilities of Discontinued Component
Total Liabilities
Commitments and Contingencies (Note J)
Shareholders’ Equity
Convertible preferred stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at December 31, 2002
Series D authorized 21,815,386 shares; issued and outstanding 13,397,386 shares at September 30, 2003
Common stock, $0.01 par value:authorized 300,000,000 shares; issued 95,315,952 shares and outstanding 81,182,651 shares at September 30, 2003; issued 63,438,441 shares and outstanding 60,761,064 shares at December 31, 2002
Paid in capital (Note I)
Unearned compensation
Accumulated other comprehensive income (loss) (Note G)
Retained earnings
Treasury stock at cost: 14,133,301 shares at September 30, 2003;and 2,677,377 shares at December 31, 2002
Total Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
5
CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating Activities
Gain on sale of assets
Gain on sale of equity investments
(Income) loss from equity investments
Stock-based compensation expense
Allowance for doubtful accounts
Changes in assets and liabilities (net of acquisition effects):
Accounts and notes receivable
Inventories
Accounts payable and accrued liabilities
Price risk management assets and liabilities
Other assets and liabilities
Cash Provided by Continuing Operations
Cash Provided by Discontinued Operations
Cash Provided by Operating Activities
Investing Activities
Changes in other investments, net
Acquisitions
Capital expenditures
Proceeds from sale of property
Proceeds from sale of equity investment
Cash Used in Investing Activities of Continuing Operations
Cash Provided by (Used in) Investing Activities of Discontinued Operations
Cash Used in Investing Activities
Financing Activities
Payments of notes payable, net
Change in bank overdraft
Issuance of debt
Payment of debt issuance costs
Payment of debt
Purchase of Series A Convertible Preferred Stock
Purchase of common stock
Issuance of common stock
Issuance of treasury stock, net
Dividends paid
Cash (Used In) Provided by Financing Activities
Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
6
This page intentionally left blank.
7
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
CommonStock
Issued
PreferredStock
December 31, 2002
Net income
Other comprehensive income
Total comprehensive income
Re-issuance of treasury stock
Common stock offering
Issuance costs of equity units
Contract adjustment payment
Repurchase of Series A
Convertible Preferred Stock
Exchange of Series A
Issuance of Series D
Repurchase of common stock
Exchange of Series D
Issuance of restricted stock
Forfeiture of restricted stock
Registration costs
Stock-based employee compensation expense
Convertible preferred stock dividends
Common stock dividends - $0.69 per share
September 30, 2003
See accompanying Notes to the Consolidated Financial Statements.
8
(Continued)
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Accounting Policies
The accompanying unaudited consolidated financial statements of ONEOK, Inc. and its subsidiaries (ONEOK or the Company) have been prepared in accordance with accounting principles generally accepted in the United States of America. The accompanying unaudited 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 Company’s business, the results of operations for the three and nine months ended September 30, 2003, are not necessarily indicative of the results that may be expected for a twelve-month period. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.
The Company’s accounting policies are consistent with those discussed in its Form 10-K for the year ended December 31, 2002, except as follows.
Critical Accounting Policies
Energy Trading and Price Risk Management Activities - In October 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) rescinded Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). EITF 98-10 required entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options, gas in storage and energy transportation and storage contracts utilized for trading activities were reflected at fair value as assets and liabilities from price risk management activities under EITF 98-10.
The rescission was effective for fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002, as well as, for contracts entered into on or after October 25, 2002. Changes to the accounting for gas in storage and existing contracts as a result of the rescission of EITF 98-10 were reported as a cumulative effect of a change in accounting principle on January 1, 2003, resulting in a gross cumulative non-cash loss of $231.0 million, $141.8 million, net of tax, in the first quarter of 2003. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods based on actual settlement prices. Also, as a result of the rescission, the Marketing and Trading segment’s gas in storage inventory is carried on the balance sheet as gas in storage at the lower of cost or market beginning January 1, 2003.
Significant Accounting Policies
Goodwill - In accordance with the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142), the Company completed its annual analysis of goodwill for impairment as of January 1, 2003 and 2002 and there was no impairment indicated. See Note F.
Asset Retirement Obligations - On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.
Statement 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is
10
depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expenses. If the obligation is settled for other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement.
All legal obligations for asset retirement obligations were identified and the fair value of these obligations was determined as of January 1, 2003. The obligations primarily relate to the 300-megawatt power plant and various processing plants, storage facilities and producing wells. As a result of the adoption of Statement 143, the Company recorded a long-term liability of approximately $16.3 million, an increase to property, plant and equipment, net of accumulated depreciation, of approximately $12.9 million, and a cumulative effect charge of approximately $2.1 million, net of tax, in the first quarter of 2003. The related depreciation and amortization expense is immaterial to the Company’s consolidated financial statements.
Common Stock Options and Awards - On January 1, 2003, the Company adopted the recognition and measurement principles of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123), as amended. The Company has elected to begin expensing the fair value of all stock-based compensation granted on or after January 1, 2003 under the prospective method allowed by Statement 123. As a result of the adoption of Statement 123, the Company recorded additional stock-based compensation expense of approximately $960,000, net of tax, during the nine months ended September 30, 2003. Prior to January 1, 2003, the Company accounted for its stock-based compensation plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations.
11
The following table sets forth the effect on net income and earnings per share if the Company had applied the fair-value recognition provisions of Statement 123 to all options granted prior to January 1, 2003.
Net income, as reported
Deduct: total stock-based employee compensation expense determined under fair value based method for awards granted prior to January 1, 2003, net of related tax effects
Pro forma net income
Earnings per share:
Basic - as reported
Basic - pro forma
Diluted - as reported
Diluted - pro forma
Reclassifications - Certain amounts in the consolidated financial statements have been reclassified to conform to the 2003 presentation.
B. Acquisitions
On January 3, 2003, the Company purchased the Texas distribution business and other assets from Southern Union Company. The results of operations of these assets have been included in the Company’s consolidated financial statements since that date. The Company paid approximately $436.6 million for these assets. The purchase price includes $16.6 million in working capital adjustments. The primary assets acquired were gas distribution operations that serve approximately 535,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville and others. Over 90 percent of the customers are residential. The other assets acquired include a 125-mile natural gas transmission system, as well as other energy related domestic assets involved in gas marketing, retail sales of propane and distribution of propane. The purchase also includes natural gas distribution investments in Mexico. The distribution assets are operated under the name Texas Gas Service Company, a division of ONEOK, Inc. The assets and assumed liabilities have been recorded at preliminary fair values. As additional information is obtained, including actuarial reports, there could be adjustments to the purchase price allocation.
12
The table of unaudited pro forma information set forth below presents a summary of consolidated results of operations of the Company as if the acquisition of the Texas assets had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or the results that may be expected in the future.
Operating revenues
Net revenues
Earnings per share from continuing operations - diluted
Earnings per share - diluted
The addition of the Texas distribution assets fits well with the Company’s concentration in the mid-continent region of the United States, adding to its distribution systems in Oklahoma and Kansas. The acquisition also adds a stable revenue source as a majority of the margins are protected from the impact of weather swings due to rate designs that include a fixed customer charge. The regulatory environment in which municipalities set rates diversifies regulatory risk.
C. Discontinued Operations
In January 2003, the Company sold approximately 70 percent of the natural gas and oil producing properties of its Production segment (the component) for an adjusted cash price of $294 million. The component is accounted for as a discontinued operation in accordance with Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Accordingly, amounts in the Company’s financial statements and related notes for all periods shown reflect discontinued operations accounting. The Company’s decision to sell the component was based on strategic evaluations of the Production segment goals and favorable market conditions. The Company recognized a pretax gain on the sale of the discontinued component of approximately $59 million in the first quarter of 2003. The gain reflects the cash received, less adjustments, selling expenses and the net book value of the assets sold.
13
The following table discloses the amount of revenues, costs and income taxes reported in discontinued operations for the periods indicated.
Natural gas sales
Oil sales
Other revenues
Operating costs
Operating income
Income from discontinued component
Gain on sale of discontinued component, net of tax of $20.7 million
The following table discloses the major classes of discontinued assets and liabilities included in the Consolidated Balance Sheet for the period indicated.
Assets:
Total current assets of discontinued component
Property, plant, and equipment
Net property, plant, and equipment
Total non-current assets of discontinued component
Total assets of discontinued component
Liabilities:
Total current liabilities of discontinued component
Total non-current liabilities of discontinued component
Total liabilities of discontinued component
D. Price Risk Management Activities and Financial Instruments
The Company’s non-regulated businesses account for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (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
14
a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, 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. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income 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.
As required by Statement 133, the Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives, strategies for undertaking various hedge transactions and its methods for assessing and testing correlation and hedge ineffectiveness. The Company specifically identifies the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. The Company assesses the effectiveness of its hedging relationships, both at the inception of the hedge and on an on-going basis.
Fair Value Hedges -The Marketing and Trading segment uses basis swaps to hedge the fair value of certain transportation commitments. At September 30, 2003, net price risk management assets include $21.5 million to recognize the fair value of the Marketing and Trading segment’s derivatives that are designated as fair value hedging instruments. Price risk management liabilities include $21.2 million to recognize the change in fair value of the related hedged firm commitment.
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. During the first quarter of 2003, the Company terminated $50 million of interest swaps that had a fair value of approximately zero. In September 2003, $100 million of our fixed rate debt was swapped to a floating rate based on the six-month London InterBank Offered Rate (LIBOR). In October 2003, we terminated $50 million of interest rate swaps that had a fair value of approximately zero. At September 30, 2003, $650 million of fixed rate debt has been swapped to a floating rate based on the three-month or six-month LIBOR at the respective reset date and the swaps have been designated as fair value hedges. In January 2003, interest rates were locked in through the first quarter of 2004. In September 2003, interest rates on $500 million of the swapped debt were locked through the first quarter of 2005. At September 30, 2003, price risk management assets include $71.5 million to recognize the fair value of the Company’s derivatives that are designated as fair value hedging instruments. Long-term debt includes approximately $71.6 million to recognize the change in fair value of the related hedged liability.
Cash Flow Hedges - The Marketing and Trading segment uses futures and swaps to hedge the cash flows associated with its natural gas inventories. Accumulated other comprehensive income at September 30, 2003, includes gains of approximately $22.7 million, net of tax, related to these hedges that will be realized within the next 16 months.
