XTO ENERGY INC - 10-Q Quarterly Report

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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 September 30, 2004

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-10662

XTO Energy Inc.

(Exact name of registrant as specified in its charter)

Delaware

75-2347769

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)


810 Houston Street, Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

(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:


Class		Outstanding as of October 29, 2004
Common stock, $.01 par value		260,333,598

XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended September 30, 2004

TABLE OF CONTENTS


		Page

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets at September 30, 2004 and December 31, 2003	3

	Consolidated Income Statements for the Three and Nine Months Ended September 30, 2004 and 2003	4

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2004 and 2003	5

	Notes to Consolidated Financial Statements	6

	Report of Independent Registered Public Accounting Firm	19

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27

Item 4.	Controls and Procedures	28

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	29

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29

Item 6.	Exhibits	30

	Signatures	31

PART I. FINANCIAL INFORMATION

XTO ENERGY INC.

Consolidated Balance Sheets


(in thousands, except shares)	September 30, 2004			December 31, 2003
	(Unaudited)
ASSETS

Current Assets:
Cash and cash equivalents	$	12,413		$	6,995
Accounts receivable, net		250,464			193,666
Derivative fair value		19,354			11,351
Current income tax receivable		17,350			4,503
Deferred income tax benefit		62,671			32,455
Other		35,998			12,193

Total Current Assets		398,250			261,163

Property and Equipment, at cost – successful efforts method:
Producing properties		6,463,654			4,253,221
Undeveloped properties		55,848			12,627
Other		90,603			70,494

Total Property and Equipment		6,610,105			4,336,342
Accumulated depreciation, depletion and amortization		(1,288,744	)		(1,024,275	)

Net Property and Equipment		5,321,361			3,312,067


Other Assets:
Derivative fair value		1,292			646
Other		51,291			37,258

Total Other Assets		52,583			37,904

TOTAL ASSETS	$	5,772,194		$	3,611,134


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable and accrued liabilities	$	335,171		$	219,056
Payable to royalty trusts		7,624			4,848
Derivative fair value		190,670			96,653

Total Current Liabilities		533,465			320,557

Long-term Debt		2,001,642			1,252,000

Other Long-term Liabilities:
Derivative fair value		41,440			18,044
Deferred income taxes payable		660,623			426,730
Asset retirement obligation		154,090			93,379
Other		37,455			34,782

Total Other Long-term Liabilities		893,608			572,935


Commitments and Contingencies (Note 5)

Stockholders’ Equity:
Common stock ($.01 par value, 500,000,000 shares authorized, 261,151,975 and 234,251,352 shares issued)		2,612			2,343
Additional paid-in capital		1,406,039			753,900
Treasury stock, at cost (911,978 and -0- shares)		(24,086	)		—
Retained earnings		1,078,698			762,640
Accumulated other comprehensive income (loss)		(119,784	)		(53,241	)

Total Stockholders’ Equity		2,343,479			1,465,642

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	5,772,194		$	3,611,134

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Income Statements (Unaudited)


(in thousands, except per share data)	Three Months Ended September 30						Nine Months Ended September 30
	2004			2003			2004			2003
REVENUES

Gas and natural gas liquids	$	409,109		$	287,109		$	1,140,846		$	745,628
Oil and condensate		92,215			33,253			192,038			100,802
Gas gathering, processing and marketing		6,355			1,786			14,755			9,638
Other		(249	)		(90	)		(696	)		1,633

Total Revenues		507,430			322,058			1,346,943			857,701


EXPENSES

Production		66,305			42,657			169,234			118,675
Taxes, transportation and other		43,111			28,511			117,934			76,345
Exploration		2,939			51			5,609			865
Depreciation, depletion and amortization		106,662			76,437			281,587			204,220
Accretion of discount in asset retirement obligation		1,896			1,388			5,218			3,871
Gas gathering and processing		1,517			2,448			5,236			7,121
General and administrative		32,725			12,928			146,706			50,653
Derivative fair value (gain) loss		554			(2,223	)		6,916			8,009

Total Expenses		255,709			162,197			738,440			469,759

OPERATING INCOME		251,721			159,861			608,503			387,942

OTHER INCOME (EXPENSE)

Gain on distribution of royalty trust units		—			16,216			—			16,216
Loss on extinguishment of debt		—			—			—			(9,601	)
Interest expense, net		(23,292	)		(16,448	)		(65,171	)		(47,235	)

Total Other Income (Expense)		(23,292	)		(232	)		(65,171	)		(40,620	)

INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		228,429			159,629			543,332			347,322

INCOME TAX

Current		6,584			3,600			21,550			9,964
Deferred		81,063			53,223			187,775			112,765

Total Income Tax Expense		87,647			56,823			209,325			122,729

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		140,782			102,806			334,007			224,593
Cumulative effect of accounting change, net of tax		—			—			—			1,778

NET INCOME	$	140,782		$	102,806		$	334,007		$	226,371

EARNINGS PER COMMON SHARE

Basic:
Net income before cumulative effect of accounting change	$	0.54		$	0.45		$	1.36		$	1.01
Cumulative effect of accounting change, net of tax		—			—			—			0.01

Net income	$	0.54		$	0.45		$	1.36		$	1.02

Diluted:
Net income before cumulative effect of accounting change	$	0.54		$	0.44		$	1.35		$	0.99
Cumulative effect of accounting change, net of tax		—			—			—			0.01

Net income	$	0.54		$	0.44		$	1.35		$	1.00

DIVIDENDS DECLARED PER COMMON SHARE	$	0.050		$	0.008		$	0.070		$	0.024

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		258,961			229,740			246,101			222,281

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)


(in thousands)	Nine Months Ended September 30
	2004			2003
OPERATING ACTIVITIES

Net income	$	334,007		$	226,371
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		281,587			204,220
Accretion of discount in asset retirement obligation		5,218			3,871
Non-cash incentive compensation		64,311			11,224
Deferred income tax		187,775			112,765
Gain on distribution of royalty trust units		—			(16,216	)
Non-cash derivative fair value loss		5,575			8,313
Cumulative effect of accounting change, net of tax		—			(1,778	)
Loss on extinguishment of debt		—			9,601
Other non-cash items		7			1,559
Changes in operating assets and liabilities (a)		(20,666	)		39,741

Cash Provided by Operating Activities		857,814			599,671

INVESTING ACTIVITIES

Proceeds from sale of property and equipment		25,524			—
Property acquisitions		(1,723,993	)		(525,847	)
Development costs		(408,259	)		(346,772	)
Other property and asset additions		(22,760	)		(19,534	)

Cash Used by Investing Activities		(2,129,488	)		(892,153	)

FINANCING ACTIVITIES

Proceeds from long-term debt		3,137,423			1,532,000
Payments on long-term debt		(2,388,000	)		(1,465,170	)
Dividends		(6,812	)		(4,801	)
Net proceeds from common stock offering		579,999			247,972
Net proceeds from exercises of stock options		6,680			6,239
Subordinated note redemption costs		—			(7,139	)
Senior note and debt offering costs		(13,056	)		(7,797	)
Purchases of treasury stock and other		(39,142	)		(6,190	)

Cash Provided by Financing Activities		1,277,092			295,114

INCREASE IN CASH AND CASH EQUIVALENTS		5,418			2,632

Cash and Cash Equivalents, Beginning of Period		6,995			14,954


Cash and Cash Equivalents, End of Period	$	12,413		$	17,586

(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	(48,240	)	$	(31,753	)
Other current assets		(36,334	)		(2,765	)
Other operating assets		291			3
Accounts payable, accrued liabilities and payable to royalty trusts		63,617			69,536
Other current liabilities		—			4,720

	$	(20,666	)	$	39,741

See Accompanying Notes to Consolidated Financial Statements.

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 registered public accountants. In the opinion of management, the accompanying financial statements include all adjustments necessary to present fairly our financial position at September 30, 2004, our income for the three and nine months ended September 30, 2004 and 2003, and our cash flows for the nine months ended September 30, 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- and nine-month periods ended September 30, 2004 and 2003 included herein have been subjected to a limited review by KPMG LLP, our independent registered public accountants. The accompanying review report of independent registered public accountants is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the independent registered public 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.

Other

Inventory of tubular goods and equipment for future use on our producing properties is included in other current assets in the consolidated balance sheets, with balances of $25.9 million at September 30, 2004 and $6.5 million at December 31, 2003.

Accrued interest payable is included in accounts payable and accrued liabilities in the consolidated balance sheets, with balances of $28.4 million at September 30, 2004 and $11.5 million at December 31, 2003.

Our effective income tax rates for the three-month and nine-month 2004 and 2003 periods are higher than the maximum federal statutory rate of 35% because of state and local taxes and compensation not deductible for tax purposes.

2. Related Party Transactions

During 2004, we have paid fees to a firm, partially owned by one of our directors, that performs property acquisition advisory services under agreements approved by the Board of Directors in February and May 2004. For acquisitions closing in November 2003 and after, we agreed to pay a one-time fee of $250,000 plus a transaction fee of 0.75% for the first $800 million in acquisitions. The transaction fee decreased to 0.55% after cumulative acquisitions exceeded $800 million. As of September 30, 2004, total fees paid under these agreements were $2.8 million. An additional amount related to the ChevronTexaco Acquisition, currently estimated to be approximately $6 million, will be due upon settlement of outstanding preferential purchase rights in November.

In August 2004, we exchanged $37.8 million interests in nonstrategic working and royalty interests, primarily purchased from ChevronTexaco Corporation, for 19,000 net contiguous acres in the Barnett Shale of North Texas and $25.4 million in other consideration. This exchange was with companies either wholly or majority owned by the adult children and a brother of Bob R. Simpson, Chairman and Chief Executive Officer of XTO Energy. In connection with this exchange, we granted the other parties an option to purchase other properties included in the ChevronTexaco

Acquisition, which was exercised on October 27, 2004 for $12.8 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.

3. Asset Retirement Obligation

Effective January 1, 2003, we adopted Statement of Financial Accounting Standards (SFAS) 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 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:


(in thousands)
Asset retirement obligation, January 1, 2004	$	93,379

Revision in estimated cash flows		5,978
Liability incurred upon acquiring and drilling wells		50,176
Liability settled upon plugging and abandoning wells		(661	)
Accretion of discount expense		5,218

Asset retirement obligation, September 30, 2004	$	154,090

4. Long-term Debt

Our long-term debt consists of the following:


(in thousands)	September 30, 2004		December 31, 2003
Senior debt-
Bank debt under revolving credit agreement due February 2009	$	405,000	$	502,000
7¹/2% senior notes due April 15, 2012		350,000		350,000
6¹/4% senior notes due April 15, 2013		400,000		400,000
4.9% senior notes due February 1, 2014, net of discount		496,929		—
5% senior notes due January 31, 2015, net of discount		349,713		—

Total long-term debt	$	2,001,642	$	1,252,000

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 13) and to reduce bank debt. The notes mature in February 2014 and interest is payable each February 1 and August 1. The 4.9% notes are recorded net of unamortized discount of $3.1 million at September 30, 2004.

In February 2004, we fully repaid our revolving agreement and entered a new five-year revolving credit agreement with commercial banks that matures in February 2009. The agreement provides for a maximum commitment amount of $1 billion, and an interest rate based on the London Interbank Offered Rate plus 1%. On September 30, 2004, borrowings under the revolving credit agreement with commercial banks were $405 million at a weighted average interest rate of 2.68%, with unused borrowing capacity of $595 million. On May 10, 2004, we entered into a second bank revolving credit agreement that permits us to borrow up to an additional $100 million on the same terms and conditions provided in our original bank revolving credit agreement. On September 30, 2004, there were no borrowings outstanding under this second agreement that was terminated on October 29, 2004. Unused borrowing capacity at September 30, 2004 totaled $695 million.

We are currently negotiating with commercial banks to enter a new $300 million five-year term loan with an initial interest rate of LIBOR plus 0.75%. Other terms and conditions are substantially the same as our existing revolving credit agreement. We expect to finalize this agreement on November 10, 2004.

In September 2004, we sold $350 million of 5% senior notes that were issued at 99.918% of par to yield 5.011% to maturity. The notes were sold pursuant to Rule 144A under the Securities Act of 1933 that allows unregistered transactions with qualified institutional buyers. The notes mature in January 2015 and interest is payable each January 31 and July 31 beginning January 31, 2005. 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. The Company has agreed to use its best efforts to effectively register the notes with the Securities and Exchange Commission by March 2005. 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 0.15%. The 5% notes are recorded net of unamortized discount of $287,000 at September 30, 2004. Net proceeds of approximately $347 million were used to reduce bank debt associated with our recent acquisitions.

