UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
X Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2007
OR
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to .
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
Registrant’s telephone number, including area code (918) 588-7000
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes X No
Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filerX Accelerated filer Non-accelerated filer
Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No X
On July 31, 2007, the Company had 103,885,788 shares of common stock outstanding.
QUARTERLY REPORT ON FORM 10-Q
As used in this Quarterly Report on Form 10-Q, the terms “we,” “our” or “us” mean ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.
The statements in this Quarterly Report on Form 10-Q that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Forward Looking Statements” and Part II, Item 1A, “Risk Factors,” in this Quarterly Report on Form 10-Q and under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2006.
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Glossary
The abbreviations, acronyms, and industry terminology used in this Quarterly Report are defined as follows:
AFUDC
Allowance for funds used during construction
Bbl
Barrels, equivalent to 42 United States gallons
Bbl/d
Barrels per day
BBtu/d
Billion British thermal units per day
Bcf
Billion cubic feet
Bcf/d
Billion cubic feet per day
Btu
British thermal units
EITF
Emerging Issues Task Force
Exchange Act
Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FIN
FASB Interpretations
Fort Union Gas Gathering
Fort Union Gas Gathering, L.L.C.
GAAP
United States Generally Accepted Accounting Principles
Guardian Pipeline
Guardian Pipeline, L.L.C.
KCC
Kansas Corporation Commission
Koch
Koch Industries, Inc.
LDC
Local distribution company
LIBOR
London Interbank Offered Rate
MBbl/d
Thousand barrels per day
Mcf
Thousand cubic feet
MDth/d
Thousand decatherms per day
Midwestern Gas Transmission
Midwestern Gas Transmission Company
MMBtu
Million British thermal units
MMBtu/d
Million British thermal units per day
MMcf
Million cubic feet
MMcf/d
Million cubic feet per day
Moody’s
Moody’s Investors Service
NGL
Natural gas liquids
Northern Border Pipeline
Northern Border Pipeline Company
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
OBPI
ONEOK Bushton Processing Inc.
OCC
Oklahoma Corporation Commission
ONEOK
ONEOK Partners
ONEOK Partners, L.P., formerly known as Northern Border Partners, L.P.
ONEOK Partners GP
ONEOK Partners GP, L.L.C., formerly known as Northern Plains Natural Gas Company, LLC, a ONEOK subsidiary
Overland Pass Pipeline Company
Overland Pass Pipeline Company LLC
S&P
Standard & Poor’s Rating Group
SEC
Securities and Exchange Commission
Statement
Statement of Financial Accounting Standards
TC PipeLines
TC PipeLines Intermediate Limited Partnership, a subsidiary of TC PipeLines, LP
TransCanada
TransCanada Corporation
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PART I—FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
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
Gain (Loss) on Sale of Assets
Operating Income
Equity earnings from investments (Note M)
Other income
Other expense
Interest expense
Income before Minority Interests and Income Taxes
Minority interests in income of consolidated subsidiaries
Income taxes
Income from Continuing Operations
Discontinued operations, net of taxes (Note C)
Income (loss) from operations of discontinued components, net of tax
Net Income
Earnings Per Share of Common Stock (Note N)
Net earnings per share, basic
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
June 30,
2007
Assets
Current Assets
Cash and cash equivalents
Short-term investments
Trade accounts and notes receivable, net
Gas and natural gas liquids in storage
Commodity exchanges and imbalances
Energy marketing and risk management assets (Note D)
Other current assets
Total Current Assets
Property, Plant and Equipment
Property, plant and equipment
Accumulated depreciation, depletion and amortization
Net Property, Plant and Equipment (Note A)
Deferred Charges and Other Assets
Goodwill and intangible assets (Note E)
Investments in unconsolidated affiliates
Other assets
Total Deferred Charges and Other Assets
Total Assets
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Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt
Notes payable
Accounts payable
Energy marketing and risk management liabilities (Note D)
Other
Total Current Liabilities
Long-term Debt, excluding current maturities
Deferred Credits and Other Liabilities
Deferred income taxes
Other deferred credits
Total Deferred Credits and Other Liabilities
Commitments and Contingencies (Note J)
Minority Interests in Consolidated Subsidiaries
Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 120,999,567 sharesand outstanding 103,842,104 shares at June 30, 2007;issued 120,333,908 shares and outstanding 110,678,499shares at December 31, 2006
Paid in capital
Accumulated other comprehensive income (loss) (Note F)
Retained earnings
Treasury stock, at cost: 17,157,463 shares at June 30, 2007 and 9,655,409 shares at December 31, 2006
Total Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Net income
Gain on sale of assets
Distributions received from unconsolidated affiliates
Income from equity investments
Stock-based compensation expense
Allowance for doubtful accounts
Changes in assets and liabilities (net of acquisition and disposition effects):
Accounts and notes receivable
Inventories
Unrecovered purchased gas costs
Commodity exchanges and imbalances, net
Deposits
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 investments in unconsolidated affiliates
Acquisitions
Capital expenditures
Changes in short-term investments
Proceeds from sale of assets
Increase in cash and cash equivalents attributable to previously unconsolidated subsidiaries
Decrease in cash and cash equivalents attributable to previously consolidated subsidiaries
Other investing activities
Cash Used in Investing Activities
Financing Activities
Borrowing (repayment) of notes payable, net
Short-term financing payments
Short-term financing borrowings
Payment of debt
Equity unit conversion
Repurchase of common stock
Issuance of common stock
Dividends paid
Distributions to minority interests
Other financing activities
Cash Used in Financing Activities
Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Effect of Accounting Change on Cash and Cash Equivalents
Cash and Cash Equivalents at End of Period
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CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
December 31, 2006
Other comprehensive income (loss)
Total comprehensive income
(Note G)
Common stock issued pursuant to various plans
Stock-based employee compensation expense
Common stock dividends - $0.68 per share
June 30, 2007
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(Continued)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Our accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP 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 six months ended June 30, 2007, are not necessarily indicative of the results that may be expected for a 12-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, 2006.
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, 2006, except as described below.
Significant Accounting Policies
Short-Term Investments - Our short-term investments consist of auction-rate securities, which are corporate or municipal bonds that have underlying long-term maturities. The interest rates are reset through auctions that are typically held every 7-35 days, at which time the securities can be sold. We invest in auction-rate securities for a portion of our cash management program.
Property - The following table sets forth our property, by segment, for the periods presented.
Energy Services
Regulated
Distribution
Net property, plant and equipment
At June 30, 2007, we had construction work in process of $455.9 million that had not yet been put in service and therefore was not being depreciated. Of this amount, $394.8 million was related to our ONEOK Partners segment and $43.8 million was related to our Distribution segment.
Income Taxes - In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109,” which was effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the recognition of penalties and interest on any unrecognized tax benefits. Our policy is to reflect penalties and interest as part of income tax expense as they become applicable. The adoption of FIN 48 had an immaterial impact on our consolidated financial statements.
We file numerous consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. We also file returns in Canada. No returns are currently under audit, and no extensions of statute of limitations have been granted.
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Pension and Postretirement Employee Benefits - In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which required us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. Statement 158 was effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31, which will be effective for our year ending December 31, 2008.
Fair Value Measurements - In September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Statement 157 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 157 to our operations and its potential impact on our consolidated financial statements.
In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. Statement 159 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 159 to our operations and its potential impact on our consolidated financial statements.
In April 2007, the FASB issued Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” which permits companies that enter into master netting arrangements to offset cash collateral receivables or payables with net derivative positions under certain circumstances. FIN 39-1 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of FIN 39-1 to our operations and its potential impact on our consolidated financial statements.
Reclassifications - We reclassified our short-term investments in our Consolidated Statement of Cash Flows for the six months ended June 30, 2006, and reported the related cash flows as an investing activity. See our discussion on page 12 for a description of our short-term investments, which consist of investments in auction-rate securities. Auction-rate securities are highly liquid, but are more appropriately classified as short-term investments rather than cash equivalents. The impact on our Consolidated Statement of Cash Flows for the six months ended June 30, 2006, is as follows:
Cash provided by (used in) investing activities
Change in cash and cash equivalents
Cash and cash equivalents at end of period
These reclassifications were not material to our Consolidated Statement of Cash Flows for the six months ended June 30, 2006, and had no impact on our Consolidated Statements of Income or our Consolidated Balance Sheets for the periods presented.
Certain other amounts in our consolidated financial statements have been reclassified to conform to the 2007 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.
Acquisition of NGL Pipeline - In July 2007, ONEOK Partners announced its agreement to acquire an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan Energy Partners, L.P. for approximately $300 million. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined products. The FERC-regulated system spans more than 1,600 miles and has a capacity to transport up to 125,000 Bbl/d. The transaction includes approximately 950,000 Bbl of storage capacity, eight NGL terminals and 50 percent ownership of the Heartland Pipeline Company (Heartland). ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which
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consists primarily of three refined products terminals and connecting pipelines. In addition, ConocoPhillips has a right of first refusal to purchase the 50 percent ownership interest in Heartland that ONEOK Partners is seeking to acquire. ONEOK Partners expects to close the transaction, subject to regulatory approval, in the third quarter of 2007. Financing for this transaction will come from ONEOK Partners’ available cash and short-term credit facilities.