The Production segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas. The Company realized losses in earnings of approximately $0.6 million and $3.7 million for the three and nine months ended September 30, 2003, respectively, related to production hedges. The realized losses were reclassified from accumulated other comprehensive income resulting from the settlement of contracts when the natural gas was sold. The losses are reported in operating revenues. Accumulated other comprehensive income at September 30, 2003 includes gains of approximately $0.5 million, net of tax, for the production hedges that will be realized in earnings within the next 15 months.
The Company’s regulated businesses also use derivative instruments from time to time. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased
15
gas adjustment. At September 30, 2003, Kansas Gas Service (KGS) had derivative instruments in place to hedge the cost of gas purchases for 36.9 Bcf of gas.
E. Regulatory Assets
The following table is a summary of the Company’s regulatory assets, net of amortization, for the periods indicated.
Recoupable take-or-pay
Pension costs
Postretirement costs other than pension
Transition costs
Reacquired debt costs
Weather normalization
Line replacements
Regulatory assets, net
On September 17, 2003, the Kansas Corporation Commission (KCC) issued an order approving a $45 million rate increase for the Company’s distribution customers in Kansas pursuant to a stipulated settlement agreement with KGS. The order settled the rate case filed by KGS in January 2003 and allowed KGS to begin operating under the new rate schedules effective September 22, 2003.
In October 2003, Oklahoma Natural Gas (ONG) filed an application with the Oklahoma Corporation Commission (OCC) requesting that it be allowed to recover costs that the Company has incurred since 2000 when it assumed responsibility for its customers’ service lines and enhanced its efforts to protect pipelines from corrosion. ONG also seeks to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The application seeks a total of $24 million in additional annual revenue. Should recovery of any regulatory assets, or portion thereof, be denied by the OCC, these assets may no longer meet the criteria for accounting in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” and, accordingly, a write-off of regulatory assets may be required.
F. Goodwill
The following table reflects the changes in the carrying amount of goodwill for the periods indicated.
Total consolidated
16
The additions to goodwill in 2003 are a result of the preliminary purchase price allocation of the Texas assets acquired in January 2003. See Note B.
G. Comprehensive Income
The tables below give an overview of comprehensive income for the periods indicated.
Other comprehensive income:
Unrealized gains on derivative instruments
Unrealized holding losses arising during the period
Realized losses in net income
Other comprehensive income before taxes
Income tax expense on other comprehensive income
Comprehensive income
Other comprehensive income (loss):
Unrealized holding gains (losses) arising during the period
Realized gains in net income
Other comprehensive income (loss) before taxes
Income tax benefit (expense) on other comprehensive income (loss)
Other comprehensive income (loss)
17
Accumulated other comprehensive income reflected in the consolidated balance sheet at September 30, 2003, includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.
H. Capital Stock
In July 2003, the Company began using shares of its common stock from treasury to meet the purchase requirements generated by participants in its Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries. All participant purchases under this plan are voluntary. During the three months ended September 30, 2003, the Company issued 269,000 shares for a total of $5.5 million.
2003 Public Offering - During the first quarter of 2003, the Company conducted public offerings of its common stock and equity units. In connection with these offerings, the Company issued a total of 13.8 million shares of its common stock at the public offering price of $17.19 per share, resulting in aggregate net proceeds to the Company, after underwriting discounts and commissions, of $16.524 per share, or $228 million.
In addition, the Company issued a total of 16.1 million equity units at the public offering price of $25 per unit, resulting in aggregate net proceeds to the Company, after underwriting discounts and commissions, of $24.25 per equity unit, or $390.4 million. Each equity unit consists of a stock purchase contract for the purchase of shares of the Company’s common stock and, initially, a senior note due February 16, 2008, issued pursuant to the Company’s existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes will be recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there will be no impact on earnings in future periods as this liability is paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense will be approximately $3.5 million over three years. Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of the Company’s common stock on January 22, 2003.
Westar - On January 9, 2003, the Company entered into an agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc. (collectively, “Westar”), to repurchase a portion of the shares of the Company’s Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of ONEOK’s $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of common stock, reflecting the Company’s two-for-one stock split in 2001, and the Series D shares are convertible into one share of common stock. Some of the differences between the Series D and the Series A are (a) the Series D has a fixed quarterly cash dividend of 23.125 cents per share, (b) the Series D is redeemable by ONEOK at any time after August 1, 2006, at a per share redemption price of $20, in the event that the per share closing price of ONEOK common stock exceeds, at any time prior to the date the notice is given, $25 for 30 consecutive trading days, (c) each share of Series D is convertible into one share of ONEOK common stock, and (d) with certain exceptions, Westar may not convert any shares of Series D held by it unless the annual per share dividend on ONEOK common stock for the previous year is greater than 92.5 cents and such conversion would not subject ONEOK to the Public Utility Holding Company Act of 1935. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. The shareholder agreement restricts Westar from selling five percent or more of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred), in a bona fide public underwritten offering, to any one person or group. The agreement allows Westar to sell up to five percent of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group who does not own more than five percent of ONEOK’s outstanding common stock (assuming conversion of all shares of Series D to be transferred). The KCC approved the Company’s agreement with Westar on January 17, 2003. On February 5, 2003, the Company consummated the agreement by purchasing $300 million of its Series A from Westar. The Company
18
exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of the Company’s newly-created Series D. Upon the cash redemption of the Series A shares, the shares were converted to approximately 18.1 million shares of common stock in accordance with the terms of the Series A shares and the prior shareholder agreement with Westar. Accordingly, the redemption is reflected as an increase to common treasury stock. The Series D exchanged for the Series A was recorded at fair value and the premium over the previous carrying value of the Series A is reflected as a decrease in retained earnings. The Company has registered for resale all of the shares of its common stock held by Westar, as well as all the shares of its Series D issued to Westar and all of the shares of its common stock issuable upon conversion of the Series D.
On August 4, 2003, Westar announced that it planned to conduct a secondary offering to the public of 9.5 million shares of ONEOK common stock. On August 5, 2003, Westar priced the secondary offering at a public offering price of $19.00 per share, which resulted in gross offering proceeds to Westar of approximately $180.5 million. The Company did not receive any proceeds from the offering. Since Westar received in excess of $150 million of total proceeds from the offering, the Company was allowed, under a new transaction agreement related to the offering, to repurchase $50 million, or approximately 2.6 million shares, of its common stock from Westar at the public offering price of $19.00 per share. The Company’s repurchase of those shares occurred immediately following the closing of the Westar offering. Of the shares sold in the Westar public offering, approximately 7.9 million shares represented ONEOK’s common stock issued by conversion of ONEOK’s Series D owned by Westar. The remaining shares consisted of approximately 1.6 million shares of ONEOK’s common stock owned by Westar. Currently, Westar beneficially owns approximately 14.5 percent of ONEOK’s common stock assuming conversion of the remaining shares of Series D held by Westar.
Dividends - Quarterly dividends on the Company’s common stock for shareholders of record during the nine months ended September 30, 2003, were $0.17 per share. On September 18, 2003, the Company’s Board of Directors approved an increase in the quarterly dividend on the Company’s common stock to $0.18 per share that was applicable to the quarterly dividend declared in September 2003. Due to the timing of the Company’s Board of Directors meetings, four quarterly dividends on common stock were declared during the first three quarters of 2003.
I. Paid in Capital
Paid in capital is $766.9 million and $339.7 million for the Company’s common stock at September 30, 2003, and December 31, 2002, respectively. Paid in capital for the Company’s convertible preferred stock was $222.2 million and $564.2 million at September 30, 2003, and December 31, 2002, respectively.
J. Commitments and Contingencies
Southwest Gas Corporation - Two substantially identical derivative actions, which were consolidated, were filed by shareholders against members of the Board of Directors and certain officers of the Company alleging violation of their fiduciary duties to the Company by causing or allowing the Company to engage in certain fraudulent and improper schemes related to the planned acquisition of Southwest Gas Corporation and waste of corporate assets. The consolidated derivative action has been settled at no significant cost to the Company. The trial Court entered a final judgment on June 24, 2003, approving the settlement by the parties after notice had been given to shareholders.
Environmental - The Company has 12 manufactured gas sites located in Kansas, which may contain 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. Remedial investigation has commenced on four sites. However, a comprehensive study is not complete and the results to date do not provide a sufficient basis for a reasonable estimation of the total liability. The site situations are not common and the Company has no previous experience with similar remediation efforts. The information
19
currently available estimates the cost of remediation to range from $100,000 to $10 million per site based on a limited comparison of costs incurred by others to remediate comparable sites. Although the information provides an insufficient basis to reasonably estimate a minimum range of the Company’s total liability, the Company has accrued a liability reflecting an estimate of the total cost of remedial investigation and feasibility study. Through September 30, 2003, the costs of the investigations and risk analysis related to these manufactured gas sites have been immaterial. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties. At this time, the Company is not recovering any environmental amounts in rates. The KCC has in the past permitted others to recover 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 remediation done and number of years over which the remediation is completed.
Yaggy Facility - In January 2001, the Yaggy gas storage facility’s operating parameters were changed as mandated by the KDHE following natural gas explosions and eruptions of natural gas geysers in or near Hutchison, Kansas. In July 2002, the KDHE issued an administrative order that assessed an $180,000 civil penalty against the Company, based on alleged violations of several KDHE regulations. A status conference was held on June 27, 2003, regarding progress toward reaching an agreed upon consent order. The matter was continued pending further settlement negotiations. The Company believes there are no adverse long-term environmental effects from the Yaggy storage facility.
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 at the Yaggy facility. These class action lawsuits were filed on the grounds that the eruptions and explosions related to natural gas that allegedly escaped from the Yaggy storage facility. On January 17, 2003, the two-year statute of limitations for known personal injury claims and all non-class members expired. In addition to the two pending class action matters, sixteen additional lawsuits have been filed against the Company or its subsidiaries seeking recovery for various claims related to the Yaggy incident, including property damage, personal injury, loss of business and, in some instances, punitive damages. Although no assurances can be given, the Company 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 in these cases and believes that its insurance coverage will provide coverage for any material liability associated with these cases.
U.S. Commodity Futures Trading Commission - On January 9, 2003, the Company received a subpoena from the U.S. Commodity Futures Trading Commission (CFTC) requesting information regarding certain trading by energy and power marketing firms and information provided by the Company to energy industry publications in connection with the CFTC’s industry wide investigation of trading and trade reporting practices of power and natural gas trading companies. The Company ceased providing such information to energy industry publications in 2002. Since receipt of the subpoena, the Company has been conducting an internal review relating to its reporting of natural gas trading information to energy industry publications. In addition, the Company has produced documents and other information to the CFTC. The Company continues to provide additional information to the CFTC in response to supplemental requests. On October 3, 2003, the Company announced that, in the course of providing information to the CFTC, it had learned that some information furnished by the Company to industry publications was inaccurate. The Company cannot determine if the inaccurate information had any impact on the price indices published, but it intends to continue to cooperate with the CFTC and continue its internal review. At the present time, the Company cannot determine the outcome of its ongoing review or the impact on the Company of the CFTC’s continuing investigation.
Labor Negotiations - On September 12, 2003, three Kansas labor unions voted to ratify a 12-month labor contract related to the Company’s KGS operations, which includes a two percent pay increase, retroactive to August 2003. Approximately 497 KGS employees are members of the unions, comprising approximately 44% of the total KGS workforce. Currently, the Company has no ongoing labor negotiations.
20
Other - The Company is a party to other litigation matters and claims, which are normal in the ordinary course of its operations. While the results of litigation and claims cannot be predicted with certainty, management believes the final outcome of such matters will not have a material adverse effect on the Company’s consolidated results of operations, financial position, or liquidity.
K. Segments
The accounting policies of the Company’s business segments are substantially the same as those described in the Summary of Significant Accounting Policies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, except for those changes discussed in Note A. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Intersegment sales for the Marketing and Trading segment were $64.5 million and $22.7 million for the three months ended September 30, 2003 and 2002, respectively, and $373.0 million and $231.1 million for the nine months ended September 30, 2003 and 2002, respectively. Energy trading contracts included in the following table are reported net of related costs. Corporate overhead costs relating to the segments are 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 consolidated gross revenues.
21
The following tables set forth certain selected financial information for the Company’s six operating segments for the periods indicated.
Three Months EndedSeptember 30, 2003
Transportationand
Storage
Sales to unaffiliated customers
Energy trading contracts, net
Intersegment sales
Total revenues
Depreciation, depletion and amortization
Income from equity investments
Three Months EndedSeptember 30, 2002
Capital expenditures (continuing operations)
Capital expenditures (discontinued component)
22
Nine Months EndedSeptember 30, 2003
Marketingand
Trading
Total assets
Nine Months EndedSeptember 30, 2002
Income (loss) from equity investments
23
L. Supplemental Cash Flow Information
The following table sets forth supplemental information with respect to the Company’s cash flows for the periods indicated.
Cash paid (received) during the period
Interest (including amounts capitalized)
Income taxes received
Noncash transactions
Cumulative effect of changes in accounting principle
Rescission of EITF 98-10 (price risk management assets and liabilities)
Adoption of Statement 143
Dividends on restricted stock
Treasury stock transferred to compensation plans
Issuance of restricted stock, net
Property, plant and equipment
Current assets
Current liabilities
Regulatory assets and goodwill
Other assets
Deferred credits
Cash paid for acquisitions
M. Earnings Per Share Information
Through February 5, 2003, the Company computed its earnings per common share (EPS) 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). In accordance with Topic D-95, the dilutive effect of the Company’s Series A Convertible Preferred Stock is considered in the computation of basic EPS utilizing the “if-converted” method. Under the Company’s “if-converted” method, the dilutive effect of the Company’s 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 Company’s common stock and its participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The Company’s Series A Convertible Preferred Stock was a participating instrument with the Company’s common stock with respect to the payment of dividends. For the three and nine months ended September 30, 2002, and the period from January 1, 2003 to February 5, 2003, the “two-class” method resulted in additional dilution. Accordingly, EPS for this
24
period reflects this further dilution. As a result of the Company’s repurchase and exchange of its Series A Convertible Preferred Stock in February 2003, the Company no longer applies the provisions of Topic D-95 to its EPS computations beginning in February 2003.
The following tables set forth the computations of the basic and diluted EPS from continuing operations for the periods indicated.
Per Share
Amount
Basic EPS from continuing operations
Income from continuing operations available for common stock
Effect of other dilutive securities:
Options and other dilutive securities
Diluted EPS from continuing operations
Income from continuing operations available for common stock and assumed conversion
Convertible preferred stock
Income from continuing operations available for common stock and assumed conversion of preferred stock
Further dilution from applying the “two-class” method
Effect of other dilutive securities
Income from continuing operations available for common stock and assumed exercise of stock options
25
Income from continuing operations available for common stock under D-95
Series A Convertible Preferred Stock dividends
Income from continuing operations available for common stock and assumed conversion of Series A Convertible Preferred Stock
Basic EPS from continuing operations under D-95
Income from continuing operations available for common stock not under D-95
Income from continuing operations available for Series D Convertible Preferred Stock dividends
Series D Convertible Preferred Stock dividends
There were 171,249 and 206,504 option shares excluded from the calculation of diluted EPS for the three months ended September 30, 2003 and 2002, respectively, since their inclusion would be antidilutive for
26
each period. There were 17,205,762 convertible preferred stock shares excluded from the calculation of diluted EPS due to the assumed conversion effect being antidilutive for the three months ended September 30, 2003. For the nine months ended September 30, 2003 and 2002, there were 92,203 and 161,796 option shares, respectively, excluded from the calculation of diluted EPS since their inclusion would be antidilutive for each period.
The repurchase and exchange of the Company’s Series A Convertible Preferred Stock from Westar in February 2003 was recorded at fair value. In accordance with EITF Topic No. D-42, the premium, or the excess of the fair value of the consideration transferred to Westar over the carrying value of the Series A Convertible Preferred Stock, is considered a preferred dividend. The premium recorded on the repurchase and exchange of the Series A Convertible Preferred Stock was approximately $44.2 million and $53.4 million, respectively, for a total premium of $97.6 million. As a result of the Company’s adoption of Topic D-95, the Company has recognized additional dilution of approximately $94.5 million through the application of the “two-class” method of computing EPS. This additional dilution offsets the total premium recorded, resulting in a net premium of $3.1 million, which is reflected as a dividend on the Series A Convertible Preferred Stock in the above EPS calculation for the nine months ended September 30, 2003.
N. Debt Covenant Compliance
In September 2003, the Company renewed its $850 million revolving credit facility, which now expires September 20, 2004. This credit facility has customary covenants that relate to liens, investments, fundamental changes in the business, the restriction of certain payments, changes in the nature of the business, transactions with affiliates, burdensome agreements, the use of proceeds, and a limit on the Company’s debt to capital ratio. The renewed facility includes a term-out option, which allows us to convert any outstanding borrowings under the credit agreement into a 364-day term note at the expiration of the credit agreement. Other debt agreements to which the Company is a party have negative covenants that relate to liens and sale/leaseback transactions. At September 30, 2003, the Company was in compliance with all covenants.
O. Subsequent Event
On October 28, 2003, the Company agreed to purchase approximately $240 million of East Texas gas and oil properties and related gathering systems from Wagner & Brown, Ltd. of Midland, Texas. The acquisition includes approximately 177.2 Bcfe of proved gas reserves, with additional probable and possible gas reserve potential. Current net gas production from these properties is approximately 26,000 Mcfe per day. The acquisition is expected to close before December 31, 2003 and, if completed, will be reflected in the Company’s December 31, 2003 financial statements.
27
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward Looking Statements and Risk Factors
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 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. Known and unknown risks, uncertainties and other factors 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 results of administrative proceedings, enforcement proceedings and litigation involving the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas regulatory authorities or any other local, state or federal regulatory body including the
28
Federal Energy Regulatory Commission (FERC) and the Commodity Futures Trading Commission (CFTC);
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. We have no obligation and make no undertaking to update publicly or revise any forward-looking statements.
Critical Accounting Policies and Estimates
Energy Trading and Risk Management Activities - We engage in price risk management activities for both energy trading and non-trading purposes. Through 2002, we accounted for price risk management activities for our energy trading contracts in accordance with Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). EITF 98-10 required entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options, gas in storage and energy transportation and storage contracts utilized for trading activities were reflected at fair value as assets and liabilities from price risk management activities under EITF 98-10.
In October 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) rescinded EITF 98-10. As a result, energy-related contracts that are not accounted for pursuant to Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, (Statement 133) are no longer carried at fair value but rather are classified as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the EITF also agreed that energy trading inventories carried under storage agreements should no longer be carried at fair value but should be carried at the lower of cost or market. Therefore, beginning in January 2003, the Marketing and Trading segment’s gas in storage inventory is carried on the balance sheet as gas in storage at the lower of cost or market.
The rescission was effective for fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002, as well as, for contracts entered into on or after October 25, 2002. Changes to the accounting for gas in storage and existing contracts as a result of the rescission of EITF 98-10 were reported as a cumulative effect of a change in accounting principle on January 1, 2003, resulting in a gross cumulative non-cash loss of $231.0 million, or $141.8 million, net of tax, in the first quarter of 2003. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods based on actual settlement prices.
The fair values of the assets and liabilities recorded pursuant to EITF 98-10 and Statement 133 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 revenues, on a net basis, in the consolidated statements of income. The fair value of these assets and liabilities reflects management’s best estimate considering various factors, including quoted market prices, time value and volatility underlying the commitments. Market prices were adjusted for the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions.
29
During the third quarter of 2002, we adopted the applicable provisions of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). EITF 02-3 provides that all mark-to-market gains and losses on derivative contracts held for trading purposes be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. The FASB staff also indicated that dealer profits on unrealized gains or losses at contract inception were not appropriate unless evidenced by quoted prices or other market transactions. Prior to the third quarter of 2002, energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3. Net energy trading revenues include sales and purchases of natural gas, crude oil, natural gas liquids and basis (the price differential that exists between two geographic locations), as well as reservation fees.
In July 2003, the EITF reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’”(EITF 03-11). EITF 03-11 provides that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. We have evaluated our activities and will continue to present the financial results of all energy trading contracts on a net basis.
Regulation - Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC, Texas Railroad Commission (TRC) and various municipalities in Texas. Certain of our other transportation activities are subject to regulation by the Federal Energy Regulatory Commission (FERC). Allocation of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from allocations generally applied by non-regulated operations. Such allocations of costs and revenues made to meet regulatory accounting requirements are considered to be in accordance with generally accepted accounting principles for regulated utilities.
During the ratemaking process, regulatory authorities may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. This causes certain expenses to be deferred as regulatory assets and amortized to expense as they are recovered through rates. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71) and, accordingly, a write-off of regulatory assets and stranded costs may be required.
On September 17, 2003, the KCC issued an order approving a $45 million rate increase for our Kansas customers pursuant to the stipulated settlement agreement with KGS. The order settled the rate case filed by KGS in January 2003 and allowed KGS to begin operating under the new rate schedules.
Impairment of Long-Lived Assets - We recognize the impairment of a long-lived asset when indicators of impairment are present and the undiscounted cash flow is not sufficient to recover the carrying amount of these assets. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows or information provided by sales and purchases of similar assets.
For further discussion of our accounting policies, see Note A of Notes to the Consolidated Financial Statements in this Form 10-Q.
30
Results of Operations
Consolidated Operations
We are a diversified energy company whose objective is to maximize value for shareholders by vertically integrating our business operations from the wellhead to the burner tip. This strategy has led us to focus on acquiring assets that provide synergistic trading and marketing opportunities along the natural gas energy chain. Products and services are provided to our customers through the following business segments:
Transactions - On January 3, 2003, we closed the purchase of our Texas assets for a cash purchase price of approximately $436.6 million. The purchase price includes $16.6 million in working capital adjustments. The assets acquired include the third largest gas distribution business in Texas, with operations that serve approximately 535,000 customers, over 90 percent of which are residential. The distribution assets are operated under the name of Texas Gas Service (TGS).
In January 2003, we closed the sale of a significant portion of the natural gas and oil producing properties of our Production segment for a cash sales price of $294 million, including adjustments. Pursuant to the sale, we sold natural gas and oil reserves in Oklahoma, Kansas and Texas. The sale included approximately 1,900 wells, 482 of which we operated. The sale is accounted for as a discontinued operation. Accordingly, the statistical and financial information related to the properties sold has been restated as a discontinued component. We recorded a pre-tax gain on the sale of the discontinued component of approximately $59 million in the first quarter of 2003.
2003 Public Offering – During the first quarter of 2003, we conducted public offerings of our common stock and equity units. In connection with these offerings, we issued a total of 13.8 million shares of our common stock at the public offering price of $17.19 per share, resulting in aggregate net proceeds, after underwriting discounts and commissions, of $16.524 per share, or $228 million.
In addition, we issued a total of 16.1 million equity units at the public offering price of $25 per unit, resulting in aggregate net proceeds, after underwriting discounts and commissions, of $24.25 per equity unit, or $390.4 million. Each equity unit consists of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes will be recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there will be no impact on earnings in future periods as this liability is paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense will be approximately $3.5 million over three years. Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of our common stock on January 22, 2003.
On February 5, 2003, we purchased $300 million of our Series A Convertible Preferred Stock (“Series A”) from Westar. These shares were converted to approximately 18.1 million common shares and are being held in treasury stock. We exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of our newly-created Series D Convertible Preferred Stock (“Series D”) and retired the
31
Series A shares received in the exchange. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between Westar and us became effective. We have registered for resale all of the shares of our common stock held by Westar, as well as all the shares of our Series D issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D shares.
On August 4, 2003, Westar announced that it planned to conduct a secondary offering to the public of 9.5 million shares of ONEOK common stock. On August 5, 2003, Westar priced the secondary offering at a public offering price of $19.00 per share, which resulted in gross offering proceeds to Westar of approximately $180.5 million. We did not receive any proceeds from the offering. Since Westar received in excess of $150 million of total proceeds from the offering, we were allowed, under a new transaction agreement related to the offering, to repurchase $50 million, or approximately 2.6 million shares, of our common stock from Westar at the public offering price of $19.00 per share. Our repurchase of those shares occurred immediately following the closing of the Westar offering. Of the shares sold in the Westar public offering, approximately 7.9 million shares represented our common stock issued by conversion of our Series D shares owned by Westar. The remaining shares consisted of approximately 1.6 million shares of our common stock owned by Westar. Currently, Westar beneficially owns approximately 14.5 percent of our common stock, assuming conversion of the remaining shares of our Series D shares held by Westar.
During 2002, we settled a number of outstanding issues pending before the OCC. We had previously recorded a charge of approximately $34.6 million in the fourth quarter of 2001 related to these matters. As a result of the settlement agreement, we revised the estimated amount of the charge and reversed $14.2 million of the charge in the second quarter of 2002.
We sold our claim related to the Enron bankruptcy for $22.1 million resulting in a gain of $14.0 million in the first quarter of 2002. The sale was subject to normal representations as to the validity, but not collectibility, of the claim and guarantees from Enron. We had previously recorded a charge of $37.4 million in the fourth quarter of 2001 related to the Enron bankruptcy.
Adoption of New Accounting Standards - On January 1, 2003, we adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. As a result of the adoption of Statement 143, we recorded a cumulative effect of a change in accounting principle charge of approximately $2.1 million, net of $1.3 million in taxes, in the first quarter of 2003.
On January 1, 2003, we adopted the recognition and measurement principles of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123), as amended. We have elected to begin expensing the fair value of all stock-based compensation granted on or after January 1, 2003, under the prospective method allowed by Statement 123, as amended. As a result of the adoption of Statement 123, we recorded additional stock-based compensation expense of approximately $960,000, net of taxes, during the nine months ended September 30, 2003.
In October 2002, the EITF of the FASB rescinded EITF 98-10. As a result, energy related contracts that are not accounted for pursuant to Statement 133, will no longer be carried at fair value but rather will be accounted for as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the Task Force also agreed that energy trading inventories carried under storage agreements should no longer be carried at fair value but should be carried at the lower of cost or market. Changes to the accounting for gas in storage and existing contracts as a result of the rescission of EITF 98-10 have been reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect loss of $141.8 million, net of $89.2 million in taxes, in the first quarter of 2003.
During the third quarter of 2002, we adopted EITF 02-3. EITF 02-3 provides that all mark-to-market gains and losses on derivative contracts held for trading purposes be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the
32
contract. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3 for all periods presented.
In July 2003, the EITF reached a consensus on EITF 03-11. EITF 03-11 provides that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. We have evaluated our activities and will continue to present the financial results of all energy trading contracts on a net basis.
The following table sets forth certain selected consolidated financial information for the periods indicated.
Three Months Ended
September 30,
Nine Months Ended
Financial Results
Cost of gas
Discontinued operations, net of taxes
Cumulative effect of changes in accounting principle, net of tax
Operating Results - Operating revenues and cost of gas both increased for the three and nine months ended September 30, 2003, compared to the same periods in 2002, primarily due to increases in commodity prices and the acquisition of our Texas assets. The decrease in energy trading revenues, net for the three-month period is primarily related to the impact of the rescission of EITF 98-10. Prior to its rescission, net revenues were recognized under fair value accounting as physical natural gas inventories were injected into storage, normally during the second and third quarters. The rescission of EITF 98-10 requires that natural gas inventories under storage agreements be carried at the lower of cost or market and precludes mark-to-market accounting for energy related contracts that do not qualify as derivatives. This revenue will now be recognized as the gas is withdrawn from storage and sold, normally in the first and fourth quarters. The decrease in energy trading revenues, net was partially offset by the recognition of $11 million in revenues in our marketing and trading operations, which related to the first and second quarters of 2003. Operating costs and depreciation, depletion and amortization have increased in 2003, compared to 2002, again primarily due to the acquisition of our Texas assets. Our TGS assets, which are included in our Distribution segment, contributed approximately $22.1 million and $76.8 million to net revenues and $3.7 million and $19.5 million to operating income for the three and nine months ended September 30, 2003, respectively, after reallocation of corporate overhead costs.
33
Other income for the nine months ended September 30, 2002 includes the gain related to the sale of our investment in Magnum Hunter Resources. Other expense for the three and nine months ended September 2002 includes increased reserves for legal costs and a charge for the settlement of litigation with Southwest Gas Corporation (Southwest) related to our terminated effort to acquire Southwest.
Our Production segment currently owns, develops and produces natural gas and oil reserves in Oklahoma. We focus on development activities rather than exploratory drilling.
In October 2003, the Company agreed to purchase approximately $240 million of East Texas gas and oil properties and related gathering systems from Wagner & Brown, Ltd. of Midland, Texas. The acquisition includes approximately 177.2 Bcfe of proved gas reserves, with additional probable and possible gas reserve potential. Current net gas production from these properties is approximately 26,000 Mcfe per day. The acquisition is expected to close before December 31, 2003 and, if completed, will be reflected in the Company’s December 31, 2003 financial statements.
In January of 2003, we closed the sale of approximately 70 percent of the natural gas and oil producing properties of our Production segment to Chesapeake Energy Corporation for a cash sales price of $294 million, including adjustments. The sale included approximately 1,900 wells, 482 of which we operated. We recorded an after-tax gain of $38.4 million ($59 million pre-tax) in the first quarter of 2003 related to this sale. The statistical and financial information related to the properties sold has been restated as a discontinued component for all periods presented.
The following tables set forth certain financial and operating information for our Production segment for the periods indicated.
Other income (expense), net
Cumulative effect of change in accounting principle, net of tax
34
Operating Information
Proved reserves
Continuing operations
Gas (MMcf)
Oil (MBbls)
Discontinued component
Average realized price (a)
Gas ($/Mcf)
Oil ($/Bbls)
Capital expenditures (Thousands)
Operating Results - Natural gas sales from continuing operations increased for the three and nine months ended September 30, 2003, compared to the same periods in 2002, due to higher natural gas prices received in 2003. Gas production was lower during the three and nine months ended September 30, 2003 compared to the same periods in 2002 due to normal production declines. Prices before hedges were $4.91 and $3.04 per Mcf for the third quarter of 2003 and 2002, respectively. Prices before hedges were $5.44 and $2.62 per Mcf for the nine months ended September 30, 2003 and 2002, respectively.
At September 30, 2003 we had hedged 12.5 MMcf per day, or 59 percent, of our anticipated gas production for the remainder of 2003 at a NYMEX price of $4.50 per Mcf. In October 2003, we hedged an additional 5 MMcf per day at the NYMEX price of $5.60 per Mcf for November and $6.00 per Mcf for December. At September 30, 2003, we had also hedged 5 MMcf per day, or 25 percent, of anticipated 2004 natural gas production at a NYMEX price of $5.30 per Mcf. In October 2003, we hedged an additional 10 MMcf per day of 2004 natural gas production at a NYMEX price of $5.18 per Mcf.
