UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the quarterly period ended March 31, 2005
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 May 2, 2005, the Company had 101,983,630 shares of common stock outstanding.
QUARTERLY REPORT ON FORM 10-Q
Part I.
Item 1.
Item 2.
Item 3.
Item 4.
Part II.
Item 5.
Item 6.
Signature
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
Three Months Ended
March 31,
(Unaudited)
Revenues
Operating revenues, excluding energy trading revenues
Energy trading revenues, net
Total Revenues
Cost of sales and fuel
Net Margin
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
Net Income
Earnings Per Share of Common Stock (Note K)
Earnings per share, basic
Earnings per share, diluted
Average Shares of Common Stock (Thousands)
Basic
Diluted
Dividends Declared 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
Energy marketing and risk management assets (Note B)
Deposits
Deferred income taxes
Other current assets
Total Current Assets
Property, Plant and Equipment
Production
Gathering and Processing
Transportation and Storage
Distribution
Energy Services
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 C)
Goodwill (Note D)
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
Accrued taxes
Accrued interest
Customers’ deposits
Unrecovered purchased gas costs
Energy marketing and risk management liabilities (Note B)
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 H)
Shareholders’ Equity
Common stock, $0.01 par value: authorized 300,000,000 shares; issued 107,437,255 shares and outstanding 102,238,676 shares at March 31, 2005; issued 107,143,722 shares and outstanding 104,106,285 shares at December 31, 2004
Paid in capital
Unearned compensation
Accumulated other comprehensive loss (Note E)
Retained earnings
Treasury stock, at cost: 5,198,579 shares at March 31, 2005 and 3,037,437 shares at December 31, 2004
Total Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating Activities
Net income
Depreciation, depletion, and amortization
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
Energy marketing and risk management assets and liabilities
Other assets and liabilities
Cash Provided by Operating Activities
Investing Activities
Changes in other investments, net
Capital expenditures
Proceeds from sale of property
Other investing activities
Cash Used in Investing Activities
Financing Activities
Borrowing (payments) of notes payable, net
Termination of interest rate swaps
Payment of debt
Purchase of common stock
Issuance of common stock
Dividends paid
Other financing activities
Cash 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, 2004
Other comprehensive income
Total comprehensive income
Repurchase of common stock
Common stock issuance pursuant to various plans
Stock-based employee compensation expense
Common stock dividends - $0.25 per share
March 31, 2005
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(Continued)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and reflect all adjustments which, in our opinion, 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 our business, the results of operations for the three months ended March 31, 2005, 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 our audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2004.
Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2004.
Significant Accounting Policies
Common Stock Options and Awards - In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (Statement 123R). Statement 123R requires companies to expense the fair value of share-based payments. In addition, there are also changes related to the expense calculation for share-based payments. Effective January 1, 2006, we will adopt Statement 123R, and we expect to use the prospective method. We are currently assessing the impact of adopting Statement 123R, but we do not believe it will have a material impact on our financial condition and results of operations, as we have been expensing share-based payments since our adoption of Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure” on January 1, 2003.
The following table sets forth the effect on net income and earnings per share if we had applied the fair-value recognition provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” to all options and awards granted prior to January 1, 2003.
Net income, as reported
Add: Stock option compensation included in net income, net of related tax effects
Deduct: Total stock option 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
Asset Retirement Obligations - In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. We are currently reviewing the applicability of FIN 47 to our operations and its potential impact on our consolidated financial statements.
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Consolidation - The Emerging Issues Task Force (EITF) is currently deliberating EITF Issue No. 04-5, “Investor’s Accounting for an Investment in a Limited Partnership When the Investor Is the Sole General Partner and the Limited Partners Have Certain Rights” (EITF 04-5). Since the changes proposed in EITF 04-5 would result in different guidance in accounting for general partners that are in different industries, the FASB staff is planning to amend SOP 78-9, Accounting for Investments in Real Estate Ventures to be consistent with EITF 04-5. SOP 78-9-a, “Interaction of AICPA Statement of Position 78-9, Accounting for Investments in Real Estate Ventures, and EITF Issue No. 04-5, ‘Investor’s Accounting for an Investment in a Limited Partnership When the Investor Is the Sole General Partner and the Limited Partners Have Certain Rights’” (SOP 78-9-a) will have the presumption that a general partner controls a limited partnership and therefore should consolidate the partnership. This presumption can be overcome if the limited partners have kick-out or substantive participating rights. As a result of this new guidance, we could be required to consolidate Northern Border Partners; however, we will begin to evaluate the impact and transition method if or when SOP 78-9-a and EITF 04-5 are finalized. The anticipated effective date of SOP 78-9-a and EITF 04-5 is January 1, 2006.
Reclassifications - Certain amounts in the consolidated financial statements have been reclassified to conform to the 2005 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.
Accounting Treatment - We account for derivative instruments and hedging activities in accordance with FASB Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), as amended. 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, we account for changes in fair value of the derivative instrument in earnings as they occur. We record these changes in fair value as energy trading revenues, net in our Consolidated Statements of Income. 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 gain or loss 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.
As required by Statement 133, we formally document 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. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.
At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis. We began accounting for the realized revenues and purchase costs of those contracts that result in physical delivery on a gross basis beginning in the third quarter of 2004. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.
Refer to Note D of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2004, for additional discussion.
Fair Value Hedges
During the first quarter of 2005, we terminated $400 million of our interest rate swap agreements and paid a net amount of $19.4 million, which included $20.2 million for the present value of future payments at the time of termination, less $0.8 million for
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interest rate savings through the termination of the swap. During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements, locking in savings of $81.9 million. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for the first quarter of 2005 for all swaps was $2.4 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:
Remainder of 2005
2006
2007
2008
2009
Thereafter
Currently, $340 million of our 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 March 31, 2005, we recorded a net liability of $9.3 million to recognize the interest rate swaps at fair value. Long-term debt was reduced by $9.3 million to recognize the change in the fair value of the related hedged liability.
Our Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges are recorded as cost of sales and fuel. The ineffectiveness related to these hedges was immaterial for the three months ended March 31, 2005 and 2004.
Cash Flow Hedges
Our Energy Services segment uses futures and basis swaps to hedge the cash flows associated with its anticipated purchases and sales of natural gas and cost of fuel used in transportation of gas. Accumulated other comprehensive loss at March 31, 2005, includes net losses of approximately $49.2 million, net of tax, related to these hedges that will be realized within the next 46 months. Over the next 12 months, we will recognize net losses of $51.1 million and we will recognize net gains of $1.9 million thereafter. Our Production segment and our Gathering and Processing segment periodically enter into derivative instruments to hedge the cash flows associated with their exposure to changes in the price of natural gas, natural gas liquids (NGLs) and crude oil. Accumulated other comprehensive loss at March 31, 2005 includes losses of approximately $11.3 million, net of tax, for the production hedges which will be realized in the income statement primarily within the next 12 months. Losses of approximately $4.6 million, net of tax, are included in accumulated other comprehensive loss at March 31, 2005 for the gathering and processing hedges, which will be realized in the income statement within the next nine months.