Overland Pass Pipeline Company - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company. Overland Pass Pipeline Company will build a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline will be initially designed to transport approximately 110,000 Bbl/d of NGLs, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture and will manage the construction project, advance all costs associated with construction and operate the pipeline. Within two years of the pipeline becoming operational, Williams will have the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required regulatory approvals as scheduled, ONEOK Partners currently expects construction of the pipeline to begin in the fall of 2007, with start-up scheduled for early 2008.
As part of a long-term agreement, Williams dedicated its NGL production from two of its natural gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is currently estimated to cost approximately $433 million, excluding AFUDC. During 2006, ONEOK Partners paid $11.6 million to Williams for acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. In addition, ONEOK Partners is investing approximately $216 million, excluding AFUDC, to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for the projects may include a combination of short- or long-term debt or equity.
ONEOK Partners - In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we own a total of approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, has increased to 45.7 percent.
Disposition of 20 Percent Interest in Northern Border Pipeline - In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became the operator of the pipeline in April 2007. Under Statement 94, “Consolidation of All Majority Owned Subsidiaries,” a majority-owned subsidiary is not consolidated if control is likely to be temporary or if it does not rest with the majority owner. Neither ONEOK Partners nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipeline’s Management Committee. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method, applied on a retroactive basis to January 1, 2006. TransCanada also paid us $10 million for expenses associated with the transfer of operating responsibility of Northern Border Pipeline to them.
Acquisition of Guardian Pipeline Interests - In April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006.
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In the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. We entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for approximately $53 million. The transaction received FERC approval, and the sale was completed on October 31, 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.
This component of our business is accounted for as discontinued operations in accordance with Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, amounts in our consolidated financial statements and related notes for the three and six months ended June 30, 2006, relating to our power generation business are reflected as discontinued operations.
Accounting Treatment - We account for derivative instruments and hedging activities in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities.” Under Statement 133, entities are required to record all derivative instruments at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative instrument in earnings as they occur. We record changes in the fair value of derivative instruments that are considered held for trading purposes as energy trading revenues, net and derivative instruments considered not held for trading purposes as cost of sales and fuel in our Consolidated Statements of Income. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness, which is reported in earnings during the period the ineffectiveness occurs. 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 accumulated other comprehensive income (loss) and is subsequently recorded in earnings when the forecasted transaction affects earnings.
As required by Statement 133, we formally document all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.
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, 2006, for additional discussion.
Fair Value Hedges - In prior years, we and ONEOK Partners terminated various interest-rate swap agreements. 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 six months ended June 30, 2007, for all terminated swaps were $5.2 million, and the remaining net savings for all terminated swaps will be recognized over the following periods.
Remainder of 2007
2008
2009
2010
2011
Thereafter
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Currently, the interest on $490 million of fixed-rate debt is swapped to floating using interest-rate swaps. The floating-rate is based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance through June 30, 2007, the weighted average interest rate on the swapped debt increased from 6.64 percent to 6.96 percent. At June 30, 2007, we recorded a net liability of $24.1 million to recognize the interest-rate swaps at fair value. Long-term debt was decreased by $24.1 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 and ineffectiveness are recorded to cost of sales and fuel. The ineffectiveness related to these hedges includes losses of $3.3 million and $3.9 million for the three months ended June 30, 2007 and 2006, respectively. The ineffectiveness related to these hedges included losses of $5.7 million and $9.3 million for the six months ended June 30, 2007 and 2006, respectively.
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 the transportation of natural gas. Accumulated other comprehensive income (loss) at June 30, 2007, includes gains of approximately $3.1 million, net of tax, related to these hedges that will be realized within the next 23 months. If prices remain at current levels, we will recognize $9.3 million in net gains over the next 12 months, and we will recognize net losses of $6.2 million thereafter. In accordance with Statement 133, the actual gains or losses that are reclassified into earnings will be based on the referenced floating price at each designated pricing period, along with the realization of the gains or losses on the related physical volumes, which are not reflected in the amounts above.
Our ONEOK Partners segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas, NGLs and condensate. If prices remain at current levels, our ONEOK Partners segment will recognize $2.3 million in net losses, all of which will be recognized over the next nine months.
Our Distribution segment also uses derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect their 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 June 30, 2007, Kansas Gas Service had derivative instruments in place to fix the cost of natural gas purchases for 2.6 Bcf, which represents part of its gas purchase requirements for the 2007/2008 winter heating months.
For all of our segments, net gains and losses are reclassified out of accumulated other comprehensive income (loss) to operating revenues or cost of sales and fuel in the period the ineffectiveness occurs. Ineffectiveness related to our cash flow hedges resulted in a loss of approximately $0.5 million and a loss of approximately $0.7 million for the three and six months ended June 30, 2007, respectively. Ineffectiveness related to our cash flow hedges resulted in a gain of approximately $2.3 million and a gain of approximately $9.5 million for the three and six months ended June 30, 2006, respectively. There were no material gains or losses during the three and six months ended June 30, 2007 and 2006, due to the discontinuance of cash flow hedge treatment.
Goodwill
Carrying Amounts - The amount of goodwill recorded on our Consolidated Balance Sheets as of June 30, 2007, and December 31, 2006, was $600.7 million.
Equity Method Goodwill - For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets includes equity method goodwill of $185.6 million as of June 30, 2007, and December 31, 2006.
Intangible Assets
Our ONEOK Partners segment had $291.3 million of intangible assets related to contracts acquired through our acquisition of the natural gas liquids businesses from Koch, which are being amortized over an aggregate weighted-average period of 40 years. The remaining intangible asset balance has an indefinite life. The aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. Amortization expense for intangible assets for the three and six months ended June 30, 2007, was $1.9 million and $3.8 million, respectively.
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The following table reflects the gross carrying amount and accumulated amortization of intangible assets at June 30, 2007, and December 31, 2006.
The tables below show the gross amount of comprehensive income (loss) and related tax (expense) benefit for the periods indicated.
Unrealized gains (losses) on energy marketing and risk management assets/liabilities
Unrealized holding losses arising during the period
Realized gains recognized in net income
Pension and postretirement benefit plan amortization
Unrealized holding gains arising during the period
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The table below shows the balance in accumulated other comprehensive income (loss) for the periods indicated.
Stock Repurchase Plan - We have no remaining shares available for repurchase under our stock repurchase plan.
On May 17, 2007, our Board of Directors authorized a stock buy back program to repurchase up to 7.5 million shares of our currently issued and outstanding common stock. On June 28, 2007, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with Bank of America, N.A. (Bank of America) at an initial price of $49.33 per share for a total of $370 million, which completed the plan approved by our Board of Directors. These shares were recorded as treasury shares in our Consolidated Balance Sheet as of June 30, 2007. Bank of America borrowed 7.5 million of our shares from third parties and will purchase shares in the open market to settle its short position. Our repurchase is subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by Bank of America over the course of the repurchase period. The price adjustment can be settled, at our option, in cash or in shares of our common stock. If we had settled at June 30, 2007, we would have owed Bank of America approximately $3.6 million related to the price adjustment.
On August 7, 2006, under a previously authorized stock repurchase plan, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52 per share for a total of $281.4 million. These shares were recorded as treasury shares in our Consolidated Balance Sheets. UBS borrowed 7.5 million of our shares from third parties and purchased shares in the open market to settle its short position. Our repurchase was subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment could have been settled, at our option, in cash or in shares of our common stock. In February 2007, the forward purchase contract with UBS was settled for a cash payment of $20.1 million, which was recorded in equity.
In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchases were accounted for as two separate transactions: (1) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (2) as a forward contract indexed to our common stock. Additionally, we classified the forward contracts as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.”
Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2007 and April 30, 2007, were $0.34 per share. Additionally, on July 19, 2007, we declared a quarterly dividend of $0.36 per share ($1.44 per share on an annualized basis) payable on August 14, 2007, to shareholders of record on July 31, 2007.
General - On March 30, 2007, ONEOK Partners amended and restated its five-year revolving credit facility agreement (2007 Partnership Credit Agreement), with several banks and other financial institutions and lenders in the following principal ways: (i) revised the pricing, (ii) extended the maturity by one year to March 2012, (iii) eliminated the interest coverage ratio covenant, (iv) increased the permitted ratio of indebtedness to EBITDA to 5 to 1 (from 4.75 to 1), (v) increased the swingline sub-facility commitments from $15 million to $50 million and (vi) changed the permitted amount of subsidiary indebtedness from $35 million to 10 percent of ONEOK Partners’ consolidated indebtedness.
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In July 2007, ONEOK Partners exercised the accordion feature in its 2007 Partnership Credit Agreement to increase the commitment amounts by $250 million to a total of $1.0 billion.
Except as discussed above, our $1.2 billion five-year credit agreement, as amended and restated in 2006, and ONEOK Partners’ 2007 Partnership Credit Agreement, contain typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006. At June 30, 2007, we and ONEOK Partners were in compliance with all covenants.
At June 30, 2007, we had $78.7 million in letters of credit issued and no borrowings outstanding under our various credit agreements, and ONEOK Partners had $10 million in letters of credit issued and $105 million in borrowings outstanding under its 2007 Partnership Credit Agreement.
The following table sets forth the components of net periodic benefit cost for our pension and other postretirement benefit plans for the periods indicated.
