UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the quarterly period ended September 30, 2005
OR
For the transition period from to .
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
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 Exchange Act). Yes x No ¨
Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
On November 2, 2005, the Company had 97,572,018 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
(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
Income from Continuing Operations
Discontinued operations, net of taxes:
Income (loss) from operations of discontinued components, net
Gain on sale of discontinued component, net
Net Income
Earnings Per Share of Common Stock (Note P)
Basic:
Earnings per share from continuing operations
Earnings (loss) per share from operations of discontinued components, net
Earnings per share from gain on sale of discontinued component, net
Net earnings per share, basic
Diluted:
Net 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 and natural gas liquids in storage
Commodity exchanges
Energy marketing and risk management assets (Note D)
Deposits
Deferred income taxes
Other current assets
Total Current Assets
Property, Plant and Equipment
Gathering and Processing
Natural Gas Liquids
Pipelines 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 E)
Goodwill (Note F)
Intangibles (Note G)
Prepaid pensions
Investments and other
Total Deferred Charges and Other Assets
Assets of Discontinued Component
Total Assets
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Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt
Notes payable
Accounts payable
Dividends payable
Accrued taxes
Accrued interest
Customers’ deposits
Unrecovered purchased gas costs
Energy marketing and risk management liabilities (Note D)
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
Liabilities of Discontinued Component
Total Liabilities
Commitments and Contingencies (Note M)
Shareholders’ Equity
Common stock, $0.01 par value: authorized 300,000,000 shares; issued 107,867,880 shares and outstanding 98,735,216 shares at September 30, 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 H)
Retained earnings
Treasury stock, at cost: 9,132,664 shares at September 30, 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
Impairment expense
Gain on sale of discontinued component
Gain on sale of assets
Income from equity investments, net
Stock-based compensation expense
Allowance for doubtful accounts
Changes in assets and liabilities (net of acquisition and disposition 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
Acquisitions
Capital expenditures
Proceeds from sale of discontinued component
Proceeds from sale of assets
Other investing activities
Cash Used in Investing Activities
Financing Activities
Borrowing (payments) of notes payable, net
Termination of interest rate swaps
Issuance of debt, net of issuance costs
Payment of debt
Purchase of common stock
Issuance of common stock
Dividends paid
Other financing activities
Cash Provided by (Used in) Financing Activities
Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
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CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
December 31, 2004
Other comprehensive loss
Total comprehensive income
Repurchase of common stock
Common stock issuance pursuant to various plans
Stock-based employee compensation expense
Common stock dividends - $1.09 per share
September 30, 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 that, 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 and nine months ended September 30, 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.
Critical Accounting Policies
Impairment of Long-Lived Assets - We assess our long-lived assets for impairment based on Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
Examples of long-lived asset impairment indicators include:
In the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant located in southwest Oklahoma had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our Statement 144 impairment analysis of the results of operations for this plant through September 30, 2005, and also the net sales proceeds from the anticipated sale of the plant. These assets were held for sale at September 30, 2005, and, accordingly, this component of our business is accounted for as discontinued operations in accordance with Statement 144.
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.
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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.
Nine Months Ended
September 30,
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 our year ending December 31, 2005. We are currently reviewing the applicability of FIN 47 to our operations and its potential impact on our consolidated financial statements.
Consolidation - In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF 04-5). EITF 04-5 presumes that a general partner controls a limited partnership and therefore should consolidate the partnership. Effective January 1, 2006, we will be required to consolidate Northern Border Partners’ operations in our consolidated financial statements. We are currently evaluating the impact of adopting EITF 04-5. However, had we consolidated Northern Border Partners at September 30, 2005, our debt to equity ratio would have changed from 72 percent debt and 28 percent equity to 78 percent debt and 22 percent equity. This increase results from the consolidation of Northern Border Partners’ debt of $1.3 billion at September 30, 2005, while the majority of their equity is reported as minority interest liability. The debt covenant calculations in our credit agreements exclude the debt of Northern Border Partners since it is a master limited partnership.
Inventory - In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13). EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 is effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We are currently reviewing the applicability of EITF 04-13 to our operations and its potential impact on our consolidated financial statements.
Reclassifications - Certain amounts in our consolidated financial statements have been reclassified to conform to the 2005 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity. Prior periods have been adjusted to reflect the sale of our Production segment and the pending sale of our Spring Creek power plant as discontinued operations. See Note C for additional information.
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On July 1, 2005, we completed the acquisition of the natural gas liquids businesses owned by several affiliates and a subsidiary of Koch Industries, Inc. (Koch) for approximately $1.33 billion, net of working capital and cash received. This transaction includes Koch Hydrocarbon, LP’s entire mid-continent natural gas liquids fractionation business; Koch Pipeline Company, L.P.’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., which has a 50 percent ownership interest in Chisholm Pipeline Company; MB1/LP, LLC (formerly MBFF, LP), which owns an 80 percent interest in the 160,000 barrel per day fractionator at Mont Belvieu, Texas; and Koch Vesco Holdings, LLC, an entity that owns a 10.2 percent interest in Venice Energy Services Company, LLC (VESCO). These assets are included in our consolidated financial statements beginning on July 1, 2005.
The unaudited pro forma information in the table below presents a summary of our consolidated results of operations as if the acquisition of the Koch natural gas liquids businesses had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or results that may be expected in the future.
We have recorded a preliminary purchase price allocation related to this acquisition. Our Natural Gas Liquids segment has recorded goodwill of approximately $172.0 million and intangibles of approximately $325.6 million. The purchase price allocation will be finalized as additional information regarding the assets acquired becomes available.
In October 2005, we entered into an agreement to sell certain natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. for approximately $528 million. The transaction is expected to close December 1, 2005, and is subject to Hart-Scott-Rodino antitrust approval. The properties are located in the Texas panhandle and include six gas processing plants, operating at approximately 60 percent of 160 million cubic foot per day capacity with 3,700 miles of gas gathering lines, and estimated natural gas liquids (NGL) production of 13,500 barrels per day. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.
In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments. We recognized a pre-tax gain on the sale of our Production segment of approximately $243.2 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. Our Board of Directors had approved the potential sale in July 2005, which resulted in our Production segment being classified as held for sale during the third quarter. In accordance with Statement 144, we did not record any depreciation, depletion or amortization for our Production segment while it was classified as held for sale.
Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. We entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for $53 million. The transaction requires Federal Energy Regulatory Commission (FERC) approval and is expected to be completed in 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.
These components of our business are accounted for as discontinued operations in accordance with Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, amounts in our financial statements and related notes for all periods shown relating to our Production segment and our power generation business are reflected as discontinued operations.
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The amounts of revenue, costs and income taxes reported in discontinued operations are as follows.
Net margin
Operating costs
Operating income (loss)
Other income (expense), net
Gain on sale of discontinued component, net of tax of $91.8 million
The following table discloses the major classes of discontinued assets and liabilities included in our Consolidated Balance Sheet for the periods indicated.