Oil sales from continuing operations decreased for the three months ended September 30, 2003, compared to the same period in 2002, due to lower volumes produced in the 2003 period reflecting normal production declines. These decreases were partially offset by increased crude oil prices resulting from favorable market conditions. The average crude oil price before hedges for the third quarter of 2003 was $29.72 per barrel. There were no crude oil hedges in place for the third quarter of 2002.
Oil sales increased for the nine months ended September 30, 2003 compared to 2002, due to increases in both price and production volumes. Oil volumes produced were higher in the first nine months of 2003 compared to 2002 as a result of additional production resulting from successful drilling in the last quarter of
35
2002. At September 30, 2003, approximately 62 percent of our anticipated oil production for the remainder of 2003 was hedged at $27.25 per barrel.
Operating costs for continuing operations increased for the three and nine months ended September 30, 2003, compared to the same periods in 2002, due to higher production taxes caused by higher prices and higher overhead costs on retained wells.
Our Production segment added 10.3 Bcfe of net reserves for the nine months ended September 30, 2003, including 4.3 Bcfe of proved developed reserves, which is comprised of 2.4 Bcfe of proved developed producing and 1.9 Bcfe of proved developed non-producing, and 6.0 Bcfe of proved undeveloped reserves.
Operational Highlights - The Gathering and Processing segment is engaged in the gathering and processing of natural gas and the fractionation, storage and marketing of natural gas liquids (NGLs). Our Gathering and Processing segment currently has a processing capacity of approximately 2.0 Bcf per day, of which approximately 0.2 Bcf per day is currently idle. Our Gathering and Processing segment owns approximately 14,000 miles of gathering pipelines that supply our gas processing plants.
In January 2003 we acquired a retail propane business as part of our purchase of our Texas assets. This business consists of a small retail propane distribution business in Austin and a retail propane bottle and delivery service primarily located in El Paso. In December 2002 we completed the sale of three processing plants and related gathering assets, along with our interest in a fourth processing plant, all located in Oklahoma, to a third party.
The following tables set forth certain selected financial and operating information for our Gathering and Processing segment for the periods indicated.
Natural gas liquids and condensate sales
Gas sales
Gathering, compression, dehydration and processing fees and other revenues
Cumulative effect of a change in accounting principle, net of tax
36
Total gas gathered (MMMBtu/d)
Total gas processed (MMMBtu/d)
Natural gas liquids sales (MBbls/d)
Natural gas liquids produced (MBbls/d)
Gas sales (MMMBtu/d)
Operating Results - The increase in natural gas liquids and condensate sales revenues for both the quarter ended September 30 and year to date 2003 compared to the same periods in 2002 is primarily due to increases in composite NGL prices, increases in crude oil prices, and additional third party sales volumes. The Conway OPIS composite NGL price based on our NGL product mix increased from $0.41 and $0.38 per gallon for the three and nine months ended September 30, 2002, respectively, to $0.57 and $0.58 per gallon for the same periods in 2003, respectively. The average NYMEX crude oil price increased from $27.41 and $24.30 per barrel for the three and nine months ended September 30, 2002, respectively, to $30.65 and $31.30 per barrel, respectively, for the same periods in 2003.
The increase in gas sales and cost of sales for both the three and nine months ended September 30, 2003, compared to the same periods in 2002 is primarily due to an increase in the price of natural gas. The average natural gas price for the mid-continent region increased from $2.88 and $2.75 per MMBtu for the three and nine months ended September 30, 2002 to $4.80 and $5.30 per MMBtu for the same periods in 2003, respectively. Gas sales volumes decreased primarily due to reduced volumes available to sale as a result of the sale of certain Oklahoma gas gathering and processing assets that occurred in December 2002. This reduction was partially offset by additional gas volumes available to sell due to reduced NGL production. NGL production was reduced because of the high value of natural gas relative to NGL prices and contractual changes that allow us to retain a larger percentage of the gas gathered and processed.
Net revenues increased for both the three and nine months ended September 30, 2003 compared to the same periods in 2002 due to higher commodity prices, continued contract restructuring which reduces processing spread risk while increasing our exposure to higher commodity prices, and the acquisition of our Texas assets. These increases were partially offset by reduced volumes of gas gathered and processed and liquids produced as the result of the sale of certain of our Oklahoma gas gathering and processing assets. NGLs produced also declined because plant operations were modified to reduce NGL production to take advantage of market conditions throughout the period due the high value of natural gas relative to NGL prices.
The decreases in operating costs for the three and nine month periods are due to the sale of certain of our Oklahoma gas gathering and processing assets and lower bad debt expenses. These decreases were partially offset by increased employee benefit costs, higher ad valorem taxes and additional operating costs as a result of the acquisition of our Texas assets. The decrease in depreciation, depletion and amortization for the three and nine month periods is primarily due to the $2.4 million impairment charge associated with the sale of the Oklahoma assets recognized in the third quarter of 2002 along with the reduction in depreciation costs resulting from not owning the assets in the current year. An additional loss of $1.3 million on the assets sold was taken in the fourth quarter of 2002 and was included as a reduction of other income.
Operating Highlights - Our Transportation and Storage segment represents our intrastate natural gas transmission pipelines, natural gas storage and nonprocessable gas gathering facilities. We own or reserve capacity in five storage facilities in Oklahoma, three in Kansas and three in Texas, with a combined working capacity of approximately 59.6 Bcf, of which 8.0 Bcf is temporarily idle. Our intrastate transmission pipelines operate in Oklahoma, Kansas and Texas and are regulated by the OCC, KCC, and
37
TRC, respectively. In July 2002, we completed a transaction to transfer certain transmission assets in Kansas to our affiliated distribution company in Kansas. Historical financial and statistical information has been adjusted to reflect this transfer. In December 2002, certain Oklahoma storage property rights were sold and a long-term agreement was entered into with the purchaser, whereby we retain storage capacity consistent with our historical usage.
In October 2003, we completed a transaction with a third party to sell certain Texas transmission assets for a sale price of approximately $3.1 million. A charge against accumulated depreciation for about $7.8 million will be recognized in the fourth quarter in accordance with Statement of Financial Accounting Standards No 71, “Accounting for the Effects of Certain Types of Regulations” and the regulatory accounting requirements of the FERC and TRC.
The following tables set forth certain selected financial and operating information for our Transportation and Storage segment for the periods indicated.
Transportation and gathering revenues
Storage revenues
Gas sales and other
Cost of fuel and gas
Volumes transported (MMcf)
Operating results -Transportation and gathering revenues increased for the three and nine months ended September 30, 2003, compared to the same periods in 2002 primarily due to the price of natural gas and its impact on the valuation of retained fuel. The average natural gas price for the mid-continent region increased from $2.88 and $2.75 per MMBtu for the three and nine months ended September 30, 2002, respectively, to $4.80 and $5.30 per MMBtu, respectively, for the same periods in 2003. Storage revenues increased in both periods primarily as a result of additional working capacity being available in 2003 compared to same periods in 2002. This additional capacity was the result of improved operating conditions and additional capacity becoming available as a result of the gas inventory sales in 2002. Gas sales and other revenues decreased for the three-month period ended September 30, 2003 compared to the same period in 2002 due to the gas inventory sales made in 2002. For the nine-month period ended September 30, 2003, gas sales and other revenue also decreased compared to the same period in 2002 due to a reduction in sales volumes associated with our wellhead purchases on certain gathering facilities in Oklahoma.
38
Cost of fuel and gas increased for the three-month period ended September 30, 2003 compared to the same period in 2002 primarily due to an increase in the price of natural gas and its impact on fuel. Cost of fuel and gas decreased for the nine months ended September 30, 2003 primarily due the decrease in sales volumes associated with our wellhead purchases on certain gathering facilities in Oklahoma and gas inventory sales made in 2002. This decrease was somewhat offset by higher natural gas prices for fuel. Additionally, the nine-month period ended September 30, 2002 included higher costs as a result of adjustments related to the reconciliation of third party contractual storage and pipeline imbalance positions.
The increase in operating costs for the three months ended September 30, 2003 compared to the same period in 2002 was primarily related to increased maintenance costs, employee costs, litigation costs, insurance costs and regulatory fees. Despite the increase in operating costs during the three-month period, operating costs decreased for the nine months ended September 30, 2003 compared to the same period in 2002 primarily due to lower litigation costs early in 2003 and lower bad debt expense and ad valorem taxes.
Our Distribution segment provides natural gas distribution services in Kansas, Oklahoma and Texas. Operations in Kansas are conducted through our Kansas Gas Service (KGS) division, which serves residential, commercial, industrial, end-use transportation and wholesale customers. Operations in Oklahoma are conducted through our Oklahoma Natural Gas (ONG) division, which serves residential, commercial, industrial, and end-use transportation customers and leases gas pipeline capacity. Operations in Texas are conducted through our Texas Gas Service (TGS) division, which serves residential, commercial, industrial, public authority and transportation customers. Our Distribution segment provides gas service to approximately 75 percent, 80 percent, and 17 percent of the populations of Kansas, Oklahoma and Texas, respectively. KGS and ONG are subject to regulatory oversight by the KCC and OCC, respectively. TGS is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the TRC.
On October 10, 2003, ONG filed an application with the OCC requesting that it be allowed to recover costs that the Company has incurred since 2000 when it assumed responsibility for its customers’ service lines and enhanced its efforts to protect pipelines from corrosion. ONG also seeks to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The application seeks a total of $24 million in additional annual revenue. A hearing is expected in January 2004.
On September 17, 2003, the KCC issued an order approving a $45 million rate increase for our Kansas customers pursuant to the stipulated settlement agreement with KGS. The order settled the rate case filed by KGS in January 2003 and allowed KGS to begin operating under the new rate schedules effective September 22, 2003. After amortization of previously deferred costs, it is estimated that operating income will increase by approximately $29.6 million on an annual basis.
On September 12, 2003, KGS completed negotiations with three Kansas labor unions to replace collective bargaining agreements that expired on July 31, 2003. Approximately 497 of our KGS employees are members of those three labor unions, comprising approximately 44% of our KGS workforce. The parties agreed to extend the existing agreements for one year with a 2% wage increase effective retroactively to August 1, 2003.
In August 2003, TGS took ownership of the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas. The gas distribution system at Fort Bliss has approximately 2,500 customers.
On June 16, 2003, KGS filed a motion with the KCC to extend the Kansas WeatherProof Bill program for an additional 3 years. However, as a result of notification that KGS’ primary contractor would not be able to provide sufficient support for the program, KGS was allowed by the KCC to withdraw its request on September 12, 2003. Accordingly, the Weatherproof Bill program will end effective December 1, 2003.
39
On January 3, 2003, we purchased our Texas gas distribution assets. The gas distribution operations serve approximately 535,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville, and others. Over 90 percent of the customers are residential. The acquisition adds a stable revenue source as a majority of the margins are protected from the impact of weather swings due to rate designs that include a fixed customer charge.
A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding cases pending before the OCC. The major cases settled were the Commission’s inquiry into our gas cost procurement practices during the winter of 2000/2001, an application seeking relief from improper and excessive purchased gas costs, and enforcement action against us, our subsidiaries and affiliated companies of ONG. In addition, all of the open inquiries related to the annual audits of ONG’s fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.
The Stipulation has a $33.7 million value to ONG customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all ONG customers in the form of billing credits totaling approximately $9.1 million. In December 2005, a final billing credit will be made to customers. The minimum amount of this credit is estimated to be approximately $2.8 million. ONG is replacing certain gas contracts, which are expected to reduce gas costs by approximately $13.8 million, due to avoided reservation fees between April 2003 and October 2005. Additional savings of approximately $8.0 million from the use of storage gas are expected to occur between November 2003 and March 2005. Any expected savings from the use of storage that are not achieved will be added to the final billing credit scheduled to be provided to customers in December 2005. ONG operating income increased in the second quarter of 2002 by $14.2 million as a result of this settlement.
In July 2002, we completed a transaction to transfer certain transmission assets in Kansas from our Transportation and Storage segment to our Distribution segment. Historical financial and statistical information have been adjusted to reflect these changes.
The following table sets forth certain selected financial information for our Distribution segment for the periods indicated.
Gross margin
Transportation revenues
Operating income (loss)
Operating results - The increases in gas sales and cost of gas for the three and nine months ended September 30, 2003, compared to the same periods in 2002, are primarily due to the addition of TGS and increased commodity prices. Additionally, cost of gas for the nine-month period was higher in 2003 due to the $14.2 million reduction in the second quarter of 2002 resulting from the OCC Joint Stipulation. Additional gas volumes in Kansas and Oklahoma due to colder weather in the first quarter of 2003 increased gas sales and cost of gas for the nine months ended September 30, 2003, compared to the same period in 2002.
40
The increase in gross margin for the three and nine months ended September 30, 2003 is due to the addition of the operations of TGS, which is partially offset by the $14.2 million reduction in gas cost in the second quarter of 2002 resulting from the OCC Joint Stipulation.
Operating costs and depreciation, depletion and amortization increased for the three and nine months ended September 30, 2003, compared to the same periods in 2002, due primarily to the addition of the operations of TGS, increased bad debt expense resulting from higher gas costs and higher employee costs.
The addition of the operations of TGS contributed approximately $22.1 million and $76.8 million to net revenues and $3.7 million and $19.5 million to operating income for the respective three and nine-month periods ended September 30, 2003, respectively. Operating income for the three and nine-month periods also increased in 2003, compared to the same periods in 2002, as a result of $3.5 million of adjustments made in connection with the implementation of KGS’ new rate schedule.
The following table sets forth certain operating information for our Distribution segment for the periods indicated.
Volumes (MMcf)
Residential
Commercial
Industrial
Wholesale
Public authority
Total volumes sold
Transportation
Total volumes delivered
Overall, gas volumes increased primarily as a result of the addition of the operations of TGS. Additionally, residential and commercial volumes increased in the three and nine months ended September 30, 2003, compared to the same periods in 2002, as a result of colder weather in Kansas and Oklahoma. Wholesale gas sales in Kansas, also known as “as available” gas sales, represent gas volumes available under contracts that exceed the needs of our residential and commercial customer base and are available for sale to other parties. Wholesale volumes decreased for the three and nine months ended September 30, 2003 over the same periods in 2002 due to increased volumes of gas injected into storage. Also impacting the reduction in wholesale volumes during the nine-month period was a larger demand in the first quarter of 2003 for Kansas retail customers due to colder weather. Public authority volumes reflect volumes used by state agencies and school districts serviced by TGS.
Transportation volumes, which include pipeline capacity leased to others and transportation for end-use customers, increased primarily due to the addition of transportation customers acquired with the Texas gas distribution assets. Volumes also increased due to commercial and industrial customers moving to new transportation rates, a marketing effort to add small-usage customers, and a reduction in the minimum volume required for transport service in Oklahoma.
The following table sets forth certain selected operating information for our Distribution segment for the periods indicated.
41
Average number of customers
Customers per employee
The average number of customers and customers per employee increased in 2003 compared to the same periods in 2002 due to the addition of the operations of TGS and its favorable ratio of customers per employee.
Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71. See Note E of the Notes to Consolidated Financial Statements for a detail of regulatory assets at September 30, 2003.
Operational Highlights - Our marketing and trading operation purchases, stores, markets, and trades natural gas to the retail sector in its core distribution area and the wholesale sector throughout most of the United States. We have mid-continent region storage positions and transport capacity of 1 Bcf per day. With current total storage capacity of 75 Bcf, withdrawal capability of 2.3 Bcf per day and injection capability of 1.4 Bcf per day, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. We recently extended our marketing and trading operations into Canada leasing storage and pipeline capacity. We continue to enhance our strategy of focusing on higher margin business, which includes providing reliable service during peak demand periods, through the use of storage and transportation capacity.
We constructed a peak electric power generating plant in mid-2001. The 300-megawatt plant is located in Oklahoma adjacent to one of our natural gas storage facilities and is configured to supply electric power during peak demand periods. This plant allows us to capture the “spark spread premium,” which is the value added by converting natural gas to electricity, during peak demand periods. In October 2003, we signed a tolling arrangement with a third party power provider for their power plant in Big Springs, Texas, which is connected to our gas transmission system in Texas. The agreement, which expires in December 2005, allows us to sell the steam and power generated. This agreement will increase our owned or contracted power capacity from 300 to 512 megawatts.
During the third quarter of 2002, we adopted certain provisions of EITF 02-3, which provide that all mark-to-market gains and losses on energy trading contracts should be presented on a net basis (energy contract sales less energy contract costs) in our income statement without regard to the settlement provisions of the contract. Prior to the third quarter of 2002, our energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3 for all periods presented. EITF 02-3 does not affect power-related revenues, which will continue to be reported on a gross basis.
In October 2002, the EITF rescinded EITF 98-10. As a result, energy-related contracts that are not accounted for pursuant to Statement 133, will no longer be carried at fair value, but rather will be accounted for as executory contracts on an accrual basis. As a result of the rescission of EITF 98-10, the
42
Task Force also agreed that energy-trading inventories carried under storage agreements should no longer be carried at fair value, but should be carried at the lower of cost or market.
The rescission is effective for fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002. Additionally, the rescission applies immediately to contracts entered into on or after October 25, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 have been reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect loss, net of tax, of $141 million. The impact from this change was non-cash. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods.
The following tables set forth certain selected financial and operating information for our Marketing and Trading segment for the periods indicated.
Power sales
Cost of power and fuel
Natural gas sales volumes (MMcf)
Natural gas gross margin ($/Mcf)
Power sales volumes (MMwh)
Power gross margin ($/Mwh)
Physically settled volumes (MMcf) (a)
Operating Results - Energy trading revenues include revenues related to trading natural gas, reservation fees, crude oil, natural gas liquids, and basis. Basis is the natural gas price differential that exists between trading locations relative to the Henry Hub natural gas price.
Net revenues decreased for the three months ended September 30, 2003, compared to the same period in 2002. The decrease is attributable to the decrease in regional basis spreads and the rescission of EITF 98-10 effective January 1, 2003. The impact of the decrease in regional basis spreads was largely felt in the natural gas price differential that existed between the Rocky Mountain and Mid-continent trading locations. The intra-month price volatility also decreased in the third quarter of 2003 compared to the same period in 2002, decreasing our storage and transport option value. These decreases were partially offset by the
43
recognition of $11 million in revenues, which related to the first and second quarters of 2003. Historically, net revenues were recognized under fair value accounting as physical natural gas inventories were injected into storage during the second and third quarters. With the rescission of EITF 98-10, natural gas inventories carried under storage agreements are no longer carried at fair value, but rather are accounted for on an accrual basis at lower of cost or market with revenues recorded when the gas is sold, typically in the first and fourth quarters.
Net revenues derived from our physical trading totaled $13.3 million in the third quarter of 2003. The change in the fair value of our derivative instruments subject to fair value accounting pursuant to Statement 133 at September 30, 2003 (excluding those instruments qualifying for hedge accounting) was immaterial. Net revenues for the third quarter of 2002 included mark-to-market earnings of $22.2 million, which represented the change in net price risk management assets and liabilities from June 30, 2002 to September 30, 2002, resulting from the application of mark-to-market accounting on all energy contracts pursuant to EITF 98-10. Margins realized from our retail gas business increased by $0.5 million for the third quarter of 2003, compared to the same period in 2002, due to our expanding customer base in Wyoming, Nebraska, and Texas. Margins realized from our wholesale power business increased by $1.3 million for the third quarter of 2003, compared to the same period in 2002, due to warmer than normal temperatures in August, generating comparatively better spark spreads in the Southwest Power Pool.
Net revenues increased for the nine months ended September 30, 2003, compared to the same period in 2002 taking into effect the rescission of EITF 98-10. This was due to comparatively colder temperatures during the winter heating season and additional marketing and trading opportunities. For the first two quarters of 2003, our use of storage and transport capacity allowed us to capture the significantly higher intra-month price volatility and inter-region inefficiencies that occurred compared to 2002. Our storage and transport capacity also enabled us to secure positive option value and realize favorable pricing spreads on stored gas volumes. In the first quarter of 2002, we sold our Enron bankruptcy claim, which added $10.4 million to our net revenues. Sales volumes increased for the nine months ended September 30, 2003, compared to the same period in 2002. The increase in sales volumes is attributable to additional marketing and trading opportunities that have developed with the recent downsizing of certain trading companies in our industry.
Liquidity and Capital Resources
General - A part of our strategy is to grow through acquisitions that complement our existing assets. We have relied primarily on operating cash flow and borrowings from a combination of commercial paper, bank lines of credit, and capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources, together with possible equity financings, such as our recent public common stock and equity unit offerings, for liquidity and capital resource needs on both a short and long-term basis. During 2002 and through the third quarter of 2003, our capital expenditures were financed through operating cash flows and short and long-term debt. Capital expenditures for 2003 are expected to be $225 million to $230 million compared to $233 million in 2002. The increase in expected capital expenditures from the amount reported in previous quarters of 2003 relates to an increase in wells proposed for drilling in the Production segment and higher requirements in the Distribution segment for the Texas operation.
Financing is provided through our commercial paper program, long-term debt and, as needed, through a revolving credit facility. Other options to obtain financing include, but are not limited to, issuance of equity, issuance of mandatory convertible debt securities, issuance of trust preferred securities by ONEOK Capital Trust I or ONEOK Capital Trust II, asset securitization and the sale/leaseback of facilities.
Our credit rating is currently an “A-” (stable outlook) by Standard and Poors and a “Baa1” (negative outlook) by Moody’s Investor Service. Our credit rating may be affected by a material change in our financial ratios or a material adverse event affecting our business. The most common criteria for assessment of our credit rating are the debt to capital ratio, pre-tax and after-tax interest coverage and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper would increase, resulting in an increase in our cost to borrow funds. In the event that we are unable to borrow funds under
44
our commercial paper program and there has not been a material adverse change in our business, we have access to an $850 million revolving credit facility, which expires September 20, 2004.
Our energy marketing and trading business relies upon the investment grade rating of our senior unsecured long-term debt to satisfy credit support requirements with several counterparties. If our credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activity could be significantly limited. Without an investment grade rating, we would be required to fund margin requirements with the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements with cash, letters of credit or other negotiable instruments. At September 30, 2003, the total notional amount that could require such funding in the event of a credit rating decline to below investment grade is approximately $18.4 million.
We are subject to commodity price volatility. Significant fluctuations in commodity prices in either physical or financial energy contracts may impact our overall liquidity due to the impact a commodity price change has on items such as the cost of NGLs and gas held in storage, recoverability and timing of recovery of regulated natural gas costs, increased margin requirements, collectibility of certain energy-related receivables and working capital. We believe that our current commercial paper program and debt capacity are adequate to meet our liquidity requirements associated with commodity price volatility. We also have no material guarantees of debt or other commitments to unaffiliated parties.
Our pension plan is currently overfunded resulting in an asset reported on our balance sheet. Due to the poor performance of the equity market and lower interest rates, the market value of our pension fund assets has decreased and, accordingly, our pension credit for our pension and supplemental retirement plans will decrease in 2003 from $20.8 million to $7.0 million. Should the value of our pension fund assets fall below our accumulated benefit obligation, we would eliminate the asset and record a minimum pension liability on the balance sheet with the difference flowing through other comprehensive income, net of tax. We believe we have adequate resources to fund our obligations under our pension plan as deemed necessary.
Westar - On January 9, 2003, we entered into an agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc. (collectively, “Westar”), to repurchase a portion of the shares of our Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of ONEOK’s $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of common stock, reflecting our two-for-one stock split in 2001, and the Series D shares are currently convertible into one share of common stock. Some of the differences between the Series D and Series A are (a) the Series D has a fixed annual cash dividend of 92.5 cents per share, (b) the Series D is redeemable by us at any time after August 1, 2006, at a redemption price of $20, in the event that the closing price of our common stock exceeds, at any time prior to the date the notice is given, $25 for 30 consecutive trading days, (c) each share of Series D is convertible into one share of our common stock, and (d) with certain exceptions, Westar may not convert any shares of Series D held by it unless the annual per share dividend on our common stock for the previous year is greater than 92.5 cents and such conversion would not subject us to the Public Utility Holding Company Act of 1935. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. Our new shareholder agreement with Westar restricts Westar from selling five percent or more of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred), in a bona fide public underwritten offering, to any one person or to a group. The agreement allows Westar to sell up to five percent of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group that does not own more than five percent of our common stock (assuming conversion of all shares of Series D to be transferred). The KCC approved our agreement with Westar on January 17, 2003. On February 5, 2003, we consummated the agreement by purchasing $300 million of our Series A from Westar. We exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of our newly-created Series D. In addition, we have registered all of the shares of our common stock held by Westar, as well as all the shares of our Series D issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D.
45
On August 4, 2003, Westar announced that it planned to conduct a secondary offering to the public of 9.5 million shares of ONEOK common stock. On August 5, 2003, Westar priced the secondary offering at a public offering price of $19.00 per share, which resulted in gross offering proceeds to Westar of approximately $180.5 million. We did not receive any proceeds from the offering. Since Westar received in excess of $150 million of total proceeds from the offering, we were allowed, under the new transaction agreement related to the offering, to repurchase $50 million, or approximately 2.6 million shares, of our common stock from Westar at the public offering price of $19.00 per share. Our repurchase of those shares occurred immediately following the closing of the Westar offering. Of the shares sold in the Westar public offering, approximately 7.9 million shares represented our common stock issued by conversion of our Series D shares owned by Westar. The remaining shares consisted of approximately 1.6 million shares of our common stock owned by Westar. Currently, Westar beneficially owns approximately 14.5 percent of our common stock assuming conversion of the remaining shares of our Series D shares held by Westar.
Cash Flow Analysis
Operating Cash Flows – Operating cash flows decreased in the nine months ended September 30, 2003 compared to the same period in 2002, despite a significant increase in income from continuing operations. The decreases in operating cash flows primarily relate to changes in working capital and deferred income taxes. The change in inventories for the nine-month period in 2003 compared to 2002 is due to the rescission of EITF 98-10, which requires that gas in storage be carried at the lower of cost or market at September 30, 2003, and no longer included in price risk management assets as it was at December 31, 2002. The change in unrecovered purchased gas costs (UPGC) for the nine-month period in 2003 compared to 2002 is primarily due to the unusually high recovery of UPGC in the first quarter of 2002 related to previously deferred UPGC due to an OCC order. The changes in price risk management assets and liabilities primarily relate to the change in mark-to-market income and derivative contracts that expired and were settled in 2003. Changes in other assets and liabilities reflect expenditures or recognition of liabilities for insurance costs, salaries, taxes other than income, and other similar items. Fluctuations in these accounts, period-to-period, reflect changes in the timing of payments or recognition of liabilities and are not directly impacted by seasonal factors.
In 2002, operating cash flows were positively impacted by the collection of accounts receivable and reduced deposits. Accounts receivable decreased for nine-month period ended September 30, 2002, due to the decrease in energy prices and decreased demand in the summer months. The reduction in restricted deposits for the same period is due to increased purchases of option contracts by our Marketing and Trading segment in the nine months ended September 30, 2002. The change in UPGC is primarily due to the unusually high recovery of UPGC in the first quarter of 2002 related to deferred UPGC at December 31, 2001, due to an OCC order.
Investing Cash Flows – Acquisitions in 2003 represent the cash purchase of our Texas assets. Cash provided by investing activities of discontinued operations represents the sale of natural gas and oil producing properties for a cash sales price of $294 million, including adjustments, of which $15 million was received in 2002.
Financing Cash Flows - Our capitalization structure is 39 percent equity and 61 percent long-term debt at September 30, 2003, compared to 47 percent equity and 53 percent long-term debt at December 31, 2002. Our capitalization structure including notes payable was 37 percent equity and 63 percent total debt at September 30, 2003, compared to 43 percent equity and 57 percent total debt at December 31, 2002. The change in our capital structure is primarily due to transactions related to Westar. In January 2003, we issued common stock and equity units, which were partially offset by the payment of notes payable and the repurchase of our Series A Convertible Preferred Stock from Westar in February 2003. In August 2003, we repurchased $50 million or approximately 2.6 million shares of our common stock from Westar. At September 30, 2003, we had $1.9 billion of long-term debt outstanding. As of that date, we could have issued $777.5 million of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements.
46
Both Standard and Poors and Moody’s Investment Services consider the equity units we issued in January 2003 to be part equity and part debt. For purposes of computing capitalization ratios, these rating agencies adjust the capitalization structure. Standard and Poors considers the equity units to be equal amounts of debt and equity for the first three years, with the effect being to increase shareholders’ equity by the same amount as long-term debt, which would result in a capitalization structure of 46 percent equity and 54 percent long-term debt at September 30, 2003. Moody’s Investment Services considers 25 percent of the equity units to be long-term debt and 75 percent to be shareholders’ equity, which would result in a capitalization structure of 48 percent equity and 52 percent long-term debt at September 30, 2003.
Our $850 million revolving credit facility was renewed September 22, 2003. The new facility expires in September 2004 and includes a term-out option, which allows us to convert any outstanding borrowings under the credit agreement into a 364-day term note at the expiration of the credit agreement. This facility is primarily used to support our commercial paper program. At September 30, 2003, we had approximately $167 million of commercial paper outstanding and approximately $12 million in temporary investments.
During the first quarter of 2003, we conducted public offerings of our common stock and equity units. In connection with these offerings, we issued a total of 13.8 million shares of common stock at the public offering price of $17.19 per share, resulting in aggregate net proceeds to us, after underwriting discounts and commissions, of $16.524 per share, or $228 million.
In addition, we issued a total of 16.1 million equity units at the public offering price of $25 per unit, resulting in aggregate net proceeds to us, after underwriting discounts and commissions, of $24.25 per share, or $390.4 million. Each equity unit consists of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5% (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes will be recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there will be no impact on earnings in future periods as this liability is paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense will be approximately $3.5 million over three years. The present value of the contract adjustment payments is accounted for as equity and reduces Paid In Capital. Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of our common stock on January 22, 2003, and a floor of $17.19 per share.
On April 4, 2003, we filed an amendment to a shelf registration statement on Form S-3 for our issuance and sale of common stock, preferred stock, purchase contracts, purchase units and debt securities, and the issuance and sale by ONEOK Capital Trust I and ONEOK Capital Trust II of trust preferred securities, in one or more offerings with an aggregate offering price of up to $1.0 billion. Also, on April 4, 2003, we filed a shelf registration statement on Form S-3 to register for resale by Westar all of the shares of our common stock held by Westar, as well as all the shares of our Series D Convertible Preferred Stock issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D Convertible Preferred Stock. Both of these registration statements have been declared effective by the Securities and Exchange Commission.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Form 10-K for the year ended December 31, 2002, except as follows.