Pension BenefitsThree Months Ended
Pension BenefitsSix Months Ended
Service cost
Interest cost
Expected return on assets
Amortization of unrecognized prior service cost
Amortization of net loss
Net periodic benefit cost
Postretirement BenefitsThree Months Ended
Postretirement BenefitsSix Months Ended
Amortization of unrecognized net asset at adoption
Amortization of loss
Contributions - For the six months ended June 30, 2007, contributions of $1.9 million were made to our pension plan and $1.9 million to our postretirement benefit plan. Additionally, we made benefit payments from our pension plan of $1.1 million and from our postretirement benefit plan of $7.7 million in the six months ended June 30, 2007. We presently anticipate our total 2007 contributions to fund future benefits will be $1.9 million for the pension plan and $5.5 million for the other postretirement benefit plan. Additionally, the 2007 expected benefit payments from our pension plan are estimated to be $2.3 million and expected benefit payments from our postretirement benefit plan are estimated to be $22.1 million.
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Environmental Liabilities - 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 our results of operations, and there have been no material effects upon earnings during 2007 related to compliance with environmental regulations. See Note K of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006, for additional discussion. There has been no material change to the status of the manufactured gas sites since December 31, 2006.
Segment Descriptions - We have divided our operations into four reportable segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows: (1) our ONEOK Partners segment gathers, processes, transports and stores natural gas; gathers, treats, stores and fractionates NGLs; and provides NGL gathering and distribution services; (2) our Distribution segment delivers natural gas to residential, commercial and industrial customers, and transports natural gas; (3) our Energy Services segment markets natural gas to wholesale and retail customers; and (4) our Other segment primarily consists of the operating and leasing operations of our headquarters building and a related parking facility. Our Distribution segment is comprised of regulated public utilities, and portions of our ONEOK Partners segment are also regulated.
Accounting Policies - The accounting policies of the segments are the same as those described in Note A and Note M of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006. Intersegment 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.
Customers - We had no single external customer from which we received 10 percent or more of our consolidated gross revenues.
Operating Segment Information - The following tables set forth certain operating segment financial data for the periods indicated.
Sales to unaffiliated customers
Intersegment sales
Total revenues
Net margin
Operating costs
Gain (loss) on sale of assets
Operating income
Equity earnings from investments
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $69.7 million, net margin of $61.0 million and operating income of $25.5 million for the three months ended June 30, 2007.
(b) - All of our Distribution segment’s operations are regulated.
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Loss from operations of discontinued components
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $69.9 million, net margin of $62.8 million and operating income of $143.8 million, including $113.9 million gain on sale of assets, for the three months ended June 30, 2006.
Total assets
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $145.8 million, net margin of $127.6 million and operating income of $59.5 million, for the six months ended June 30, 2007.
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(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $146.7 million, net margin of $129.3 million and operating income of $178.1 million, including $113.9 million gain on sale of assets, for the six months ended June 30, 2006.
The following table sets forth supplemental information with respect to our cash flow for the periods indicated.
Six Months Ended
Cash paid (received) during the period
Interest
Equity Earnings from Investments- - The following table sets forth our equity earnings from investments for the periods indicated. All amounts in the table below are equity earnings from investments in our ONEOK Partners segment for the periods indicated.
Bighorn Gas Gathering, L.L.C.
Venice Energy Services Company, L.L.C. (a)
Lost Creek Gathering Company, L.L.C.
(a) - Venice Energy Services Company, L.L.C. is a cost method investment.
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Unconsolidated Affiliates Financial Information - Summarized combined financial information of our unconsolidated affiliates is presented below.
Operating revenue
Operating expenses
Distributions paid to ONEOK Partners
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, 2006.
The following tables set forth the computations of the basic and diluted EPS for the periods indicated.
Income from continuing operations available for common stock
Diluted EPS from continuing operations
Effect of options and other dilutive securities
Income from continuing operations available for common stock and common stock equivalents
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Mandatory convertible units
Options and other dilutive securities
There were no anti-dilutive option shares for the three months ended June 30, 2007. There were 341,300 option shares excluded from the calculation of diluted EPS for the three months ended June 30, 2006, since their inclusion would have been anti-dilutive for the period. There were 9,202 and 390,112 option shares excluded from the calculation of diluted EPS for the six months ended June 30, 2007 and 2006, respectively, since their inclusion would have been anti-dilutive for each period.
General Partner Interest - See Note B for discussion of the April 2006 acquisition of the additional general partner interest in ONEOK Partners. The limited partner units we received from ONEOK Partners were newly created Class B limited partner units. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on our common units and generally have the same voting rights as our common units. Under the ONEOK Partners’ partnership agreement and in conjunction with the issuance of additional common units by ONEOK Partners, we, as the general partner, are required to make equity contributions in order to maintain our representative general partner interest.
Our investment in ONEOK Partners at both June 30, 2007 and 2006, is shown in the table below.
General partner interest
Limited partner interest
Total ownership interest
(a) - Represents approximately 0.5 million common units and 36.5 million Class B units.
Cash Distributions - Under the ONEOK Partners’ partnership agreement, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash. Available cash generally consists of all cash receipts adjusted for cash disbursements and net changes to cash reserves. Available cash will generally be distributed 98 percent to limited partners and 2 percent to the general partner. As an incentive, the general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, the general partner receives:
15 percent of amounts distributed in excess of $0.605 per unit,
25 percent of amounts distributed in excess of $0.715 per unit, and
50 percent of amounts distributed in excess of $0.935 per unit.
ONEOK Partners’ income is allocated to the general and limited partners in accordance with their respective partnership ownership percentages. The effect of any incremental income allocations for incentive distributions that are allocated to the general partner is calculated after the income allocation for the general partner’s partnership interest and before the income allocation to the limited partners.
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The following table shows ONEOK Partners’ general partner and incentive distributions related to the periods indicated.
General partner distributions
Incentive distributions
Total distributions received from ONEOK Partners
The quarterly distributions paid by ONEOK Partners to limited partners in the first and second quarters of 2007 were $0.98 per unit and $0.99 per unit, respectively. The quarterly distributions paid by ONEOK Partners to limited partners in the first and second quarters of 2006 were $0.80 per unit and $0.88 per unit, respectively.
In July 2007, ONEOK Partners declared a cash distribution of $1.00 per unit payable in the third quarter.
Relationship - We own 45.7 percent of ONEOK Partners and consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows of ONEOK Partners except for our quarterly distributions. Distributions are declared quarterly by ONEOK Partners based on the terms of its partnership agreement, and for the three months ended June 30, 2007 and 2006, cash distributions declared from ONEOK Partners to us totaled $51.1 million and $44.2 million, respectively. For the six months ended June 30, 2007 and 2006, cash distributions declared from ONEOK Partners to us totaled $101.0 million and $48.0 million, respectively. See Note K for more information on ONEOK Partners’ results.
Affiliate Transactions - We have certain transactions with our ONEOK Partners affiliate and its subsidiaries, which comprise our ONEOK Partners segment.
ONEOK Partners sells natural gas from its gathering and processing operations to our Energy Services segment. In addition, a large portion of ONEOK Partners’ revenues from its pipelines and storage operations are from our Energy Services and Distribution segments, which utilize ONEOK Partners’ transportation and storage services.
As part of the transaction between us and ONEOK Partners, ONEOK Partners acquired certain contractual rights to the Bushton Plant from us through a Processing and Services Agreement, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012. ONEOK Partners has contracted for all of the capacity of the Bushton Plant from OBPI. In exchange, ONEOK Partners pays us for all direct costs and expenses of the Bushton Plant, including reimbursement of a portion of our obligations under equipment leases covering the Bushton Plant. Volumes available for processing at this straddle plant have declined due to contract terminations and natural field declines, which made it more efficient to process the remaining natural gas at other facilities. On January 1, 2007, the Bushton Plant was temporarily idled. New facilities are being added to the Bushton Plant. The Bushton Plant will resume operations once these facilities are complete and Overland Pass Pipeline begins operating.
We provide a variety of services to our affiliates, including cash management and financing services, employee benefits provided through our benefit plans, administrative services provided by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs are allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a service that applies equally to all employees is allocated based upon the number of employees in each affiliate. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and wages.
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The following table shows transactions with ONEOK Partners for the periods shown.
Revenue
Expense
Administrative and general expenses
Total expense
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The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2006. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2007, are not necessarily indicative of the results that may be expected for a 12-month period.
EXECUTIVE SUMMARY
The following discussion highlights some of our achievements and significant issues affecting us for the periods presented. Please refer to the Financial and Operating Results section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements for a complete explanation of the following items.
Diluted earnings per share of common stock from continuing operations (EPS) decreased to $0.31 for the three months ended June 30, 2007, compared with $0.65 for the same period in 2006. For the six-month period, EPS decreased to $1.67 from $1.80 for the same period last year. Operating income for the three months ended June 30, 2007, decreased to $135.7 million from $269.6 million for the same period in 2006, and for the six-month period decreased to $464.0 million from $539.9 million for the same period in 2006. Excluding the gain (loss) on sale of assets, which primarily relates to the $113.9 million gain on the sale of a 20 percent interest in Northern Border Pipeline in the second quarter of 2006, operating income decreased to $136.1 million for the three-month period, compared with $154.5 million for the same period last year, and increased to $462.2 million for the six-month period, compared with $423.6 million for the same period last year. The decrease in operating income for the three-month period is primarily due to our Energy Services segment’s decreased storage and marketing margins and financial trading margins, partially offset by its increased transportation margins. This decrease was partially offset by the implementation of new rate schedules in Kansas and Texas in our Distribution segment. The increase in operating income for the six-month period, exclusive of the gain (loss) on sale of assets, is primarily due to the implementation of new rate schedules in Kansas and Texas in our Distribution segment. Our Energy Services segment partially offset this increase as a result of decreased transportation, financial trading and retail margins, partially offset by increased storage and marketing margins in the six-month period.