Energy marketing and risk management assets
Property, plant and equipment, net
Liabilities
Energy marketing and risk management liabilities
Other liabilities
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. 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
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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 and 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 with 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 interest rate savings through the termination of the swaps. During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements and received $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 nine months of 2005 for all terminated swaps was $5.9 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 September 30, 2005, we recorded a net liability of $5.4 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $5.4 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 $1.7 million and $1.4 million for the three and nine months ended September 30, 2005, respectively. The ineffectiveness related to these hedges was immaterial for the three and nine months ended September 30, 2004.
Cash Flow Hedges
Our Energy Services segment uses futures and swaps to hedge the cash flows associated with our anticipated purchases and sales of natural gas and cost of fuel used in transportation of gas. Accumulated other comprehensive loss at September 30, 2005, includes net losses of approximately $259.5 million, net of tax, related to these hedges that will be realized within the next 44 months. We will recognize $174.3 million in net losses over the next 12 months, and we will recognize net losses of $85.2 million thereafter. Our Gathering and Processing segment periodically enters into derivative instruments to hedge the cash flows
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associated with our exposure to changes in the price of natural gas, NGLs and crude oil. Accumulated other comprehensive loss at September 30, 2005, which includes net losses of approximately $5.7 million, net of tax, related to these hedges, will be realized in the income statement primarily within the next 12 months. Our Natural Gas Liquids segment utilizes swaps to hedge our exposure to changes in the price of NGLs. Accumulated other comprehensive loss at September 30, 2005, which includes net losses of approximately $0.9 million, net of tax, related to these swaps, will be realized in the income statement in December 2005. These losses will be partially offset by the gains on the related physical sales that will be recognized in earnings at the time the derivative instruments are settled.
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 a loss of approximately $7.0 million and a loss of approximately $7.1 million for the three and nine months ended September 30, 2005, respectively. Ineffectiveness related to these cash flow hedges for the three and nine months ended September 30, 2004, resulted in a gain of approximately $0.1 million and a loss of approximately $4.0 million, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive loss during the nine months ended September 30, 2004, due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur.
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 September 30, 2005, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 8.9 Bcf, which represents part of its gas purchase requirements for the 2005/2006 winter heating months.
Prior to the issuance of the $800 million of notes in the second quarter of 2005, we entered into $500 million in treasury rate-lock agreements to hedge the changes in cash flows of our anticipated interest payments from changes in treasury rates prior to the issuance of the notes. Upon issuance of the notes in June 2005, the treasury rate-lock agreements terminated, which resulted in us paying $2.4 million. This amount, net of tax, has been recorded as accumulated other comprehensive loss and will be recognized in the income statement over the term of the related debt issuances.
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
Pension costs
Weather normalization
Ad valorem tax
Service lines
Regulatory assets, net
We amortize reacquired debt costs in accordance with the accounting rules prescribed by the Oklahoma Corporation Commission (OCC) and Kansas Corporation Commission (KCC). These costs were included as a component of interest in the rate order issued by the OCC on October 4, 2005, and were included in a previous rate order issued by the KCC.
The remaining amount of regulatory assets, net is being recovered through various rate cases with the exception of an immaterial amount, which we expect to eventually recover.
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In July 2005, we acquired the natural gas liquids businesses owned by Koch for approximately $1.33 billion, net of working capital and cash received. See Note B for additional information regarding this acquisition. The acquisition increased our mid-continent operating focus through a downstream extension of our natural gas gathering and processing operation. The assets acquired provide commercial, operational and administrative synergies as these assets enhance our existing mid-stream operating areas. This acquisition creates new and expanded commercial opportunities and we anticipate volumes and margins of our existing business to increase. Our gathering and processing assets were the second largest producer of NGLs on the system and all but one of our processing plants is connected to the system. Additionally, the acquisition improves our market access to the largest NGL hub, which is located in the gulf coast. As a result of our preliminary purchase price allocation, we assigned $1.2 billion to identifiable assets consisting of approximately $912.7 million to tangible assets based on the fair value of the net assets and approximately $325.6 million to identifiable intangible assets that will be amortized on a straight-line basis over the remaining useful lives of the assets, as determined by underlying contract terms or third-party appraisals. The excess of the purchase price over the fair value of identifiable assets acquired, net of liabilities assumed is $172.0 million which is recorded as goodwill.
The following table reflects the changes in the carrying amount of goodwill for the periods indicated.
Goodwill
Intangible assets primarily relate to contracts acquired through the acquisition of the natural gas liquids businesses from Koch and based on the preliminary purchase price allocation are being amortized over our aggregate weighted-average period of 40 years. See Notes B and F for additional information regarding the acquisition that resulted in intangible assets. The aggregate amortization expense for each of the next five years is estimated to be approximately $8.1 million. The following tables reflect the gross carrying amount and accumulated amortization of intangibles at September 30, 2005.
Intangibles
Accumulated amortization
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The tables below give an overview of comprehensive income for the periods indicated. The assumption of derivative instruments in the table below relates to the derivative instruments transferred to the buyer of our Production segment.
Unrealized losses on derivative instruments
Unrealized holding losses arising during the period
Realized losses in net income
Assumption of derivative instruments related to sale of discontinued component
Other comprehensive loss before taxes
Income tax benefit on other comprehensive loss
Comprehensive loss
Realized (gains) losses in net income
Comprehensive income
Accumulated other comprehensive loss at September 30, 2005 and 2004, primarily includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.
Stock Repurchase Plan - During the third quarter of 2005, we repurchased approximately 2.3 million shares of our common stock pursuant to a plan approved by our Board of Directors on January 20, 2005, bringing the total repurchased under the plan to 6.0 million shares. 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.
Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2005, May 2, 2005, and July 29, 2005, were $0.25 per share, $0.28 per share and $0.28 per share, respectively. Additionally, a quarterly dividend of $0.28 per share was declared in September, payable in the fourth quarter of 2005.
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In June 2005, we entered into a $1.0 billion short-term bridge financing agreement. The interest rate is based, at our election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate 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.
On July 1, 2005, we borrowed $1.0 billion under the short-term bridge financing agreement to assist in financing the acquisition of assets from Koch. See Note B for additional information about this acquisition. We funded the remaining acquisition cost through our commercial paper program. We anticipate permanent financing of the acquisition to come from a combination of proceeds from the sale of assets, such as our Production segment, our natural gas gathering and processing assets located in Texas and our Spring Creek power plant, proceeds from the February 2006 settlement of the purchase contracts that are part of our mandatory convertible equity units, and free cash flow. At September 30, 2005, we had lowered the commitment of outstanding indebtedness under the bridge financing agreement to $900.0 million. The reduction in indebtedness under our short-term bridge financing agreement is a result of a required prepayment due to the sale of our Production segment.
In July 2005, we amended our 2004 $1.0 billion five-year credit agreement to increase the limit on our debt-to-equity ratio from 67.5 percent debt to 70 percent debt for the period from July 25, 2005, to February 28, 2006. Beginning on March 1, 2006, the limit on our debt will return to 67.5 percent of total capital.