Our Distribution segment also uses 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 March 31, 2005, our Distribution segment did not have any derivative instruments in place to hedge the cost of natural gas purchases.
Net gains and losses are reclassified out of accumulated other comprehensive loss to operating revenues or cost of sales and fuel when the anticipated purchase or sale occurs. Ineffectiveness related to these cash flow hedges was approximately $0.6 million and $1.1 million for the three months ended March 31, 2005 and 2004, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive loss during the first quarter of 2004 due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur.
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The following table is a summary of regulatory assets, net of amortization, for the periods indicated.
Recoupable take-or-pay
Postretirement costs other than pension
Reacquired debt costs
Deferred taxes
Transition costs
Weather normalization
Pension costs
Ad valorem tax
Service lines
Regulatory assets, net
In January 2004, the Oklahoma Corporation Commission (OCC) approved Oklahoma Natural Gas’ request for recovery of costs related to customers’ service lines, pipeline corrosion control, investment in gas in storage and rising levels of fuel-related bad debts. The OCC’s order also authorized Oklahoma Natural Gas to defer homeland security costs. We are amortizing the deferred costs associated with these OCC directives over an 18-month period. At March 31, 2005, we had approximately $0.7 million remaining to be amortized. These deferred costs are included in the captions “Service lines” and “Other” in the regulatory assets table above.
In September 2003, the Kansas Corporation Commission (KCC) issued an order to Kansas Gas Service which included approval to recover $26.4 million of deferred postretirement and postemployment benefit costs over nine years and made the weather normalization adjustment rider, which had been renewed annually, a permanent component of customer rates.
“Weather normalization” represents the revenue over- or under-recovered through this rider. This amount is deferred as a regulatory asset for a 12-month period. Kansas Gas Service then applies an adjustment to the customers’ bills for 12 months to refund the over-collected revenue or bill the under-collected revenue.
The OCC has authorized Oklahoma Natural Gas’ recovery of the take-or-pay settlement, pension and postretirement benefit costs over periods ranging from 10-20 years.
We amortize reacquired debt costs in accordance with the accounting rules prescribed by the OCC and KCC. These costs were included as a component of interest in the most recent rate filing with the OCC and were included in the rate order issued by the KCC.
The $5.1 million “Ad valorem tax” represents an increase in Kansas Gas Service’s taxes above the amount approved in the September 2003 rate order. Kansas law permits a utility to file a tariff to recover additional ad valorem tax expense incurred above the amount currently recovered in the cost of service rate. This excess amount is recoverable through a surcharge, provided the utility reports the change in taxes to the KCC, on an annual basis. Kansas Gas Service filed the tariff and received approval for recovery from the KCC during the third quarter of 2004.
We completed our annual analysis of goodwill for impairment as of January 1, 2005 and there was no impairment indicated.
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The table below gives an overview of comprehensive income for the periods indicated.
Unrealized losses on derivative instruments
Unrealized holding losses arising during the period
Realized (gains) losses in net income
Other comprehensive loss before taxes
Income tax benefit on other comprehensive loss
Other comprehensive loss
Comprehensive income
Accumulated other comprehensive loss at March 31, 2005 and 2004, primarily includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.
Stock Repurchase Plan - During the first quarter of 2005, we repurchased approximately 2.1 million shares of our common stock pursuant to a plan approved by our Board of Directors on January 20, 2005. This plan allows us to purchase up to a total of 7.5 million shares of our common stock on or before January 20, 2007.
Common Stock - Since September 17, 2004, the Thrift Plan for Employees of ONEOK, Inc. and subsidiaries (the Thrift Plan) has from time to time purchased shares of ONEOK common stock on the open market to meet the purchase requirements generated by participants in the Thrift Plan. Previously, the Thrift Plan used newly issued shares to meet the participants’ purchase requirements. All participant purchases of ONEOK common stock under the Thrift Plan are voluntary. We use newly issued shares to meet the purchase requirements generated by our Dividend Reinvestment Plan and our Long-Term Incentive Plan.
Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2005, were $0.25 per share. In April 2005, our Board of Directors announced an increase in the quarterly dividend of our common stock to $0.28 per share payable in the second quarter of 2005.
The table below provides the components of net periodic benefit cost (income) for our pension and other postretirement benefit plans.
Pension Benefits
Three Months EndedMarch 31,
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 cost (income)
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Contributions - For the three months ended March 31, 2005, $0.1 million and $4.0 million of contributions were made to our pension plan and other postretirement benefit plan, respectively. We presently anticipate our total 2005 contributions to be $1.8 million for the pension plan and $16.1 million for the other postretirement benefit plan.
Environmental - We are 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 us 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 us to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities in the process of transporting natural gas or NGLs or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our 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 our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. 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 our business, financial condition and results of operations.
We own or retain 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 remediation work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. We have commenced active remediation on six sites and have achieved regulatory closure at two of these locations, while active remediation continues on the remaining four sites. We have completed some analysis of the six other sites upon which no active remediation is being conducted. The site situations are not similar. We have no previous experience with similar remediation efforts, and therefore are unable to fully estimate individual or aggregate costs that may be required to satisfy the remedial obligations.
Our 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 we may be entitled. At this time, we have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. Total costs to remediate the two sites, which have achieved regulatory closure, were approximately $700,000. Total remedial costs for each of the remaining sites are expected to exceed $500,000 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 our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.
Our 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 2005 related to compliance with environmental regulations.
Yaggy Facility - In January 2001, our 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 Hutchinson, Kansas. In July 2002, the KDHE issued an administrative order that assessed a civil penalty against us, based on alleged violations of several KDHE regulations. On April 5, 2004, we entered into a Consent Order with the KDHE in which we 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 us to conduct an environmental remediation and a geoengineering study. Based on information currently available to us, we do not believe there are any material adverse effects resulting from the Consent Order.
In February 2004, a jury awarded the plaintiffs $1.7 million in actual damages in a lawsuit involving property damage alleged to relate to the gas explosions and eruptions. In April 2004, the judge in this case awarded punitive damages in the amount of $5.25 million. We have filed an appeal of the jury verdict and the punitive damage award. Based on information currently available to us, we believe our legal reserves and insurance coverage are adequate and that this matter will not have a material adverse effect on us.
