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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended March 31, 2003

OR

Commission File Number: 1-10662

XTO Energy Inc.

(Exact name of registrant as specified in its charter)

(817) 870-2800

(Registrant’s telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if change since last report)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

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XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended March 31, 2003

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P A R T   I.    F I N A N C I A L   I N F O R M A T I O N

XTO ENERGY INC.

Consolidated Balance Sheets

See Accompanying Notes to Consolidated Financial Statements.

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XTO ENERGY INC.

Consolidated Income Statements (Unaudited)

See Accompanying Notes to Consolidated Financial Statements.

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XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)

See Accompanying Notes to Consolidated Financial Statements.

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XTO ENERGY INC.

Notes to Consolidated Financial Statements

The accompanying consolidated financial statements of XTO Energy Inc. (formerly named Cross Timbers Oil Company), with the exception of the consolidated balance sheet at December 31, 2002, have not been audited by independent public accountants. In the opinion of our management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at March 31, 2003 and our income and cash flows for the three months ended March 31, 2003 and 2002. All such adjustments are of a normal recurring nature. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

The financial data for the three months ended March 31, 2003 included herein has been subjected to a limited review by KPMG LLP, our independent accountants. The accompanying review report of independent accountants is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the independent accountant’s liability under Section 11 does not extend to it.

Certain disclosures have been condensed or omitted from these financial statements. Accordingly, these financial statements should be read with the consolidated financial statements included in our 2002 Annual Report on Form 10-K.

Effective January 1, 2003, we have adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 provides that, if the fair value for asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by SFAS No. 143, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with the offsetting charge to property cost. Periodic accretion of discount of the estimated liability is recorded in the income statement. Prior to adoption of SFAS No. 143, we accrued for any estimated asset retirement obligation, net of estimated salvage value, as part of our calculation of depletion, depreciation and amortization. This method resulted in recognition of the obligation over the life of the property on a unit-of-production basis, with the estimated obligation netted in property cost as part of the accumulated depreciation, depletion and amortization balance.

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties (including removal of our offshore platforms in Alaska) at the end of their productive lives, in accordance with applicable state laws. We have determined our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. As of the January 1, 2003 adoption date of SFAS 143, we recorded a long-term liability for asset retirement obligation of $75.3 million, an increase in property cost of $60.7 million, a reduction of accumulated depreciation, depletion and amortization of $17.3 million and a cumulative effect of accounting change gain, net of tax, of $1.8 million. The following is a reconciliation of the asset retirement obligation for the three months ended March 31, 2003:

If we had adopted SFAS No. 143 as of January 1, 2002, we estimate that the asset retirement obligation at that date would have been $62.2 million, based on the same assumptions used in our calculation of the obligation at January 1,

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2003. The estimated 2002 pro forma effect of January 1, 2002 adoption of SFAS No. 143 on net income and earnings per share, for annual and interim periods, is not material.

On March 31, 2003, borrowings under the revolving credit agreement with commercial banks were $620 million with unused borrowing capacity of $180 million. The weighted average interest rate of 2.73% at March 31, 2003 is based on the one-month London Interbank Offered Rate plus 1.375%. On April 30, 2003, the revolving credit agreement was amended to allow for the release of security in the event that the Company is rated investment grade by either Standard and Poors or Moody’s Investors Service, assuming it has a rating immediately below investment grade from the other agency. Additionally, a $1.8 billion borrowing base was approved by the banks. The current commitment of $800 million borrowing capacity remains unchanged.

On April 23, 2003, we sold $400 million of 6¼% senior notes due in 2013 pursuant to Rule 144A under the Securities Act of 1933 which allows unregistered transactions with qualified institutional buyers. The notes are general unsecured indebtedness effectively ranking subordinate to bank borrowings, equal to our other senior unsecured notes and above our senior subordinated notes. The notes mature on April 15, 2013 and interest is payable each April 15 and October 15. The notes have not been registered under the Securities Act of 1933 and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. We may redeem all or part of the notes at any time at a price of 100% of their principal balance plus accrued interest and a make-whole premium payment. The make-whole premium is calculated as any excess over the principal balance of the present value of remaining principal and interest payments, discounted at the U.S. Treasury rate for a comparable maturity plus ½%.

Net proceeds of $393.1 million (after deducting initial purchaser commissions and estimated offering expenses) from the sale of notes, combined with proceeds from the concurrent sale of common stock (Note 7), will be used to finance our pending producing property acquisition from units of Williams of Tulsa, Oklahoma (Note 12), to redeem our 8¾% senior subordinated notes and to reduce bank debt. Until closing of these property transactions and redemption of the 8¾% senior subordinated notes, the proceeds of the senior notes and common stock offerings have been used to repay bank debt. As of May 1, 2003, there were no outstanding bank borrowings under our revolving credit agreement.

On April 17, 2003, we notified holders of our 8¾% senior subordinated notes that we will redeem the remaining $163.2 million note balance on May 19, 2003, at a redemption price of 104.375%, or $170.3 million, plus accrued interest of approximately $700,000. Including write-off of unamortized costs related to the notes, we will record a pre-tax loss on extinguishment of debt of approximately $9.6 million.

Litigation

On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross Timbers Oil Company, was filed against us in the District Court of Dewey County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which we have assumed the obligation to pay royalties. The plaintiffs allege that we reduced royalty payments by post-production deductions and entered into contracts with subsidiaries that were not arm’s-length transactions. The plaintiffs further allege that these actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions are a breach of the leases under which the royalties are paid. These deductions allegedly include production and post-production costs, marketing costs, administration costs and costs incurred by us in gathering, compressing, dehydrating, processing, treating, blending and/or transporting the gas produced. We contend that, to the extent any fees are proportionately borne by the plaintiffs, these fees are established by arm’s-length negotiations with third parties or, if charged by affiliates, are comparable to fees charged by third party gatherers or processors. We further contend that any such fees enhance the value of the gas or the products derived from the gas. The parties signed a settlement

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agreement under which we will pay $2.5 million to settle the plaintiffs’ claims for the period January 1, 1993 through June 30, 2002. Our portion of this liability, net of amounts allocable to Hugoton Royalty Trust units we do not own, is $2.1 million, which has been accrued in our financial statements. The court approved the settlement in April 2003. Payment of the settlement will occur in July 2003.

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District Court for the Western District of Oklahoma against us and certain of our subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The plaintiff alleges that we underpaid royalties on gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% during at least the past 10 years as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. The plaintiff also alleges that we have failed to pay the fair market value of the carbon dioxide produced. According to the U.S. Department of Justice, the plaintiff has made similar allegations in over 70 actions filed against more than 300 other companies. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each violation and attorney fees and expenses. The plaintiff also seeks an order for us to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene and asked the court to unseal the case. The court unsealed the case in May 1999. A multi-district litigation panel ordered that the lawsuits against us and other companies filed by Grynberg be transferred and consolidated to the federal district court in Wyoming. We believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

In February 2000, the Department of Interior notified us and several other producers that certain Native American leases located in the San Juan Basin had expired because of the failure of the leases to produce in paying quantities from February through August 1990. The Department of Interior demanded abandonment of the property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. We have reached a tentative settlement with the Department of Interior to pay $288,000 in settlement of all claims. The settlement should be finalized in second quarter 2003. Management’s estimate of the potential liability from this claim has been accrued in our financial statements.

In June 2001, we were served with a lawsuit styled Price, et al. v. Gas Pipelines, et al. (formerly Quinque case). The action was filed in the District Court of Stevens County, Kansas, against us and one of our subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. Plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims to cover all oil and gas leases (other than the Federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas delivered into their pipelines resulting in underpayments to the plaintiffs. Plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of action. The amount of damages was not specified in the complaint. In February 2002, we, along with one of our subsidiaries, were dismissed from the suit and another subsidiary of the Company was added. A hearing was held in January 2003, and the court held that a class should not be certified. Plaintiffs’ counsel has indicated that he intends to further contest the court’s ruling. We believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

We are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on our financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year.

See Note 6 regarding commodity sales commitments.

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Derivatives

We use financial and commodity-based derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for speculative or trading purposes. See Note 6.

All derivative financial instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or the value confirmed by the counterparty. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), which is later transferred to earnings when the hedged transaction occurs. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of the hedge derivatives, are recorded in derivative fair value (gain) loss in the income statement. This ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged.

The components of derivative fair value (gain) loss, as reflected in the consolidated income statements are:

The estimated fair values of derivatives included in the consolidated balance sheets at March 31, 2003 and December 31, 2002 are summarized below. The increase in the net derivative liability from December 31, 2002 to March 31, 2003 is primarily attributable to increased natural gas prices, partially offset by cash settlements during the period.

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Concentrations of Credit Risk

Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. Because of declining credit ratings of some of our customers, we have greater concentrations of credit with a few large integrated energy companies with investment grade ratings. Financial and commodity-based swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. As of March 31, 2003, our allowance for collectibility of all accounts receivable was $5.7 million.