In September 2005, we exercised the accordion feature of our 2004 $1.0 billion five-year credit agreement to increase the commitment amounts by $200 million to a total of $1.2 billion. The interest rate payable under this five-year credit agreement is a floating rate calculated in the same manner as the $1.0 billion short-term bridge financing agreement. Additionally, we amended the five-year credit and the short-term bridge financing agreements to change the definition of Consolidated Net Worth to eliminate the effect of gains and losses recorded in accumulated other comprehensive income (loss) as a result of certain commodity hedging agreements. The effect of these amendments was to increase the amount of indebtedness we can incur while maintaining compliance with the covenants in those agreements that limit our debt-to-equity ratio.
Both the five-year credit agreement and short-term bridge financing agreement contain 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-equity 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 September 30, 2005, we were in compliance with all covenants.
We had $168.7 million in letters of credit outstanding at September 30, 2005.
We had 16.1 million mandatory convertible equity units outstanding at September 30, 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 seek to remarket the notes and any cash received will be put 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 require the holders of the mandatory convertible equity units to purchase our common stock. If the notes are successfully remarketed, we will receive $402.5 million and issue 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.
In June 2005, we issued $800 million of notes, comprised of $400 million in 10-year maturities with a coupon of 5.2 percent and $400 million in 30-year maturities with a coupon of 6.0 percent. The notes were issued under our shelf registration statement dated April 15, 2003. Proceeds from this debt issuance were used to repay commercial paper borrowings and for general corporate purposes.
In March 2005, we had $335 million of long-term debt mature. We funded payment of this debt with working capital and the issuance of commercial paper in the short-term market.
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The tables below provide the components of net periodic benefit cost for our pension and other postretirement benefit plans.
Components of Net Periodic Benefit Cost
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
Contributions - Contributions of $1.0 million and $12.3 million were made to our pension plan and other postretirement benefit plan, respectively, for the nine months ended September 30, 2005. 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. 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. See Note L in our Annual Report on Form 10-K for the year ended December 31, 2004, for additional discussion. There has been no material change to the status of the manufactured gas sites since December 31, 2004.
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Yaggy Facility - 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 are 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. On April 11, 2005, the court denied the plaintiffs’ motion for a new trial and denied a post-trial motion filed by defendants. We filed our notice of appeal of the residential class verdict and the attorney fee award. The cases have now been transferred to the Kansas Supreme Court for appeal. With the exception of appeals, all litigation regarding our Yaggy facility has been resolved.
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 Note N and the Summary of Significant Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2004, with the exception of the segments described below. Our Distribution segment is comprised of regulated public utilities. 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 10 percent or more of our consolidated gross revenues for the periods covered by this report.
In September 2005, we completed the sale of our Production segment. Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. These components of our business are accounted for as discontinued operations in accordance with Statement 144. Our Production segment is included in the Other segment in the tables below, while our power generation business is included in our Energy Services segment.
With the acquisition of assets from Koch on July 1, 2005, we formed a new operating segment called Natural Gas Liquids. This segment consists of our existing natural gas liquids marketing business, which was previously part of our Gathering and Processing segment, and the assets acquired from Koch excluding those natural gas liquids gathering and pipeline distribution assets regulated by the FERC, which have been transferred to our Pipelines and Storage segment. VESCO, also acquired as part of the asset acquisition, was added to our Gathering and Processing segment.
Segment results for the Gathering and Processing segment for all prior periods have been restated to reflect the transfer of our existing natural gas liquids marketing business to the Natural Gas Liquids segment. The segment formerly named Transportation and Storage has been renamed Pipelines and Storage in order to better describe the activities of the segment.
As discussed in Note D, at the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment. 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.
Three Months EndedSeptember 30, 2005
Sales to unaffiliated customers
Intersegment sales
Income (loss) from operations of discontinued components
Income (loss) from equity investments
Three Months EndedSeptember 30, 2004
Income from equity investments
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Nine Months EndedSeptember 30, 2005
Operating income
Total assets
Nine Months EndedSeptember 30, 2004
Intersegment sales (a)
The following table sets forth supplemental information with respect to our cash flow for the periods indicated.
Cash paid during the period
Interest, including amounts capitalized
Cash paid (received) for interest includes swap terminations, treasury rate-lock terminations and ineffectiveness of $22.6 million and $(82.9) million for the nine months ended September 30, 2005 and 2004, respectively.
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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 from continuing operations available for common stock
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units
Options and other dilutive securities
Income from continuing operations available for common stock and common stock equivalents
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There were 21,681 and 8,997 option shares excluded from the calculation of diluted EPS for the three months ended September 30, 2005, and 2004, respectively, since their inclusion would be antidilutive for each period. For the nine months ended September 30, 2005, and 2004, there were 48,062 and 14,711 option shares, respectively, excluded from the calculation of diluted EPS since their inclusion would be antidilutive for each period.
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Executive Summary - Operating income for our third quarter of 2005 was $123.2 million, an increase of $74.8 million, or 155 percent, compared with the same period in 2004. For the first nine months of 2005, operating income was $361.7 million, an increase of $87.5 million, or 32 percent, from the same period last year.
Diluted earnings per share of common stock from continuing operations (EPS) increased to 49 cents for the third quarter of 2005 from 15 cents for the same period in 2004. For the nine-month period, EPS increased to $1.56 for 2005 from $1.25 in 2004.
Our Energy Services segment benefited from increases in natural gas prices and volatility during the third quarter of 2005. An increase of $54.6 million and $29.6 million for the three- and nine-month periods, respectively, was due to storage and transportation activities primarily attributable to opportunities to realize higher margins from selling natural gas from storage due to increases in natural gas prices and volatility, and gains associated with the increase in basis spreads on financial instruments used to hedge purchases and sales associated with storage activities.
Favorable energy prices also had a significant impact on our Gathering and Processing segment’s results during the nine-month period for 2005. Average prices for natural gas, natural gas liquids (NGLs) and crude oil exceeded prices for the same period in 2004. The gross processing spread was also higher in 2005 and continued to exceed the previous five-year average. The effect of these higher prices increased our Gathering and Processing segment’s operating income 16 percent for the quarter and 41 percent for the nine-month period, compared with the same periods in 2004.
On July 1, 2005, we completed the acquisition of the natural gas liquids businesses owned by several affiliates and a subsidiary of Koch Industries, Inc. (Koch). The results of operations for these acquired assets accounted for increases in both our Natural Gas Liquids segment and our Pipelines and Storage segment.
On October 4, 2005, the Oklahoma Corporation Commission (OCC) issued a final order on our application for a rate increase by Oklahoma Natural Gas. The OCC unanimously approved an annual rate increase of $57.5 million. In July, the Commission’s administrative law judge recommended an increase in annual revenues of approximately $58.0 million. Oklahoma Natural Gas implemented new rates, subject to refund, on July 28, 2005, based on the judge’s report.
Discontinued Operations - In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments. We recognized a pre-tax gain on the sale of the discontinued component for our Production segment of approximately $243.2 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt.
Additionally, in the third quarter of 2005 we made the decision to sell our Spring Creek power plant and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant located in southwest Oklahoma had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our impairment analysis of the results of operations for this plant through September 30, 2005, and also considered net sales proceeds from a sale of the plant. In October 2005, we entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for $53 million. The transaction requires Federal Energy Regulatory Commission (FERC) approval and is expected to be completed in 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.