5. 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 United States District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against the Company and certain of our subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorneys fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other companies have been consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion has not been scheduled. While we are unable to predict the outcome of this case or estimate the amount of any possible loss, 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. The 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. The 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. The 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 to gas measured in Kansas, Colorado and Wyoming. The court has set an evidentiary hearing in April 2005 to determine whether the amended class should be certified. 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. The 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 to gas measured in Kansas, Colorado and Wyoming. The court has set an evidentiary hearing in April 2005 to determine whether the amended class should be certified. 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.

In September 2004, we were served with a lawsuit styled Burkett, et al. v. J.M. Huber Corp. and XTO Energy Inc. The action was filed in the District Court of La Plata County, Colorado against us and J.M. Huber Corporation. The plaintiffs allege that the defendants have deducted in their calculation of royalty payments expenses of compression, gathering, treatment, dehydration, or other costs to place the natural gas produced in a marketable condition at a marketable location. The plaintiffs seek to represent a class consisting of all lessors and their successors in interest who own or have owned mineral interests located in La Plata County, Colorado and that are leased to or operated by Huber or us, except to the extent that the lessors or their successors have expressly authorized deduction of post-production expenses from royalties. We acquired the interests of Huber in producing properties in La Plata County effective October 1, 2002, and have assumed the responsibility for certain liabilities of Huber prior to the effective date, which may include liability for post-production deductions made by Huber. We have filed our response and intend to file a response for Huber. We believe that the Company has good defenses against this claim 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 were contacted by the U.S. Environmental Protection Agency regarding the EPA’s claims that we violated the National Pollutant Discharge Elimination System general permit concerning the discharge of produced water and sanitary wastes into the Cook Inlet from our two operated Cook Inlet production platforms. A meeting was held in September 2004 with the EPA to discuss a possible settlement of the alleged violations, which settlement amount will be less than $200,000. We have accrued management’s estimate of the potential liability from this claim 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

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 October 2004, we have acquired more than 80,000 net acres in the Barnett Shale of North Texas (Note 13). Approximately 60,000 net acres are undeveloped properties with an estimated value of $69 million that are generally subject to lease expiration if initial wells are not drilled within one year. Because we have ample resources to meet the drilling requirements, we currently do not anticipate significant impairment of these leases.

In October 2004, we agreed to acquire an aircraft for $17.1 million, either through purchase or lease. We made an initial payment of $6.8 million and currently expect to take delivery of the plane in the first half of 2005.

See Note 7 regarding commodity sales commitments.

6. 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 7.

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 10). 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:


(in thousands)	Three Months Ended September 30						Nine Months Ended September 30
	2004			2003			2004			2003
Change in fair value of Btu swap contracts	$	(1,467	)	$	(2,498	)	$	1,255		$	4,882

Change in fair value of other derivatives that do not qualify for hedge accounting		1,287			412			(43	)		(1,483	)

Ineffective portion of derivatives qualifying for hedge accounting		734			(137	)		5,704			4,610

Derivative fair value (gain) loss	$	554		$	(2,223	)	$	6,916		$	8,009

The estimated fair values of derivatives included in the consolidated balance sheets at September 30, 2004 and December 31, 2003 are summarized below. The increase in the net derivative liability from December 31, 2003 to September 30, 2004 is primarily attributable to the effect of rising oil and gas prices, partially offset by cash settlements of derivatives during the period.


(in thousands)	September 30, 2004			December 31, 2003
Derivative Assets:
Fixed-price natural gas futures and swaps	$	17,862		$	11,997
Fixed-price crude oil futures and differential swaps		2,784			—
Derivative Liabilities:
Fixed-price natural gas futures and swaps		(167,106	)		(96,702	)
Fixed-price crude oil futures and differential swaps		(45,754	)		—
Btu swap contracts		(19,250	)		(17,995	)

Net derivative liability	$	(211,464	)	$	(102,700	)

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. Typically, we have greater concentrations of credit with several A- or better-rated integrated energy companies. 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 derivative contracts. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. As of September 30, 2004, our allowance for uncollectible receivables was $4.2 million, reflecting a reduction of $2.2 million in our estimated exposure since December 31, 2003.

7. Commodity Sales Commitments

Our policy is to routinely hedge a portion of our production at commodity prices management deems attractive. This policy assures cash flow needed for funding our development program and provides more predictable economic returns for our acquisitions. 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 these benefits. See Note 6 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 and crude oil 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.


Production Period	Base Production			Production Related to 2004 Acquisitions			Total
Production Period	Mcf per Day	Average NYMEX Price per Mcf		Mcf per Day	Average NYMEX Price per Mcf		Mcf per Day	Average NYMEX Price per Mcf
2004 November to December	450,000	$	4.93	50,000	$	6.34	500,000	$	5.07
2005 January to December	200,000	$	5.79	50,000	$	6.34	250,000	$	5.90

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:


	Delivery Location
Production Period	Arkoma			Houston Ship Channel			Mid- Continent			Rockies			San Juan Basin			Total
2004
November to December
Mcf per day		60,000			265,000			60,000			10,000			65,000		460,000
Basis per Mcf (a)	$	(0.11	)	$	(0.20	)	$	(0.26	)	$	(0.71	)	$	(0.67	)
2005
January to March
Mcf per day		10,000			210,000			—			10,000			70,000		300,000
Basis per Mcf (a)	$	(0.06	)	$	(0.21	)		—		$	(0.71	)	$	(0.67	)

April to June
Mcf per day		—			270,000			—			5,000			30,000		305,000
Basis per Mcf (a)		—		$	(0.14	)		—		$	(0.75	)	$	(0.68	)

July to August
Mcf per day		—			270,000			—			5,000			30,000		305,000
Basis per Mcf (a)		—		$	(0.12	)		—		$	(0.75	)	$	(0.68	)

September
Mcf per day		—			250,000			—			5,000			30,000		285,000
Basis per Mcf (a)		—		$	(0.12	)		—		$	(0.75	)	$	(0.68	)

October
Mcf per day		—			270,000			—			5,000			30,000		305,000
Basis per Mcf (a)		—		$	(0.14	)		—		$	(0.75	)	$	(0.68	)

November to December
Mcf per day		—			220,000			—			10,000			40,000		270,000
Basis per Mcf (a)		—		$	(0.17	)		—		$	(0.76	)	$	(0.68	)

(a) Reductions to NYMEX gas prices for delivery location.

In the first nine months of 2004, net losses on futures and basis swap hedge contracts decreased gas revenue by $93.7 million. In the first nine months of 2003, net losses on futures and basis swap hedge contracts decreased gas

revenue by $183.5 million. As of September 30, 2004, an unrealized pre-tax derivative fair value loss of $148.4 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income. Based on September 30 mark-to-market prices, $131.3 million of this fair value loss is expected to be reclassified into earnings through September 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 October 2004 gas production resulted in reduced gas revenue of approximately $3.1 million, or $0.12 per Mcf.

Crude Oil

In connection with our acquisitions announced in second quarter 2004, we entered oil futures contracts to sell 10,000 Bbls per day from July 2004 through December 2005 at an average West Texas Intermediate NYMEX price of $35.91 per Bbl. For 5,000 Bbls per day of this hedged production, we entered a crude sweet and sour differential swap of $3.05 per Bbl, to effectively fix the price for crude sour production at $32.86 per Bbl. Prices to be realized for hedged oil production are expected to be less than the NYMEX price because of location, quality and other adjustments.

In the first nine months of 2004, net losses on futures and differential swap hedge contracts decreased oil revenue by $6.9 million. In the first nine months of 2003, net losses on futures hedge contracts decreased oil revenue by $3.7 million. As of September 30, 2004, an unrealized pre-tax derivative fair value loss of $43 million, related to cash flow hedges of oil price risk, was recorded in accumulated other comprehensive income. Based on September 30 mark-to-market prices, $36.9 million of this fair value loss is expected to be reclassified into earnings through September 2005. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

8. 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.

In May 2004, we completed a public offering of 23.8 million shares of common stock at $25.23 per share. Net proceeds of $580 million were used to reduce bank borrowings that funded our producing property acquisitions from ExxonMobil Corporation and our deposit on the ChevronTexaco acquisition (Note 13).

In August 2004, our Board of Directors authorized the repurchase of up to 15 million shares of our common stock which may be purchased from time to time in open market or negotiated transactions. This authorization effectively replaces the share repurchase authorization remaining from May 2000. As of September 30, 2004, we have not repurchased any shares.

See Note 12.

9. 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:


(in thousands, except per share data)	Three Months Ended September 30
	2004					2003
	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	140,782	258,961	$	0.54	$	102,806	229,740	$	0.45

Effect of dilutive securities:
Stock options		—	2,363				—	3,138

Diluted	$	140,782	261,324	$	0.54	$	102,806	232,878	$	0.44


	Nine Months Ended September 30
	2004					2003
	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	334,007	246,101	$	1.36	$	226,371	222,281	$	1.02

Effect of dilutive securities:
Stock options		—	2,218				—	3,086

Diluted	$	334,007	248,319	$	1.35	$	226,371	225,367	$	1.00

10. Comprehensive Income

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


	Three Months Ended September 30						Nine Months Ended September 30
(in thousands)	2004			2003			2004			2003
Net income	$	140,782		$	102,806		$	334,007		$	226,371

Other comprehensive income (loss):
Change in hedge derivative fair value		(95,813	)		92,951			(206,876	)		(136,031	)
Hedge derivative contracts settlements reclassified into earnings from other comprehensive income (a)		39,613			29,871			101,623			187,157

Net unrealized hedge derivative gain (loss)		(56,200	)		122,822			(105,253	)		51,126
Income tax benefit (expense)		18,922			(42,988	)		38,710			(17,894	)

Total other comprehensive income (loss)		(37,278	)		79,834			(66,543	)		33,232

Total comprehensive income	$	103,504		$	182,640		$	267,464		$	259,603

(a)

For realized gains upon contract settlements, the reduction to comprehensive income offsets contract proceeds generally recorded as oil and gas revenue. For realized losses upon contract settlements, the increase in comprehensive income offsets contract payments generally recorded as reductions to oil and gas revenue.

11. Supplemental Cash Flow Information

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


	Nine Months Ended September 30
(in thousands)	2004		2003
Interest	$	47,195	$	32,184
Income tax	$	34,397	$	5,244

The accompanying consolidated statements of cash flows exclude the following non-cash transactions during the nine-month periods ended September 30, 2004 and 2003:

Grants of 1,902,000 performance shares and vesting of 2,442,000 performance shares in 2004 and grants of 662,000 performance shares and vesting of 679,000 performance shares in 2003 (Note 12)

Exchange of nonstrategic working and royalty interests for nonproducing acres in August 2004 (Note 2)

Distribution of 1,360,000 Cross Timbers Royalty Trust units as a dividend to common stockholders in 2003

12. Employee Benefit Plans

During the first nine months of 2004, a total of 3,411,000 stock options were exercised at a weighted average exercise price of $17.81 per share. As a result of these exercises, outstanding common stock increased by 1,334,000 shares and stockholders’ equity increased by a net $11 million. During the first nine months of 2004, a total of 1,464,000 stock options were granted at a weighted average exercise price of $32.58 per share. Over 80% of all outstanding options are currently exercisable.

Outstanding performance share grants to executive officers and other key employees totaled 1,096,000 shares at December 31, 2003. After grants of 1,888,000 performance shares to executive officers and other key employees and vesting of 2,428,000 performance shares, 278,000 performance shares that vest when the stock reaches $37.50 and 278,000 performance shares that vest when the stock reaches $42.50 remained outstanding at September 30, 2004. Also during the first nine months of 2004, 14,000 vested performance shares were issued to nonemployee directors under an annual automatic grant as partial compensation for their services. Non-cash compensation expense related to performance share vesting totaled $64.3 million for the first nine months of 2004.

Since 2001, it has been the historical practice of the Board of Directors to grant executive officers stock-based performance awards that vest upon a common stock target price increase of a specified increment. These awards were originally 100,000 performance shares that vested when the common stock price increased by $2.50, and were payable only in unrestricted common shares. As adjusted for stock splits, the last of which was on March 17, 2004, these awards for executive officers totaled 250,000 performance shares with vesting when the common stock price increased by $1.00. During second quarter 2004, the Company began granting cash-equivalent, or phantom, performance shares to executive officers in lieu of performance shares. Vested cash-equivalent performance shares are payable solely in cash in an amount equal to the fair market value of the underlying common stock upon vesting.

During the first nine months of 2004, 725,000 cash-equivalent performance shares were issued to executive officers and vested. Cash-equivalent performance share compensation expense recognized in the first nine months of 2004 totaled $22.3 million. As of September 30, 2004, there are no cash-equivalent performance shares outstanding.

