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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended March 31, 2004

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, 2004

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PART I. FINANCIAL INFORMATION

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

1. Interim 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, 2003, have not been audited by independent public accountants. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at March 31, 2004 and our income and cash flows for the three months ended March 31, 2004 and 2003. 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-month periods ended March 31, 2004 and 2003 included herein have 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 2003 Annual Report on Form 10-K.

See “Accounting Pronouncements” under Item 2 of this quarterly report on Form 10-Q.

2. Asset Retirement Obligation

Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” recording a cumulative effect of accounting change gain, net of tax, of $1.8 million. 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 determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of the asset retirement obligation activity:

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3. Long-term Debt

Our long-term debt consists of the following:

In January 2004, we sold $500 million of 4.9% senior notes that were issued at 99.34% of par to yield 4.98% to maturity. Net proceeds of approximately $490 million were used to fund our January 2004 property acquisitions of $243 million (Note 12) and to reduce bank debt. The notes mature in February 2014 and interest is payable each February 1 and August 1 beginning August 1, 2004. The 4.9% notes are recorded net of unamortized discount of $3.235 million at March 31, 2004.

In February 2004, we fully repaid our revolving facility and entered a new five-year revolving credit agreement with commercial banks that matures in February 2009. The new agreement provides for an initial commitment amount of $800 million, which may be increased to a maximum of $1 billion, and an interest rate based on the London Interbank Offered Rate plus 1%. On March 31, 2004, borrowings under the revolving credit agreement with commercial banks were $214 million, with unused borrowing capacity of $586 million. The weighted average interest rate of 2.27% at March 31, 2004 is based on the one-month LIBOR plus 1%. After closing acquisitions in April (Note 12), our bank borrowings were $667 million at April 30, 2004, with unused borrowing capacity of $133 million.

4. Commitments and Contingencies

Litigation

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. 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 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

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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 filed an amended class action petition, which reduces the proposed class to only royalty owners, reduces the claims to mismeasurement of volume only, conspiracy, unjust enrichment and accounting, and only applies as to gas measured in Kansas, Colorado and 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.

On August 5, 2003, the Price plaintiffs served one of our subsidiaries with a new original class action petition styled Price, et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against natural gas pipeline owners and operators. Plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas royalty owners either from whom the defendants had purchased natural gas or measured natural gas since January 1, 1974 to the present. The new petition alleges the same improper analysis of gas heating content, which had previously been alleged in the Price case discussed above until it was removed from the case by the filing of the amended class action petition. In all other respects, the new petition appears to be identical to the amended class action petition in that it has a proposed class of only royalty owners, alleges conspiracy, unjust enrichment and accounting, and only applies as to gas measured in Kansas, Colorado and Wyoming. The amount of damages was not specified in the complaint. 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.

Other

To secure tubular goods required to support our drilling program, we have entered a contract with a tubular goods supplier who commits to deliver, at market prices, our next quarter’s tubular products ordered by us at least 30 days prior to the beginning of the quarter. There is no minimum order requirement, and our order is subject to modification by the supplier. The contract is cancellable by either party with at least 60 days notice prior to the beginning of the next calendar quarter.

Through April 2004, we have acquired approximately 20,000 net undeveloped acres in the Barnett Shale of North Texas with an estimated value of $21 million (Note 12) that are subject to lease expiration if initial wells are not drilled within a specified period of generally no more than one year. Because we have ample resources to meet the drilling requirements, we currently do not anticipate significant impairment of these leases.

See Note 6 regarding commodity sales commitments.

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5. Financial Instruments

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 (Note 9). 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. Btu swap contracts do not qualify for hedge accounting.

The components of derivative fair value loss in the consolidated income statements are:

The estimated fair values of derivatives included in the consolidated balance sheets at March 31, 2004 and December 31, 2003 are summarized below. The increase in the net derivative liability from December 31, 2003 to March 31, 2004 is primarily attributable to the effect of rising natural gas prices, partially offset by cash settlements of derivatives during the period.

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

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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, and we have master netting agreements with most counterparties that provide for offsetting payables against receivables from separate swap contracts. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. As of March 31, 2004, our allowance for uncollectible receivables was $4.2 million, reflecting a reduction of $2 million in our estimated exposure since December 31, 2003.

6. Commodity Sales Commitments

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 more predictable production growth and cash flows. See Note 5 regarding accounting for cash flow hedge derivatives.

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 the 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 2005.

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.

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

In first quarter 2004, net losses on futures and basis swap hedge contracts decreased gas revenue by $23.2 million. In first quarter 2003, net losses on futures and basis swap hedge contracts decreased gas revenue by $106.5 million. As of March 31, 2004, an unrealized pre-tax derivative fair value loss of $136.4 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income. Based on March 31 mark-to-market prices, $132.8

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million of this fair value loss is expected to be reclassified into earnings through March 2005. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

The settlement of futures contracts and basis swap agreements related to April 2004 gas production resulted in reduced gas revenue of approximately $6 million, or $0.26 per Mcf.

Crude Oil

As of March 31, 2004, there were no outstanding oil futures, collars or basis swap contracts. In first quarter 2003, net losses on oil futures hedge contracts decreased oil revenue by $3.7 million.

7. Equity

We effected a four-for-three stock split on March 18, 2003 and a five-for-four stock split on March 17, 2004. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits.

See Note 11.

8. Common Shares Outstanding and Earnings per Common Share

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

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9. Comprehensive Income

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

10. Supplemental Cash Flow Information

The following are total interest and income tax payments during each of the periods:

Included in property acquisitions in the consolidated statement of cash flows for the three months ended March 31, 2004 is $147.2 million for the cash purchase price of corporations whose primary assets are producing properties (Note 12).

The accompanying consolidated statements of cash flows exclude the following non-cash equity transactions during the three-month periods ended March 31, 2004 and 2003:

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11. Employee Benefit Plans

During the first three months of 2004, a total of 508,000 stock options were exercised at a weighted average exercise price of $11.03 per share. As a result of these exercises, outstanding common stock increased by 357,000 shares and stockholders’ equity increased by a net $4.4 million.

During the first three months of 2004, 764,000 performance shares were issued to key employees and nonemployee directors and 1,335,000 performance shares vested. As of March 31, 2004, there were 250,000 performance shares outstanding that vest when the common stock price reaches $26.86 and 275,000 performance shares outstanding that vest when the common stock price reaches $28.00. Non-cash compensation expense related to performance shares was $33.2 million for the first three months of 2004 and was $263,000 for the first three months of 2003.

As of April 19, 2004, the common stock price reached a high of $28.60 on the New York Stock Exchange, resulting in vesting of the 525,000 performance shares outstanding at March 31, 2004, as well as 250,000 additional shares that were granted in April 2004 with vesting at $27.86. The April vesting of performance shares resulted in non-cash compensation expense of $21.4 million. An additional 137,500 performance shares and 112,500 phantom performance shares were issued that vest when the common stock price reaches $28.86. Vested phantom performance shares are payable solely in cash in an amount equal to the fair market value of the underlying common stock on the date of vesting.

The following are pro forma net income and earnings per share for the three months ended March 31, 2004 and 2003, as if stock-based compensation had been recorded at the estimated fair value of stock awards at the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation: