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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2005

OR

For the transition period from                      to                     .

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code (918) 588-7000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x No ¨.

On May 2, 2005, the Company had 101,983,630 shares of common stock outstanding.

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ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q

As used in this Quarterly Report on Form 10-Q, the terms “we”, “our” or “us” mean ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.

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Part I - FINANCIAL INFORMATION

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)

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ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Our accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and reflect all adjustments which, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2005, are not necessarily indicative of the results that may be expected for a twelve-month period. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2004.

Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2004.

Significant Accounting Policies

Common Stock Options and Awards - In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (Statement 123R). Statement 123R requires companies to expense the fair value of share-based payments. In addition, there are also changes related to the expense calculation for share-based payments. Effective January 1, 2006, we will adopt Statement 123R, and we expect to use the prospective method. We are currently assessing the impact of adopting Statement 123R, but we do not believe it will have a material impact on our financial condition and results of operations, as we have been expensing share-based payments since our adoption of Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure” on January 1, 2003.

The following table sets forth the effect on net income and earnings per share if we had applied the fair-value recognition provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” to all options and awards granted prior to January 1, 2003.

Asset Retirement Obligations - In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. We are currently reviewing the applicability of FIN 47 to our operations and its potential impact on our consolidated financial statements.

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Consolidation - The Emerging Issues Task Force (EITF) is currently deliberating EITF Issue No. 04-5, “Investor’s Accounting for an Investment in a Limited Partnership When the Investor Is the Sole General Partner and the Limited Partners Have Certain Rights” (EITF 04-5). Since the changes proposed in EITF 04-5 would result in different guidance in accounting for general partners that are in different industries, the FASB staff is planning to amend SOP 78-9, Accounting for Investments in Real Estate Ventures to be consistent with EITF 04-5. SOP 78-9-a, “Interaction of AICPA Statement of Position 78-9, Accounting for Investments in Real Estate Ventures, and EITF Issue No. 04-5, ‘Investor’s Accounting for an Investment in a Limited Partnership When the Investor Is the Sole General Partner and the Limited Partners Have Certain Rights’” (SOP 78-9-a) will have the presumption that a general partner controls a limited partnership and therefore should consolidate the partnership. This presumption can be overcome if the limited partners have kick-out or substantive participating rights. As a result of this new guidance, we could be required to consolidate Northern Border Partners; however, we will begin to evaluate the impact and transition method if or when SOP 78-9-a and EITF 04-5 are finalized. The anticipated effective date of SOP 78-9-a and EITF 04-5 is January 1, 2006.

Other

Reclassifications - Certain amounts in the consolidated financial statements have been reclassified to conform to the 2005 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.

Accounting Treatment - We account for derivative instruments and hedging activities in accordance with FASB Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), as amended. Under Statement 133, entities are required to record all derivative instruments at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative instrument in earnings as they occur. We record these changes in fair value as energy trading revenues, net in our Consolidated Statements of Income. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and is subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the hedge, are reported in earnings.

As required by Statement 133, we formally document all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.

At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis. We began accounting for the realized revenues and purchase costs of those contracts that result in physical delivery on a gross basis beginning in the third quarter of 2004. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.

Refer to Note D of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2004, for additional discussion.

Fair Value Hedges

During the first quarter of 2005, we terminated $400 million of our interest rate swap agreements and paid a net amount of $19.4 million, which included $20.2 million for the present value of future payments at the time of termination, less $0.8 million for

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interest rate savings through the termination of the swap. During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements, locking in savings of $81.9 million. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for the first quarter of 2005 for all swaps was $2.4 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:

Currently, $340 million of our fixed rate debt is swapped to floating. The floating rate debt is based on both the three and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. At March 31, 2005, we recorded a net liability of $9.3 million to recognize the interest rate swaps at fair value. Long-term debt was reduced by $9.3 million to recognize the change in the fair value of the related hedged liability.

Our Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges are recorded as cost of sales and fuel. The ineffectiveness related to these hedges was immaterial for the three months ended March 31, 2005 and 2004.