KGS uses derivative instruments to hedge the cost of anticipated gas purchases during the winter heating months to protect KGS customers from upward volatility in the market price of natural gas. At September 30, 2003, KGS had derivative instruments in place to hedge the cost of purchases for 36.9 Bcf of gas. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly purchased gas adjustment.
47
TGS uses derivative instruments to mitigate the volatility of the cost of gas to protect its customers in the city of El Paso. At September 30, 2003, TGS had no derivative instruments in place to hedge the cost of purchases of gas. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased gas adjustment.
The following table provides a detail of our Marketing and Trading segment’s maturity of derivatives based on heating injection and withdrawal periods from April to March. Executory storage and transportation contracts and their related hedges are not included in the following table. This maturity schedule is consistent with our Marketing and Trading segment’s trading strategy.
Source of Fair Value (1)
Matures
through
March 2004
March 2007
March 2009
after
Total
fair
value
Prices actively quoted (2)
Prices provided by other external sources (3)
For further discussion of trading activities and assumptions used in our trading activities, see the Critical Accounting Policies in Notes A and D of the notes to consolidated financial statements included in this Form 10-Q.
Interest Rate Risk - At September 30, 2003, the interest rate on 64.3 percent of our long-term debt was fixed after considering the impact of interest rate swaps. During the first quarter of 2003, we terminated $50 million in interest rate swaps that had a fair value of approximately zero. In September 2003, $100 million of our fixed rate debt was swapped to a floating rate based on the six-month London InterBank Offered Rate (LIBOR). In October 2003, we terminated $50 million in interest rate swaps that had a fair value of approximately zero. At September 30, 2003, $650 million of fixed rate debt has been swapped to a floating rate based on the three-month or six-month LIBOR at the respective reset date and the swaps have been designated as fair value hedges. In January 2003, interest rates were locked in through the first quarter of 2004. In September 2003, interest rates were locked in through the first quarter of 2005 on $500 million of the $650 million that were swapped to floating. The swaps will result in an estimated $24.2 million in savings during 2003 and an estimated $22.4 million in savings during 2004. At September 30, 2003, price risk management assets include $71.5 million to recognize the fair value of derivatives that are designated as fair value hedging instruments. Long-term debt includes approximately $71.6 million to recognize the change in fair value of the related hedged liability. Interest expense decreased approximately $0.1 million for the three months ended September 30, 2003, and increased approximately $0.9 million for the nine months ended September 30, 2003, to recognize the ineffectiveness of these hedges.
A 100 basis point move in the annual interest rate on all of our outstanding long-term debt would change our annual interest expense by approximately $1.0 million before taxes. This amount is limited based on the LIBOR locks that we have in place through the first quarter of 2005. If these locks were not in place, a 100 basis point change in the interest rates would affect our annual interest expense by $6.5 million before
48
taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.
Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $0.9 million and $6.0 million at September 30, 2003 and 2002, respectively.
The following table details the average, high and low VAR calculations:
Value at Risk
Average
High
Low
The variations in the VAR data are reflective of our marketing and trading growth and market volatility during the quarter.
Item 4. Controls and Procedures
Quarterly Evaluation of the Company’s Disclosure Controls - We evaluated the effectiveness of the design and operation of our disclosure controls and procedures (Disclosure Controls) as of the end of the period covered by this Quarterly Report. This evaluation (the Disclosure Controls Evaluation) was done under the supervision and with the participation of management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO). Rules adopted by the Securities and Exchange Commission (SEC) require that in this section of this Quarterly Report we present the conclusions of the CEO and the CFO about the effectiveness of our Disclosure Controls based on and as of the date of the Disclosure Controls Evaluation.
Disclosure Controls – Disclosure Controls are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (Exchange Act), such as this Quarterly Report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
Limitations on the Effectiveness of Controls – Our management, including the CEO and CFO, does not expect that our Disclosure Controls will prevent all errors and all fraud. A control system, including our Disclosure Controls, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, some controls may become inadequate because of changes in conditions, or the degree of compliance with policies or procedures that may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
49
Scope of the Controls Evaluation – The CEO/CFO evaluation of our Disclosure Controls included a review of the controls’ objectives and design, the controls’ implementation by us and the effect of the controls on the information generated for use in this Quarterly Report. In the course of the Disclosure Controls Evaluation, we sought to identify data errors, control problems or acts of fraud and to confirm that appropriate corrective action, including process improvements, were being undertaken. This type of evaluation will be done on a quarterly basis so that the conclusions concerning controls effectiveness can be reported in our Quarterly Reports on Form 10-Q and our Annual Report on Form 10-K. The overall goals of these evaluation activities are to monitor our Disclosure Controls and to make modifications as necessary. Our intent in this regard is that the Disclosure Controls will be maintained as dynamic systems that change (including with improvements and corrections) as conditions warrant.
Since the date of the Disclosure Controls Evaluation to the date of this Quarterly Report, there have been no significant changes in our internal controls or in other factors that could significantly affect our internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.
Conclusions – Based upon the Disclosure Controls Evaluation, our CEO and CFO have concluded that, subject to the limitations noted above, our Disclosure Controls are effective in providing reasonable assurance of achieving their objective of timely alerting them to material information required to be disclosed by us in periodic reports we file with the SEC.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
United States ex rel. Jack J. Grynberg v. ONEOK, Inc., ONEOK Resources Company, and Oklahoma Natural Gas Company, (CTN-8), No. CIV-97-1006-R, United States District Court for the Western District of Oklahoma, transferred, In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293, United States District Court for the District of Wyoming. On May 15, 2003, the Tenth Circuit dismissed plaintiff Grynberg’s appeal of the order that granted the motion of the United States to dismiss certain portions of plaintiff Grynberg’s complaint. Grynberg may appeal the order at the end of the case. Discovery is still ongoing regarding whether Grynberg has met the unique jurisdictional prerequisites for maintaining an action under the False Claims Act.
Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Price I”). On August 22, 2003, we filed an answer to plaintiffs’ fourth amended petition. Also, on or about August 5, 2003, we learned that plaintiffs filed a similar class action in May 2003 in Kansas against the same defendants as in this Price I case, but alleged claims based on undermeasurement of Btu’s, rather than volumetric undermeasurement as in this Price I case. The new case filed by the plaintiffs is described below and referred to as Price II.
Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al., 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Price II”). This case was filed in May, 2003. The defendants include 21 groups of defendants, one group consisting of ONEOK, Inc., Mid-Continent Market Center, Inc., ONEOK Field Services Company, Westar Transmission Company and Oklahoma Natural Gas Company (collectively, the “ONEOK Group”). Since the filing of this action, Westar Transmission Company has been dismissed from the case without prejudice. The plaintiffs seek class action status, claiming that the defendants measured gas from wells located in Wyoming, Kansas and Colorado and systematically and intentionally understated the heating content of that gas to the detriment of royalty owners. The purported class is gas royalty owners on non-federal and non-Indian lands in Kansas, Colorado and Wyoming. This case was filed after the court denied class status by the same group of plaintiffs seeking class relief for both undermeasurement of volume and understatement of heating content in the Price I case. After the court’s ruling in Price I, the plaintiffs filed an amended petition in that case removing allegations of understatement of heating content and have asserted those allegations in this Price II case. The joint defense group in this Price II case filed a motion to dismiss on the grounds that the plaintiffs had impermissibly split their claim. That motion was overruled on October 9, 2003. A
50
scheduling conference will be held in the near future. The issue of whether the plaintiffs may bring a class action is the current main legal issue that must be decided in both Price cases.
U.S. Commodity Futures Trading Commission. On January 9, 2003, we received a subpoena from the U.S. Commodity Futures Trading Commission (CFTC) requesting information regarding certain trading by energy and power marketing firms and information provided by us to energy industry publications in connection with the CFTC’s industry wide investigation of trading and trade reporting practices of power and natural gas trading companies. We ceased providing such information to energy industry publications in 2002. Since receipt of the subpoena, we have been conducting an internal review relating to our reporting of natural gas trading information to energy industry publications. In addition, we have produced documents and other information to the CFTC. We continue to provide additional information to the CFTC in response to supplemental requests. On October 3, 2003, we announced that, in the course of providing information to the CFTC, we had learned that some information furnished by us to industry publications was inaccurate. We cannot determine if the inaccurate information had any impact on the price indices published, but we intend to continue to cooperate with the CFTC and continue our internal review. At the present time, we cannot determine the outcome of our ongoing review or the impact on us of the CFTC’s continuing investigation.
Item 2. Changes in Securities and Use of Proceeds
Not Applicable.
Item 3. Defaults Upon Senior Securities
Item 4. Submission of Matters to Vote of Security Holders
Item 5. Other Information
51
Item 6. Exhibits and Reports on Form 8-K
Exhibits
The following exhibits are filed as part of this Quarterly Report on Form 10-Q:
Exhibit Description
Reports on Form 8-K
We filed the following Current Reports on Form 8-K during the quarter ended September 30, 2003.
July 31, 2003 – Furnished the Company’s results of operations for the quarter ended June 30, 2003.
August 4, 2003 – Announced that the Company had entered into a new transaction agreement with Westar Industries, Inc., a wholly-owned subsidiary of Westar Energy, Inc.
August 5, 2003 – Announced that Westar Energy, Inc. and its wholly-owned subsidiary, Westar Industries, Inc., priced a secondary offering of 9.5 million shares of ONEOK, Inc. common stock at a public offering price of $19.00 per share.
August 19, 2003 – Announced that the Company’s Kansas Gas Service Company division negotiated a $45 million stipulated settlement agreement with the staff of the Kansas Corporation Commission, Citizens’ Utility Ratepayer Board and all interveners in its rate case.
September 18, 2003 – Announced that the Company’s board of directors approved a one-cent increase in the quarterly dividend to 18 cents per share of ONEOK common stock.
September 19, 2003 – Announced that the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries is subject to a “blackout period,” as defined by Regulation BTR (Blackout Trading Restriction), in connection with the quarterly payment of dividends by the Company on its shares of common stock.
September 22, 2003 – Announced that the Company had renewed its $850 million, 364-day credit agreement.
52
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Registrant
Date: November 5, 2003
By:
/s/ Jim Kneale
Jim Kneale
Senior Vice President, Treasurer and
Chief Financial Officer
(Principal Financial Officer)
53