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The two class action lawsuits filed against us in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at, and in the vicinity of, our Yaggy facility in January 2001 resulted in jury verdicts in September 2004. The jury awarded the plaintiffs in the residential class $5.0 million in actual damages, and the judge ordered the payment of $2.0 million in attorney fees and $0.6 million in expenses, all of which is covered by insurance. In the other class action relating to business claims, the jury awarded no damages. The jury rejected claims for punitive damages in both cases. We are reviewing our options for appealing the verdict rendered in the residential claimants’ class action along with the attorney fee and expense award.
With the exception of appeals, all litigation regarding our Yaggy facility has been resolved.
Enron - We have repurchased a portion of the Enron Corp. guaranty claim that Enron Corp. and Enron North American Corp. (ENA) sought to avoid in the adversary proceeding. We are now providing the defense of the adversary proceeding for both the portion of the guaranty claim constituting the repurchased claim and also the portion of the guaranty claim previously sold. Based on information currently available to us, we do not expect the adversary proceeding to have a material adverse effect on us.
In addition to the adversary proceeding, Enron Corp. and ENA have filed an objection to portions of the guaranty claim and to portions of the underlying claim against ENA, creating a new contested matter in the Enron Corp. and ENA bankruptcy cases which involve different legal and factual issues than those raised in the adversary proceeding. Enron Corp. and ENA allege in this matter that the guaranty claim and underlying claim against ENA are overstated. The filing of this matter may trigger additional obligations for us to repurchase some of the claims previously sold. Based on the information currently available to us, we do not expect this matter to have a material adverse effect on us.
Other - We are a party to other litigation matters and claims, which are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.
Our business segments and the accounting policies of our business segments are the same as those described in the Footnote N and the Summary of Significant Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2004. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. Our equity method investments do not represent operating segments. We have no single external customer from which we received ten percent or more of our consolidated gross revenues for the periods covered by this report.
As discussed in Note B, at the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and separated the management and operations of our physical marketing, retail marketing and trading activities. We began accounting separately for the different types of revenue earned from these activities, with certain revenues accounted for on a gross rather than a net basis.
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The following tables set forth certain selected financial information for our operating segments for the periods indicated.
Sales to unaffiliated customers
Intersegment sales
Net margin
Operating costs
Operating income
Total assets
March 31, 2004
Intersegment sales (a)
(a) - Intersegment sales for Energy Services were $213.1 million for the three months ended March 31, 2004. These are included in energy trading revenues, net above.
The following table sets forth supplemental information with respect to our cash flow for the periods indicated.
Cash paid (received) during the period
Interest including amounts capitalized
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Cash paid (received) for interest includes swap terminations and ineffectiveness of $20.2 million and $(82.9) million for the three months ended March 31, 2005 and 2004, respectively.
We compute earnings per common share (EPS) as described in Note R of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2004.
The following tables set forth the computations of the basic and diluted EPS for the periods indicated.
Basic EPS
Income available for common stock
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units
Options and other dilutive securities
Income available for common stock and common stock equivalents
There were 11,022 and 23,892 option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2005 and 2004, respectively, since their inclusion would be antidilutive for each period.
In September 2004, we entered into a $1.0 billion five-year credit agreement. The principal amount of the credit facility may be increased by $200 million if requested by us and the corresponding incremental commitments are received from new or existing lenders. The interest rate is a floating rate based at our election on either (i) the higher of prime or one-half of one percent above the Federal Funds Overnight Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings by Moody’s Investors Service and Standard and Poor’s. The credit agreement contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our business, changes in the nature of our business, transactions with affiliates, the use of proceeds, a limit on our debt to capital ratio, a limit on investments in master limited partnerships and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends to ONEOK, Inc. At March 31, 2005, we had no amounts outstanding under this credit agreement.
Other debt agreements to which we are a party contain negative covenants that relate to liens and sale/leaseback transactions. At March 31, 2005, we are in compliance with all covenants.
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Executive Summary - We started off our 2005 year with net income of $107.7 million for the first quarter compared to $105.2 million for the same quarter in 2004. Commodity prices have had a favorable impact, particularly in our Gathering and Processing segment. Higher prices also benefited our Production segment.
The impact of increased shares and dilutive securities outstanding resulted in lower earnings per share of common stock for the quarter compared to the same quarter in 2004. While increased net income added two cents to earnings per diluted share of common stock, the increased number of shares and dilutive securities resulted in dilution of nine cents, six cents of which was due to the mandatory convertible equity units. Diluted earnings per share of common stock was $0.97 for this quarter compared to $1.04 for the same quarter in 2004. Under our stock repurchase program approved in January 2005, we repurchased 2.1 million shares of our common stock during the first quarter of 2005. The plan allows us to repurchase up to 7.5 million shares on or before January 2007.
In January 2005, we filed a rate case in Oklahoma seeking $99.4 million in annual rate relief, or $60.9 million after taxes. By statute, the OCC has 180 days to issue a final order. This would allow us to put the new rates, if approved, into effect prior to the 2005/2006 heating season. The amount requested includes $10.7 million of interim rate relief granted in January 2004.
We have confirmed our previously released guidance of $2.22 to $2.28 for the 2005 year. This guidance does not include earnings from financial trading operations for the remainder of 2005.
We have completed a full quarter since our acquisition of Northern Plains Natural Gas Company (Northern Plains), which owns 82.5 percent of the general partner interest in Northern Border Partners, one of the largest publicly-traded master limited partnerships. This acquisition added $2.5 million to income before taxes for the quarter, which is recorded in other income in the Other segment. We expect this acquisition to serve as a new growth vehicle for us.
On April 21, 2005, our Board of Directors increased our quarterly dividend to $0.28 per share, a 12 percent increase over the $0.25 dividend paid the previous quarter. This is a result of continued evaluation of our dividend payout in relation to both our financial performance and our peer companies.
Regulatory - Several regulatory initiatives positively impacted the earnings and future earnings potential for our Distribution segment. These initiatives are discussed beginning on page 31.
Impact of New Accounting Standards - In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (Statement 123R). Statement 123R requires companies to expense the fair value of share-based payments. In addition, there are also changes related to the expense calculation for share-based payments. Effective January 1, 2006, we will adopt Statement 123R, and we expect to use the prospective method. We are currently assessing the impact of adopting Statement 123R, but we do not believe it will have a material impact on our financial condition and results of operations, as we have been expensing share-based payments since our adoption of Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure” on January 1, 2003.