Cash Flow Hedges

Our Energy Services segment uses futures and basis swaps to hedge the cash flows associated with its anticipated purchases and sales of natural gas and cost of fuel used in transportation of gas. Accumulated other comprehensive loss at March 31, 2005, includes net losses of approximately $49.2 million, net of tax, related to these hedges that will be realized within the next 46 months. Over the next 12 months, we will recognize net losses of $51.1 million and we will recognize net gains of $1.9 million thereafter. Our Production segment and our Gathering and Processing segment periodically enter into derivative instruments to hedge the cash flows associated with their exposure to changes in the price of natural gas, natural gas liquids (NGLs) and crude oil. Accumulated other comprehensive loss at March 31, 2005 includes losses of approximately $11.3 million, net of tax, for the production hedges which will be realized in the income statement primarily within the next 12 months. Losses of approximately $4.6 million, net of tax, are included in accumulated other comprehensive loss at March 31, 2005 for the gathering and processing hedges, which will be realized in the income statement within the next nine months.

Our Distribution segment also uses derivative instruments from time to time. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas adjustment. At March 31, 2005, our Distribution segment did not have any derivative instruments in place to hedge the cost of natural gas purchases.

Net gains and losses are reclassified out of accumulated other comprehensive loss to operating revenues or cost of sales and fuel when the anticipated purchase or sale occurs. Ineffectiveness related to these cash flow hedges was approximately $0.6 million and $1.1 million for the three months ended March 31, 2005 and 2004, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive loss during the first quarter of 2004 due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur.

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The following table is a summary of regulatory assets, net of amortization, for the periods indicated.

In January 2004, the Oklahoma Corporation Commission (OCC) approved Oklahoma Natural Gas’ request for recovery of costs related to customers’ service lines, pipeline corrosion control, investment in gas in storage and rising levels of fuel-related bad debts. The OCC’s order also authorized Oklahoma Natural Gas to defer homeland security costs. We are amortizing the deferred costs associated with these OCC directives over an 18-month period. At March 31, 2005, we had approximately $0.7 million remaining to be amortized. These deferred costs are included in the captions “Service lines” and “Other” in the regulatory assets table above.

In September 2003, the Kansas Corporation Commission (KCC) issued an order to Kansas Gas Service which included approval to recover $26.4 million of deferred postretirement and postemployment benefit costs over nine years and made the weather normalization adjustment rider, which had been renewed annually, a permanent component of customer rates.

“Weather normalization” represents the revenue over- or under-recovered through this rider. This amount is deferred as a regulatory asset for a 12-month period. Kansas Gas Service then applies an adjustment to the customers’ bills for 12 months to refund the over-collected revenue or bill the under-collected revenue.

The OCC has authorized Oklahoma Natural Gas’ recovery of the take-or-pay settlement, pension and postretirement benefit costs over periods ranging from 10-20 years.

We amortize reacquired debt costs in accordance with the accounting rules prescribed by the OCC and KCC. These costs were included as a component of interest in the most recent rate filing with the OCC and were included in the rate order issued by the KCC.

The $5.1 million “Ad valorem tax” represents an increase in Kansas Gas Service’s taxes above the amount approved in the September 2003 rate order. Kansas law permits a utility to file a tariff to recover additional ad valorem tax expense incurred above the amount currently recovered in the cost of service rate. This excess amount is recoverable through a surcharge, provided the utility reports the change in taxes to the KCC, on an annual basis. Kansas Gas Service filed the tariff and received approval for recovery from the KCC during the third quarter of 2004.

We completed our annual analysis of goodwill for impairment as of January 1, 2005 and there was no impairment indicated.

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The table below gives an overview of comprehensive income for the periods indicated.

Accumulated other comprehensive loss at March 31, 2005 and 2004, primarily includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.

Stock Repurchase Plan - During the first quarter of 2005, we repurchased approximately 2.1 million shares of our common stock pursuant to a plan approved by our Board of Directors on January 20, 2005. This plan allows us to purchase up to a total of 7.5 million shares of our common stock on or before January 20, 2007.

Common Stock - Since September 17, 2004, the Thrift Plan for Employees of ONEOK, Inc. and subsidiaries (the Thrift Plan) has from time to time purchased shares of ONEOK common stock on the open market to meet the purchase requirements generated by participants in the Thrift Plan. Previously, the Thrift Plan used newly issued shares to meet the participants’ purchase requirements. All participant purchases of ONEOK common stock under the Thrift Plan are voluntary. We use newly issued shares to meet the purchase requirements generated by our Dividend Reinvestment Plan and our Long-Term Incentive Plan.

Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2005, were $0.25 per share. In April 2005, our Board of Directors announced an increase in the quarterly dividend of our common stock to $0.28 per share payable in the second quarter of 2005.

The table below provides the components of net periodic benefit cost (income) for our pension and other postretirement benefit plans.