ONEOK Partners declared an increase in its cash distribution to $1.00 per unit ($4.00 per unit on an annualized basis) in July 2007, an increase of approximately 5 percent over the $0.95 declared in July 2006. ONEOK declared an increase in its cash dividend to $0.36 per share ($1.44 per share on an annualized basis) in July 2007, an increase of approximately 13 percent over the $0.32 paid in the third quarter of 2006.
SIGNIFICANT ACQUISITIONS AND DIVESTITURES
Acquisition of NGL Pipeline - In July 2007, ONEOK Partners announced its agreement to acquire an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan Energy Partners, L.P. for approximately $300 million. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined products. The FERC-regulated system spans more than 1,600 miles and has a capacity to transport up to 125,000 Bbl/d. The transaction includes approximately 950,000 Bbl of storage capacity, eight NGL terminals and 50 percent ownership of the Heartland Pipeline Company (Heartland). ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which consists primarily of three refined products terminals and connecting pipelines. In addition, ConocoPhillips has a right of first refusal to purchase the 50 percent ownership interest in Heartland that ONEOK Partners is seeking to acquire. ONEOK Partners expects to close the transaction, subject to regulatory approval, in the third quarter of 2007. Financing for this transaction will come from ONEOK Partners’ available cash and short-term credit facilities and will be accounted for in our ONEOK Partners segment.
In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we own a total of approximately 37.0 million common and Class B limited
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partner units and the entire 2 percent general partner interest and control the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, has increased to 45.7 percent. This acquisition and divestiture is accounted for in our ONEOK Partners segment.
In connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became the operator of the pipeline in April 2007. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method, applied on a retroactive basis to January 1, 2006. This transaction is accounted for in our ONEOK Partners segment. TransCanada also paid us $10 million for expenses associated with the transfer of operating responsibility of Northern Border Pipeline to them.
Also in April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006. This acquisition is accounted for in our ONEOK Partners segment.
CAPITAL PROJECTS
All of the capital projects discussed below are in our ONEOK Partners segment.
Piceance Lateral Pipeline - In March 2007, ONEOK Partners announced that Overland Pass Pipeline Company plans to construct a 150-mile lateral pipeline to transport as much as 100,000 Bbl/d of NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams announced that it intends to construct a new natural gas processing plant in the Piceance Basin and will dedicate its NGL production from that plant and an existing plant to be delivered into the lateral pipeline. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required regulatory approvals, ONEOK Partners currently expects construction of this lateral pipeline extension to begin in the summer of 2008 and be completed in early 2009, at a current cost estimate of approximately $120 million, excluding AFUDC.
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Arbuckle Pipeline Natural Gas Liquids Pipeline Project - In March 2007, ONEOK Partners announced plans to build the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast, at a cost of $260 million, excluding AFUDC. The Arbuckle Pipeline will have the capacity to transport 160,000 Bbl/d of raw natural gas liquids and will interconnect with our existing Mid-Continent infrastructure and our fractionation facility in Mont Belvieu, Texas, and other Gulf Coast-area fractionators. The expansion project is expected to be completed by early 2009.
Williston Basin Gas Processing Plant Expansion - In March 2007, a subsidiary of ONEOK Partners, announced the expansion of its Grasslands natural gas processing facility in North Dakota at a cost of $30 million, excluding AFUDC. The Grasslands facility is ONEOK Partners’ largest natural gas processing plant in the Williston Basin. The expansion will increase processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d as well as increasing fractionation capacity to approximately 10,000 Bbl/d from 7,700 Bbl/d. The expansion project is expected to come on line in phases starting in late summer of 2007 through the first quarter of 2008.
Fort Union Gas Gathering Expansion Project - In January 2007, Crestone Powder River, L.L.C., a subsidiary of ONEOK Partners, announced that Fort Union Gas Gathering will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines, resulting in 649 MMcf/d of additional capacity in the Powder River basin. The expansion is expected to cost approximately $110 million, excluding AFUDC, which will be financed within the Fort Union Gas Gathering partnership and will occur in two phases, with 240 MMcf/d expected to be in service by the fourth quarter of 2007 and 409 MMcf/d by the first quarter of 2008. The additional capacity has been fully subscribed for 10 years beginning with the in-service date of the expansion. Crestone Powder River, L.L.C. owns approximately 37 percent of Fort Union Gas Gathering. This project is accounted for under the equity method of accounting.
Guardian Pipeline Expansion and Extension Project - In October 2006, Guardian Pipeline, a subsidiary of ONEOK Partners, filed its application for a certificate of public convenience and necessity with the FERC for authorization to construct and operate approximately 110 miles of new mainline pipe, two compressor stations, seven meter stations and other associated facilities. The pipeline expansion will extend Guardian Pipeline from the Milwaukee, Wisconsin, area to the Green Bay, Wisconsin, area. The project is supported by long-term shipper commitments. The cost of the project is estimated to be $250 million, excluding AFUDC, with a targeted in-service date of November 2008.
Midwestern Gas Transmission Eastern Extension Project - In March 2006, Midwestern Gas Transmission, a subsidiary of ONEOK Partners, accepted the certificate of public convenience and necessity issued by the FERC for its Eastern Extension Project. An organization that is opposed to, and includes landowners affected by, the project filed a request for rehearing and for a stay of the March 2006 Order. In August 2006, the FERC denied those requests. In July 2007, ONEOK Partners received FERC authorization to construct, which is a notice to proceed. Construction has begun and the pipeline extension is anticipated to be in service in the fourth quarter of 2007. The Eastern Extension Project will add approximately 31 miles of pipeline with 120 MDth/d (approximately 120 MMcf/d) of transportation capacity with total capital expenditures estimated to be $41 million, excluding AFUDC.
REGULATORY
Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution segment. See discussion of our Distribution segment’s regulatory initiatives on page 35.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” Statement 157, “Fair Value Measurements,” Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” and FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” are included in Note A of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.
Information about our critical accounting estimates is included under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates,” in our Annual Report on Form 10-K for the year ended December 31, 2006.
FINANCIAL AND OPERATING RESULTS
Consolidated Operations
Selected Financial Information - The following table sets forth certain selected consolidated financial information for the periods indicated.
0perating costs
Operating Results - Net margin decreased for the three months ended June 30, 2007, compared with the same period in 2006, primarily due to our Energy Services segment’s decreased storage and marketing margins and financial trading margins, partially offset by its increased transportation margins. This decrease was also partially offset by the implementation of new rate schedules in Kansas and Texas in our Distribution segment.
Net margin increased for the six months ended June 30, 2007, compared with the same period in 2006, primarily due to the implementation of new rate schedules in Kansas and Texas in our Distribution segment. Our Energy Services segment partially offset this increase. Our Energy Services segment experienced decreased transportation, financial trading and retail margins, partially offset by increased storage and marketing margins in the six-month period.
Net margin was also positively impacted for both the three- and six-month periods by our ONEOK Partners segment due to ONEOK Partners’ natural gas liquids business benefiting from higher product price spreads; higher isomerization price spreads; and increased natural gasoline sales used in the production of ethanol fuel. This increase was partially offset by decreased net margin in ONEOK Partners’ gathering and processing business, primarily due to lower volumes processed associated with the anticipated contract terminations at certain processing facilities.
Depreciation and amortization decreased for the three and six months ended June 30, 2007, primarily due to a goodwill and asset impairment charge of $11.8 million recorded in the second quarter of 2006 related to Black Mesa Pipeline, Inc., which is included in our ONEOK Partners segment.
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Gain (loss) on sale of assets decreased for the three and six months ended June 30, 2007, primarily due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded during the second quarter of 2006 in our ONEOK Partners segment.
Equity earnings from investments for the three and six months ended June 30, 2007 and 2006, primarily include earnings from ONEOK Partners’ interest in Northern Border Pipeline. The decrease in equity earnings for the six-month period is primarily due to the decrease in ONEOK Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent in the second quarter of 2006. See page 28 for discussion of ONEOK Partners’ disposition of the 20 percent partnership interest in Northern Border Pipeline.
Interest expense increased for the six-month period ended June 30, 2007, primarily due to the additional borrowings by ONEOK Partners to complete the April 2006 transactions with us. This resulted in $21.3 million in lower interest expense in the first quarter of 2006 compared with the same period in 2007. The increased interest expense was partially offset by lower short-term interest expense of $12.1 million during the six months ended June 30, 2007, as compared with the same period in 2006, as a result of the proceeds from the sale of assets to ONEOK Partners, which reduced short-term debt.
Minority interest in income of consolidated subsidiaries for the three and six months ended June 30, 2007 and 2006, reflects the remaining 54.3 percent of ONEOK Partners that we do not own. For the three-and six-month periods ended June 30, 2007, minority interest was lower due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006 in our ONEOK Partners segment. Additionally, minority interest in net income of consolidated subsidiaries for our ONEOK Partners’ segment for the six months ended June 30, 2006, included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline for the six months ended June 30, 2007.
Additional information regarding our results of operations is provided in the discussion of operating results for each of our segments.
Overview - We own 45.7 percent of ONEOK Partners. The remaining interest in ONEOK Partners is reflected as minority interest in income of consolidated subsidiaries on our Consolidated Statements of Income.