In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. We are currently reviewing the applicability of FIN 47 to our operations and its potential impact on our consolidated financial statements.
The Emerging Issues Task Force (EITF) is currently deliberating EITF Issue No. 04-5, “Investor’s Accounting for an Investment in a Limited Partnership When the Investor Is the Sole General Partner and the Limited Partners Have Certain Rights” (EITF 04-5). Since the changes proposed in EITF 04-5 would result in different guidance in accounting for general partners that are in different industries, the FASB staff is planning to amend SOP 78-9, Accounting for Investments in Real Estate Ventures to be consistent with EITF 04-5. SOP 78-9-a, “Interaction of AICPA Statement of Position 78-9, Accounting for Investments in Real Estate Ventures, and EITF Issue No. 04-5, ‘Investor’s Accounting for an Investment in a Limited Partnership When the Investor is the Sole General Partner and the Limited Partners Have Certain Rights’” (SOP 78-9-a) will have the presumption that a general partner controls a limited partnership and therefore should consolidate the partnership. This presumption can be overcome if the limited partners have kick-out or substantive participating rights. As a result of this new guidance, we could be required to
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consolidate Northern Border Partners; however we will begin to evaluate the impact and transition method if or when SOP 78-9-a and EITF 04-5 are finalized. The anticipated effective date of SOP 78-9-a and EITF 04-5 is January 1, 2006.
Critical Accounting Policies and Estimates
Derivatives and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading, and risk management activities. We account for derivative instruments utilized in connection with these activities and services 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.
Under Statement 133, entities are required to record derivative instruments at fair value. The fair value of derivative instruments is determined by commodity exchange prices, over-the-counter quotes, 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 38 for amounts in our portfolio at March 31, 2005 that were determined by prices actively quoted, prices provided by other external sources, and prices derived from other sources. The majority of our portfolio’s fair value is based on actual market prices. 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.
Market value changes result in a change in the fair value of our derivative instruments. 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, we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility 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.
To minimize the risk of fluctuations in natural gas, natural gas liquids (NGLs) and crude oil prices, we periodically enter into futures transactions and swaps in order to hedge anticipated sales and purchases of natural gas and crude oil production, fuel requirements and NGL inventories. Interest rate swaps are also used to manage interest rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair value or cash flows. 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 gain or loss on the hedged item attributable to the risk being hedged. 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 ineffectiveness of designated hedges is reported in earnings.
Many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment. Energy-related contracts that are not derivatives pursuant to Statement 133 are accounted for on an accrual basis as executory contracts.
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 each reporting unit with goodwill, as determined in accordance with Statement 142, to the book value of the reporting unit. 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 with 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, we will record an impairment charge. We completed our annual analysis of goodwill for impairment as of January 1, 2005 and there was no impairment indicated. At March 31, 2005, we had $225.2 million of goodwill recorded on our balance sheet.
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.” 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:
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We do not currently anticipate any goodwill or asset impairments to occur within the next year, but if such events were to occur over the long-term, the impact could be significant to our financial condition and results of operations.
Pension and Postretirement Employee Benefits - We have a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. Nonbargaining unit employees hired after December 31, 2004 are not eligible for our defined benefit pension plan; however, they are covered by a profit sharing plan. Nonbargaining unit employees retiring between the ages of 50 and 55 who elect postretirement medical coverage, all nonbargaining unit employees hired on or after January 1, 1999, employees who are members of the International Brotherhood of Electrical Workers hired after June 30, 2003 and gas union employees hired after July 1, 2004 who elect postretirement medical coverage pay 100 percent of the retiree premium for participation in the plan. Additionally, any employees who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits. Our actuarial consultant calculates the expense and liability related to these plans and 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. In determining the projected benefit obligations and the costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize.
During 2004, we recorded net periodic benefit costs of $0.9 million related to our defined benefit pension plan and $25.0 million related to postretirement benefits. We estimate that in 2005 we will record net periodic benefit costs of $13.0 million related to our defined benefit pension plan and $27.4 million related to postretirement benefits. These increases primarily reflect our acquisition of Northern Plains, amendments in benefits payable under our gas union contracts and a change in our assumed discount rate. We will be reimbursed for approximately $2.5 million of this increase by Northern Border Partners for defined benefit pension plan expenses that we incur for them. In determining our estimated expenses for 2005, our actuarial consultant assumed an 8.75 percent expected return on plan assets and a discount rate of 6.0 percent. A decrease in our expected return on plan assets to 8.5 percent would increase our 2005 estimated net periodic benefit costs by approximately $1.5 million for our defined benefit pension plan and would not have a significant impact on our postretirement benefit plan. An increase in our assumed discount rate to 6.5 percent would decrease our 2005 estimated net periodic benefit costs by approximately $4.5 million for our defined benefit pension plan and $1.9 million for our postretirement benefit plan.
See Note G of Notes to Consolidated Financial Statements in this Form 10-Q.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal exposures 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 estimates 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
Operating Results - Changes in commodity prices can have a significant impact on our earnings, particularly in our Gathering and Processing segment and Production segment. Net margin increased for the three months ended March 31, 2005 compared to the same period in 2004 primarily due to:
These increases were partially offset by:
For an explanation of Energy trading revenues, net, see the discussion of our Energy Services segment beginning on page 32.
Consolidated operating costs increased primarily due to increased labor and employee benefit costs.
Depreciation, depletion and amortization increased primarily due to:
The following tables show the components of other income and other expense for the three months ended March 31, 2005 and 2004.
Equity income
Unrealized gain on investment
Interest income
Gains on sale of property
Other Income
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Donations, civic, and governmental
Litigation expense and claims, net
Other Expense
In the first quarter of 2004, we were required to repurchase a portion of the Enron claims we sold in 2002, resulting in an expense related to the decrease in value of the claims. Additionally, in the first quarter of 2004, we accrued amounts related to various other litigation. These amounts are included in litigation expense and claims, net.
More information regarding our results of operations is provided in the discussion of operating results for each of our segments.
Overview - Our Production segment owns, develops and produces natural gas and oil reserves in Oklahoma and Texas. We focus on developmental drilling 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. We typically serve as operator on wells where we have significant ownership interest. In our role as operator, we control operating decisions that impact production volumes and lifting costs, which are the costs incurred to extract natural gas and oil. We continually focus on reducing finding costs, which is the cost per Mcfe of adding proved reserves through drilling, and minimizing production costs.
Development Activities - For the three months ended March 31, 2005, we had the following results:
For the three months ended March 31, 2004, 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.
Natural gas sales
Oil sales
Other revenues
Net revenues
Other income (expense), net
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Operating Information
Proved reserves (a)
Gas (MMcf)
Oil (MBbls)
Average realized price (b)
Gas ($/Mcf)
Oil ($/Bbl)
Capital expenditures (Thousands of dollars)
Operating Results - Net revenues increased for the three months ended March 31, 2005 compared to the same period in 2004 due to:
Operating costs decreased, primarily due to a $1.1 million decrease in overhead costs, mainly attributable to the 2004 transition costs from our Texas property acquisition.
Capital Expenditures - Capital expenditures primarily relate to our developmental drilling program. Production from existing wells naturally declines over time and additional drilling on 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 utilize derivative instruments in order to hedge anticipated sales of natural gas and oil production. The realized financial impact of the derivative transactions is included in net margin.
The following tables set forth our remaining 2005 and 2006 hedging information for our Production segment. For 2006 we have entered into NYMEX-based costless collars to secure a range of prices for a portion of our expected natural gas and oil production.
Nine Months Ending
December 31, 2005
Product
Volumes
Hedged
Basis - AdjustedAverage Price
Natural gas
Texas
Oklahoma
Oil
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Year Ending
December 31, 2006
Texas (a)
Oklahoma (a)
Oil (a)
(a) - Hedged with NYMEX-based costless collars.
See Item 3, Quantitative and Qualitative Disclosures About Market Risk and Note B of the Notes to Consolidated Financial Statements in this Form 10-Q.
Overview- Our Gathering and Processing segment is engaged in the gathering, processing and marketing of natural gas and fractionation, storage and marketing of NGLs primarily in Oklahoma, Kansas and Texas. We have active processing capacity of approximately 1.8 Bcf/d. Our Gathering and Processing segment owns approximately 13,800 miles of gathering pipelines that supply our gas processing plants.
Gathering and processing operations include the gathering of natural gas production from gas and oil wells. Through gathering systems, these volumes are aggregated into sufficient volumes to be processed to remove water vapor, solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed NGL stream. This stream is then separated by a distillation process, referred to as fractionation, into component products (ethane, propane, isobutane, normal butane and natural gasoline) 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. Characteristics of the contract types are as follows.
Additionally, we purchase natural gas at the wellhead under index-based purchase agreements that can be used to supply plant fuel and shrink, with the excess being sold monthly at index-based prices.
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We have been successful in amending contracts covering approximately 27 percent of the volumes associated with our keep whole contracts to allow us to charge conditioning fees for processing when the keep whole spread is negative. This helps mitigate the impact of an unfavorable keep whole spread by effectively converting a keep whole contract to a fee contract during periods of negative keep whole spread. 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 renegotiating any under-performing gas purchase and gathering contracts.
Additionally, we adjust 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 prices or price spread. These strategies are used to improve the net margin generated by this segment.
We are impacted by producer drilling activity, which is sensitive to geological success as well as availability of capital and commodity prices. We are exposed to volume risk from both a competitive and a production standpoint. We continue to see declines in certain fields that supply our gathering and processing operations and the possibility exists that declines may surpass development from new drilling. The factors that typically affect our ability to compete are:
We sell our NGL production and also purchase NGLs from third parties for resale to a diverse base of customers. We have 89 MBbls/d of mid-continent NGL fractionation capacity. We own and operate two NGL storage facilities in Kansas, with a combined storage capacity of 16 MMBbls, which provide both long- and short-term storage services. The storage facilities have truck and rail loading facilities and have direct pipeline interconnects with the key NGL pipelines, NGL storage facilities and refiners in the mid-continent region. The results of our storage operations are impacted by:
The main factors that affect our NGL margins are:
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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
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 ($/Bbl)
Average realized condensate price ($/Bbl)
Average natural gas price ($/MMBtu)(mid-continent region)
Gross processing spread ($/MMBtu)
Operating Results - The increase in net margin for the three months ended March 31, 2005 compared to the same period for 2004 is primarily due to:
The gross processing spread for the first quarter of 2005, which is the relative difference in economic value between NGLs and natural gas on a Btu basis, was considerably higher than the previous five-year average of $1.78. Based on current market conditions, the gross processing spread for the remainder of 2005 is above the previous five-year average. Improved contractual terms for gas gathering and processing resulting from our continued efforts to renegotiate unprofitable gas purchase and gathering contracts continues to positively impact net margin.
Gas sales revenues and volumes increased as a result of the monthly election of certain producers that allows them to convert their contracts from keep whole to either fee or POP, thereby reducing our fuel and shrink make-up requirements and increasing our residue gas available for sale. Additionally, NGL sales decreased due to the termination of several marginal third party purchase contracts.
Higher employee benefits costs contributed to the operating costs increase.
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Risk Management - We use derivative instruments to minimize the risks associated with price volatility. For 2005, we are using a variety of instruments, including physical forward sales, New York Mercantile Exchange (NYMEX) futures, and over-the-counter natural gas basis swaps, to hedge the cash flows for the purchases and sales of natural gas, sales of condensate and sales of NGLs produced by our operations. We use physical forward sales and derivative instruments to secure a certain price for our POP natural gas, condensate and NGL products. The keep whole spread is hedged with a combination of derivative instruments for the purchase of natural gas and derivative instruments and physical forward sales for NGLs. For 2006, we have entered into NYMEX-based costless collars to secure a range of prices for our POP natural gas and condensate products. The realized financial impact of the derivative transactions is included in our operating income in the period that the physical transaction occurs.
The following table sets forth our remaining 2005 and 2006 hedging information for our Gathering and Processing segment.
Volumes Hedged
Average Price
Percent of Proceeds:
Condensate (a)
NGL (b)
Natural gas (c)
Keep Whole:
Gross processing spread (d)
(a) - Hedged with NYMEX-based swaps.
(b) - Hedged with forward sales and swaps.
(c) - Hedged with NYMEX futures and basis swaps.
(d) - Hedged with NYMEX futures, basis swaps and NGL forward sales.
Price
Natural gas (a)
We continue to evaluate market conditions to take advantage of favorable pricing opportunities for our company-owned production associated with the POP contracts, as well as our keep whole quantities.
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 operate approximately 5,600 miles of gathering and intrastate transmission pipelines in Oklahoma, Kansas and Texas where we are regulated by the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), and Texas Railroad Commission (RRC), respectively. We have a peak transportation capacity of 2.9 Bcf/d. The majority of our revenues are derived from services provided to affiliates. We primarily serve LDCs, large industrial companies, irrigation, 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 Federal Energy Regulatory Commission (FERC) and state regulatory
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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, natural gas price volatility and weather. The strength of the economy has a direct relationship on manufacturing and industrial companies and their resulting demand for natural gas. Volatility in the natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage. Transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand.