These components of our business are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Accordingly, amounts in our financial statements and related notes for all periods shown relating to our Production segment and our power generation business are reflected as discontinued operations. The sale of our Production segment and the pending sale of our power generation business are in line with our business strategy to sell assets when deemed less strategic or as other conditions warrant.
Acquisition - On July 1, 2005, we completed the acquisition of the natural gas liquids businesses owned by Koch for approximately $1.33 billion, net of working capital and cash received. This transaction includes Koch Hydrocarbon, LP’s entire mid-continent natural gas liquids fractionation business; Koch Pipeline Company, L.P.’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., which has a 50 percent ownership interest in Chisholm Pipeline Company; MB1/LP, LLC (formerly MBFF, LP), which owns an 80 percent interest in the 160,000 barrel per day fractionator at Mont Belvieu, Texas;
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and Koch Vesco Holdings, LLC, an entity that owns a 10.2 percent interest in Venice Energy Services Company, LLC (VESCO). These assets are included in our consolidated financial statements beginning on July 1, 2005.
The acquisition was initially financed through our $1.0 billion short-term bridge financing agreement, which we entered into in June 2005, and our commercial paper program. We anticipate permanent financing of the acquisition to come from a combination of the proceeds from the settlement of our mandatory convertible equity units in February 2006, proceeds from the sale of less strategic assets and free cash flow.
Divestiture - In October 2005, we entered into an agreement to sell certain natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. for approximately $528 million. The transaction is expected to close December 1, 2005, and is subject to Hart-Scott-Rodino antitrust clearance. The properties are located in the Texas panhandle and include six gas processing plants, operating at approximately 60 percent of 160 million cubic foot per day capacity with 3,700 miles of gas gathering lines, and estimated NGL production of 13,500 barrels per day. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.
Regulatory - Several regulatory initiatives positively impacted the earnings and future earnings potential for our Distribution segment. These initiatives are discussed beginning on page 41.
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 our year ending December 31, 2005. We are currently reviewing the applicability of FIN 47 to our operations and its potential impact on our consolidated financial statements.
In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF 04-5). EITF 04-5 presumes that a general partner controls a limited partnership and therefore should consolidate the partnership. Effective January 1, 2006, we will be required to consolidate Northern Border Partners’ operations in our consolidated financial statements. We are currently evaluating the impact of adopting EITF 04-5. However, had we consolidated Northern Border Partners at September 30, 2005, our debt to equity ratio would have changed from 72 percent debt and 28 percent equity to 78 percent debt and 22 percent equity. This increase results from the consolidation of Northern Border Partners’ debt of $1.3 billion at September 30, 2005, while their equity is reported as minority interest in partners’ equity. The debt covenant calculations in our credit agreements exclude the debt of Northern Border Partners, since it is a master limited partnership.
In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13). EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 is effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We are currently reviewing the applicability of EITF 04-13 to our operations and its potential impact on our consolidated financial statements.
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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 47 for amounts in our portfolio at September 30, 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, NGLs and crude oil prices, we periodically enter into derivative transactions to hedge anticipated sales and purchases of natural gas, NGLs, crude oil, fuel requirements and transportation firm commitments. 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 in the period incurred.
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 September 30, 2005, we had $397.2 million of goodwill recorded on our balance sheet.
We assess our long-lived assets for impairment based on Statement 144. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
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We do not currently anticipate any additional 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 some employees. 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.
We use September 30 as the measurement date for our annual actuarial study related to our defined benefit pension plan and our postretirement benefit plan. We currently anticipate using a discount rate of 5.75 percent to estimate our 2006 expense and liability related to these plans. We have not completed our current actuarial study, however, the impact of using a discount rate of 5.75 percent, compared to 6.00 percent in our prior year study, will generally cause our expense for 2006 to increase compared to our expense recorded for 2005.
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 relate to Northern Plains’, our subsidiary which provides services to Northern Borders Partners, amendments in benefits payable under our gas union contracts and a change in our assumed discount rate. See Note L 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 - Net margin increased for the three and nine months ended September 30, 2005, compared with the same periods in 2004 primarily due to:
For an explanation of energy trading revenues, net, see the discussion of our Energy Services segment beginning on page 36.
Consolidated operating costs increased for the three- and nine-month periods primarily due to the costs related to the natural gas liquids assets acquired from Koch and increased employee benefit costs.
Depreciation, depletion and amortization increased for the three- and nine-month periods primarily due to the costs associated with the natural gas liquids assets acquired from Koch. Additionally, depreciation, depletion and amortization increased for the nine-month period due to a charge related to the replacement of our customer service system in Texas and regulatory asset amortization resulting from the Kansas rate case, both in our Distribution segment.
The following tables show the components of other income and other expense for the periods indicated.
Equity income
Income (expense) from benefit plan investments
Interest income
Realized gain on investment
Unrealized loss on investment
Other Income
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Litigation expense and claims, net
Donations, civic, and governmental
Loss on sale of assets
Other Expense
More information regarding our results of operations is provided in the discussion of operating results for each of our segments.
Overview - Our Gathering and Processing segment is engaged in the gathering and processing of natural gas and fractionation of NGLs primarily in Oklahoma, Kansas and Texas. We own approximately 13,900 miles of gathering pipelines that supply our gas processing plants. We have active processing capacity of approximately 1.8 Bcf/d and NGL fractionation capacity of 89 MBbls/d.
Our operations include the gathering of natural gas production from oil and natural gas 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. Some of 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 company-owned fractionation facilities. The component products can then be stored, transported and/or marketed to a diverse customer base of end users.
We generally gather and process gas under three types of contracts:
Contracts covering approximately 29 percent of the volumes associated with our keep whole contracts allow us to charge conditioning fees for processing, in the event 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 is a strategy that we continue to execute. We are also continuing our strategy of renegotiating any under-performing gas purchase and gathering contracts.
Additionally, we have the ability to 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.
We are impacted by producer drilling activity, which is sensitive to geological success as well as availability of capital and commodity prices. The mid-continent region is currently experiencing a significant upturn in oil and gas drilling activity. This resurgence in drilling activity has been driven by increased prices for natural gas, crude oil and by the long-term projections of continued demand for natural gas. We are exposed to volume risk from both a competitive and a production standpoint. We continue to see production declines in certain fields that supply our gathering and processing operations, and the possibility exists that declines may surpass development from new drilling.
For more discussion of our gathering and processing operations, including factors that affect our ability to compete, see our Form 10-K for the year ended December 31, 2004.
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Acquisition - The following acquisition is discussed beginning on page 25.
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.
Three Months Ended
Natural gas liquids and condensate sales
Gas sales
Gathering, compression, dehydration and processing fees and other revenues
Operating Information
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)
Capital expenditures (Thousands of dollars)
Conway OPIS composite NGL price ($/gal) (based on our NGL product mix)
Average NYMEX crude oil price ($/Bbl)
Average realized condensate sales price ($/Bbl)
Average natural gas price ($/MMBtu) (mid-continent region)
Gross processing spread ($/MMBtu)
Operating Results - The financial and operating results above have been restated to reflect the transfer of the natural gas liquids marketing business that was previously included in our Gathering and Processing segment to our new Natural Gas Liquids segment.
The increase in net margin for the three month period is primarily due to an increase of $8.3 million attributable to higher natural gas and NGL prices on our POP contracts, net of hedging activities. This increase was offset by a decrease of $1.5 million due to less volume processed as a result of natural production declines and contract expirations.
The increase in net margin for the nine months ended September 30, 2005, compared with the same periods for 2004, is primarily due to:
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The gross processing spread for the three and nine months ended September 30, 2005, which is the relative difference in economic value between NGLs and natural gas on a Btu basis, was higher than the previous five-year average of $1.78. The gross processing spread in the third quarter of 2005 was $3.62 per MMBtu versus $3.07 per MMBtu in the third quarter of 2004; however, it had a minimal impact on margins because of hedging activities. Improved contractual terms for gas gathering and processing resulting from our continued efforts to renegotiate under-performing gas purchase, gas processing and gathering contracts, continue to positively impact net margin.
The increase in operating costs for both the three- and nine-month periods is primarily due to an increase of $0.6 million and $1.7 million, respectively, in materials, supplies and utilities related to compressor utilization and maintenance. The remaining increase is associated with higher employee-related costs.
The decrease in other income (expense) for both the three- and nine-month periods is partially due to the accrual of a $0.5 million insurance deductible associated with VESCO. The Venice, Louisiana plant suffered damage in August 2005 from Hurricane Katrina and is not currently operating. Management expects that insurance payments from our carriers will cover the remaining costs associated with repairing the damage to the facility. The facility is currently expected to be repaired and back in service during the first quarter of 2006.
The increase in capital expenditures for the nine-month period is primarily related to additional compression expenditures and growth activities.
In October 2005, we entered into an agreement to sell certain natural gas gathering and processing assets located in Texas. See page 26 for additional information. The impact of these assets on our Gathering and Processing segment’s operating income for the three and nine months ended September 30, 2005, was $14.0 million and $32.5 million, respectively.
Risk Management - We use derivative instruments to minimize the risks associated with price volatility. The realized financial impact of the derivative transactions is included in our operating income in the period that the physical transaction occurs.
The following tables set forth our remaining 2005 and 2006 hedging information for our Gathering and Processing segment.
Product
Percent of Proceeds:
Condensate (a)
NGL (b)
Natural gas (c)
Keep Whole:
Gross processing spread (d)
Natural gas (a)
Natural gas (b)
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We continue to evaluate market conditions to take advantage of favorable pricing opportunities associated with our POP contracts, as well as our keep whole quantities.
See Item 3, Quantitative and Qualitative Disclosures About Market Risk and Note D of the Notes to Consolidated Financial Statements in this Form 10-Q.
Overview - Our Natural Gas Liquids segment primarily gathers, fractionates and treats raw NGLs produced from gas processing plants located in Oklahoma, Kansas and the Texas panhandle. We own and operate, or ship through affiliated companies, approximately 4,600 miles of gathering and distribution lines with gathering capacity of 277 MBbls/d and distribution capacity of 360 MBbls/d. Our gathering lines are connected to approximately 90 percent of the natural gas processing plants located in the mid-continent producing areas.
Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, butane and natural gasoline. Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline quality specifications, which limit NGL content in the natural gas stream.
The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, raw form until they are gathered, primarily by pipeline, and delivered to our fractionators. A fractionator, by applying heat and pressure, separates each NGL component into pure marketable products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). We have approximately 380 MBbls/d of fractionation capacity through our ownership or interest in four different facilities. These NGL products are then stored and/or distributed to petrochemical, heating and motor gasoline end users. Our fractionation and storage facilities are centrally located and provide flexible redelivery of NGL products to the two primary U.S. NGL market centers, Conway, Kansas and Mont Belvieu, Texas. We have the ability to satisfy our customer redelivery requests to these two market centers, and through our own account we can also market our NGL products to the highest value locations. We own or lease approximately 20.4 MMBbls of storage capacity in the mid-continent and gulf coast regions.
Our Natural Gas Liquids segment focuses on increasing market value of NGL products through use of our natural gas liquids assets. We are engaged in three primary business activities downstream of the natural gas gathering and processing segment.
We are impacted by producer drilling activity, which is sensitive to geological success as well as availability of capital and commodity prices. The mid-continent region is currently experiencing a significant upturn in oil and gas drilling activity. This resurgence in drilling activity has been driven primarily by increased prices for natural gas and crude oil and by long-term projections of continued demand in the U.S. natural gas market. We continue to see production declines in certain fields that supply the gathering and processing facilities in our operating region and the possibility exists that declines may surpass development from new drilling. The factors that typically affect our ability to compete for NGL supplies are:
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The main factors that affect our margins are:
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our Natural Gas Liquids segment for the periods indicated.
Storage and fractionation revenues
Cost of sales
Natural gas liquids gathered (MBbls/d)
Natural gas liquids fractionated (MBbls/d)
Operating Results - The results of operations for 2004 shown above are related to the natural gas liquids marketing business that was previously included in our Gathering and Processing segment. The increases for both the three- and nine-month periods are primarily related to the natural gas liquids assets acquired from Koch in July 2005. The increases associated with the acquisition for both the three- and nine-month periods include:
The remaining net margin increase for both the three- and nine-month periods is primarily related to increased storage margins of $1.1 million and $4.8 million, respectively, from restructured storage contracts. Additionally, net margin also increased $1.9 million for the nine-month period as a result of higher NGL prices, driven primarily by higher marketing fees from increased NGL prices.
Increased storage regulatory compliance costs resulted in an additional $2.0 million in operating costs for the nine-month period in 2005 compared with 2004.
Overview - Our Pipelines and Storage segment, formerly known as Transportation and Storage, operates our intrastate natural gas transmission pipelines, natural gas storage, regulated natural gas liquids gathering and distribution pipelines and nonprocessable natural gas gathering facilities. We also provide interstate transportation service under Section 311(a) of the Natural Gas Policy
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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. The natural gas liquids gathering and distribution pipelines are interstate pipelines regulated by FERC and transport raw NGLs and NGL products pursuant to filed tariffs.
We operate approximately 5,600 miles of natural gas gathering and intrastate transmission pipelines in Oklahoma, Kansas and Texas, where we are regulated by the 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 local distribution companies (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 FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Factors that affect competition are location, natural gas prices, fees for services and quality of service provided.
Following our acquisition of the Koch natural gas liquids assets in July 2005, we operate approximately 2,500 miles of regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas and Texas. Our natural gas liquids gathering system delivers raw NGLs gathered from gas processing plants located in these states to fractionation facilities in Medford, Oklahoma. Our NGL distribution pipelines move products from fractionators in Oklahoma and Kansas to market points in Conway, Kansas and Mont Belvieu, Texas. These pipelines are operated under the guidance and oversight of various governmental agencies including programs mandated by the OCC, the KCC, FERC, and other various state and governmental agencies. All of these NGL gathering and distribution pipelines are subject to tariff.
Our Pipeline and Storage segment 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 and NGL components. Volatility in the natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage. In addition, our NGL gathering pipelines are affected by operational or market driven changes in the output of the processing plants to which we are connected. Processing plant output may increase or decrease as a result of the relative value of natural gas to NGL prices. In addition, volume delivered through the system may increase or decrease as a result of the relative NGL price between the mid-continent and gulf coast regions. Natural gas 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 Pipelines and Storage segment for the periods indicated.
Transportation and gathering revenues
Storage revenues
Gas sales and other revenues
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Natural gas transported (MMcf)
Natural gas liquids transported (MBbls/d)
Average natural gas price ($/MMBtu)(mid-continent region)
Operating results - Net margin increased for both the three and nine months ended September 30, 2005, compared with the same periods in 2004, primarily due to:
Operating costs increased $7.2 million and $7.0 million for the three- and nine-month periods ended, respectively, compared with 2004, primarily related to $5.4 million for operating the newly-acquired NGL pipelines with the balance being driven by higher regulatory compliance costs and employee costs.
The increase in depreciation, depletion and amortization of approximately $3.0 million for both the three- and nine-month periods is primarily related to the newly-acquired NGL pipelines.
The decrease in other income (expense), net, for the nine-month period is due to the $6.9 million gain on the 2004 sale of certain assets, which was partially offset by unrelated litigation costs.
Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical products and risk management services through our network of contracted gas supply, transportation and storage capacity. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our total storage capacity under lease is 86 Bcf, with maximum withdrawal capability of 2.3 Bcf per day and maximum injection capability of 1.6 Bcf per day. Our current transportation capacity is 1.6 Bcf per day. The contracted storage and transportation capacity connects the major supply and demand centers throughout the United States. With these contracted assets, our ongoing business strategies include identifying, developing and delivering specialized services and products for premium value to our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Also, our storage and transportation capacity allows us opportunities to optimize these positions through our application of market knowledge and risk management skills. We provide risk management services to our customers.
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. In the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. These assets were held for sale at September 30, 2005, and, accordingly, this component of our business is accounted for as discontinued operations, in accordance with Statement 144. In October 2005, we concluded that our Spring Creek power plant located in southwest Oklahoma had been impaired and recorded an impairment expense of $52.2 million. For additional information see discussion of discontinued operations on page 25.
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Energy and power revenues
Other revenues
Discontinued operations, net of taxes
Natural gas marketed (Bcf)
Natural gas gross margin ($/Mcf)
Physically settled volumes (Bcf)
Operating Results - Increases in natural gas price and volatility during the third quarter of 2005 had a direct impact on our Energy Services segment identified in the explanations below.
Energy and power revenues, as well as cost of sales and fuel, increased for the three-month period due to a 14.4 percent increase in sales volumes and a significant increase in commodity prices compared to the same period in 2004.
Net margin increased for the three months ended September 30, 2005, compared with the same period in 2004, primarily due to:
Net margins increased for the nine month period primarily due to:
Net margin also increased $5.9 million for the nine-month period due to a timing difference in revenue recognition between physical transportation activities and the associated derivative contracts that hedge the physical transportation commitment. The derivative contracts hedging the transportation commitment were marked-to-market, as a portion of the derivatives did not highly correlate between the receipt and delivery points causing the derivative instrument to be marked-to-market without the physical underlying offset, or a portion of the hedged item was determined to be ineffective.
Operating costs increased $5.6 million and $3.7 million for the three- and nine-month periods, respectively, primarily due to increased employee-related costs and increased litigation expense.
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Natural gas volumes marketed increased for the three- and nine-month periods due to our expanded Canadian operations, additional long-term contracts and opportunities to sell into supply-constrained markets.
Our natural gas in storage at September 30, 2005, was 63.9 Bcf compared to 79.1 Bcf at September 30, 2004. At September 30, 2005, our total natural gas storage capacity under lease was 86 Bcf compared to 85 Bcf at September 30, 2004.
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. 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 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 margins from these activities.
Marketing and storage, gross
Less: Storage and transportation costs
Marketing and storage, net
Retail marketing
Financial trading
Overview - Our Distribution segment provides natural gas distribution services to over 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
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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.
Our 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 our customers based on the actual cost of gas purchased by the respective distribution division. Changes in the level of 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.
In September 2005, Hurricane Rita caused significant damage to customers’ homes and businesses in the Texas Gas Service service area located in south Jefferson County and Port Arthur, Texas. Texas Gas Service suffered damage to its Port Arthur service center, meters in south Jefferson County and Port Arthur, Texas, and incurred system gas loss. The financial impact will be nominal due to insurance coverage that covers property damage, gas loss and business interruption loss.
Selected Financial Information - The following table sets forth certain selected financial information for the Distribution segment for the periods indicated.
Transportation revenues
Gross margin
Operating Results - Net margin increased by $16.5 million and $17.2 million for the three and nine months ended September 30, 2005, respectively, compared with the same periods in 2004, primarily due to a $14.9 million increase resulting from the implementation of new rate schedules in Oklahoma and a $0.7 million increase resulting from increased wholesale sales during the third quarter of 2005. The nine-month period also increased as a result of $2.6 million in additional margin during the time frame the limited issue filing was in effect in Oklahoma.
Operating costs increased $11.9 million for the three-month period, primarily due to the following:
The $14.2 million increase in operating costs for the nine-month period was primarily due to increased labor and employee benefit costs of $13.2 million and the accrual of an insurance deductible of $0.5 million related to Hurricane Rita.
Depreciation, depletion and amortization increased for the nine-month period primarily due to a $2.9 million charge related to the replacement of our field customer service system in Texas. The ad valorem tax recovery rider in Kansas increased amortization for the nine-month period by $3.8 million, which is offset by increased revenues. The remaining increase for the nine-month period is primarily due to additional plant and equipment.
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Selected Operating Data - The following tables set forth certain operating information for our Distribution segment for the periods indicated.
Average number of customers
Customers per employee
Volumes (MMcf)
Residential
Commercial
Industrial
Wholesale
Public Authority
Total volumes sold
Transportation
Total volumes delivered
Margin
Gross margin on gas sales
Certain amounts have been reclassified to reflect transportation margin net of its related fuel cost. There was no impact on gross margin. All prior periods have been restated.
Residential and commercial volumes decreased for the nine-month period due to:
Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes increased for the three- and nine-months ended September 30, 2005, as fewer volumes were required to meet the needs of residential, commercial and industrial customers, resulting in additional volume being available for sale to other parties.
Public authority gas volumes reflect volumes used by state agencies and school districts serviced by Texas Gas Service.
Transportation volumes increased for the three- and nine-month periods primarily due to commercial and industrial customers of Oklahoma Natural Gas migrating to new transportation rates as a result of lower minimum transport thresholds.
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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 $12.3 million and $8.0 million for new business development for the three months ended September 30, 2005, and 2004, respectively, and $32.2 million and $25.0 million for new business development for the nine months ended September 30, 2005, and 2004, respectively.
Regulatory Initiatives
Oklahoma - On October 4, 2005, the OCC issued a final order on our application for a rate increase by Oklahoma Natural Gas. The OCC unanimously approved an annual rate increase of $57.5 million. In July, the Commission’s administrative law judge recommended an increase in annual revenues of approximately $58.0 million. Oklahoma Natural Gas implemented new rates, subject to refund, on July 28, 2005, based on the judge’s report. The refund obligation associated with the difference between the rates we have been collecting since July 28, 2005, and the OCC approved rate increase is not material to our financial results for the three- and nine-month periods.