Our policy is to routinely hedge a portion of our production at commodity prices management deems attractive. While there is a risk we may not be able to realize the benefit of rising prices, management plans to continue this strategy because of the benefits of predictable, stable cash flows. See Note 5 regarding accounting for commodity hedges.

In addition to selling gas under fixed price physical delivery contracts, we enter futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on natural gas and crude oil sales. When actual commodity prices exceed the fixed price provided by these contracts, we pay this excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We have hedged a portion of our exposure to variability in future cash flows from natural gas sales through December 2004 and from crude oil sales through December 2003.

Natural Gas

We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments.

We have closed certain futures contracts and swap agreements that were designated as cash flow hedges with deferred gains of $13.3 million recorded in accumulated other comprehensive income (loss). These deferred gains will be recognized as gas revenue of $0.28 per Mcf on production of 175,000 Mcf per day from April through December 2003.

In January 2003, we entered collar agreements which provide a floor (put) and ceiling (call) price for natural gas. If the market price of natural gas exceeds the ceiling price, we pay the counterparty the difference between these prices. If the market price of natural gas is between the floor and ceiling price, no payments are due from either the Company or the counterparty. If the market price is below the floor price, the counterparty pays us the difference between these prices. We have entered costless collar agreements for April to December 2003 on 50,000 Mcf per day with a floor price of $4.50 per Mcf and an average ceiling price of $5.57 per Mcf. We expect realized prices to be less than these NYMEX floor and ceiling prices because of location, quality and other adjustments.

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The price we receive for our gas production is generally less than the NYMEX price because of basis adjustments for delivery location, quality and other factors. We have entered basis swap agreements which effectively fix the basis adjustment for the following production and periods:

In first quarter 2003, net losses on futures and basis swap hedge contracts decreased gas revenue by $106.5 million. In first quarter 2002, net gains on futures and basis swap hedge contracts increased gas revenue by $35.3 million. Including the effect of fixed price physical delivery contracts, all hedging activities increased gas revenue by $58.7 million for the 2002 quarter. As of March 31, 2003, an unrealized pre-tax derivative fair value loss of $136.3 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). If these contracts had been settled at the March 31 mark-to-market prices, $125.1 million of the fair value loss would be reclassified into earnings through March 2004.

The settlement of futures contracts and swap agreements related to April 2003 gas production resulted in decreased gas revenue of $10.4 million, or approximately $0.57 per Mcf.

Crude Oil

In 2002, we entered a sour oil basis swap on 5,000 Bbls of oil per day through June 2003 at the NYMEX West Texas Intermediate price less $1.25 per Bbl to effectively fix quality and other price differentials. Because this basis swap agreement includes an extendable option, it does not qualify for hedge accounting.

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In February 2003, we entered crude oil costless three-way collars for 2,000 Bbls per day for April through December 2003. These collars have three pricing points as shown in the table below: a ceiling price, a provisional floor price and a strike price. At market prices above the ceiling price, we pay the counterparty the difference between these prices. At market prices within the range of the ceiling and the provisional floor price, no payments are due from either the Company or the counterparty. At market prices within the range of the provisional floor and strike price, the counterparty pays us the difference between the market price and the provisional floor price. At market prices below the strike price, the counterparty pays us $6.40, the spread between the provisional floor and strike price.

In first quarter 2003, net losses on futures hedge contracts decreased oil revenue by $3.7 million. There were no hedging activities related to first quarter 2002 oil production. As of March 31, 2003, there was no unrealized derivative fair value gain or loss related to cash flow hedges of oil price risk recorded in accumulated other comprehensive income (loss).

Transportation Contracts

We have entered firm transportation contracts with various pipelines. Under these contracts we are obligated to transport the following volumes or pay for any deficiencies at the reservation fee rate. If we fail to deliver these volumes to the pipeline, we could owe the pipeline up to the maximum monthly commitment. Our production committed to these pipelines is expected to exceed the minimum daily volumes. We have generally delivered minimum volumes to avoid payment for unused pipeline transportation capacity.

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We effected a four-for-three stock split on March 18, 2003. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect this stock split.

On April 23, 2003, we completed a public offering of 13,800,000 shares of common stock at $18.75 per share. Estimated net proceeds from the offering of $247.7 million and net proceeds from the concurrent sale of senior notes (Note 3) will be used to fund our pending producing property acquisition from units of Williams of Tulsa, Oklahoma (Note 12), to redeem our 8¾% senior subordinated notes and to reduce bank debt.

See Note 11.

The following reconciles earnings (numerator) and shares (denominator) used in the computation of basic and diluted earnings per share:

In accordance with SFAS No. 130, Reporting Comprehensive Income, the following are components of comprehensive income: