UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the quarterly period ended June 30, 2004
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 August 2, 2004, the Company had 103,047,219 shares of common stock outstanding.
QUARTERLY REPORT ON FORM 10-Q
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.
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Part I - FINANCIAL INFORMATION
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
Six Months Ended
June 30,
(Unaudited)
Revenues
Operating revenues, excluding energy trading revenues
Energy trading revenues, net
Cost of gas
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 before Income Taxes
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
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
Dividends per share of Common Stock
See accompanying Notes to Consolidated Financial Statements.
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CONSOLIDATED BALANCE SHEETS
Assets
Current Assets
Cash and cash equivalents
Trade accounts and notes receivable, net
Materials and supplies
Gas in storage
Assets from price risk management activities (Note D)
Deposits
Other current assets
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 (Note F)
Prepaid pensions
Investments and other
Total Deferred Charges and Other Assets
Total Assets
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Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt
Notes payable
Accounts payable
Dividends payable
Accrued taxes
Accrued interest
Customers’ deposits
Unrecovered purchased gas costs
Liabilities from price risk management activities (Note D)
Deferred income taxes
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
Total Liabilities
Commitments and Contingencies (Note J)
Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 106,012,637 shares and outstanding 102,976,466 shares at June 30, 2004; issued 98,194,674 shares and outstanding 95,194,666 shares at December 31, 2003
Paid in capital
Unearned compensation
Accumulated other comprehensive loss (Note G)
Retained earnings
Treasury stock, at cost: 3,036,171 shares at June 30, 2004 and 3,000,008 shares at December 31, 2003
Total Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating Activities
Income from continuing operations
Gain on sale of assets
Income 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
Regulatory assets
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
Other investing activities
Cash Used in Continuing Operations
Cash Used in Investing Activities
Financing Activities
Payments of notes payable, net
Change in bank overdraft
Issuance of debt
Termination of interest rate swaps
Payment of debt issuance costs
Payment of debt
Purchase of Series A Convertible Preferred Stock
Issuance of common stock
Issuance (receipt) of treasury stock, net
Dividends paid
Cash Provided by (Used in) Financing Activities
Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
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CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
CommonStock
Issued
December 31, 2003
Net income
Other comprehensive income (loss)
Total comprehensive income
Receipts of restricted stock
Common stock offering
Stock issuance pursuant to various plans
Offering costs
Stock-based employee compensation expense
Common stock dividends (Note H)
June 30, 2004
See accompanying Notes to the Consolidated Financial Statements.
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(Continued)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 months and six months ended June 30, 2004, 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, 2003.
The Company’s accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, except as follows.
Critical Accounting Policies and Estimates
Pension and Postretirement Employee Benefits - In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) as guidance on how employers should account for provisions of the recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). The Company adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-1), which was adopted by the Company in the first quarter of 2004. See Note I.
Significant Accounting Policies
Common Stock Options and Awards - 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 of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123) to all options and awards granted prior to January 1, 2003.
Net income, as reported
Add: Stock based compensation included in net income, net of related tax effects
Deduct: Total stock based compensation expense determined under fair value based method for all awards, net of related tax effects
Pro forma net income
Earnings per share:
Basic - as reported
Basic - pro forma
Diluted - as reported
Diluted - pro forma
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Related Party Transactions - From time to time and in the normal course of business, the Company:
The table below shows the purchase and sales transactions with the related parties. The purchase and sale transactions are conducted under substantially the same terms as comparable third-party transactions.
Frontier
Williford Companies
Production Property - In July 2004, the FASB proposed FASB Staff Position No. 142-b, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities” (FSP FAS 142-b) to clarify that oil and gas-producing properties are excluded from the requirements in Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”. The comment deadline is August 17, 2004. The Company continues to classify the cost of oil and gas mineral rights as property, plant and equipment on the balance sheet, which is consistent with proposed FSP FAS 142-b.
Reclassifications - Certain amounts in the consolidated financial statements, primarily related to current and noncurrent deferred taxes, have been reclassified to conform to the 2004 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.
In May 2004, the Company sold its investment in natural gas distribution operations located in Mexico for approximately $2 million and recorded a pre-tax gain of $1.6 million which is included in other income in the Other segment.
On March 1, 2004, the Company sold certain natural gas transmission and gathering pipelines and compression facilities for approximately $13 million. As a result of the sale, the Company recorded a pre-tax gain of $6.9 million, which is included in other income in the Transportation and Storage segment.
In January 2003, the Company sold a portion of its Production segment (the component). 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.
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The amounts of revenue, costs and income taxes reported in discontinued operations are as follows.
Natural gas sales
Oil sales
Other revenues
Net revenues
Operating costs
Operating income
Income from discontinued component
Gain on sale of discontinued component, net of tax of $20.7 million
Accounting Treatment - The Company accounts 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 at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, the Company accounts for changes in fair value of the derivative instrument as they occur. 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 is 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 risk management objectives, strategies for undertaking various hedge transactions and 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 hedging relationships, both at the inception of the hedge and on an ongoing basis.
In July 2003, the Emerging Issues Task Force (EITF) of the FASB 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. The Company has continued to present the financial results of all energy trading contracts on a net basis.
At the beginning of the third quarter, the Company completed a reorganization of its Marketing and Trading segment and renewed its focus on the physical marketing and storage business. The Company separated the management and operations of its physical marketing, retail marketing and trading activities and began accounting separately for the different types of revenue sources among these activities. As a result of this reorganization, the Company is evaluating the accounting treatment related to the presentation of revenues for the different types of activities to determine which amounts should be reported on a gross or net
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basis under the guidance in EITF 03-11. The Company expects that a portion of these activities will be presented on a gross basis beginning with the third quarter of 2004. Reporting of these transactions on a gross basis will not impact operating income but will increase revenues and cost of gas.
Fair Value Hedges
The Marketing and Trading segment uses basis swaps to hedge the fair value of certain transportation commitments. At June 30, 2004, net price risk management assets include $8.7 million to recognize the fair value of the Marketing and Trading segment’s derivatives that are designated as fair value hedging instruments. The ineffectiveness related to these hedges was a loss of approximately $0.4 million and $1.4 million for the three and six months ended June 30, 2004, respectively. This amount is included as a reduction in operating revenues.
The Company is subject to the risk of fluctuations 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 2004, the Company terminated $670 million of its interest rate swap agreements to lock in savings and received $91.8 million, which includes $8.9 million of interest rate savings previously recorded. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed-rate, long-term debt. The net proceeds received upon termination of the interest rate swaps was $81.9 million, after reduction for ineffectiveness and unpaid interest. During 2004, $3.2 million in interest expense savings was recognized and the remaining amount of $78.7 million will be recognized in the income statement over the remaining term of the debt instruments originally hedged. Consequently, the savings in interest expense will be recognized over the following periods:
2004
2005
2006
2007
2008
Thereafter
The Company has entered into new swap agreements to replace the terminated agreements. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both the three and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. At June 30, 2004, the Company recorded a $40.7 million net liability to recognize the interest rate swaps at fair value. Long-term debt was also decreased by $40.7 million to recognize the change in the fair value of the related hedged liability.
The change in the fair value of the related hedged liability and the terminated swaps resulted in $38.8 million which is included in long-term debt at June 30, 2004.
Cash Flow Hedges
The Marketing and Trading segment uses futures and swaps to hedge the cash flows associated with its natural gas. Accumulated other comprehensive income (loss) at June 30, 2004, includes losses of approximately $24.2 million, net of tax, related to these hedges that will be realized within the next seven months. The offsetting gains will be recorded when the physical delivery of the hedged item occurs. When gas inventory is sold, net gains and losses are reclassified out of accumulated other comprehensive income to energy trading revenues, net. Ineffectiveness related to these cash flow hedges was a loss of approximately $2.0 million and $3.1 million for the three and six months ended June 30, 2004, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive income during the six months ended June 30, 2004, due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur.