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 investment in gas in storage. 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 categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at Oklahoma Natural Gas’ next general rate case. This interim relief expired on July 27, 2005, and was replaced by the rate increase of $57.5 million approved on October 4, 2005. As the final rate increase exceeded the interim revenues that were subject to refund, no refund obligation was incurred associated with this rate increase.
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.
Discontinued Operations
Overview - In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments. We recognized a pre-tax gain on the sale of the discontinued component for our Production segment of approximately $243.2 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. Our Board of Directors had approved the potential sale in July 2005, which resulted in our Production segment being classified as held for sale during the third quarter. In accordance with Statement 144, we did not record any depreciation, depletion or amortization for our Production segment while it was classified as held for sale.
Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant located in southwest Oklahoma had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our Statement 144 impairment analysis of the results of operations for this plant through September 30, 2005, and also considered net sales proceeds from a sale of the plant. Ultimately, the decision reached was to sell the plant and in October 2005, we entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for $53 million. The transaction requires FERC approval and is expected to be completed in 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.
These components of our business are accounted for as discontinued operations in accordance with Statement 144. Accordingly, amounts in our financial statements and related notes for all periods shown relating to our Production segment and our power generation business are reflected as discontinued operations. The sale of our Production segment and the pending sale of our power generation business are in line with our business strategy to sell assets when deemed less strategic or as other conditions warrant.
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Selected Financial Information - The amounts of revenue, costs and income taxes reported in discontinued operations are as follows.
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 nine months of 2005 were $189.9 million, compared with $192.3 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 credit agreements. 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, asset securitization and the sale/leaseback of facilities.
In June 2005, we entered into a $1.0 billion short-term bridge financing agreement. The interest rate is based, at our election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings by Moody’s Investor Service (Moody’s) and Standard and Poor’s (S&P).
On July 1, 2005, we borrowed $1.0 billion under the short-term bridge financing agreement to assist in financing the acquisition of assets from Koch. See page 25-26 for additional information about this acquisition. We funded the remaining acquisition cost through our commercial paper program. We anticipate permanent financing of the acquisition to come from a combination of proceeds from the sale of assets, such as our Production segment, our natural gas gathering and processing assets located in Texas and our Spring Creek power plant, proceeds from the February 2006 settlement of the purchase contracts that are part of our mandatory convertible equity units, and free cash flow. At September 30, 2005, we had lowered the commitment of outstanding indebtedness under the short-term bridge financing agreement to $900.0 million. The reduction in indebtedness under our short-term bridge financing agreement is a result of a required prepayment due to the sale of our Production segment.
In July 2005, we amended our 2004 $1.0 billion five-year credit agreement to increase the limit on our debt-to-equity ratio from 67.5 percent debt to 70 percent debt for the period from July 25, 2005, to February 28, 2006. Beginning on March 1, 2006, the limit on our debt returns to 67.5 percent of total capital.
In September 2005, we exercised the accordion feature of our 2004 $1.0 billion five-year credit agreement to increase the commitment amounts by $200 million to a total of $1.2 billion. The interest rate payable under this five-year credit agreement is a floating rate calculated in the same manner as the $1.0 billion short-term bridge financing agreement. Additionally, we amended the five-year credit and the short-term bridge financing agreements to change the definition of Consolidated Net Worth
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to eliminate the effect of gains and losses recorded in accumulated other comprehensive income (loss) as a result of certain commodity hedging agreements. The effect of these amendments was to increase the amount of indebtedness we can incur while maintaining compliance with the covenants in those agreements that limit our debt-to-equity ratio.
Both the five-year credit agreement and the bridge financing agreement contain 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-equity 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.
The total amount of short-term borrowings authorized by our Board of Directors is $2.5 billion. At September 30, 2005, we had $302.5 million in commercial paper outstanding, $900.0 million drawn on our short-term bridge financing agreement, $168.7 million in letters of credit issued, and approximately $86.2 million in cash and temporary investments. We also had $2.3 billion of long-term debt outstanding, including current maturities. As of September 30, 2005, we could have issued $1.1 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements.
In March 2005, $335 million of our long-term debt matured. We funded payment of this debt with working capital and the issuance of commercial paper in the short-term market.
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 mandatory convertible equity units we issued in January 2003 to be part equity and part debt. For purposes of computing capitalization ratios, these rating agencies adjust our capitalization structure. S&P considers our mandatory convertible 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 57 percent long-term debt and 43 percent equity at September 30, 2005. Moody’s considers 25 percent of our mandatory convertible equity units to be long-term debt and 75 percent to be shareholders’ equity, which would result in a capitalization structure of 55 percent long-term debt and 45 percent equity at September 30, 2005.
Currently, we have $48.2 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, trusted preferred securities, 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 mandatory convertible equity units.
Credit Rating - Our credit ratings are currently a “BBB” (Stable) by S&P and a “Baa2” (Stable) by Moody’s. In October 2005, Moody’s downgraded us to “Baa2” from “Baa1”, S&P downgraded us to “BBB” from “BBB+” and both removed the negative
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watch. 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-equity 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 our $1.2 billion five-year 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 September 30, 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 $125.6 million. A decline in our credit rating below investment grade may also significantly impact other business segments.
We have reviewed our commercial paper agreement, trust indentures, building leases, equipment leases, marketing and trading contracts, and other various contracts that may be subject to rating triggers, and we do not have a significant exposure. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating. Our five-year credit and short-term bridge financing agreements contain a provision that would cause the cost to borrow funds to increase based on the amount borrowed under these agreements if our credit rating is negatively adjusted. The agreements also contain a default provision based on a material adverse change. An adverse rating change is not defined as a default or material adverse change.
Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices in either physical or financial energy contracts may impact our overall liquidity due to the impact commodity price changes have 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 our pension plan and our 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 our 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.
Oklahoma Corporation Commission - On October 4, 2005, the OCC issued a final order on the application for a rate increase by Oklahoma Natural Gas. The OCC unanimously approved an annual rate increase of $57.5 million. In July, the Commission’s administrative law judge recommended an increase in annual revenues of approximately $58.0 million. Oklahoma Natural Gas implemented new rates, subject to refund, on July 28, 2005, based on the judge’s report. The refund obligation associated with the difference between the rates we have been collecting since July 28, 2005, and the OCC approved rate increase is not material to our financial results for the three- and nine-month periods.
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 investment in gas in storage. 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 categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at Oklahoma Natural Gas’ next general rate case. This interim relief expired on July 27, 2005, and was replaced by the rate increase of $57.5 million approved on October 4, 2005. As the final rate increase exceeded the interim revenues that were subject to refund, no refund obligation was incurred associated with this rate increase. At September 30, 2005, we have under-collected approximately $1.8 million of the revenues that we were
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entitled to recover under this order. We have been authorized to collect this deficiency in December 2005, by offsetting the amount against the final billing credit associated with the Joint Stipulation discussed below.