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Contributions - For the three months ended March 31, 2005, $0.1 million and $4.0 million of contributions were made to our pension plan and other postretirement benefit plan, respectively. We presently anticipate our total 2005 contributions to be $1.8 million for the pension plan and $16.1 million for the other postretirement benefit plan.

Environmental - We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities in the process of transporting natural gas or NGLs or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results of operations and cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the Kansas Department of Health and Environment (KDHE) presently governs all remediation work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. We have commenced active remediation on six sites and have achieved regulatory closure at two of these locations, while active remediation continues on the remaining four sites. We have completed some analysis of the six other sites upon which no active remediation is being conducted. The site situations are not similar. We have no previous experience with similar remediation efforts, and therefore are unable to fully estimate individual or aggregate costs that may be required to satisfy the remedial obligations.

Our preliminary review of similar cleanup efforts at former manufactured gas sites reveals that costs can range from $100,000 to $10 million per site. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties, to which we may be entitled. At this time, we have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. Total costs to remediate the two sites, which have achieved regulatory closure, were approximately $700,000. Total remedial costs for each of the remaining sites are expected to exceed $500,000 per site, but there is no assurance that costs to investigate and remediate the remaining sites will not be significantly higher. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.

Our expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations and there have been no material effects upon earnings during 2005 related to compliance with environmental regulations.

Yaggy Facility - In January 2001, our Yaggy gas storage facility’s operating parameters were changed as mandated by the KDHE following natural gas explosions and eruptions of natural gas geysers in or near Hutchinson, Kansas. In July 2002, the KDHE issued an administrative order that assessed a civil penalty against us, based on alleged violations of several KDHE regulations. On April 5, 2004, we entered into a Consent Order with the KDHE in which we paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. In addition, the Consent Order requires us to conduct an environmental remediation and a geoengineering study. Based on information currently available to us, we do not believe there are any material adverse effects resulting from the Consent Order.

In February 2004, a jury awarded the plaintiffs $1.7 million in actual damages in a lawsuit involving property damage alleged to relate to the gas explosions and eruptions. In April 2004, the judge in this case awarded punitive damages in the amount of $5.25 million. We have filed an appeal of the jury verdict and the punitive damage award. Based on information currently available to us, we believe our legal reserves and insurance coverage are adequate and that this matter will not have a material adverse effect on us.

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The two class action lawsuits filed against us in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at, and in the vicinity of, our Yaggy facility in January 2001 resulted in jury verdicts in September 2004. The jury awarded the plaintiffs in the residential class $5.0 million in actual damages, and the judge ordered the payment of $2.0 million in attorney fees and $0.6 million in expenses, all of which is covered by insurance. In the other class action relating to business claims, the jury awarded no damages. The jury rejected claims for punitive damages in both cases. We are reviewing our options for appealing the verdict rendered in the residential claimants’ class action along with the attorney fee and expense award.

With the exception of appeals, all litigation regarding our Yaggy facility has been resolved.

Enron - We have repurchased a portion of the Enron Corp. guaranty claim that Enron Corp. and Enron North American Corp. (ENA) sought to avoid in the adversary proceeding. We are now providing the defense of the adversary proceeding for both the portion of the guaranty claim constituting the repurchased claim and also the portion of the guaranty claim previously sold. Based on information currently available to us, we do not expect the adversary proceeding to have a material adverse effect on us.

In addition to the adversary proceeding, Enron Corp. and ENA have filed an objection to portions of the guaranty claim and to portions of the underlying claim against ENA, creating a new contested matter in the Enron Corp. and ENA bankruptcy cases which involve different legal and factual issues than those raised in the adversary proceeding. Enron Corp. and ENA allege in this matter that the guaranty claim and underlying claim against ENA are overstated. The filing of this matter may trigger additional obligations for us to repurchase some of the claims previously sold. Based on the information currently available to us, we do not expect this matter to have a material adverse effect on us.

Other - We are a party to other litigation matters and claims, which are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.

Our business segments and the accounting policies of our business segments are the same as those described in the Footnote N and the Summary of Significant Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2004. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. Our equity method investments do not represent operating segments. We have no single external customer from which we received ten percent or more of our consolidated gross revenues for the periods covered by this report.

As discussed in Note B, at the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and separated the management and operations of our physical marketing, retail marketing and trading activities. We began accounting separately for the different types of revenue earned from these activities, with certain revenues accounted for on a gross rather than a net basis.

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The following tables set forth certain selected financial information for our operating segments for the periods indicated.