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 revenues
Volumes transported (MMcf)
Operating results - Net margin decreased slightly for the three months ended March 31, 2005 compared to the same period in 2004 primarily due to $0.5 million of reduced storage revenue related to intra-month business. This decrease was partially offset by higher volumes transported.
Operating costs decreased primarily due to:
The decrease in other income (expense), net, is due to the $6.9 million gain on the sale of the Texas assets, which was partially offset by unrelated litigation costs.
Overview - Our Distribution segment provides natural gas distribution services to approximately 2 million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In Oklahoma and Kansas, we also serve wholesale customers and in Texas, we also serve public authority customers. We provide gas service to approximately 86 percent, 71 percent and 14 percent of the distribution markets of Oklahoma, Kansas and Texas, respectively. Oklahoma Natural Gas and Kansas Gas Service are subject to regulatory oversight by the OCC and KCC, respectively. Texas Gas Service is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Texas Gas Service’s rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the RRC. This segment also includes an interstate gas transportation company, OkTex Pipeline, which is regulated by the FERC.
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Our 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 significantly impacting our gross margin since most factors that affect gas sales also affect cost of gas by an equivalent amount. 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 other months of the year.
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 - Net margin decreased by $6.8 million for the three months ended March 31, 2005 compared to the same period in 2004 primarily due to reduced customer usage as a result of warmer weather. This decrease was partially offset by the following increases in net margin:
A decrease in operating costs resulted from reduced bad debt expense of $2.6 million, offset by increased labor and employee benefit costs of $2.8 million.
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
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Volumes (MMcf)
Residential
Commercial
Industrial
Wholesale
Public Authority
Total volumes sold
Transportation
Total volumes delivered
Margin
Total margin
Residential and commercial volumes decreased due to:
Wholesale sales, also known as “as available” gas sales, represent gas volumes available under contracts that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes increased as fewer volumes were required to meet the needs of residential, commercial, and industrial customers.
Public authority volumes reflect volumes used by state agencies and school districts serviced by Texas Gas Service.
Transportation volumes increased primarily due to Oklahoma Natural Gas’ commercial and industrial customers migrating to new transportation rates and a marketing effort to add small usage transport customers.
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 $9.4 million and $8.8 million for new business development for the three months ended March 31, 2005 and 2004, respectively.
Regulatory Initiatives
Oklahoma - On January 28, 2005, Oklahoma Natural Gas filed a rate case with the OCC requesting annual rate relief of approximately $99.4 million, of which $38.5 million would be paid in additional income taxes. This amount includes $10.7 million of the interim rate relief granted in January 2004 and discussed below. The OCC has 180 days to issue a final order on the rate case. If approved, the new rates will take effect prior to the 2005/2006 heating season.
On January 30, 2004, the OCC issued an order allowing Oklahoma Natural Gas 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 Oklahoma Natural Gas’ service lines and gas in storage investment. The OCC’s order also approved a modified distribution main extension policy and authorized Oklahoma Natural Gas to defer homeland security costs. The order authorized the new rates to be in effect for a maximum of 18 months and categorizes $10.7 million of the annual additional revenues as
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interim and subject to refund until a final determination at Oklahoma Natural Gas’ next general rate case, which was filed on January 28, 2005. We believe any refund obligation is remote and, accordingly, have not recorded a reserve. Approximately $7.0 million annually is considered final and not subject to refund.
Texas - On November 12, 2003, Texas Gas Service filed an appeal with the RRC based on the denial of proposed rate relief by the cities of Port Neches, Nederland and Groves, Texas. In July 2004, the RRC approved approximately $0.9 million in annual revenue relief. On October 7, 2004, Texas Gas Service filed a petition in the District Court of Travis County, Texas seeking judicial review of certain aspects of the ratemaking decisions contained in the RRC’s final order. We expect resolution in 2006.
General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (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 Energy Services segment primarily purchases, stores, transports and markets natural gas in the retail and wholesale sector throughout most of the United States. We have a large leased storage and pipeline capacity position, primarily in the mid-continent region of the United States, with total transportation capacity of 2.0 Bcf/d. With total storage capacity of 87 Bcf, maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.5 Bcf/d spread across 19 different facilities, we have direct access to most supply and market regions of the country coupled with the flexibility to capture volatility in the energy markets. Due to the seasonality of supply and demand balances, earnings will typically be significantly higher during the winter months than the summer months. Our energy services operations extend into Canada through the leasing of storage and pipeline capacity, which allows us to bring gas supply from western Canada into the market areas of the upper midwestern and northeastern parts of the United States. On a smaller scale, we also trade natural gas and power.
We continue to enhance our customer-focused strategy by providing reliable service during peak demand periods through the use of our storage and transportation capacities. The physical and financial energy services we provide help our customers execute their commodity procurement and asset management strategies.
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for the Energy Services segment for the periods indicated.
Energy and power revenues
Natural gas marketed (Bcf)
Natural gas gross margin ($/Mcf)
Electricity marketed (MMwh)
Physically settled volumes (Bcf)
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Operating Results - Net margin decreased for the three months ended March 31, 2005 compared to the same period in 2004 primarily due to:
Operating costs decreased primarily due to lower employee costs.
Natural gas sales volumes increased due to our expanded Canadian operations and additional long term contracts.
Our natural gas in storage at March 31, 2005 was 40 Bcf compared to 33 Bcf at March 31, 2004. At March 31, 2005, our total natural gas storage capacity under lease was 87 Bcf compared to 83 Bcf at March 31, 2004.
Included in net margin is the change in value of our derivative instruments subject to fair value accounting pursuant to Statement 133, which resulted in a gain of $16.8 million and a loss of $2.7 million for 2005 and 2004, respectively.
At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. We separated the management and operations of our wholesale marketing, retail marketing and trading activities and began accounting separately for the different types of revenue earned from these activities. Prior to the third quarter, we managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis.
Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from 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 and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3” (EITF 03-11). For derivative instruments considered held for trading purposes that result in physical delivery, the indicators 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” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.
For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) were used to determine the proper treatment. We began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. Prior periods have not been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.
Marketing and storage activities primarily include physical marketing (purchases and sales) using our firm storage and transportation capacity, including cash flow and fair value hedges and other derivative instruments to manage our risk associated with these activities. The combination of owning supply, controlling strategic assets and risk management services allows us to provide commodity-diverse products and services to our customers such as peaking and load following services. Power activities are also included in the marketing and storage business. Retail marketing includes revenues from providing physical marketing and supply services to residential and small commercial and industrial customers. Financial trading revenues include activities that are generally executed using financially settled derivatives. These activities are normally short term in nature with a focus of capturing short term price volatility. The following table shows these types of margins by activity.
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Three Months
EndedMarch 31,2005
Marketing and storage, gross
Less: Storage and transportation costs
Marketing and storage, net
Retail marketing
Financial trading
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 credit agreements, 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 2004 and 2005, our capital expenditures were financed through operating cash flows and short and long-term debt. Capital expenditures for the first quarter of 2005 were $58 million compared to $49 million for the same period in 2004, exclusive of any acquisitions.
Financing - Financing is provided through our commercial paper program, long-term debt and, as needed, through a credit agreement. 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. We used commercial paper to finance the recent acquisition of Northern Plains.
In September 2004, we entered into a $1.0 billion five-year credit agreement. The principal amount of the credit facility may be increased by $200 million if requested by us and the corresponding incremental commitments are received from new or existing lenders. The interest rate is a floating rate based at our election on either (i) the higher of prime or one-half of one percent above the Federal Funds Overnight Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings by Moody’s Investors Service (Moody’s) and Standard and Poor’s (S&P). The credit agreement contains customary affirmative and negative covenants including covenants relating to liens, investments, fundamental changes in our business, changes in the nature of our business, transactions with affiliates, the use of proceeds, a limit on our debt to capital ratio, a limit on investments in master limited partnerships and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends to ONEOK, Inc. At March 31, 2005, we had no amounts outstanding under this credit agreement.
The total amount of short-term borrowings authorized by our Board of Directors is $1.2 billion. At March 31, 2005, we had $688.5 million in commercial paper outstanding and approximately $35.5 million in cash and temporary investments. We also had $1.5 billion of long-term debt outstanding, including current maturities. As of March 31, 2005, we could have issued $1.9 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements.
The following table sets forth our capitalization structure for the periods indicated.
Long-term debt
Equity
Debt (including Notes payable)
Both S&P and Moody’s 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. S&P 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 44 percent long-term debt and 56 percent equity at
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March 31, 2005. Moody’s 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 40 percent long-term debt and 60 percent equity at March 31, 2005.
We have 16.1 million equity units outstanding at March 31, 2005. Each unit consists of two components, an equity purchase contract and a note (see Notes H and J of Notes to Consolidated Financial Statements in our 2004 Form 10-K for additional information). In November 2005, we will remarket the notes and will put the cash received into a treasury portfolio pledged as collateral against the purchase contracts. This action will have no effect on our liquidity. In February 2006, the purchase contracts are required to be exercised. This will result in our receipt of $402.5 million and the issuance of common shares of stock, the number of which will depend upon the average closing price of our common stock for the 20 trading days prior to the date of issuance. For more information, refer to our Prospectus Supplement dated January 23, 2003.
Currently, we have $848.2 million available under one of our shelf registration statements on Form S-3 for the issuance and sale of shares of our common stock, debt securities, preferred stock, stock purchase contracts and stock purchase units. We also have $402.5 million remaining under another shelf registration statement on Form S-3 to cover the issuance of common stock required upon settlement of the forward purchase contracts that are part of the equity units.
Credit Rating - Our credit ratings are currently a “BBB+” (stable outlook) by S&P and a “Baa1” (stable outlook) by Moody’s. Our credit ratings may be affected by a material change in our financial ratios or a material adverse event affecting our business. The most common criteria for assessment of our credit ratings are the debt to capital ratio, pretax 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 and we could potentially lose access to commercial paper borrowings. 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 a $1.0 billion credit agreement, which expires September 16, 2009.
Our Energy Services segment relies 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 March 31, 2005, the amount we could have been required to fund for the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association agreements is approximately $99.0 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, and 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 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 price in either physical or financial energy contracts may impact our overall liquidity due to the impact the 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 and Postretirement Benefit Plans - We calculate benefit obligations based upon generally accepted actuarial methodologies using the projected benefit obligation (PBO) for pension plans and the accumulated postretirement benefit obligation for other postretirement plans. We use a September 30 measurement date. The benefit obligations are the actuarial present value of all benefits attributed to employee service rendered. The PBO is measured using the pension benefit formula and assumptions as to future compensation levels. A plan’s funded status is calculated as the difference between the benefit obligation and the fair value of plan assets. Our funding policy for the pension plans is to make annual contributions in accordance with regulations under the Internal Revenue Code and in accordance with generally accepted actuarial principles. Contributions made to the pension plan and postretirement benefit plan in 2004 were $6.8 million and $17.2 million, respectively. We presently anticipate our total 2005 contributions to be $1.8 million for the pension plan and $16.1 million for the other postretirement benefit plan. We will be reimbursed approximately $2.5 million by Northern Border Partners for defined benefit pension plan expenses that we incur for them. We believe we have adequate resources to fund our obligations under our pension and postretirement benefit plans.
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Oklahoma Corporation Commission - A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding Oklahoma Natural Gas cases pending before the OCC. The major cases settled were the OCC’s inquiry into our gas cost procurement practices during the winter of 2000/2001, an application seeking relief from improper and excessive purchased gas costs, and enforcement action against Oklahoma Natural Gas, our subsidiaries and affiliated companies. In addition, all of the open inquiries related to the annual audits of Oklahoma Natural Gas’ fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.
The Stipulation has a $33.7 million value to Oklahoma Natural Gas customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all Oklahoma Natural Gas customers in the form of billing credits totaling approximately $9.1 million. In December 2005, a final billing credit will be made to customers. The minimum amount of this credit is estimated to be approximately $2.8 million. Oklahoma Natural Gas replaced certain gas contracts, which reduced gas costs by approximately $13.8 million, due to avoided reservation fees between April 2003 and October 2005. We anticipate additional savings of approximately $8.0 million from the use of storage gas. Any expected savings from the use of storage that are not achieved will be added to the final billing credit scheduled to be provided to customers in December 2005.
Cash Flow Analysis
Operating Cash Flows - Operating cash flows increased by $66.6 million for the three months ended March 31, 2005 compared to the same period in 2004. The increase in operating cash flows was primarily the result of a net decrease in working capital of $337.9 million in 2005 compared to a net decrease in working capital of $274.5 million in 2004. These decreases primarily related to decreases in gas in storage since we have lower inventory levels at March 31 than at December 31 due to withdrawals of inventory from storage. Accounts receivable fluctuates primarily due to sales billed in the last month of the period and collected the first month of the following period. Price changes and volumes sold can have a substantial impact on operating cash flows, which happened in 2005 as a result of our Energy Services segment’s commodity prices and volumes related to accounts receivable being lower at March 31, 2005 than at December 31, 2004.