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 $2.0 million from the use of storage gas. We estimate expected savings of approximately $6.0 million from the use of storage that was 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 decreased by $48.0 million for the nine months ended September 30, 2005, compared with the same period in 2004. The decrease in operating cash flows was primarily the result of a net increase in working capital of $170.9 million in 2005 compared with a net increase in working capital of $60.2 million in 2004. In 2005, higher prices and our current positions with counterparties increased our Energy Services segment’s deposit (margin) requirements, which resulted in a decrease in operating cash flows.
Investing Cash Flows - Acquisitions in 2005 primarily represent the cash purchase of the Koch assets. The sale of our Production segment resulted in proceeds from the sale of discontinued component. The proceeds from sale of assets in 2005 resulted from the sale of Cimarex Energy Company common stock, formerly Magnum Hunter Resources (MHR) common stock. The MHR common stock was acquired upon exercise of MHR stock purchase warrants in February 2005, resulting in us paying $22.7 million which is included in changes in other investments, net.
Proceeds from the sale of certain natural gas transmission and gathering pipelines, compression assets and investments totaled $17.2 million for the nine months ended September 30, 2004.
Financing Cash Flows - In June 2005, we issued $800 million of notes and used a portion of the proceeds to repay commercial paper. The commercial paper had been issued to finance the Northern Border Partners acquisition, to repay $335 million of long-term debt that matured on March 1, 2005, and to meet operating needs. We incurred $1.35 billion of notes payable related to the Koch assets acquisition. This increase was partially offset by $643 million in payments on notes payable and commercial paper, which represents the cash received from the sale of our Production segment, and payments made in the normal course of operations.
During the first nine months of 2005, we paid $188.7 million to repurchase approximately 6.0 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.
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 swaps. 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 instruments originally hedged. In the second quarter of 2005, we terminated $500 million of our treasury rate-lock agreements, which resulted in us paying $2.4 million. This amount, net of tax, has been recorded to accumulated other comprehensive loss and will be recognized in the income statement over the term of the related debt issuances.
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. During the second and third quarters of 2004, we incurred $298 million of notes payable used in the ordinary course of business. 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.
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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, including anticipated operating income from the businesses we acquired on July 1, 2005, from Koch Industries, Inc. and affiliates; management’s plans and objectives for future operations; business prospects; outcome of regulatory and legal proceedings; market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain 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 our operations and other statements contained or incorporated in this Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “forecast,” “intend,” “believe,” “projection” or “goal.”
You should not place undue reliance on 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 and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
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Other factors and assumptions not identified above were also involved in the making of the forward-looking statements. The failure of those assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. We have no obligation and make no undertaking to update publicly or revise any forward-looking information.
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.
Kansas Gas Service uses derivative instruments to hedge the cost of anticipated gas purchases during the winter heating months and to protect Kansas Gas Service customers from upward volatility in the market price of natural gas. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas adjustment. At September 30, 2005, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 8.9 Bcf, which represents part of their gas purchase requirements for the 2005/2006 winter heating months.
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 sources and other assumptions (4)
Total
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Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
(Thousands of dollars)
Net fair value of contracts outstanding at December 31, 2004
Contracts realized or otherwise settled during the period
Fair value changes in all contracts
Net fair value of contracts outstanding at September 30, 2005
For further discussion of trading activities and assumptions used in our trading activities, see Accounting Treatment in Note D of the Notes to Consolidated Financial Statements included in this Form 10-Q.
Interest Rate and Currency Risk - At September 30, 2005, the interest rate on approximately 85 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 swaps. During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements and received 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 nine months of 2005 for all terminated swaps was $5.9 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:
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 September 30, 2005, we had a net liability of $5.4 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $5.4 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 $7.8 million for the first nine 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 $9.9 million, compared with the savings of $27.6 million in 2004.
Prior to the issuance of the $800 million of notes in the second quarter of 2005, we entered into $500 million in treasury rate-lock agreements to hedge the changes in cash flows of our anticipated interest payments from changes in treasury rates prior to the issuance of the notes. Upon issuance of the notes in June 2005, the treasury rate-lock agreements terminated, which resulted in us paying $2.4 million. This amount, net of tax, has been recorded to accumulated other comprehensive loss and will be recognized in the income statement over the term of the related debt issuances.
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 change 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
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the change in fair value are recorded in net margin. At September 30, 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 $43.9 million and $4.2 million at September 30, 2005, and 2004, respectively.
The following table details the average, high and low daily VAR calculations.
VAR
Average
High
Low
The variations in the VAR data are reflective of market volatility and changes in the portfolio during the quarter. In particular, there was significant volatility in the latter part of the third quarter of 2005.
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 September 30, 2005, in ensuring 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 September 30, 2005, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except for those controls described in the next paragraph.
In July 2005, we completed the acquisition of the natural gas liquids assets from Koch as more fully described in Note B in the Notes to our Consolidated Financial Statements included in Part I of this report. As part of our ongoing integration activities, we are in the process of developing and incorporating controls and procedures related to these assets into our internal controls over financial reporting. Until such controls are more fully developed, we have implemented and are relying on compensating controls and have performed extensive reviews of our reported results. As with any acquisition, there are inherent risks in the timing, development and implementation of internal controls that could negatively impact us; however, we do not believe they will have a material impact on our financial statements.
PART II - OTHER INFORMATION
In the Matter of the Application of Oklahoma Natural Gas Company, a Division of ONEOK, Inc., for a Review and Change or Modification in its Rates, Charges, Tariffs and Terms and Conditions of Service,Oklahoma Corporation Commission, Cause No. PUD 200400610. The four primary parties in this matter executed a Stipulation and Settlement Agreement, which resolved the various issues raised on appeal in the case. The Commission unanimously approved the settlement on October 4, 2005. The annual revenue increase is $57.5 million.
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Cornerstone Propane Partners, L.P., et al. v. E Prime, Inc., ONEOK Energy Marketing and Trading Company, L.P., ONEOK, Inc., and Calpine Energy Services, L.P., United States District Court for the Southern District of New York, Case No. 04-CV-00758. On October 3, 2005, the Court granted Plaintiffs’ Motion for Class Certification without a hearing.
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 August 11, 2005, the Judicial Panel on Multidistrict Litigation issued a Transfer Order transferring this matter to the District of Nevada for inclusion in the multi-district litigation (MDL-1566) proceedings In Re Western States Wholesale Natural Gas Antitrust Litigation.
Issuer Purchases of Equity Securities
The following table sets forth information relating to our purchases of equity securities during the three months ended September 30, 2005.
Period
July 1-31, 2005
August 1-31, 2005
September 1-30, 2005
173,801 shares for the period July 1-31, 2005
29,621 shares for the period August 1-31, 2005
60,842 shares for the period September 1-30, 2005
291 shares for the period July 1-31, 2005
243 shares for the period August 1-31, 2005
73 shares for the period September 1-30, 2005
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. In July 2005, our Board increased the total number of shares of our common stock available for issuance under this program from 50,000 to 100,000.
Through June 30, 2005, a total of 31,135 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 September 30, 2005, under this program.
Date
July 1, 2005
July 13, 2005
August 2, 2005
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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.
Date: November 4, 2005
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