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 and oil. Accumulated other comprehensive income (loss) at June 30, 2004, includes losses of approximately $8.2 million, net of tax, for the production hedges that will be realized in the income statement within the next 18 months.
The Gathering and Processing segment periodically enters into derivative instruments to minimize the risk associated with natural gas price volatility related to the Company’s natural gas and NGL sales. Accumulated other comprehensive income (loss) at June
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30, 2004 includes income of approximately $0.1 million, net of tax, for gathering and processing hedges entered into during the second quarter of 2004 that will be realized in the income statement within the next six months.
The Company’s regulated businesses also use derivative instruments from time to time. Gains or losses associated with these derivative instruments are included in and recoverable through the monthly purchased gas adjustment. At June 30, 2004, Kansas Gas Service Company (KGS) had derivative instruments in place to hedge the cost of natural gas purchases for 3.1 Bcf of natural gas, representing part of KGS’ gas purchase requirements for the 2004/2005 winter heating months based on normal weather conditions. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly purchased gas adjustment.
The following table is a summary of the 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
Service lines
Regulatory assets, net
On January 30, 2004, the Oklahoma Corporation Commission (OCC) approved Oklahoma Natural Gas Company’s (ONG) request 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 efforts to protect pipelines from corrosion. ONG also sought to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The order allows rate relief of $17.7 million annually with $10.7 million as interim and subject to refund until a final determination at the Company’s next general rate case. ONG has committed to filing for a general rate review no later than January 31, 2005. Approximately $7.0 million annually is considered final and not subject to refund. With the approval of ONG’s request, the Company began amortizing the deferred costs associated with these OCC directives over an eighteen month period. At June 30, 2004, the Company had approximately $4.0 million remaining to be amortized compared to $6.0 million at December 31, 2003. These deferred costs are included in the captions “Service lines” and “Other” in the regulatory assets table above.
ONG’s current estimate of future rate relief is substantially in excess of the refund threshold of $10.7 million. The Company believes that any refund obligation is remote and, accordingly, it has not recorded a reserve. The Company will continue to monitor the regulatory environment to determine any changes in its estimated future rate relief. Should its analysis indicate a potential refund liability, the Company will record a reserve for this obligation.
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The following table reflects the changes in the carrying amount of goodwill for the periods indicated.
Total consolidated
The 2004 adjustment to goodwill resulted from the sale of certain natural gas transmission and gathering pipelines and compression facilities on March 1, 2004. The 2003 adjustments to goodwill resulted from the preliminary purchase price allocation of the Texas assets acquired in January 2003.
The Company completed its annual analysis of goodwill for impairment as of January 1, 2004 and there was no impairment indicated.
The tables below give an overview of comprehensive income for the periods indicated.
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments
Unrealized holding gains arising during the period
Realized losses in net income
Other comprehensive income (loss) before taxes
Income tax benefit (provision) on other comprehensive loss
Comprehensive income
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Unrealized holding gains (losses) arising during the period
Accumulated other comprehensive income (loss) reflected in the consolidated balance sheet at June 30, 2004, includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.
Common Stock - The Company uses newly issued shares 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 June 30, 2004, the Company issued 339,688 shares for a total of $7.2 million. During the six months ended June 30, 2004, the Company issued 664,888 shares for a total of $14.5 million. The Company also uses newly issued shares to meet the purchase requirements generated by the Dividend Reinvestment Plan and the Long-Term Incentive Plan.
2004 Common Stock Offering - During the first quarter of 2004, the Company sold 6.9 million shares of its common stock to an underwriter at $21.93 per share, resulting in proceeds to the Company, before expenses, of $151.3 million.
Dividends - Quarterly dividends paid on the Company’s common stock for shareholders of record during the three and six months ended June 30, 2004, were $0.21 per share and $0.40 per share, respectively. In May 2004, the Company’s board of directors announced an increase in the quarterly dividend on the Company’s common stock to $0.23 per share payable in the third quarter of 2004.
The table below provides the components of net periodic benefit cost (income).
Pension Benefits
Three Months EndedJune 30,
Components of Net Periodic Benefit Cost (Income)
Service cost
Interest cost
Expected return on assets
Amortization of unrecognized net asset at adoption
Amortization of unrecognized prior service cost
Amortization of loss
Net periodic benefit income
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Postretirement Benefits
Net periodic benefit cost
Contributions - For the six months ended June 30, 2004, $1.8 million and $6.8 million of contributions had been made for the pension plan and other postretirement benefit plan, respectively. The Company presently anticipates its total 2004 contributions to be $4.8 million for the pension plan and $13.4 million for the other postretirement benefit plan.
Other Postretirement Benefits Changes - In May 2004, the FASB issued FSP FAS 106-2 as guidance on how employers should account for provisions of the recently enacted Medicare Reform Act. The Company adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded FSP FAS 106-1, which was adopted by the Company in the first quarter of 2004. The Medicare Reform Act allows employers who sponsor a postretirement health care plan that provides a prescription drug benefit to receive a subsidy for the cost of providing that drug benefit. In order for employers to receive the subsidy payment under the Medicare Reform Act, the value of the offered prescription drug plan must be at least actuarially equivalent to the standard prescription drug coverage provided under Medicare Part D. Due to the Company’s lower deductibles and better coverage of drug costs, the Company believes that its plan is of greater value than Medicare Part D and will meet the actuarially equivalent definitions. The three months ended June 30, 2004, was the first time the Company could record a benefit related to the Medicare Reform Act, since a September 30 measurement date is used for this plan. The reduction in the accumulated postretirement benefit obligation related to benefits attributed to past service was $18.1 million. The amortization for the actuarial experience gain as a component of the net amortization was $0.4 million for both the three and six months ended June 30, 2004. The reduction in current period service cost due to the subsidy was $0.2 million for both the three and six months ended June 30, 2004. The resulting reduction in interest cost on the accumulated postretirement benefit obligation was $0.3 million for both the three and six months ended June 30, 2004. The Company believes that its plan will continue to provide drug benefits that are at least actuarially equivalent to Medicare Part D, that its plan will continue to be the primary plan for the Company’s retirees and that the Company will receive the subsidy. The Company does not expect that the Medicare Reform Act will have a significant effect on the Company’s retirees’ participation in its postretirement benefit plan.
Environmental - The Company is subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose the Company to fines, penalties and/or interruptions in operations that could be material to the results of the Company’s operations. If an accidental leak or spill of hazardous materials occurs from the Company’s lines or facilities, in the process of transporting natural gas, or at any facilities that the Company owns, operates or otherwise uses, the Company could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect the Company’s results of operations and cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at the Company’s facilities. The Company cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to the Company. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on the Company’s business, financial condition and results of operations.
The Company owns or retains legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas. These sites contain potentially harmful materials that 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 work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. The Company has commenced active remediation on
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three sites with regulatory closure achieved at two of these locations, and has begun assessment at the remaining sites. The site situations are not common and the Company has no previous experience with similar remediation efforts. The Company has completed some analysis of the remaining nine sites, but is unable to accurately estimate individual or aggregate costs that may be required to satisfy the remedial obligations.
The Company’s preliminary review of similar cleanup efforts at former manufactured gas sites reveals that costs can range from $100,000 to $10 million per site. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties, to which the Company may be entitled. At this time, the Company has not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and the Company is not recovering any environmental amounts in rates. The cost to remediate the two sites, which have achieved regulatory closure, totaled approximately $800,000. Total remedial costs for each of the remaining sites are expected to exceed $400,000 per site, but there is no assurance that costs to investigate and remediate the remaining sites will not be significantly higher. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed the Company’s current estimates, additional expenses could be recorded. Such amounts 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.
The Company’s expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations and there have been no material effects upon earnings during 2004 related to compliance with environmental regulations.