In September 2004, the Compensation Committee of the Board of Directors announced that it intended to restructure the Company’s equity incentive program to discontinue the use of performance shares for executive officers and to provide that all future grants to the officers would be in the form of options or other stock appreciation shares.

As a result, in October 2004, the Compensation Committee of the Board of Directors amended the change in control performance share grant agreements to delete the provisions regarding the grant of performance shares for every $1.00 increment in the price of the common stock and to provide that, immediately prior to a change in control, executive officers will receive a lump-sum cash payment equal to the value of 1,250,000 shares of common stock on the date of the change in control. A provision, providing that certain officers will also receive a total grant of 387,500 performance shares immediately prior to a change in control without regard to the price of our common stock, has been revised to provide that such payment will be in cash and not in shares of common stock. All amounts to be granted under these agreements will be adjusted for any future stock splits or other extraordinary transactions. If the executive officers are subject to the 20% parachute excise tax, the Company will pay the executive officer an additional amount to “gross up” the payment so that the executive officer will receive the full amount due under the terms of the amended change in control grant agreement after payment of the excise tax.

Prior to May 2004, the Company recognized compensation expense for stock-based performance awards upon vesting because management was unable to assess the probable date the stock target price would be achieved. Since May 2004, because of more frequent vesting of stock-based performance awards related to common stock price increases in 2004, management assesses whether the vesting period of stock-based awards can be reasonably estimated. When management is able to reasonably estimate a probable vesting period, compensation is recognized ratably over the estimated vesting period or at actual vesting, if earlier. On September 29, 2004, 556,000 performance shares were granted to key employees other than executive officers. For the 278,000 performance shares that vest at $37.50, management has estimated a reasonably probable vesting period of one year, resulting in related compensation of $10.4 million to be recognized at the earlier of actual vesting or ratably accrued through September 2005. Management has concluded that a probable vesting period cannot be currently estimated for the remaining 278,000 performance shares that vest when the common stock price reaches $42.50.

The following are pro forma net income and earnings per share for the three and nine months ended September 30, 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:


(in thousands, except per share data)		Three Months Ended September 30						Nine Months Ended September 30
		2004			2003			2004			2003
Net income as reported		$	140,782		$	102,806		$	334,007		$	226,371

Add:
Stock-based compensation expense included in the income statement, net of related tax effects			9,860			5			54,559			7,295

Deduct:
Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects			(9,833	)		(2,602	)		(63,508	)		(8,411	)

Pro forma net income		$	140,809		$	100,209		$	325,058		$	225,255

Earnings per common share:
Basic	As reported	$	0.54		$	0.45		$	1.36		$	1.02

	Pro forma	$	0.54		$	0.44		$	1.32		$	1.01

Diluted	As reported	$	0.54		$	0.44		$	1.35		$	1.00

	Pro forma	$	0.54		$	0.43		$	1.31		$	1.00

On October 15, 2004, the Board of Directors adopted the XTO Energy Inc. 2004 Stock Incentive Plan subject to shareholder approval at a special meeting of shareholders to be held on November 16, 2004. Under the proposed 2004 Plan, a total of 18 million shares of common stock may be issued pursuant to grants of stock options, stock appreciation rights, stock units, stock awards, bonus shares, dividend equivalents, and other stock-based awards. Grants under the 2004 Plan are subject to the provision that awards outstanding at any given point in time under all Company equity incentive plans cannot exceed 6% of the shares of common stock outstanding. Awards generally vest and become exercisable over a minimum three-year period, with provision for accelerated vesting.

13. Acquisitions

In January 2004, we acquired producing properties located primarily in East Texas and northern Louisiana in three separate transactions totaling $243 million after adjustments of $6 million for net revenues, preferential right elections and other items from the effective date of the transaction. The acquisitions were funded with a portion of the proceeds from the sale of 4.9% senior notes in January 2004 (Note 4).

From February through April 2004, we purchased $223.1 million of properties located primarily in the Barnett Shale of North Texas and in the Arkoma Basin. We completed the purchases of $78.7 million of these properties in first quarter 2004. In April, we closed the acquisition of the remaining $144.4 million of properties, of which $12 million was paid in February. These acquisitions are subject to typical post-closing adjustments. Funding was provided by bank debt and cash flow from operations.

In two separate transactions during April 2004, we acquired predominantly oil-producing properties in the Permian Basin of West Texas and in the Powder River Basin of Wyoming from ExxonMobil Corporation for a total agreed purchase price of $336 million, subject to a contingent payable of up to an additional $5 million dependent on earnings from one property in the following year. The adjusted price at closing totaled $331 million, subject to the contingent payable of up to $5 million. The acquisitions were funded with bank borrowings that were repaid with proceeds from the sale of common stock in May 2004 (Note 8).

In May 2004, we entered an agreement with ChevronTexaco Corporation to acquire properties for a stated purchase price of $1.1 billion and paid a $110 million deposit toward the purchase price. These properties expand our operations in our Eastern Region, the Permian Basin and Mid-Continent and add new coal bed methane properties in the Rocky Mountains and a new operating region in South Texas. The acquisition closed on August 16, 2004. After adjustments for net revenues from the January 1, 2004 effective date, preferential purchase right elections and other typical closing adjustments, the adjusted purchase price was $912 million. Post-closing adjustments for outstanding preferential purchase rights, final net revenues, volume balancing and income tax effects will be made within twelve months. The acquisition was funded through existing bank credit facilities and the sale of common stock in May 2004.

Two acquisitions that closed in first quarter 2004 were purchases of corporations that own producing and nonproducing properties as their primary assets. After purchase accounting adjustments, including a $71.1 million step-up adjustment for deferred income taxes, the cost of all properties acquired in the first nine months of 2004 was $1.8 billion.

In April 2003, we entered an agreement with units of Williams of Tulsa, Oklahoma to acquire natural gas and coal bed methane producing properties in the Raton Basin of Colorado, the Hugoton Field of southwestern Kansas and the San Juan Basin of New Mexico and Colorado for $400 million. The transaction closed in May 2003. After typical closing adjustments, the purchase price was $381 million, which was financed with proceeds from our sale of senior notes and common stock.

Acquisitions were recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for the nine months ended September 30, 2004 and 2003 and the year ended December 31, 2003, as if the ChevronTexaco, ExxonMobil and Williams acquisitions were made at the beginning of each period. These pro forma results are not necessarily indicative of future results.