ONEOK Partners gathers and processes natural gas and fractionates NGLs primarily in the Mid-Continent and Rocky Mountain regions. ONEOK Partners’ operations include the gathering of natural gas production from crude oil and natural gas wells. Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, iso-butane, normal butane and natural gasoline (collectively NGL products). 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.
The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed form until they are fractionated. ONEOK Partners gathers, stores, fractionates and treats mixed NGLs, and stores NGL products produced from gas processing plants located in Oklahoma, Kansas and the Texas panhandle. ONEOK Partners’ fractionators, by applying heat and pressure, separate each NGL component into marketable NGL products that can then be stored or distributed to petrochemical, heating and motor gasoline manufacturers. ONEOK Partners’ NGL assets connect the NGL production basins in Oklahoma, Kansas and the Texas panhandle with the key NGL market centers in Conway, Kansas, and Mont Belvieu, Texas.
ONEOK Partners also operates intrastate and FERC-regulated interstate natural gas transmission pipelines, natural gas storage and FERC-regulated and intrastate natural gas liquids gathering and distribution pipelines and non-processable natural gas gathering facilities. ONEOK Partners also provides interstate natural gas transportation service under Section 311(a) of the Natural Gas Policy Act.
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Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our ONEOK Partners segment for the periods indicated.
Three Months Ended
Depreciation and amortization
Total gas gathered (BBtu/d)
Total gas processed (BBtu/d)
Natural gas liquids gathered (MBbl/d)
Natural gas liquids sales (MBbl/d)
Natural gas liquids fractionated (MBbl/d)
Natural gas liquids transported (MBbl/d)
Natural gas transported (MMcf/d)
Natural gas sales (BBtu/d)
Capital expenditures (Thousands of dollars)
Conway-to-Mont Belvieu OPIS average spread Ethane/Propane mixture ($/gallon)
Realized composite NGL sales prices ($/gallon)
Realized condensate sales price ($/Bbl)
Realized natural gas sales price ($/MMBtu)
Realized gross processing spread ($/MMBtu)
Operating Results - Net margin increased for the three and six months ended June 30, 2007, primarily due to ONEOK Partners’ natural gas liquids business, which benefited from higher product price spreads; higher isomerization price spreads; and increased natural gasoline sales used in the production of ethanol fuel. This increase was partially offset by decreased net margin in ONEOK Partners’ gathering and processing business, primarily due to lower volumes processed associated with the anticipated contract terminations at certain processing facilities.
Operating costs increased for the three and six months ended June 30, 2007, primarily due to higher employee-related costs.
Depreciation and amortization decreased for the three and six months ended June 30, 2007, primarily due to a goodwill and asset impairment charge of $11.8 million recorded in the second quarter of 2006 related to Black Mesa Pipeline, Inc.
Gain (loss) on sale of assets decreased for the three and six months ended June 30, 2007, primarily due to the $113.9 million gain on the sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006.
Equity earnings from investments for the three and six months ended June 30, 2007 and 2006, primarily include earnings from ONEOK Partners’ interest in Northern Border Pipeline. The decrease in equity earnings from investments for the six-month period is primarily due to the decrease in ONEOK Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006. See page 28 for discussion of the disposition of the 20 percent partnership interest in Northern Border Pipeline.
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Minority interest in income of consolidated subsidiaries decreased for the six months ended June 30, 2007, compared with the same period in 2006, primarily due to Guardian Pipeline. Minority interest in income of consolidated subsidiaries for the six months ended June 30, 2006, included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline for the six months ended June 30, 2007.
The increase in capital expenditures for the three- and six-month periods ended June 30, 2007, is driven primarily by ONEOK Partners’ capital projects which are discussed beginning on page 28.
Overview - Our Distribution segment provides natural gas distribution services to over two 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 addition, our distribution companies in Oklahoma and Kansas serve wholesale customers, and in Texas we serve public authority customers.
Selected Financial Information - The following table sets forth certain selected financial information for our Distribution segment for the periods indicated.
Gas sales
Transportation revenues
Cost of gas
Margin
Other revenues
Loss on sale of assets
Operating Results - Net margin increased by $10.7 million for the three months ended June 30, 2007, compared with the same period in 2006, primarily due to an increase of $10.9 million resulting from the implementation of new rate schedules, which includes $9.8 million in Kansas and $1.1 million in Texas.
Net margin increased by $42.5 million for the six months ended June 30, 2007, compared with the same period in 2006, primarily due to:
an increase of $32.1 million resulting from the implementation of new rate schedules, which includes $28.8 million in Kansas and $3.3 million in Texas and
an increase of $10.7 million from higher customer sales volumes as a result of a return to more normal weather in our entire service territory.
Operating costs increased $5.3 million for the six months ended June 30, 2007, compared with the same period in 2006, primarily due to:
an increase of $2.1 million in employee-related costs,
an increase of $2.0 million in bad debt expense, and
an increase of $2.0 million due to higher property taxes.
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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
Residential
Commercial
Industrial
Wholesale
Public Authority
Total volumes sold
Transportation
Total volumes delivered
Margin on gas sales
Residential and commercial volumes increased for the three- and six-month periods due to a return to more normal weather from the unseasonably warm weather in 2006.
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 decreased for the three and six months ended June 30, 2007, compared with the same periods of 2006, due to reduced volumes available for sale.
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 $11.8 million and $11.3 million for new business development for the three months ended June 30, 2007 and 2006, respectively, and $21.4 million and $24.8 million for new business development for the six months ended June 30, 2007 and 2006, respectively. The decrease in new business capital expenditures during the first six months of 2007, compared with the same period in 2006, resulted from:
warmer than normal weather in the first quarter of 2006, which favorably impacted construction and
wet weather in the second quarter of 2007, which had an unfavorable impact on construction activity.
While capital expenditures for the six months ended June 30, 2007, are lower than the same period last year, we expect our 2007 capital expenditures to be consistent with our 2006 capital expenditures.
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Regulatory Initiatives
Oklahoma - On January 31, 2007, Oklahoma Natural Gas filed an application at the OCC seeking recovery of costs incurred in compliance with the federal Pipeline Safety Improvement Act of 2002. In the most recent rate filing, the parties stipulated that transmission pipeline Integrity Management Program (IMP) costs should be addressed in a subsequent proceeding, and in the order issued October 2005, the OCC authorized Oklahoma Natural Gas to defer such costs (inclusive of operations and maintenance expense, depreciation, ad valorem taxes and a rate of return). The new application seeks recovery of all costs through July 2007, which are currently $6.7 million in IMP deferrals. The hearing on the application is scheduled for August 9, 2007.
Kansas - In May 2006, Kansas Gas Service announced that it filed a request with the KCC to increase its annual revenues by $73.3 million. Since its last rate case in 2003, Kansas Gas Service had invested approximately $170 million in its natural gas distribution system to provide service for 642,000 Kansas customers. In October 2006, Kansas Gas Service reached a settlement with the KCC staff and all other involved parties to increase annual revenues by approximately $52 million. The terms of the settlement were approved by the KCC in November 2006. The rate increase is effective for services rendered on or after January 1, 2007.
General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71, “Accounting for the Effects of Certain Types of Regulation.” Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.
Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. 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 96 Bcf, with maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.5 Bcf/d. Our current transportation capacity is 1.6 Bcf/d. Our contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. With these contracted assets, our business strategies include identifying, developing and delivering specialized services and products valued by 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.
Our Energy Services segment conducts business with ONEOK Partners, our 45.7 percent owned affiliate, which comprises our ONEOK Partners segment. Our Energy Services segment also conducts business with our Distribution segment. These services are provided under agreements with market-based terms.
Due to seasonality of natural gas consumption, earnings are normally higher during the winter months than the summer months. Our Energy Services segment’s margins are subject to fluctuations during the year primarily due to the impact certain seasonal factors have on sales volumes and the price of natural gas. Natural gas sales volumes are typically higher in the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices that occur during the winter heating months. During periods of high natural gas demand, we utilize storage capacity to supplement natural gas supply volumes to meet peak day demand obligations or market needs.
Numerous risk management opportunities and operational strategies exist that can be implemented through the use of storage facilities and transportation capacity. We utilize our industry knowledge and expertise in order to capitalize on opportunities that are provided through market volatility. We utilize our experience to optimize the value of our contracted assets, and we use our risk management and marketing capabilities to both manage risk and to deploy a limited amount of risk capital to generate additional returns. We manage our contracted transportation and storage capacity by utilizing derivative instruments such as over-the-counter forward, swap and option contracts and NYMEX futures and option contracts. We apply a combination of cash-flow and fair-value hedge accounting when implementing hedging strategies that take advantage of favorable market conditions. See Note D of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for additional information. Additionally, certain non-trading transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, will not qualify for hedge accounting treatment. These economic hedges receive mark-to-market accounting treatment, as they are derivative contracts and are not designated as part of a hedge relationship.
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Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our Energy Services segment for the periods indicated.
Energy and power revenues
Natural gas marketed (Bcf)
Natural gas gross margin ($/Mcf)
Physically settled volumes (Bcf)
Operating Results - Net margin decreased by $45.3 million for the three months ended June 30, 2007, compared with the same period in 2006, primarily due to:
a decrease of $34.3 million in storage margins, net of hedging activities, due to:
a decrease of $9.7 million from marketing, primarily due to a decrease in natural gas price volatility having an unfavorable impact on marketing opportunities,
a decrease of $6.6 million in our financial trading margins, and
a decrease of $1.1 million in retail activities from lower physical margins due to a wetter than normal start to the irrigation season in our core marketing area, partially offset by
an increase of $6.5 million in transportation margins, net of hedging activities, associated with favorable changes in the unrealized fair value of derivative instruments and improved regional spreads during the second quarter of 2007.