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 a civil penalty against the Company, based on alleged violations of several KDHE regulations. On April 5, 2004, the Company and the KDHE entered into a Consent Order in which the Company paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. In addition, the Consent Order requires the Company to conduct an environmental remediation and a geoengineering study. The Company believes there are no material adverse effects resulting from the Consent Order.
Two 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, and in the vicinity of, the Yaggy facility in January 2001. These class action lawsuits claim that the explosions were caused by the release of natural gas from the Company’s operations. In addition to the two pending class action matters, there are four currently pending lawsuits that have been filed against the Company or subsidiaries seeking recovery for various claims related to the Yaggy incident, including property damage, personal injury, loss of business and, in some instances, punitive damage. In February 2004, a jury awarded the plaintiffs in one lawsuit $1.7 million in actual damages. In April 2004, the judge awarded punitive damages in the amount of $5.25 million. The Company has filed its notice of appeal of the jury verdict and the punitive damage award. The Company is vigorously defending these matters and, although no assurances can be given, believes its legal reserves and insurance coverage are adequate and that the ultimate resolution of these matters will not have a material adverse effect on the Company’s financial position or results of operations.
U.S. Commodity Futures Trading Commission - On April 14, 2004, the Company received a subpoena from the U.S. Commodity Futures Trading Commission (CFTC) requesting information in connection with the CFTC’s industry wide investigation relating to “Activities Affecting the Price of Natural Gas in the Fall of 2003”. The CFTC specifically requested information related to reporting of natural gas storage information to the Energy Information Agency during the time period of October 31, 2003—January 2, 2004. The Company cooperated fully with the CFTC’s request and has furnished the requested information. At the present time the Company cannot determine whether the CFTC’s industry wide investigation will have any adverse impact on the Company.
The Company and its wholly owned subsidiary, ONEOK Energy Marketing and Trading Company, L.P., have been named as two of the defendants in a class action lawsuit filed in the United States District Court for the Southern District of New York brought on behalf of persons who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. Although the Company agreed to a civil monetary penalty with the CFTC in that matter, it cannot guarantee other additional legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not arise. However, the Company plans to vigorously defend any claims related to this issue and does not expect this matter to have a material adverse effect on the Company’s consolidated results of operations, financial condition or liquidity.
Labor Negotiations - On July 1, 2004, KGS and the United Steelworkers of America Locals 12561, 13417, and 14228, the Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the
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United States and Canada Local 781 and the International Union of Operating Engineers Local 126 labor unions agreed upon a five-year contract expiring June 30, 2009. Approximately 475 KGS employees are members of these three labor unions, comprising approximately 41 percent of the KGS workforce. The parties agreed to a three percent wage increase retroactive to June 1, 2004 and an increase for each of the next four years as follows:
Currently, the Company has no ongoing labor negotiations.
Other - The Company is a party to other litigation matters and claims including environmental matters, 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.
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, 2003, except for those changes discussed in Note A. Intersegment sales are recorded on the same basis as sales to unaffiliated customers. 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.
The following tables set forth certain selected financial information for the Company’s six operating segments for the periods indicated.
Three Months Ended June 30, 2004
Sales to unaffiliated customers
Intersegment sales
Total Revenues
Depreciation, depletion and amortization
Operating income (loss)
(a) - Intersegment sales for Marketing and Trading were $114.3 million for the three months ended June 30, 2004.
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Three Months Ended June 30, 2003
(a) - Intersegment sales for Marketing and Trading were $111.0 million for the three months ended June 30, 2003.
Six Months Ended June 30, 2004
Total assets
(a) - Intersegment sales for Marketing and Trading were $327.4 million for the six months ended June 30, 2004.
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Six Months Ended June 30, 2003
Cumulative effect of changes in accounting principles, net of tax
(a) - Intersegment sales for Marketing and Trading were $308.5 million for the six months ended June 30, 2003.
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 paid (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
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Property, plant and equipment
Current assets
Current liabilities
Regulatory assets and goodwill
Other assets
Deferred credits
Cash paid for acquisitions
The Company computes earnings per common share (EPS) as described in Note S of the Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.
The following tables set forth the computations of the basic and diluted EPS from continuing operations for the periods indicated.
Basic EPS from continuing operations
Income from continuing operations available for common stock
Effect of other dilutive securities:
Mandatory convertible units
Options and other dilutive securities
Diluted EPS from continuing operations
Income from continuing operations available for common stock and common stock equivalents
Series D Convertible Preferred Stock dividends
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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
Further dilution from applying the “two-class” method
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
There were 37,902 and 145,474 option shares excluded from the calculation of diluted EPS for the three months ended June 30, 2004 and 2003, respectively, since their inclusion would be antidilutive for each period. For the six months ended June 30, 2004 and 2003, there were 20,713 and 216,709 option shares, respectively, excluded from the calculation of diluted EPS since their inclusion would be antidilutive for each period.
During 2003, the Company issued mandatory convertible equity units. These mandatory convertible units have a dilutive effect on EPS if the average stock price for the most recent 20 trading days exceeds $20.63 per share. For the three months ended June 30, 2004, the applicable average stock price was $21.47 which resulted in 0.8 million dilutive units and reduced diluted EPS by less than one cent. For the six months ended June 30, 2004, the applicable average stock price was $22.02 which resulted in 1.2 million dilutive units and reduced diluted EPS by approximately $0.01 per share.
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, was 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
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million, which is reflected as a dividend on the Series A Convertible Preferred Stock in the above EPS calculation for the six months ended June 30, 2003.
The Company’s revolving 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 facility includes a term-out option, which allows the Company 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 June 30, 2004, the Company was in compliance with all covenants.
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Executive Summary - In May, our board of directors announced another increase in our quarterly common stock dividend, the third increase this year. Since January 1, 2004, our quarterly dividend has increased from 18 to 23 cents per common share, an increase of 28 percent.
In August, we increased our earnings guidance for 2004 by six cents, to a range of $2.18 to $2.24 per share. The impact of higher prices for natural gas liquids compared to natural gas on keep whole contracts as well as higher prices in general for natural gas and natural gas liquids has had a positive effect on our Gathering and Processing segment. As a result, operating income for this segment in 2004 is expected to exceed 2003 by $36 million. For the six months ended June 30, 2004, operating income for this segment exceeded the same period in 2003 by $24 million. Our continuing effort to amend keep whole contracts and modify plant operations has had a positive effect in this part of our business.
Conversely, we expect our Marketing and Trading segment to be below last year, earning approximately $155 million compared to $197 million in 2003. Although we continue to generate strong earnings from our physical business, trading revenues are expected to decrease due primarily to reduced volatility in prices and weather as well as decreases in inter-regional price spreads.
At the beginning of the third quarter, we completed a reorganization of our Marketing and Trading segment and renewed our focus on our physical marketing and storage business, adding three new local distribution company (LDC) customers and two new large industrial customers. We separated the management and operations of our physical marketing, retail marketing and trading activities and began accounting separately for the different types of revenue sources among these activities.
In July 2004, our Marketing and Trading segment entered into a multi-year agreement to sell gas to the natural gas distributor for the city of Chicago. Based on current New York Mercantile Exchange (NYMEX) prices, gas revenues provided under this agreement are expected to range between $300 million and $575 million over the term of the agreement.
The acquisition of the natural gas and oil properties in Texas during 2003 has positively impacted the Production segment in the current year as we anticipated.
With our stable earnings base, we continue to perform well.
Acquisitions and Divestitures - In May 2004, we sold our investment in natural gas distribution operations located in Mexico for approximately $2 million and recorded a pre-tax gain of $1.6 million, which is included in other income in the Other segment.
On March 1, 2004, we sold certain natural gas transmission and gathering pipelines and compression facilities for approximately $13 million. As a result of the sale, we recorded a pre-tax gain of $6.9 million, which is included in other income in our Transportation and Storage segment.