	Pro Forma (Unaudited)
(in thousands, except per share data)	Nine Months Ended September 30				Year Ended December 31, 2003
	2004		2003		Year Ended December 31, 2003
Revenues	$	1,586,303	$	1,214,248	$	1,645,307

Net income before cumulative effect of accounting change	$	400,359	$	297,927	$	381,985

Net income	$	400,359	$	299,705	$	383,763

Earnings per common share:
Basic	$	1.57	$	1.25	$	1.58

Diluted	$	1.55	$	1.23	$	1.56

Weighted average shares outstanding:
Basic		255,422		239,774		242,242

Diluted		257,641		242,860		245,307

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of XTO Energy Inc.:

We have reviewed the accompanying consolidated balance sheet of XTO Energy Inc. (a Delaware corporation) and its subsidiaries as of September 30, 2004, and the related consolidated income statements for the three- and nine-month periods ended September 30, 2004 and 2003, and the consolidated cash flow statements for the nine-month periods ended September 30, 2004 and 2003. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards established by the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of XTO Energy Inc. as of December 31, 2003, and the related consolidated statements of income, stockholders’ equity, and cash flows for the year then ended (not presented herein), included in the Company’s 2003 Annual Report on Form 10-K, and in our report dated March 5, 2004, we expressed an unqualified opinion on those statements. Our report on those statements referred to a change in accounting for asset retirement obligations in 2003. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003 is fairly stated, in all material respects, in relation to the consolidated balance sheet included in the Company’s 2003 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Dallas, Texas

November 4, 2004

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2003 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

Oil and Gas Production and Prices


	Quarter Ended September 30						Nine Months Ended September 30
	2004		2003		Increase (Decrease)		2004		2003		Increase
Total production
Gas (Mcf)		77,895,107		65,418,122	19	%		221,190,219		176,078,257	26	%
Natural gas liquids (Bbls)		650,433		713,990	(9	%)		1,945,292		1,758,535	11	%
Oil (Bbls)		2,390,538		1,167,628	105	%		5,225,414		3,542,133	48	%
Mcfe		96,140,933		76,707,830	25	%		264,214,455		207,882,265	27	%

Average daily production
Gas (Mcf)		846,686		711,067	19	%		807,264		644,975	25	%
Natural gas liquids (Bbls)		7,070		7,761	(9	%)		7,100		6,442	10	%
Oil (Bbls)		25,984		12,692	105	%		19,071		12,975	47	%
Mcfe		1,045,010		833,781	25	%		964,286		761,473	27	%

Average sales price
Gas per Mcf	$	5.02	$	4.19	20	%	$	4.94	$	4.04	22	%
Natural gas liquids per Bbl	$	27.95	$	18.38	52	%	$	24.56	$	19.72	25	%
Oil per Bbl	$	38.58	$	28.48	35	%	$	36.75	$	28.46	29	%

Average NYMEX prices
Gas per MMBtu	$	5.76	$	4.97	16	%	$	5.81	$	5.66	3	%
Oil per Bbl	$	43.80	$	30.26	45	%	$	39.06	$	31.03	26	%

Bbl - Barrel

Mcf - Thousand cubic feet

Mcfe -Thousand cubic feet of natural gas equivalent (computed on an energy equivalent basis of one Bbl equals six Mcf)

MMBtu - One million British Thermal Units, a common energy measurement

Production increases from 2003 to 2004 for the quarter and nine-month periods are primarily because of acquisitions and development activity, partially offset by natural decline. Third party pipeline curtailments reduced third quarter 2004 daily natural gas production by approximately 16,000 Mcf. Completion of a third party pipeline and additional processing facilities in fourth quarter 2004 should alleviate the production curtailment that began in third quarter 2004. Fourth quarter 2004 production will also reflect a full quarter of production from the ChevronTexaco acquisition which closed on August 16, 2004.

Colder than normal weather, record low gas storage levels and continued increasing demand caused gas prices to remain relatively high during the first five months of 2003. With diminished demand related to higher prices, natural gas prices were lower during the summer months, then rose with cooler weather in late 2003 and early 2004. Forecasts for continued production declines, increasing natural gas demand and larger than projected storage withdrawals supported higher prices in the first six months of 2004. Mild summer weather and increased gas storage inventories led to declining gas prices in August and early September. Natural gas prices rose substantially in mid-September and October because of reduced Gulf of Mexico gas production due to damage to offshore production and transportation facilities caused by Hurricane Ivan and because of low domestic heating oil inventories. Prices will continue to be

affected by weather, the improving U.S. economy, the level of North American production and import levels of liquified natural gas. Management expects natural gas prices to remain volatile. The NYMEX price for October 2004 was $5.72 per MMBtu. At October 29, 2004, the average NYMEX futures price for the following twelve months was $7.85 per MMBtu.

Crude oil prices are generally determined by global supply and demand. During 2003, increased demand, continued uncertainties in the Middle East and production discipline by OPEC maintained oil prices at relatively high levels. Oil prices have continued to increase in 2004 because of increasing demand and low crude stocks. In June and July 2004, oil supply disruption concerns caused prices to rise near $40 per Bbl. OPEC members agreed to increase daily oil production by two million barrels beginning July 2004 and an additional 500,000 barrels beginning August 2004 to maintain market stability and prices. Although OPEC decided to increase daily oil production by one million barrels beginning November 2004, oil prices have continued to increase. Low global oil inventories, continued instability in the Middle East, political unrest in Nigeria and hurricanes in the Gulf of Mexico led to record oil prices exceeding $55 per Bbl in October. The average NYMEX price for October 2004 was $53.08 per Bbl. At October 29, 2004, the average NYMEX futures price for the following twelve months was $49.46 per Bbl.

We use price hedging arrangements, including fixed-price physical delivery contracts, to reduce price risk on a portion of our oil and gas production. We have hedged a portion of our exposure to variability in future cash flows from natural gas and oil sales through December 2005; see Note 7 to Consolidated Financial Statements. During third quarter 2004, our hedging activities decreased gas revenue by $32.7 million, or $0.42 per Mcf and decreased oil revenue by $6.9 million, or $2.90 per Bbl. For the first nine months of 2004, our hedging activities decreased gas revenue by $93.7 million, or $0.42 per Mcf and decreased oil revenue by $6.9 million, or $1.33 per Bbl. During third quarter 2003, our hedging activities decreased gas revenue by $29.9 million, or $0.46 per Mcf. For the first nine months of 2003, our hedging activities decreased gas revenue by $183.5 million, or $1.04 per Mcf and decreased oil revenue by $3.7 million or $1.04 per Bbl. There were no oil hedges in third quarter 2003.