Net margin decreased by $17.0 million for the six months ended June 30, 2007, compared with the same period in 2006, primarily due to:
a decrease of $15.6 million in transportation margins, net of hedging activities, associated with unfavorable changes in the unrealized fair value of derivative instruments and a decrease in realized margins in the Mid-Continent region primarily in the first quarter of 2007,
a decrease of $14.5 million in our financial trading margins, and
a decrease of $3.6 million in retail activities from lower physical margins due to market conditions, partially offset by
an increase of $12.2 million from improved storage margins, net of hedging activities, related to:
an increase of $4.3 million in marketing margins primarily associated with marketing origination activity.
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Operating costs decreased $2.0 million for the three months ended June 30, 2007, primarily due to lower employee-related costs.
Natural gas volumes marketed increased for the three and six months ended June 30, 2007, compared with the same periods in 2006, due to a 63 percent and 22 percent increase in heating degree days in 2007 in our service territory for the three- and six-month periods, respectively, compared with the same periods in 2006.
Our natural gas in storage at June 30, 2007, was 64.4 Bcf compared with 73.3 Bcf at June 30, 2006. At June 30, 2007 and 2006, our total natural gas storage capacity under lease was 96 Bcf and 86 Bcf, respectively. Storage demand fees on cyclable storage are expensed in the month incurred and noncyclable storage demand fees are deferred until the natural gas is withdrawn for storage.
The acquisition of natural gas storage capacity has become more competitive as a result of new entrants from the financial services sector, the increase in the spread between summer and winter natural gas prices, and natural gas price volatility. The increased demand for storage capacity has resulted in an increase in both the cost of leasing storage capacity and the required term of the lease. Longer terms for our storage capacity leases could result in significant increases in our contractual commitments.
The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on a number of factors, including whether the derivative instrument is (1) held for trading purposes, (2) financially settled, (3) results in physical delivery or services rendered, and (4) qualifies for the normal purchase or sale exception as defined in Statement 133. In accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,” EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and Statement 133, we report settled derivative instruments as follows:
all financially settled derivative contracts are reported on a net basis,
derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis,
derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis, and
derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis.
We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery.
The following table shows our margins by activity for the periods indicated.
Marketing and storage, gross
Less: Storage and transportation costs
Marketing and storage, net
Retail marketing
Financial trading
Marketing and storage activities, net, primarily include physical marketing, purchases and sales, firm storage and transportation capacity expense, including the impact of cash flow and fair value hedges, and other derivative instruments used 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.
Retail marketing includes revenues from providing physical marketing and supply services, coupled with risk management services to residential and small commercial and industrial customers.
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Financial trading margin includes activities that are generally executed using financially settled derivatives. These activities are normally short term in nature, with a focus on capturing short-term price volatility. Energy trading revenues, net, in our Consolidated Statements of Income include financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are required to be reported on a net basis.
LIQUIDITY AND CAPITAL RESOURCES
General - Part of our strategy is to grow through acquisitions and internally generated growth projects 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 similar commitments to unaffiliated parties. During the three and six months ended June 30, 2007 and 2006, our capital expenditures were financed through operating cash flows and short- and long-term debt. Total capital expenditures for the first six months of 2007 were $277.0 million, compared with $132.6 million for the same period in 2006, exclusive of acquisitions. ONEOK Partners’ capital expenditures for the first six months of 2007 were $202.4 million, compared with $53.6 million for the same period in 2006, exclusive of acquisitions. The increase in capital expenditures for 2007 compared with 2006 is driven primarily by ONEOK Partners’ capital projects, which are discussed beginning on page 28.
Financing - Financing is provided through available cash, our commercial paper program and long-term debt. We also have credit agreements, as discussed below, which are used as a back-up for the commercial paper program and short-term liquidity needs. 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 sale/leaseback of facilities. ONEOK Partners’ operations are also financed through available cash or the issuance of debt or limited partner units.
The total amount of short-term borrowings authorized by our Board of Directors is $2.5 billion. The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $1.5 billion. At June 30, 2007, we had no commercial paper outstanding, $78.7 million in letters of credit issued and available cash and cash equivalents of approximately $246.6 million. At June 30, 2007, ONEOK Partners had $10 million in letters of credit issued, $105 million in borrowings outstanding under the 2007 Partnership Credit Agreement, as described in Note H of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q, and available cash and short-term investments of approximately $82.7 million. As of June 30, 2007, we could have issued $1.9 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements. As of June 30, 2007, ONEOK Partners could have issued, under the most restrictive provisions of its agreements, $1.1 billion of additional debt.
Our $1.2 billion five-year credit agreement, as amended and restated in 2006, and ONEOK Partner’s 2007 Partnership Credit Agreement, contain typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q, and Note H of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K, for the year ended December 31, 2006. At June 30, 2007, we and ONEOK Partners were in compliance with all covenants.
Currently, we have $48.2 million available under a shelf registration statement on Form S-3, for the issuance and sale of shares of our common stock, debt securities, preferred stock, stock purchase contracts and stock purchase units.
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Capitalization Structure - The following table sets forth our capitalization structure for the periods indicated.
Long-term debt
Equity
Debt (including Notes payable)
We do not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in our five-year credit agreement, the debt of ONEOK Partners is excluded. At June 30, 2007, our capitalization structure, excluding the debt of ONEOK Partners, was 52 percent debt and 48 percent equity, and at December 31, 2006, our capitalization structure, excluding the debt of ONEOK Partners, was 48 percent debt and 52 percent equity. See Note G of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for discussion of the June 2007 repurchase of 7.5 million shares of our common stock, which reduced our equity.
Credit Rating - Our credit ratings as of June 30, 2007, are shown in the table below.
Our credit ratings may be affected by a material change in our financial ratios or a material event affecting our business. The most common criteria for assessment of our credit ratings are the debt-to-capital ratio, business risk profile, pretax and after-tax interest coverage and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper borrowings would increase, resulting in an increase in our cost to borrow funds, and we could potentially lose access to the commercial paper market. In the event that ONEOK is unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we have access to a $1.2 billion five-year credit agreement, which expires July 2011, and ONEOK Partners has access to a $1.0 billion revolving credit agreement that expires March 2012.
ONEOK Partners’ $250 million and $225 million long-term notes payable, due 2010 and 2011, respectively, contain provisions that require ONEOK Partners to offer to repurchase the senior notes at par value if its Moody’s or S&P credit ratings fall below investment grade (Baa3 for Moody’s and BBB- for S&P) and the investment grade ratings are not reinstated within a period of 40 days. Further, the indentures governing ONEOK Partners’ senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures governing the senior notes due 2012, 2016 and 2036 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016 and 2036 to declare those notes immediately due and payable in full. ONEOK Partners may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause it to borrow money under its credit facilities or seek alternative financing sources to finance the repurchases and repayment. ONEOK Partners could also face difficulties accessing capital or its borrowing costs could increase, impacting its ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill its debt obligations.
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. A decline in our credit rating below investment grade may also significantly impact other business segments. At June 30, 2007, we could have been required to fund approximately $75 million in margin requirements upon such a downgrade.
Other than ONEOK Partners’ note repurchase obligations and the margin requirements for our Energy Services segment described above, we have determined that we do not have significant exposure to rating triggers under our commercial paper
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agreement, trust indentures, building leases, equipment leases, and other various contracts. 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 credit agreements contain provisions that would cause the cost to borrow funds to increase if our credit rating is negatively adjusted. ONEOK Partners’ credit agreements have similar provisions. An adverse rating change is not defined as a default of our credit agreements.
Capital Projects - See the “Capital Projects” section beginning on page 28 for discussion of capital projects.
ONEOK Partners’ Class B Units - The units we received from ONEOK Partners were newly created Class B limited partner units. Distributions on the Class B limited partner units were prorated from the date of issuance. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on ONEOK Partners common units and generally have the same voting rights as the common units.
At a special meeting of the ONEOK Partners common unitholders held March 29, 2007, the unitholders approved a proposal to permit the conversion of all or a portion of the Class B limited partner units issued in the ONEOK Transactions into common units at the option of the Class B unitholder. The March 29, 2007, special meeting was adjourned to May 10, 2007, to allow unitholders additional time to vote on a proposal to approve amendments to the ONEOK Partners’ Partnership Agreement which, had the amendments been approved, would have granted voting rights for units held by us and our affiliates if a vote is held to remove us as the general partner and would have required fair market value compensation for our general partner interest if we are removed as general partner. While a majority of ONEOK Partners common unitholders voted in favor of the proposed amendments to the ONEOK Partners Partnership Agreement at the reconvened meeting of the common unitholders held May 10, 2007, the proposed amendments were not approved by the required two-thirds affirmative vote of the outstanding units, excluding common units and Class B units held by us and our affiliates. As a result, effective April 7, 2007, the Class B limited partner units are entitled to receive increased quarterly distributions equal to 110 percent of the distributions paid with respect to the common units.
On June 21, 2007, we, as the sole holder of ONEOK Partners Class B limited partner units, waived our right to receive the increased quarterly distributions on the Class B units for the period April 7, 2007, through December 31, 2007, and continuing thereafter until we give ONEOK Partners no less than 90 days advance notice that we have withdrawn our waiver. Any such withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after 90 days following delivery of the notice.