Regulatory - On January 30, 2004, the Oklahoma Corporation Commission (OCC) issued an order allowing Oklahoma Natural Gas Company (ONG) annual rate relief of $17.7 million in order to recover expenses related to its investment in service lines and cathodic protection, an increased level of uncollectible revenues, and a return on ONG’s service lines and gas in storage investment. The Commission’s order also approved a modified distribution main extension policy and authorized ONG to defer expected homeland security costs. The order authorized the new rates to be in effect for a maximum of 18 months and categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at ONG’s next general rate case. Approximately $7.0 million annually is considered final and not subject to refund. ONG has committed to filing for a general rate review no later than January 31, 2005.
Our current estimate of the future rate relief is substantially in excess of the refund threshold of $10.7 million. We believe any refund obligation is remote and, accordingly, have not recorded a reserve. We will continue to monitor the regulatory environment to determine any changes in our estimated future rate relief. Should our analysis indicate a potential refund liability, we will record a reserve for the obligation.
Impact of New Accounting Standards - In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) as guidance on how employers should account for provisions of the recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). We adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS
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106-1), which we adopted in the first quarter of 2004. The Medicare Reform Act allows employers who sponsor a postretirement health care plan that provides a prescription drug benefit to receive a subsidy for the cost of providing that drug benefit. In order for employers to receive the subsidy payment under the Medicare Reform Act, the value of the offered prescription drug plan must be at least actuarially equivalent to the standard prescription drug coverage provided under Medicare Part D. Due to our lower deductibles and better coverage of drug costs, we believe that our plan is of greater value than Medicare Part D and will meet the actuarially equivalent definitions. The three months ended June 30, 2004, was the first time we could record a benefit from Medicare Reform Act, since a September 30 measurement date is used for this plan. The reduction in the accumulated postretirement benefit obligation related to benefits attributed to past service was $18.1 million. The amortization for the actuarial experience gain as a component of the net amortization was $0.4 million for both the three and six months ended June 30, 2004. The reduction in current period service cost due to the subsidy was $0.2 million for both the three and six months ended June 30, 2004. The resulting reduction in interest cost on the accumulated postretirement benefit obligation was $0.3 million for both the three and six months ended June 30, 2004. We believe that our plan will continue to provide drug benefits that are actuarially equivalent to Medicare Part D, that our plan will continue to be the primary plan for our retirees and that we will receive the subsidy. We do not expect that the Medicare Reform Act will have a significant effect on our retirees’ participation in our postretirement benefit plan.
Energy Trading Derivatives and Risk Management Activities - We engage in wholesale marketing and trading, price risk management activities and asset optimization services. In providing asset optimization services, we partner with other utilities to provide risk management functions on their behalf. We account for derivative instruments utilized in connection with these activities under the fair value basis of accounting in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133) as amended by Statement of Financial Accounting Standards No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133” (Statement 137), No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (Statement 138) and No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement 149). We were not impacted by Statement 149.
Under Statement 133, entities are required to record all derivative instruments at fair value. A number of assumptions are considered in the determination of fair value. Our derivatives are primarily concentrated in markets where quoted prices exist. Transactions are also executed in markets for which market prices may exist but the market may be relatively inactive thereby resulting in limited price transparency that requires management’s subjectivity in estimating fair values. Other factors impacting our estimates of fair value include volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. Refer to the table on page 45 for amounts in our portfolio at June 30, 2004 that were determined by prices actively quoted, prices provided by other external sources, and prices derived from other sources. The gain or loss from changes in fair value is recorded in the period of the change. The volatility of commodity prices may have a significant impact on the gain or loss in any given period. For more information on fair value sensitivity and a discussion of the market risk of pricing changes, see Item 3, Quantitative and Qualitative Disclosures About Market Risk.
Energy-related contracts that are not accounted for pursuant to Statement 133 are no longer carried at fair value, but are accounted for on an accrual basis as executory contracts. Energy trading inventories carried under storage agreements are no longer carried at fair value, but are carried at the lower of cost or market. Changes to the accounting for existing contracts as a result of the rescission of Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10) were 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 $141.8 million.
Regulation - Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, Kansas Corporation Commission (KCC), Railroad Commission of Texas (RRC) and various municipalities in Texas. Certain of our other transportation activities are subject to regulation by the Federal Energy Regulatory Commission (FERC). ONG, Kansas Gas Service Company (KGS), Texas Gas Service Company (TGS) and portions of the Transportation and Storage segment follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). During the rate-making 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. Accordingly, actions of the regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred would be recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations becomes no longer subject to
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the provision of Statement 71, a write-off of regulatory assets and stranded costs may be required. At June 30, 2004, our regulatory assets totaled $203.9 million.
Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually based on Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value. If the fair value is less than the book value, an impairment is indicated and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations associated with the goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, an impairment charge is recorded. See Note F of the Notes to Consolidated Financial Statements in this Form 10-Q.
We assess our long-lived assets for impairment based on Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
Examples of long-lived asset impairment indicators include:
Pension and Postretirement Employee Benefits - We have a defined pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. Our actuarial consultant, in calculating the expense and liability related to these plans, uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. Assumptions used in determining the projected benefit obligations and the costs can change from period to period which could result in material changes in the costs and liabilities we recognize. See Note I of the Notes to Consolidated Financial Statements in this Form 10-Q.
Contingencies - Our accounting for contingencies covers a variety of business activities including contingencies for potentially uncollectible receivables, and legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”. We base our estimates on currently available facts and our projections of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.
For further discussion of our accounting policies, see Note A of Notes to the Consolidated Financial Statements in this Form 10-Q.
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Consolidated Operations
The following table sets forth certain selected consolidated financial information for the periods indicated.
Financial Results
Discontinued operations, net of taxes (Note C)
Cumulative effect of a change in accounting principle, net of tax
Operating Results - Changes in commodity prices can have a significant impact on our earnings, particularly in our Gathering and Processing segment. Volatility in prices, such as we experienced in the first half of 2003, provides the opportunity for increased margins in our Marketing and Trading segment. Net revenues decreased for the three and six months ended June 30, 2004 compared to the same periods in 2003 primarily due to reduced volatility in natural gas prices partially offset by increases in our Distribution, Production and Gathering and Processing segments due to rate relief, higher volumes sold and market conditions, respectively.
Consolidated operating costs remained relatively stable for the three months ended June 30, 2004 compared to the same period in 2003. Consolidated operating costs increased for the six months ended June 30, 2004 compared to the same period in 2003, primarily due to:
Depreciation, depletion and amortization increased for the three and six months ended June 30, 2004 compared to the same periods in 2003, primarily due to:
In order to consolidate the three customer service systems in our Distribution segment and provide better customer service, we are implementing a new customer service system. In June 2004, the system was installed in Texas. Installation will follow in Kansas and Oklahoma within the next year. We have implemented control processes and performed extensive testing on this system. However, as with any significant system conversion, there are inherent risks and uncertainties that could negatively impact us.
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The following tables show the components of other income and other expense for the three and six months ended June 30, 2004 and 2003.
Gains on sale of property
Partnership income
Interest income
Benefit plan income (expense)
Litigation expenses and claims, net
Donations, civic, and governmental
In 2002, we sold our claims related to the Enron bankruptcy. In the first quarter of 2004, we were required to repurchase a portion of those claims resulting in an expense of approximately $1.8 million related to the decrease in value of the claims.
More information regarding our results of operations is provided in the discussion of each segment’s results. The discontinued component is included in our Production segment discussion and the cumulative effect of a change in accounting principle is included in our Marketing and Trading segment’s financial results.
Overview - Our Production segment owns, develops and produces natural gas and oil reserves in Oklahoma and Texas. We focus on development activities rather than exploratory drilling.