Results of Operations

Quarter Ended September 30, 2004 Compared with Quarter Ended September 30, 2003

Net income for third quarter 2004 was $140.8 million compared to $102.8 million for third quarter 2003. Third quarter 2004 earnings include the net after-tax effects of stock-based incentive compensation of $9.9 million, related primarily to vesting of cash-equivalent performance shares, and a derivative fair value loss of $300,000. Third quarter 2003 earnings include the net after-tax effects of a $1.4 million derivative fair value gain and a non-cash gain of $10.5 million resulting from the distribution of our Cross Timbers Royalty Trust units as a dividend to common stockholders.

Total revenues for third quarter 2004 were $507.4 million, a 58% increase from third quarter 2003 revenues of $322.1 million. Operating income for the quarter was $251.7 million, a 57% increase from third quarter 2003 operating income of $159.9 million. Gas and natural gas liquids revenues increased $122 million (42%) because of the 20% increase in gas prices, the 52% increase in natural gas liquids prices and the 19% increase in gas volumes, partially offset by the 9% decrease in natural gas liquids volumes. Oil revenue increased $59 million (177%) because of the 105% increase in production and the 35% increase in oil prices. Third quarter gas gathering, processing and marketing revenues increased $4.6 million from third quarter 2003 primarily because of increased margins and prices.

Expenses for third quarter 2004 totaled $255.7 million, a 58% increase from third quarter 2003 expenses of $162.2 million. Production expense increased $23.6 million (55%) primarily because of increased production, maintenance, labor and power and fuel costs. Taxes, transportation and other increased $14.6 million (51%) from the third quarter of 2003 primarily because of a corresponding increase in revenues. Depreciation, depletion and amortization increased $30.2 million (40%) because of increased production and higher acquisition costs. General and administrative expense increased $19.8 million (153%) primarily because of a $15.6 million increase in stock-based incentive compensation, of which $500,000 is non-cash.

We recorded a derivative fair value loss of $500,000 in the third quarter of 2004 as compared with a derivative fair value gain of $2.2 million in third quarter 2003. These losses primarily reflect the net effect of rising gas prices

during the quarter on derivatives that do not qualify for hedge accounting. See Note 6 to Consolidated Financial Statements.

Interest expense increased $6.8 million (42%) primarily because of a 38% increase in weighted average borrowings to partially fund acquisitions.

The effective income tax rate for the 2004 quarter was 38.4%, as compared with 35.6% for third quarter 2003. The higher rate is primarily because of increased state income taxes.

Nine Months Ended September 30, 2004 Compared with Nine Months Ended September 30, 2003

Net income for the nine months ended September 30, 2004 was $334 million, compared to $226.4 million for the same 2003 period. Earnings for the first nine months of 2004 include the net after-tax effects of primarily non-cash stock-based incentive compensation of $54.6 million, special bonuses totaling $11.7 million related to acquisitions announced in second quarter 2004, and a $4.4 million derivative fair value loss. Earnings for the first nine months of 2003 include the net after-tax effects of non-cash incentive compensation of $7.3 million, loss on extinguishment of debt of $6.2 million, a $5.2 million derivative fair value loss, a non-cash contingency gain of $1.1 million, a non-cash gain of $10.5 million resulting from the distribution of Cross Timbers Royalty Trust units as a dividend to common stockholders and a $1.8 million gain on the cumulative effect of accounting change for the adoption of Statement of Financial Accounting Standards No. 143 for asset retirement obligations.

Total revenues for the first nine months of 2004 were $1.3 billion, or $489.2 million (57%) higher than revenues of $857.7 million for the first nine months of 2003. Operating income for the first nine months of 2004 was $608.5 million, a 57% increase from operating income of $387.9 million for the comparable 2003 period. Gas and natural gas liquids revenues increased $395.2 million (53%) primarily because of the 26% increase in gas production and the 11% increase in natural gas liquids production, as well as the 22% increase in gas prices and the 25% increase in natural gas liquids prices. Oil revenue increased $91.2 million (91%) because of the 48% increase in production and the 29% increase in prices. Gas gathering, processing and marketing revenues increased $5.1 million (53%) primarily because of increased margins and prices.

Expenses for the first nine months of 2004 totaled $738.4 million, a 57% increase from total expenses for the first nine months of 2003 of $469.8 million. Production expense increased $50.6 million (43%) primarily because of increased production, maintenance, labor, compression, workover and power and fuel costs. Taxes, transportation and other increased $41.6 million (54%) primarily because of a corresponding increase in revenues. Depreciation, depletion and amortization increased $77.4 million (38%) because of increased production and higher acquisition costs.

General and administrative expense increased $96.1 million (190%) primarily because of a $75.4 million increase in stock-based incentive compensation from $11.2 million to $86.6 million, of which $64.3 million is non-cash. Stock-based incentive compensation was approximately 3.4% of the increase in our market capitalization for the first nine months of 2004 after adjusting for the effects of the May 2004 common stock offering. General and administrative expense for year-to-date 2004 also includes a total of $11.7 million in special bonuses related to the ChevronTexaco and ExxonMobil acquisitions announced in second quarter 2004.

The derivative fair value loss for the first nine months of 2004 was $6.9 million compared to a derivative fair value loss of $8 million in the first nine months of 2003. The decreased loss is primarily because of the effect of rising crude oil prices on the fair value of Btu swap contracts in 2004. See Note 6 to Consolidated Financial Statements.

Interest expense increased $17.9 million (38%) primarily because of a 38% increase in the weighted average borrowings to partially fund property acquisitions. During the first nine months of 2003, we recognized a $9.6 million loss on extinguishment of debt related to the redemption of our 8¾% senior subordinated notes and a $16.2 million gain on the distribution of Cross Timbers Royalty Trust units as a dividend to common stockholders.

The 2004 year-to-date effective income tax rate was 38.5%, as compared with a 35.3% effective rate for the nine-month 2003 period. The higher rate is because of increased state income taxes and compensation exceeding tax deductible limits.