Investing Cash Flows - Proceeds from the sale of certain natural gas transmission and gathering pipelines and compression assets totaled $13 million for the first quarter 2004. The change in other investments increased in the first quarter of 2005 compared to 2004 due primarily to the February 2005 exchange of 1.5 million Magnum Hunter Resources (MHR) stock purchase warrants with an exercise price of $15 per share for 1.5 million shares of MHR common stock.
Financing Cash Flows - On March 1, 2005, we had $335 million of long-term debt mature. We funded this payment with working capital and the issuance of commercial paper in the short-term market.
During the first quarter of 2005, we paid $63.6 million to repurchase approximately 2.1 million shares of our stock pursuant to a plan approved by our Board of Directors on January 20, 2005. This plan allows us to repurchase up to a total of 7.5 million shares of our common stock on or before January 20, 2007.
We terminated $400 million of our interest rate swap agreements in the first quarter of 2005, which resulted in us paying $19.4 million. This amount included $20.2 million for the present value of future payments at the time of termination, less $0.8 million for interest rate savings through the termination of the swap. The $20.2 million payment has been recorded as a reduction in long-term debt and will be recognized in the income statement over the term of the debt instrument originally hedged.
During the first quarter of 2004, we paid off $600 million in notes payable using cash generated from operating activities and proceeds from our first quarter 2004 equity offering. We also 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. 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.
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 and legal proceedings,
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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 generally identified by words such as “anticipate,” “estimate,” “expect,” “forecast,” “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 forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions, risks and other factors referred to specifically in connection with forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others:
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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, 2004.
The following table provides a detail of our Energy Services segment’s maturity of derivatives based on heating injection and withdrawal periods from April to March. Executory storage and transportation contracts and their related hedges are not included in the following table.
Source of Fair Value (1)
Prices actively quoted (2)
Prices provided by other external sources (3)
Prices derived from quotes, other external sourcesand other assumptions (4)
Total
For further discussion of trading activities and assumptions used in our trading activities, see Accounting Treatment in Note B of the Notes to Consolidated Financial Statements included in this Form 10-Q.
Interest Rate and Currency Risk - At March 31, 2005, the interest rate on approximately 77 percent of our long-term debt was fixed after considering the impact of interest rate swaps.
During the first quarter of 2005, we terminated $400 million of our interest rate swap agreements and paid a net amount of $19.4 million, which included $20.2 million for the present value of future payments at the time of termination, less $0.8 million for interest rate savings through the termination of the swap. During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements, locking in savings of $81.9 million. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for the first quarter of 2005 for all swaps was $2.4 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:
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Currently, $340 million of fixed rate debt is swapped to floating. The floating debt rate is based on both the three and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. At March 31, 2005, we had a net liability of $9.3 million to recognize the interest rate swaps at fair value. Long-term debt was reduced by $9.3 million to recognize the change in fair value of the related hedged liability.
Total savings from the interest rate swaps and amortization of terminated swaps was $3.7 million for the first three months of 2005. The swaps are expected to generate the following savings for the remainder of the year:
Total swap savings for 2005 are expected to be $11.1 million, which is a decrease compared to the savings of $27.6 million in 2004.
A 100 basis point move in the LIBOR rate on all of our outstanding long-term debt would change annual interest expense by approximately $3.4 million before taxes. If interest rates changed significantly, we may have the ability to 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 Energy Services 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 margin. At March 31, 2005, 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 $17.2 million and $7.6 million at March 31, 2005 and 2004, respectively.
The following table details the average, high and low VAR calculations.
Ended
VAR
Average
High
Low
The variations in the VAR data are reflective of market volatility and changes in the portfolio during the quarter.
Quarterly Evaluation of Disclosure Controls and Procedures - We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Securities and Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported, within the time periods specified in the U.S. Securities and Exchange Commission’s (SEC) rules and forms. Under the supervision and with the participation of senior management, including our Chairman and Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Act. Based on this evaluation, our Principal Executive Officer and our Principal Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2005 to ensure the timely disclosure of required information in our periodic SEC filings.
Changes in Internal Controls Over Financial Reporting - We have not made any changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Act) during the quarter ended March 31, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II - OTHER INFORMATION
Samuel P. Legget, et al. v. Duke Energy Corporation et al; Case No. 13847 in the Chancery Court of Tennessee for the Twenty-Fifth Judicial District at Somerville. On March 7, 2005, we, along with all of the other defendants in this matter, filed a Notice of Removal to remove this matter to federal court. On March 27, 2005, Reliant, a co-defendant in this matter, filed a Notice of Tag Along with the Multi-District Panel in Washington, D.C., in an attempt to have this matter combined with currently pending Multi-District litigation matters filed in California. Plaintiffs have filed a motion for remand back to state court.
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 April 11, 2005, the court denied plaintiffs’ motion for a new trial and denied a post trial motion filed by defendants. We are continuing our review of options for appeal of the residential claimants’ class action verdict and subsequent award of attorney fees.
Issuer Purchases of Equity Securities
The following table sets forth information relating to our purchases of equity securities during the three months ended March 31, 2005.
Period
January 1-31, 2005
February 1-28, 2005
March 1-31, 2005
91,746 shares for the period January 1-31, 2005
21,505 shares for the period February 1-28, 2005
42,142 shares for the period March 1-31, 2005
33 shares for the period January 1-31, 2005
61 shares for the period February 1-28, 2005
127 shares for the period March 1-31, 2005
444 shares for the period January 1-31, 2005
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Employee Stock Award Program
Under our Employee Stock Award Program, we issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the per-share closing price of our common stock on the New York Stock Exchange (NYSE) was for the first time at or above $26 per share, and we will issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. A total of 50,000 shares of our common stock are available for issuance under this program.
Through December 31, 2004, a total of 12,681 shares had been issued to employees under this program. The following table sets forth information on the number of shares issued during the three months ended March 31, 2005 under this program.
Date
February 4, 2005
March 4, 2005
On April 1, 2005, our common stock closed above $31.00 per share, which resulted in 4,607 shares being issued to eligible employees.
The issuance of shares under this program has not been registered under the Securities Act of 1933, as amended (1933 Act) in reliance upon Securities and Exchange Commission releases, including Release No. 6188, dated February 1, 1980, stating that there is no sale of the shares in the 1933 Act sense to employees under this type of program.
Not Applicable.
The following exhibits are filed as part of this Quarterly Report on Form 10-Q:
Exhibit Description
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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
Executive Vice President -
Finance and Administration
and Chief Financial Officer
(Principal Financial Officer)
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