As a result of our strategy to grow through acquisitions and developmental drilling, the number of wells we operate increases as we grow our producing reserves. In our role as operator, we control operating decisions that impact production volumes and lifting costs, which are costs incurred to extract the natural gas and oil. We continually focus on reducing finding costs and minimizing production costs.
Acquisitionand Divestiture - The following acquisition and divestiture are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:
Development Activities - For the six months ended June 30, 2004, we had the following results:
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For the six months ended June 30, 2003, we had the following results:
Selected Financial and Operating Information - The following tables set forth certain financial and operating information for our Production segment for the periods indicated.
Other income (expense), net
Cumulative effect of change in accounting principle, net of tax
Operating Information
Proved reserves (a)
Continuing operations
Gas (MMcf)
Oil (MBbls)
Discontinued component
Average realized price (c)
Gas ($/Mcf)
Oil ($/Bbls)
Capital expenditures (Thousands of dollars)
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Operating Results - Natural gas and crude oil sales increased for the three and six months ended June 30, 2004 compared to the same periods in 2003 due to:
Our Texas properties produced 2.2 Bcf and 4.8 Bcf of natural gas during the three and six months ended June 30, 2004, respectively. Oil production from these properties was 32,000 Bbls and 67,000 Bbls for the same periods.
Average natural gas prices before hedges were:
Other revenues increased for the three and six months ended June 30, 2004 as a result of the flow line fees and revenues from our Texas flow line system which we purchased in December 2003.
Operating costs increased for the three months ended June 30, 2004 compared to the same period in 2003 primarily due to a $1.8 million increase in lease operating expenses related to the acquisition of the Texas properties.
For the six months ended June 30, 2004 compared to the same period in 2003, the Texas acquisition led to the following increases in operating costs:
The increases in depreciation, depletion and amortization for the three and six-month periods were also primarily due to the Texas acquisition.
The Production segment added 6.5 Bcfe of net natural gas and oil reserves for the six months ended June 30, 2004. This included 2.4 Bcfe of proved developed reserves, comprised of 0.4 Bcfe of proved developed producing reserves and 2.0 Bcfe of proved developed non-producing reserves.
Discontinued Component - Income from the discontinued component includes only one month of production in 2003 before the properties were sold.
Capital Expenditures - Capital expenditures primarily relate to our developmental drilling program. Production from existing wells naturally declines over time and additional drilling for existing wells is necessary to maintain or enhance production from existing reserves.
Risk Management - The volatility of energy prices has a significant impact on the profitability of this segment. We utilized derivative instruments for the three and six months ended June 30, 2004 and 2003, in order to hedge anticipated sales of natural gas and oil production. The realized financial impact of the derivative transactions is included in net revenues. For the remainder of 2004, we have hedged approximately 95 percent of our anticipated natural gas production at an average net price at the wellhead of $5.50 per Mcf, and approximately 100 percent of our anticipated oil production at a fixed NYMEX price of $30.35 per Bbl. Currently, we have hedges on 20 MMcf per day of our 2005 natural gas production at a net wellhead price of $5.68 per Mcf. We have also hedged an additional 10 MMcf per day for the first quarter of 2005 at a net wellhead price of $6.12 per Mcf.
Overview- Our Gathering and Processing segment is engaged in the gathering, processing and marketing of natural gas and the fractionation (separation), storage and marketing of natural gas liquids (NGLs) primarily in Texas, Oklahoma and Kansas. We have processing capacity of approximately 1.9 Bcf/d, of which approximately 0.1 Bcf/d is currently idle. We own approximately 13,800 miles of gathering pipelines that supply gas to our processing plants.
The gathering and processing operation includes the gathering of natural gas production from oil and gas wells and the processing of this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed stream. This stream is then separated by a distillation process into component products (ethane, propane, isobutane, normal butane and natural gasoline)
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by third party and company-owned fractionation facilities. The component products can then be stored, transported and marketed to a diverse customer base of end users.
We generally gather and process gas under three types of contracts. The following table sets forth our contract mix on a volumetric basis for the periods indicated.
Three Months Ended
Contract Type
Fee
Percent of Proceeds
Keep Whole
Characteristics of the contract types are explained below.
We have been successful in amending contracts covering about 18 percent of the volume associated with our keep whole contracts to allow us to charge conditioning fees for processing when the keep whole spread is negative. This amendment helps mitigate the impact of unfavorable keep whole spreads between the two commodities by effectively converting a keep whole contract to a fee contract during periods of negative keep whole spreads. Our effort to add this conditioning language began in 2002 and remains a strategy that we continue to execute today. We are also continuing our strategy of restructuring any unprofitable gas purchase and gathering contracts.
Additionally, we are able to modify plant operations to take advantage of market conditions. By changing the temperatures and pressures at which the gas is processed, we can produce more of the specific commodities that have the most favorable price spread or prices. These strategies are intended to decrease the volatility of the net revenues generated by this segment.
We are exposed to volume risk from both a competitive and a production standpoint. We continue to see declines in the fields that feed our gathering and processing operations and the possibility exists that declines may outpace development from new drilling. The factors that typically affect our ability to compete are the fees charged under the contract, pressures maintained on the gathering systems, location of the gathering systems relative to our competitors, efficiency and reliability of operations and the delivery capabilities that exist at each plant location.
Acquisition - The following acquisition is described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:
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Selected Financial and Operating Information - 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
Cost of sales
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)
Conway OPIS composite NGL price ($/gal) (based on our NGL product mix)
Average NYMEX crude oil price ($/Bbl)
Average natural gas price ($/MMBtu) (mid-continent region)
Operating Results - Net revenues for the three months ended June 30, 2004 increased compared to the same period in 2003 for the following reasons:
Net revenues for the six months ended June 30, 2004 increased compared to the same period in 2003 primarily due to higher NGL and condensate prices.
Improved contractual terms for gas gathering and processing resulting from our continued efforts to restructure unprofitable gas purchase and gathering contracts and favorable keep whole spreads contributed to the increase in net revenues for both the three and six-month periods in 2004 compared to the same periods in 2003.
Increases for both the three and six-month periods were partially offset by lower volumes gathered and processed as a result of natural field declines, bypassing of certain non-processable gas at our plants and the termination of low margin gas purchase and gathering agreements.
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Decreased gas sales and cost of sales for the six-month period primarily resulted from the decrease in natural gas prices. Natural gas sales volumes also decreased while NGL volumes produced increased because market conditions favored NGL production in the first quarter of 2004 while contrasting market conditions favored gas sales in the first quarter of 2003.
Operating costs remain in line with management expectations and were slightly lower than in 2003 for both the three and six-month periods.
Depreciation, depletion and amortization increased for the three months ended June 30, 2004 compared to the same period in 2003 primarily due to the properties acquired and our normal capital expenditure program.
Risk Management - We used derivative instruments during the three and six months ended June 30, 2004 and 2003 to minimize risk associated with natural gas price volatility. For the six months ended June 30, 2004 we used derivative instruments to minimize the risk associated with our natural gas and NGL sales. The realized financial impact of the derivative transactions is included in our operating income. For the remainder of 2004, we have hedged approximately 50 percent of our equity condensate sales at an average NYMEX price of $38.38 per Bbl. We have also pre-sold for the remainder of 2004, approximately 50 percent of certain equity natural gas liquids at a weighted average price of $0.62 per gallon.
Overview - Our Transportation and Storage segment operates our intrastate natural gas transmission pipelines, natural gas storage and nonprocessable gas gathering facilities. We also provide interstate transportation service under Section 311(a) of the Natural Gas Policy Act. 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. We have significant supply and market connections to 68 pipelines, 34 processing plants and seven producing fields.
We operate approximately 5,500 miles of gathering and intrastate transmission pipelines in Oklahoma, Kansas and Texas where we are regulated by the OCC, KCC, and RRC, respectively. We have a peak transportation capacity of 2.9 Bcf per day. The majority of our revenues are derived from services provided to affiliates. We serve local distribution companies, large industrial companies, power generation facilities and marketing companies. We compete directly with other interstate and intrastate pipelines and storage facilities. Competition for transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Factors that affect competition are location, natural gas prices, fees for services and quality of service provided.
Our business is affected by the economy, price volatility and weather. Transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand. Volatility in the natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage.
Acquisition and Divestitures - The following acquisition is described on page 25:
The following acquisition and divestiture are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:
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Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for the 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 - Net revenues showed little change for the three and six months ended June 30, 2004 compared to the same periods in 2003.
For the three and six months ended June 30, 2004, net revenues were impacted by the following:
The increase in other income, net for the six months ended June 30, 2004 compared to the same period in 2003 includes the gain on the sale of the Texas assets of $6.9 million, offset by litigation costs.
Overview - Our Distribution segment provides natural gas distribution services in Kansas, Oklahoma and Texas. Operations in Kansas are conducted through KGS, which serves residential, commercial, industrial, transportation and wholesale customers. Operations in Oklahoma are conducted through ONG, which serves residential, commercial, industrial and transportation customers. Operations in Texas are conducted through TGS, which serves residential, commercial, industrial, public authority and transportation customers. Our Distribution segment provides gas service to approximately 71 percent, 86 percent and 14 percent of the distribution markets 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. TGS’ rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the RRC.
Gas sales to residential and commercial customers are seasonal, as a substantial portion of gas is used principally for heating. Accordingly, the volume of gas sales is consistently higher during the heating season (November through March) than in the other months of the year.
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Acquisitions - The following acquisitions are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:
Selected Financial Information - The following table sets forth certain selected financial information for the Distribution segment for the periods indicated.
Gross margin
Transportation revenues
Operating Results - The Distribution segment’s operating results are primarily impacted by the number of customers, usage and the ability to establish delivery rates that provide an authorized rate of return on our investment and cost of service. Gas costs are passed through to distribution customers based on the actual cost of gas purchased by the respective distribution division.
Substantial swings in gas sales can occur from year to year without impacting our gross margin since most factors that affect gas sales also affect cost of gas by an equivalent amount. The decrease in gross margin for the three months ended June 30, 2004 compared to the same period in 2003 is primarily attributable to:
The increase in gross margin for the six months ended June 30, 2004 compared to the same period in 2003 is primarily attributable to:
The $16.5 million increase in KGS’ gross margin is a result of an order issued by the KCC approving $45 million annually in rate relief. ONG’s new rate schedule, which added $8.3 million to gross margin in the six months ended June 30, 2004, is part of $17.7 million in rate relief approved by an order from the OCC.
The increase in transportation revenues for the three and six months ended June 30, 2004 is primarily due to the acquisitions of the distribution system at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the
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Rio Grande Valley region in Texas in August 2003. Additionally, lower thresholds to qualify for transportation rates in Oklahoma have contributed to the increase, as certain commercial and industrial customers have converted to transportation rates.
Operating costs increased for the three months ended June 30, 2004 compared to the same period in 2003 primarily due to:
These increases in operating costs were partially offset by decreased bad debt expense of $1.8 million.
Operating costs increased for the six months ended June 30, 2004 compared to the same periods in 2003 primarily due to:
Depreciation, depletion and amortization increased for the three and six months ended June 30, 2004 compared to the same period in 2003 primarily due to:
Selected Operating Data - The following table sets forth certain operating information for our Distribution segment for the periods indicated.
Average Number of Customers
Customers per employee
Volumes (MMcf)
Residential
Commercial
Industrial
Wholesale
Public Authority
Total volumes sold
Transportation
Total volumes delivered
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Margin
Total margin
Residential and commercial volumes decreased for the three and six months ended June 30, 2004 compared to the same periods in 2003 due to:
Industrial volumes decreased for the three and six months ended June 30, 2004 compared to the same periods in 2003 due to:
Wholesale sales, 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 increased for the three and six months ended June 30, 2004 compared to the same periods in 2003 as fewer volumes were required to meet the needs of KGS’ residential, commercial, and industrial customers resulting in greater volumes available for wholesale customers.
Public authority volumes reflect volumes used by state agencies and school districts serviced by TGS.
Transportation volumes increased for the three and six months ended June 30, 2004 compared to the same periods in 2003 primarily due to:
Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and periodically upgrade facilities to assure safe, reliable, and efficient operations. Our capital expenditure program included $8.2 million and $6.0 million for new business development for the three months ended June 30, 2004 and 2003, respectively, and $17.0 million and $11.9 million for new business development for the six months ended June 30, 2004 and 2003, respectively.
Regulatory Initiatives
Oklahoma- On January 30, 2004, the OCC issued an order allowing ONG an annual rate relief of $17.7 million in order to recover expenses related to its investment in service lines and cathodic protection, an increased level of uncollectible revenues, and a return on ONG’s service lines and gas in storage investment. The Commission’s order also approved a modified distribution main extension policy and authorized ONG to defer expected homeland security costs. The order authorized the new rates to be in effect for a maximum of 18 months and categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at ONG’s next general rate case. Approximately $7.0 million annually is considered final and not subject to refund. ONG has committed to filing for a general rate review no later than January 31, 2005.
Our current estimate of the future rate relief is substantially in excess of the refund threshold of $10.7 million. We believe any refund obligation is remote and, accordingly, have not recorded a reserve. We will continue to monitor the regulatory environment to determine any changes in our estimated future rate relief and, should our analysis indicate a potential refund liability, we will record a reserve for the obligation.
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Kansas - On September 17, 2003, the KCC issued an order approving $45 million in rate relief 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, we estimate that operating income will increase by approximately $29.6 million annually.
Texas - On November 12, 2003, TGS filed an appeal with the RRC based on the denial of proposed rate filing by the cities of Port Neches, Nederland and Groves, Texas. On July 22, 2004, the RRC approved approximately $0.9 million in annual revenue relief. The rates were implemented in May 2003 and were subject to refund prior to the RRC approval.
General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.
Overview - Our Marketing and Trading segment primarily purchases, stores, transports, markets, and trades natural gas in the retail sector in our core distribution area and the wholesale sector throughout most of the United States. We have a large storage and transport position, primarily in the mid-continent region of the United States, with total transportation capacity of 1.3 Bcf/d. With total cyclical storage capacity of 84 Bcf, withdrawal capability of 2.4 Bcf/d and injection capability of 1.6 Bcf/d spread across 19 different facilities, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. Due to seasonality of supply and demand balances, earnings will be significantly higher during the winter period than the summer period. We recently extended our marketing and trading operations into Canada by leasing storage and pipeline capacity. Our current Canadian operations bring gas supply from Western Canada into the upper Midwest with recent activity to supply customers in the Northeast.
We continue to enhance our strategy of customer-focus by providing reliable service during peak demand periods, through the use of our storage and transportation capacity. The physical and financial energy services we provide to our customers help them better execute their commodity-procurement and asset-management strategies.
In July 2004, we entered into a multi-year agreement to sell gas to the natural gas distributor for the city of Chicago. Based on current NYMEX prices, gas revenues provided under this agreement are expected to range between $300 million and $575 million over the term of the agreement.
Power - Our 300-megawatt peak electric power generating plant is located in Oklahoma adjacent to one of our natural gas storage facilities and is configured to supply electric power during peak demand periods. This plant allows us to capture the “spark spread premium,” which is the value added by converting natural gas to electricity, during peak demand periods. Because of seasonal demands for electricity for summer cooling, the demands on our power plant are more volatile in the summer months. In October 2003, we signed a tolling arrangement with a third party for its power plant in Big Springs, Texas, which is connected to our corporate-owned gas transmission system. The agreement, which expires in December 2005, allows us to sell the steam and power generated from the Electric Reliability Council of Texas (ERCOT). This agreement increases our owned or contracted power capacity from 300 to 512 megawatts.