In addition, since the proposed amendments to the ONEOK Partners’ Partnership Agreement were not approved by the common unitholders, if the common unitholders vote at any time to remove us or our affiliates as the general partner, quarterly distributions payable on Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 125 percent of the distributions payable with respect to the common units.
Stock Repurchase Plan - For more information regarding the Stock Repurchase Plan, refer to discussion in Note G of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact our overall liquidity due to the impact the commodity price change has on items such as the cost of NGLs and gas held in storage, increased margin requirements, the cost of transportation to various market locations, collectibility of certain energy-related receivables and working capital. We believe that our current commercial paper program and ONEOK Partners’ lines of credit are adequate to meet liquidity requirements associated with commodity price volatility.
Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans is included under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources,” in our Annual Report on Form 10-K for the year ended December 31, 2006. See Note I of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for 2007 anticipated contributions.
ENVIRONMENTAL LIABILITIES
For more information regarding our environmental liabilities, refer to discussion in Note J of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
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CASH FLOW ANALYSIS
Operating Cash Flows - Operating cash flows increased by $178.3 million for the six months ended June 30, 2007, compared with the same period in 2006, primarily as a result of changes in components of working capital. These changes increased operating cash flows by $502.5 million, compared with an increase of $389.5 million for the same period last year, due to increases in accounts payable, decreases in inventory, and decreases in energy marketing and risk management assets and liabilities, partially offset by increases in accounts receivable.
Investing Cash Flows - Cash used in investing activities was $275.8 million for the six months ended June 30, 2007, compared with $488.0 million for the same period in 2006.
The decreased use of cash in 2007 was primarily related to our ONEOK Partners segment’s acquisition of the remaining 66-2/3 percent interest in Guardian Pipeline for approximately $77 million during 2006. We also purchased from TransCanada its 17.5 percent general partner interest in ONEOK Partners for $40 million during 2006. These acquisitions were offset by our ONEOK Partners segment’s receipt of $297.0 million from the sale of its 20 percent partnership interest in Northern Border Pipeline in April 2006.
We had a decrease in short-term investments of $5.1 million between December 31, 2006 and June 30, 2007, compared to a total investment of $496.5 million in the first six months of 2006.
We had increased capital expenditures of $144.4 million for the six-month period due to our capital projects. See page 28 for discussion of our capital projects.
Investing cash flows for 2006 also include the impact of the deconsolidation of Northern Border Pipeline and consolidation of Guardian Pipeline.
Financing Cash Flows - Cash used in financing activities was $452.6 million for the six months ended June 30, 2007, compared with $199.3 million for the same period in 2006.
We paid $20.1 million for the settlement of the forward purchase contract related to our stock repurchase in February 2007 and approximately $370 million for our stock repurchase in June 2007.
On February 16, 2006, we successfully settled our 16.1 million equity units with 19.5 million shares of our common stock. With the settlement of the equity units, we received $402.4 million in cash, which we used to repay a portion of our commercial paper. We paid down a total of $641.5 million of our commercial paper during the six months ended June 30, 2006.
We had net borrowings of $99 million during the six months ended June 30, 2007, compared to net borrowings of $257.5 million during the same period in 2006. Increased borrowings in 2006 were the result of the following items.
Our ONEOK Partners segment financed a portion of its purchase of our former gathering and processing, natural gas liquids, and pipelines and storage segments for $1.05 billion.
Our ONEOK Partners segment borrowed $77 million under its revolving credit agreement to acquire the 66-2/3 percent interest in Guardian Pipeline.
These increases were partially offset by our repayment of the remaining $900 million under our short-term bridge financing agreement, which was used to initially finance our acquisition of the assets from Koch.
In March 2006, our ONEOK Partners segment borrowed $33 million under its 2006 Partnership Credit Agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a redemption premium of $3.6 million.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Some of the statements contained and incorporated in this Quarterly Report on 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 our anticipated financial performance, management’s plans and objectives for our future operations, our business prospects, the 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
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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 Quarterly Report on Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast” and other words and terms of similar meaning.
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:
actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners;
the effects of weather and other natural phenomena on our operations, including energy sales and prices and demand for pipeline capacity;
competition from other U.S. and Canadian energy suppliers and transporters as well as alternative forms of energy;
the capital intensive nature of our businesses;
the profitability of assets or businesses acquired by us;
risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
economic climate and growth in the geographic areas in which we do business;
the risk of a significant slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy;
the uncertainty of estimates, including accruals and costs of environmental remediation;
the timing and extent of changes in commodity prices for natural gas, NGLs, electricity and crude oil;
the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, and authorized rates or recovery of gas and gas transportation costs;
the impact of recently issued and future accounting pronouncements and other changes in accounting policies;
the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere;
the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension expense and funding resulting from changes in stock and bond market returns;
risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
the results of administrative proceedings and litigation, regulatory actions and receipt of expected regulatory clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC;
our ability to access capital at competitive rates or on terms acceptable to us;
risks associated with adequate supply to our gas gathering and processing, fractionation and pipeline facilities, including production declines which outpace new drilling;
the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;
the impact of the outcome of pending and future litigation;
the possible loss of gas distribution franchises or other adverse effects caused by the actions of municipalities;
the impact of unsold pipeline capacity being greater or less than expected;
the ability to market pipeline capacity on favorable terms, including the effects of:
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performance of contractual obligations by our customers and shippers;
the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
timely receipt of approval by applicable governmental entities for construction and operation of our pipeline projects and required regulatory clearances;
our ability to acquire all necessary rights-of-way permits and consents in a timely manner, our ability to promptly obtain all necessary materials and supplies required for construction and our ability to construct pipelines without labor or contractor problems;
our ability to promptly obtain all necessary materials and supplies required for construction of gathering, processing and transportation facilities;
our ability to control construction costs and completion schedules of our pipeline projects and other projects;
the composition and quality of the natural gas we gather and process in our plants and transport on our pipelines;
the efficiency of our plants in processing natural gas and extracting NGLs;
the mechanical integrity of facilities operated;
demand for our services in the proximity of our facilities;
the impact of potential impairment charges;
our ability to control operating costs;
the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
acts of nature, sabotage, terrorism or other similar acts causing damage to our facilities or our suppliers’ or shippers’ facilities; and
the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2006, and in this Quarterly Report on Form 10-Q. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2006.
COMMODITY PRICE RISK
ONEOK Partners is exposed to commodity price risk as its natural gas interstate and intrastate pipelines collect natural gas from its customers for operations or as part of its fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by its customers, the pipelines must buy or sell natural gas, store or use natural gas from inventory, and are exposed to commodity price risk. At June 30, 2007, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ natural gas interstate and intrastate pipeline operations.
In addition, ONEOK Partners is exposed to commodity price risk primarily as a result of NGLs in storage, spread risk associated with the relative values of the various components of the NGL stream and the relative value of NGL purchases at one location and sales at another location, known as basis risk. ONEOK Partners has not entered into any hedges with respect to its NGL marketing activities.
ONEOK Partners is also exposed to commodity price risk, primarily NGLs, as a result of receiving commodities in exchange for its gathering and processing services. To a lesser extent, ONEOK Partners is exposed to the relative price differential between natural gas and NGLs with respect to its keep-whole processing contracts and the risk of price fluctuations and the cost of intervening transportation at various market locations. ONEOK Partners uses commodity fixed-price physical
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forwards and derivative contracts, including NYMEX-based futures and over-the-counter swaps, to minimize earnings volatility related to natural gas, NGL and condensate price fluctuations.
ONEOK Partners has reduced its gross processing spread exposure through a combination of physical and financial hedges. ONEOK Partners utilizes a portion of its percent of proceeds equity natural gas as an offset, or natural hedge, to an equivalent portion of its keep-whole shrink requirements. This has the effect of converting ONEOK Partners’ gross processing spread risk to NGL commodity price risk, and uses financial instruments to hedge the sale of NGLs. Through this approach, ONEOK Partners has reduced its gross processing spread exposure by 5,220 MMBtu/d (or 1,560 Bbl/d) for the remainder of 2007. The NGLs have been hedged at an average price of $0.80 per gallon in 2007. The NGLs have been hedged at an average price of $0.85 per gallon in 2008.
The following tables set forth ONEOK Partners’ hedging information for the remainder of 2007 and for the year ending December 31, 2008.
Six Months Ending
December 31, 2007
Commodity Risk
Natural gas liquids (Bbl/d) (a)
Spread Risk
Gross processing spread (MMBtu/d) (a)
Year Ending
December 31, 2008
ONEOK Partners’ commodity price risk is estimated as a hypothetical change in the price of natural gas, NGLs and crude oil at June 30, 2007, excluding the effects of hedging. ONEOK Partners’ condensate sales are based on the price of crude oil.
ONEOK Partners estimates that a $0.01 per gallon increase in the composite price of NGLs would increase annual net margin by approximately $1.8 million.
ONEOK Partners estimates that a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.5 million.
ONEOK Partners estimates that a $0.10 per MMBtu increase in the price of natural gas would increase annual net margin by approximately $0.2 million.
The above estimates of commodity price risk do not include any effects on demand for its services that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause ethane to be sold in the natural gas stream, impacting gathering and processing margins, NGL exchange margins, natural gas deliveries and NGL volumes shipped.
Our Distribution segment uses derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect their 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 June 30, 2007, Kansas Gas Service had derivative instruments in place to fix the cost of natural gas purchases for 2.6 Bcf, which represents part of their gas purchase requirements for the 2007/2008 winter heating months.
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Fair Value Component of the Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of the energy marketing and risk management assets and liabilities, excluding derivative instruments that have been declared as either fair value or cash flow hedges.
Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
Net fair value of derivatives outstanding at December 31, 2006
Derivatives realized or otherwise settled during the period
Fair value of new derivatives when entered into during the period
Other changes in fair value
Net fair value of derivatives outstanding at June 30, 2007
The net fair value of derivatives outstanding includes the effect of settled energy contracts and current period changes resulting primarily from newly originated transactions and the impact of market movements on the fair value of energy marketing and risk management assets and liabilities. Fair value estimates consider the market in which the transactions are executed. The market in which exchange traded and over-the-counter transactions are executed is a factor in determining fair value. We utilize third-party references for pricing points from NYMEX and third-party over-the-counter brokers to establish the commodity pricing and volatility curves. We believe the reported transactions from these sources are the most reflective of current market prices. Fair values are subject to change based on valuation factors. The estimate of fair value includes an adjustment for the liquidation of the position in an orderly manner over a reasonable period of time under current market conditions. The fair value estimate also considers the risk of nonperformance based on credit considerations of the counterparty.
Maturity of Energy Trading Contracts - The following table provides details of our Energy Services segment’s maturity of derivatives based on injection and withdrawal periods from April through March. This maturity schedule is consistent with our business strategy. Derivative instruments that have been declared as either fair value or cash flow hedges are not included in the following table.
Prices actively quoted (b)
Prices provided by other external sources (c)
Prices derived from quotes, other external sources and other assumptions (d)
Total
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 in this Quarterly Report on Form 10-Q.
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Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $4.1 million and $9.4 million at June 30, 2007 and 2006, respectively. The following table details the average, high and low daily VAR calculations for the periods indicated.
Average
High
Low
Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges. The variations in the VAR data are reflective of market volatility and changes in the portfolios during the year. The decrease in VAR for 2007, compared with 2006, was due to decreased price volatility in 2007 and lower average commodity prices in the first quarter of 2007.
To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact risk management decisions may have on our business, operating results or financial position.
INTEREST RATE RISK
General - We are subject to the risk of interest rate fluctuation in the normal course of business. We manage interest rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates. At June 30, 2007, the interest rate on 82.9 percent of our long-term debt, exclusive of the debt of our ONEOK Partners segment, was fixed after considering the impact of interest-rate swaps, while the interest rate on 92.6 percent of ONEOK Partners’ long-term debt was fixed after considering the impact of interest-rate swaps.
At June 30, 2007, a 100 basis point move in the annual interest rate on our variable-rate long-term debt would have changed our annual interest expense by $4.9 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.
Fair Value Hedges - See Note D of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for discussion of the impact of interest-rate swaps and net interest expense savings from terminated swaps.
Total savings from the interest-rate swaps and amortization of terminated swaps was $3.6 million for the six months ended June 30, 2007. The swaps are expected to net the following savings for the remainder of the year:
interest expense savings of $5.1 million related to the amortization of the swap value at termination, less
approximately $1.5 million in interest expense from the existing $490 million of swapped debt, based on LIBOR rates at June 30, 2007.
Total net swap savings for 2007 are expected to be $7.2 million, compared with $7.6 million for 2006.
CURRENCY RATE RISK
As a result of our Energy Services segment’s operations in Canada, we are subject to currency exposure related to our firm transportation and storage contracts. Our objective with respect to currency risk is to reduce the exposure due to exchange-rate fluctuations. We use physical forward transactions, which result in an actual two-way flow of currency on the settlement date since we exchange U.S. dollars for Canadian dollars with another party. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with the change in fair value are recorded in net margin. At June 30, 2007, our exposure to risk from currency translation was not material, and there were no material currency translation gains or losses recorded during the six months ended June 30, 2007 or 2006.
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Quarterly Evaluation of Disclosure Controls and Procedures - As of the end of the period covered by this report, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that as of June 30, 2007, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
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 Exchange Act) during the second quarter ended June 30, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
Additional information about our legal proceedings is included under Part I, Item 3, “Legal Proceedings,” in our Annual Report on Form 10-K for the year ended December 31, 2006.
Gas Index Pricing Litigation Cases - On July 27, 2007, the court denied the defendants’ motions to dismiss in two of the cases, Learjet, Inc., et al. v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte, Kansas, in November 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada) and Breckenridge Brewery of Colorado, LLC, et al. v. ONEOK, Inc., et al. (filed in the District Court of Denver County, Colorado, in May 2006, transferred to MDL-1566 in the United States District Court for the District of Nevada). On that same date in J.P. Morgan Trust Company v. ONEOK, Inc., et al. (filed in the District of Wyandotte County, Kansas, in October 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada), the court granted the plaintiff’s motion to alter or amend judgment, vacated the court’s previous order granting the defendants’ motion to dismiss, and ordered the defendants to file an answer to the plaintiff’s amended complaint. Additionally, the Judicial Panel for Multidistrict Litigation has transferred three more of the cases to the MDL-1566 proceeding which includeMissouri Public Service Commission v. ONEOK, Inc., et al. (filed in the Sixth Judicial Circuit Court of Jackson County, Missouri, in October 2006, removed to the United States District Court for the Western District Court of Missouri);Arandell Corporation, et al. v. Xcel Energy, Inc., et al. (filed in the Circuit Court for Dane County, Wisconsin, in December 2006, removed to the United States District Court for the Western District of Wisconsin); and Heartland Regional Medical Center, et al. v. ONEOK, Inc., et al (filed in the Circuit Court of Buchanan County, Missouri, in March 2007, removed to the United States District Court for the Western District of Missouri).
Our investors should consider the risks set forth in Part I, Item 1A, “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2006, that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report on Form 10-Q, including Forward-Looking Statements, which are included in Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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RISK FACTORS RELATED TO ONEOK PARTNERS’ BUSINESS
ONEOK Partners has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The Internal Revenue Service (IRS) may challenge this treatment, which could adversely affect the value of its limited partner units.
When ONEOK Partners issues additional units or engages in certain other transactions, ONEOK Partners determines the fair market value of its assets and allocates any unrealized gain or loss attributable to its assets to the capital accounts of its unitholders and its general partner. ONEOK Partners’ methodology may be viewed as understating the value of its assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under ONEOK Partners’ current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to ONEOK Partners’ tangible assets and a lesser portion allocated to ONEOK Partners’ intangible assets. The IRS may challenge ONEOK Partners’ valuation methods, or ONEOK Partners’ allocation of the Section 743(b) adjustment attributable to ONEOK Partners’ tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of ONEOK Partners’ unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to ONEOK Partners’ unitholders. It also could affect the amount of gain from ONEOK Partners unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to ONEOK Partners unitholders’ tax returns without the benefit of additional deductions.
ONEOK Partners’ treatment of a purchaser of common units as having the same tax benefits as the seller could be challenged, resulting in a reduction in value of the common units.
Because ONEOK Partners cannot match transferors and transferees of common units, ONEOK Partners is required to maintain the uniformity of the economic and tax characteristics of these units in the hands of the purchasers and sellers of these units. ONEOK Partners does so by adopting certain depreciation conventions that do not conform to all aspects of the United States Treasury regulations. An IRS challenge to these conventions could adversely affect the tax benefits to a unitholder of ownership of the common units and could have a negative impact on their value or result in audit adjustments to ONEOK Partners unitholders’ tax returns.
ISSUER PURCHASES OF EQUITY SECURITIES
The following table sets forth information relating to our purchases of our common stock for the periods shown.
April 1-30, 2007
May 1-31, 2007
June 1-30, 2007
See Note G of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for discussion of the June 2007 repurchase of the 7.5 million shares of our common stock.
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EMPLOYEE STOCK AWARD PROGRAM
Under our Employee Stock Award Program, we issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $26 per share, and we have issued and will continue to 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. The total number of shares of our common stock authorized for issuance under this program is 200,000.
Through June 30, 2007, a total of 130,219 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 June 30, 2007.
April 25, 2007
April 27, 2007
May 4, 2007
May 9, 2007
May 21, 2007
May 22, 2007
May 23, 2007
May 30, 2007
The shares issued under this program have not been registered under the Securities Act of 1933, as amended (1933 Act), in reliance upon the position taken by the SEC (see Release No. 6188, dated February 1, 1980) that the issuance of shares to employees pursuant to a program of this kind does not involve a sale of shares in the 1933 Act sense.
Not Applicable.
We held our 2007 annual meeting of shareholders on May 17, 2007. At this meeting, the individuals set forth below were elected by a plurality vote to our Board of Directors in Class A to serve for a term of three years:
William M. Bell
John W. Gibson
Pattye L. Moore
David J. Tippeconnic
The individuals set forth below are the members of our Board of Directors whose term of office as a director continued after the meeting:
James C. Day
David L. Kyle
Bert H. Mackie
Mollie B. Williford
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In addition, at this meeting our shareholders did not approve a shareholder proposal relating to the separation of the positions of Chairman of the Board and Chief Executive Officer as follows:
Proposal relating to separation of the positions of Chairman of the Board and Chief Executive Officer
As previously reported, on June 21, 2007, Jim W. Mogg and Julie H. Edwards were elected to our Board of Directors in Class B and C, respectively.
The following exhibits are filed as part of this Quarterly Report on Form 10-Q:
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Registrant
Date: August 3, 2007
By:
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial Officer)
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