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Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for the Marketing and Trading segment for the periods indicated.
Power sales
Cost of sales and fuel
Natural gas marketed (MMcf)
Natural gas gross margin ($/Mcf)
Electricity marketed (MMwh)
Physically settled volumes (MMcf) (a)
Operating Results - Energy trading revenues decreased for the three months ended June 30, 2004 compared to the same period in 2003. The decrease resulted from:
These decreases were partially offset by continued customer expansion and favorable contract extensions.
We have also increased our storage capacity resulting in increased storage expense which is included in energy trading revenues.
Power margins decreased due to comparatively weaker spark spreads in the Southwest Power Pool and ERCOT, while overall sales and purchases increased due to our Big Springs tolling agreement signed late in the fourth quarter of 2003.
Net revenues decreased for the six months ended June 30, 2004, compared to the same period in 2003 due to lower natural gas price volatility and inter-regional basis spreads. Lower natural gas price volatility reduced revenue associated with our storage capacity and lower inter-regional basis spreads reduced our 2004 transportation margins compared to 2003.
Weaker spark spreads in the Southwest Power Pool and ERCOT were responsible for reducing net revenues from power sales for the six months ended June 30, 2004 compared to the same period in 2003. The decrease in natural gas price volatility reduced the revenue generated from our natural gas option portfolio and the weaker spark spreads reduced revenue associated with our Spring Creek peaking electric power plant and Big Springs tolling agreement.
Natural gas sales volumes increased for the three months ended June 30, 2004 compared to the same period in 2003 due to expanded Canadian and retail operations.
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The natural gas storage inventory level at June 30, 2004 was 58.9 Bcf compared to 48.5 Bcf at June 30, 2003.
Operating costs remained relatively stable for the three months ended June 30, 2004 compared to the same period in 2003.
Operating costs increased for the six months ended June 30, 2004 compared to same period in 2003 primarily due to:
These increases in operating costs were offset by decreased employee costs of $0.5 million.
At the beginning of the third quarter, we completed a reorganization of our Marketing and Trading segment and renewed our focus on our physical marketing and storage business, adding three new LDC customers and two new large industrial customers. We separated the management and operations of our physical marketing, retail marketing and trading activities and began accounting separately for the different types of revenue sources among these activities. As a result of this reorganization, we are evaluating the accounting treatment related to the presentation of revenues for the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in 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). We expect that a portion of these activities representing our non-trading revenues will be presented on a gross basis beginning with the third quarter of 2004. Reporting of these transactions on a gross basis will not impact operating income but will increase revenues and cost of gas.
Liquidity and Capital Resources
General - Part of our strategy is to grow through acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and bank lines of credit, and issuance of debt and equity in the capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources for liquidity and capital resource needs on both a short and long-term basis. We have no material guarantees of debt or other commitments to unaffiliated parties. During 2003 and through the first half of 2004, our capital expenditures were financed through operating cash flows and short and long-term debt. Capital expenditures for 2004 are expected to be in the range of $270 million to $280 million compared to $215 million in 2003.
Financing - 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.
Credit Rating - 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 assessing 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 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. We expect the revolving credit facility to be renewed upon expiration.
Our energy marketing and trading business relies heavily upon the investment grade rating of our senior unsecured long-term debt to satisfy credit requirements with most of our counterparties. If our credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At June 30, 2004, the amount we could be required to fund the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements is approximately $39.9 million. A decline in our credit rating below investment grade may also significantly impact other business segments.
We have reviewed our commercial paper agreement, trust indentures, building leases, equipment leases, marketing, trading and risk contracts and other various contracts which may be subject to rating triggers and no such triggers were identified. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our
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credit rating. The revolving credit agreement contains a provision that would cause the cost to borrow funds to increase based on the amount borrowed under this agreement if our credit rating is negatively adjusted. The credit agreement also contains a default provision based on a material adverse change. An adverse rating change is not defined as a default or material adverse change. We currently do not have any funds borrowed under this credit agreement.
Commodity Prices - 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, 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.
Pension Plan - Our pension plan is currently overfunded resulting in an asset reported on our balance sheet. Due to the previous poor performance of the equity market and lower interest rates at our plan valuation date of September 30, 2003, 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 2004 from $4.4 million to $1.9 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.
Cash Flow Analysis
Operating Cash Flows - Operating cash flows increased by $173.9 million for the six months ended June 30, 2004 compared to the same period in 2003, despite a decrease in income from continuing operations. The primary impact on operating cash flows resulted from changes in working capital, much of which relates to decreases in gas in storage. Weather can have a significant impact on gas inventory levels. Warmer weather at the end of 2003 resulted in higher than normal inventory levels. During the first quarter of 2004, the withdrawal of inventory from storage reduced our gas inventory levels and positively impacted our operating cash flows for the six-month period in 2004. During the six months ended June 30, 2003, we injected higher levels of inventory into storage, which negatively impacted our operating cash flows.
Decreases in deposits, or margin requirements, by our Marketing and Trading segment had a positive impact on our 2004 operating cash flows. Changes in other assets and liabilities reflect expenditures or recognition of liabilities for insurance costs, salaries, taxes other than income, and other similar items. Period-to-period fluctuations in these accounts reflect changes in the timing of payments or recognition of liabilities and are not directly impacted by seasonal factors.
Investing Cash Flows - Proceeds from the sale of certain natural gas transmission and gathering pipelines, compression assets and investments totaled $15 million.
Acquisitions in the first quarter of 2003 represent the cash purchase of our Texas distribution 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 $281 million was received in 2003 and the remaining amount was received in the prior year.
Financing Cash Flows - The following table sets forth our capitalization structure for the periods indicated.
Long-term debt
Equity
Debt (including Notes payable)
At June 30, 2004, we had $1.9 billion of long-term debt outstanding, including current maturities. As of June 30, 2004, we could have issued $2.0 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements. During the first quarter, we paid off $600 million in notes payable using cash generated from operating activities and proceeds from our February 2004 equity offering. During the second quarter of 2004, we incurred $40 million of notes payable used in the ordinary course of business.
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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 50 percent long-term debt and 50 percent equity at June 30, 2004. 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 47 percent long-term debt and 53 percent equity at June 30, 2004.
Our $850 million revolving credit facility was renewed September 22, 2003. The current 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 June 30, 2004, we had $40 million in commercial paper outstanding and approximately $19.0 million in temporary investments.
We use newly issued shares to meet the purchase requirements generated by participants in our Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries. All participant purchases under this plan are voluntary. During the three months ended June 30, 2004, we issued 339,688 shares for a total of $7.2 million. During the six months ended June 30, 2004, we issued 664,888 shares for a total of $14.5 million. We also use newly issued shares to meet the purchase requirements generated by our Dividend Reinvestment Plan and our Long-Term Incentive Plan.
During the first quarter of 2004, we sold 6.9 million shares of our common stock to an underwriter at $21.93 per share, resulting in proceeds to us, before expenses, of $151.3 million.
We terminated $670 million of our interest rate swap agreements in the first quarter of 2004 to lock-in savings and generate a positive cash flow of $91.8 million, which included $8.9 million of interest savings previously recognized. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed rate long-term debt. The proceeds received upon termination of the interest rate swaps, net of amounts previously recognized, will be recognized in the income statement over the term of the debt instruments originally hedged.
During the first quarter of 2003, we issued a total of 16.1 million equity units. 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 number of shares that we will issue for each stock purchase contract issued as part of the equity units will be determined based on our average closing price over the 20-trading day period ending on the third trading day prior to February 16, 2006. If this average closing price:
Labor Negotiations - On July 1, 2004, KGS and the United Steelworkers of America Locals 12561, 13417, and 14228, the Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada Local 781 and the International Union of Operating Engineers Local 126 labor unions agreed upon a five-year contract expiring June 30, 2009. Approximately 475 of our KGS employees are members of these three labor unions, comprising approximately 41 percent of our KGS workforce. The parties agreed to a three percent wage increase retroactive to June 1, 2004 and an increase for each of the next four years as follows:
Currently, we have no ongoing labor negotiations.
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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:
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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.
Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, 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 June 30, 2004, KGS had derivative instruments in place to hedge the cost of gas purchases for 3.1 Bcf of gas, representing part of KGS’ gas purchase requirements for the 2004/2005 winter heating months based on normal weather conditions. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly purchased gas adjustment.
TGS may use derivative instruments to mitigate the volatility of gas costs to protect its customers in the city of El Paso. At June 30, 2004, TGS had no derivative instruments in place to hedge the cost of gas purchases. 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 contacts 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)
Total
FairValue
Prices actively quoted (2)
Prices provided by other external sources (3)
Prices derived from quotes, other external sources and other assumptions (4)
For further discussion of trading activities and assumptions used in our trading activities, see the Critical Accounting Policies in Note A and Accounting Treatment in Note D of the Notes to Consolidated Financial Statements included in this Form 10-Q.
Interest Rate and Currency Risk - At June 30, 2004, the interest rate on approximately 59 percent of our long-term debt was fixed after considering the impact of interest rate swaps.
During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements to lock in savings and received $91.8 million, which includes $8.9 million of interest rate savings previously recorded. These interest rate swaps were previously
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initiated as a strategy to hedge the fair value of fixed rate, long-term debt. The net proceeds received upon termination of the interest rate swaps were $81.9 million, after reduction for ineffectiveness and unpaid interest. During 2004, $3.2 million in interest expense savings was recognized and the remaining amount of $78.7 million will be recognized in the income statement over the remaining term of the debt instruments originally hedged. Consequently, the remaining savings in interest expense will be recognized over the following periods:
We have entered into new swap agreements to replace the terminated agreements. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both the three and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. At June 30, 2004, we recorded a $40.7 million net liability to recognize the interest rate swaps at fair value. Long-term debt was also decreased by $40.7 million to recognize the change in the fair value of the related hedged liability.
The change in the fair value of the related hedged liability and the terminated swaps resulted in $38.8 million included in long-term debt at June 30, 2004.
Total savings from the interest rate swaps was $16.5 million for the first half of 2004. The swaps are expected to generate the following savings for the remainder of the year:
Total swap savings for 2004 are expected to be $30 million which is an increase over the savings of $24.4 million and $20.6 million in 2003 and 2002, respectively.
A 100 basis point move in the LIBOR rate on all of our outstanding long-term debt would change annual interest expense by approximately $7.4 million before taxes. If interest rates changed significantly, we would take action to manage the exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.
With our Marketing and Trading segment’s expansion into Canada, we are subject to currency exposure. Our objective with respect to currency risk is to reduce the exposure due to exchange-rate fluctuations. We use physical forward transactions, which result in an actual two-way flow of currency on the settlement date since we exchange U.S. dollars for Canadian dollars with another party. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with the change in fair value are recorded in net revenues. At June 30, 2004, our exposure to risk from currency translation was not material.
Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $2.7 million and $1.7 million at June 30, 2004 and 2003, 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 market volatility and changes in the portfolio during the quarter.
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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 on Form 10-Q. 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 on Form 10-Q 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 on Form 10-Q, 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 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.
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 on Form 10-Q. 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 is 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.
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
United States ex rel. Jack J. Grynberg v. ONEOK, Inc., et al., 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. The parties have completed discovery regarding whether Mr. Gryberg has met the unique jurisdictional prerequisites for maintaining an action under the False Claims act. On June 4, 2004, we joined with the numerous other defendants in filing a motion to dismiss contending that Mr. Grynberg has not satisfied such unique jurisdictional prerequisites to maintain this action. A hearing on this motion has not been set by the court.
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In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Department of Health and Environment. On April 11, 2004, we paid to the Kansas Department of Health and Environment (“KDHE”) the seventy-nine thousand dollars ($79,000) we were ordered to pay to reimburse the KDHE for its cost related to the investigation of the Yaggy gas storage facility incident. Additionally, remediation that we are required to perform pursuant to our consent order with the KDHE is ongoing. For additional discussion of this matter, see Note J of the Notes to Consolidated Financial Statements included in this Form 10-Q.
Loyd Smith, et al v. Kansas Gas Service Company, Inc., ONEOK, Inc., Western Resources, Inc., Mid Continent Market Center, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., and ONEOK Gas Transportation, L.L.C., Case No. 01-C-0029, in the District Court of Reno County, Kansas, and Gilley et al. v. Kansas Gas Service Company, Western Resources, Inc., ONEOK, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., ONEOK Gas Transportation L.L.C. and Mid-Continent Market Center, Inc., Case No. 01-C-0057, in the District Court of Reno County, Kansas. On June 14, 2004, the court transferred venue for trial of these cases from Reno County to Wyandotte County, Kansas. The court has set trial for August 24, 2004.
The following table sets forth information relating to our recent purchases of equity securities.
Issuer Purchases of Equity Securities
Period
April 1-30, 2004
May 1-31, 2004
June 1-30, 2004
Not Applicable.
We held our 2004 annual meeting of shareholders on May 20, 2004. At this meeting, the individuals set forth below in Class A were elected by a plurality vote to our board of directors for a term of three years, and the individual set forth below in Class B was elected by a plurality vote to our board of directors for a term of one year:
William M. Bell
(Class A)
Julie H. Edwards
Pattye L. Moore
J.D. Scott
James C. Day
(Class B)
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The individuals set forth below are the members of our board of directors whose term of office as a director continued after the meeting:
Class B
Class C
(Term ending 2005)
(Term ending 2006)
David L. Kyle
William L. Ford
Bert H. Mackie
Douglas Ann Newsom
Mollie B. Williford
Gary D. Parker
Eduardo A. Rodriguez
In addition, at the annual meeting the appointment of KPMG LLP as our independent auditor for the 2004 fiscal year was ratified by our shareholders as follows:
Appointment of KPMG LLP as principal independent auditor
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 June 30, 2004, dated as follows:
April 15, 2004 - Announced that the Company’s board of directors declared a two-cent per share increase in the quarterly dividend to 21 cents per share of ONEOK, Inc. common stock.
April 15, 2004 - Announced that Eduardo A. Rodriquez, Executive Vice President for Legal and Administrative Affairs at Hunt Building Corporation, was elected to the Company’s board of directors.
April 15, 2004 - Announced that the Company had terminated its agreement to purchase the 22.5 percent interest in Gulf Coast Fractionators owned by ConocoPhillips.
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April 26, 2004 - Announced that the Company will present at the AGA Financial Forum in Bonita Springs, Florida on Monday, May 3, 2004, beginning at approximately 2:25 p.m. E.D.T.
April 28, 2004 - Announced that the Company entered into an agreement to sell all the stock of ONEOK Energy International, Inc. and ONEOK International Investments, Inc. to Choahuila Energy, LLC for a sales price of approximately $2 million which was expected to close in early May 2004.
April 28, 2004 - Furnished the Company’s results of operations for the quarter ended March 31, 2004.
May 20, 2004 - Announced that the Company’s board of directors declared a two-cent per share increase in the quarterly dividend to 23 cents per share of ONEOK, Inc. common stock.
June 17, 2004 - Announced that the Company will present at the 2004 Wachovia Securities Nantucket Equity Conference in Nantucket, Massachusetts on Thursday, June 24, 2004, beginning at approximately 10:00 a.m. Central Time.
June 18, 2004 - Announced that the Company’s earnings guidance for 2004 remains in the range of $2.12 to $2.18 per diluted share of common stock, updated segment operating income estimates and provided quarterly earnings per share guidance.
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Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Registrant
Jim Kneale
Senior Vice President, Treasurer andChief Financial Officer(Principal Financial Officer)
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