Comparative Expenses per Mcf Equivalent Production

The following are expenses on an Mcf equivalent (Mcfe) produced basis:


	Three Months Ended September 30						Nine Months Ended September 30
	2004		2003		Increase		2004		2003		Increase (Decrease)
Production	$	0.69	$	0.56	23	%	$	0.64	$	0.57	12	%
Taxes, transportation and other		0.45		0.37	22	%		0.45		0.37	22	%
Depreciation, depletion and amortization (DD&A)		1.11		1.00	11	%		1.07		0.98	9	%
General and administrative (G&A) (a)		0.18		0.17	6	%		0.18		0.19	(5	%)
Interest		0.24		0.21	14	%		0.25		0.23	9	%

(a)

Excludes the following:

In the 2004 quarter, stock-based incentive compensation of $15.7 million ($0.16 per Mcfe)

In the 2004 nine-month period, stock-based incentive compensation of $86.6 million ($0.33 per Mcfe) and special acquisition-related bonuses of $11.7 million ($0.04 per Mcfe)

In the 2003 nine-month period, stock-based incentive compensation of $11.2 million ($0.05 per Mcfe). Stock-based incentive compensation was not significant in the 2003 quarter.

The following are explanations of significant variances of expenses on an Mcfe basis:

Production expenses - Increased production expense is because of higher workover, maintenance, labor and power and fuel costs.

Taxes, transportation and other - These expenses generally increase with product prices.

DD&A - Increased DD&A is because of higher acquisition costs per Mcfe.

Interest - Increased interest is because of a greater portion of acquisitions financed by debt.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $857.8 million for the first nine months of 2004, compared with $599.7 million for the same 2003 period. Cash provided by operating activities for the first nine months of 2004 increased primarily because of production from acquisitions and development activity and increased product prices. Cash flow from operating activities was reduced by changes in operating assets and liabilities of $20.7 million in the first nine months of 2004 and increased by $39.7 million in the first nine months of 2003. Changes in operating assets and liabilities are primarily the result of timing of cash receipts and disbursements. Cash flow from operating activities was also reduced by exploration expense of $5.6 million in the first nine months of 2004 and $900,000 in the comparable 2003 period.

During the nine months ended September 30, 2004, cash provided by operating activities of $857.8 million, common stock offering proceeds of $580 million and net debt proceeds of $749.4 million were used to fund net property acquisitions, development costs and other net capital additions of $2.129 billion, dividends of $6.8 million, senior note and debt offering costs of $13.1 million and treasury stock purchases and other net costs of $32.5 million primarily related to performance share vesting and employee stock option exercises. The resulting increase in cash and cash equivalents for the period was $5.4 million.

Total current assets increased $137.1 million during the first nine months of 2004 primarily because of a $56.8 million, or 29%, increase in accounts receivable related to increased production and product prices, a $12.8 million increase in current income taxes receivable related to federal tax prepayments and a $23.8 million increase in other current assets primarily because of increased warehouse stock of tubular goods. Deferred income tax benefit increased $30.2 million primarily because of higher gas prices and the resulting loss in net hedge derivatives. Total current liabilities increased $212.9 million during the first nine months of 2004 primarily because of a $94 million increase in derivative fair value liabilities attributable to the effect of higher gas prices, as well as a $116.1 million increase in accounts payable and accrued liabilities related to increased production and product prices.

Working capital decreased $75.8 million from a negative position of $59.4 million at December 31, 2003 to negative working capital of $135.2 million at September 30, 2004 primarily because of the timing of cash receipts and disbursements. Excluding the effects of derivative fair value and deferred tax current assets and liabilities, working capital decreased $20 million from a negative position of $6.5 million at December 31, 2003 to a negative $26.5 million at September 30, 2004.

Any payments due counterparties under our hedge derivative contracts should ultimately be funded by higher prices received from sales of our production. Since production receipts often lag payments to the counterparties by as much as six weeks, any interim cash needs are funded by bank debt.

Acquisitions and Development

In August 2004, we exchanged $37.8 million interests in nonstrategic working and royalty interests, primarily purchased from ChevronTexaco, for 19,000 net contiguous acres in the Barnett Shale of North Texas and $25.4 million in other consideration. This exchange was with companies either wholly or majority owned by the adult children and a brother of Bob R. Simpson, Chairman and Chief Executive Officer of XTO Energy. In connection with this exchange, we granted the other parties an option to purchase other properties included in the ChevronTexaco Acquisition, which was exercised on October 27, 2004 for $12.8 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.

Exploration and development expenditures for the first nine months of 2004 were $413.9 million, compared with $347.6 million for the first nine months of 2003. Primarily as a result of our recent acquisitions, we have increased our 2004 exploration and development budget to $600 million. Development will focus on drilling and workover opportunities and will be funded by cash flow from operations. Actual costs may vary significantly due to many factors, including development results and changes in drilling and service costs.

Acquisitions that have closed through September 2004 total approximately $1.7 billion. The Board of Directors approved acquisitions in excess of our previously announced budget of $650 million to take advantage of significant acquisition opportunities. As with 2004 acquisitions to date, any acquisitions during the remainder of the year are expected to be funded with a combination of cash flow from operations, bank debt and public and private sales of equity and debt.

Through the first nine months of 2004, we participated in drilling 430 gas wells and 20 oil wells and performed 194 workovers. Our drilling activity for the year to date was concentrated in East Texas and the Arkoma and San Juan basins. Workovers have focused on recompletions, artificial lift and wellhead compression. These projects generally have met or exceeded management expectations.

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. As a result of substantial increases in steel prices, our 2004 development budget includes $30 million for projected increased cost of tubular materials. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program and limit our production growth.

Through October 2004, we have acquired more than 80,000 net acres in the Barnett Shale of North Texas. Approximately 60,000 net acres are undeveloped properties with an estimated value of $69 million that are generally subject to lease expiration if initial wells are not drilled within one year. Because we have ample resources to meet the drilling requirements, we currently do not anticipate significant impairment of these leases.

The unused borrowing capacity of $695 million at September 30, 2004 under our revolving credit agreements is available to fund future acquisitions and development. Upon finalization of our new $300 million term loan on November 10, 2004, our unused borrowing capacity will be approximately $737 million. See Debt and Equity below.

Debt and Equity

As of September 30, 2004, long-term debt increased by $749.6 million from the balance at December 31, 2003. On September 30, 2004, borrowings under the revolving credit agreement with commercial banks were $405 million at a weighted average interest rate of 2.68%, with unused borrowing capacity of $595 million. On May 10, 2004, we entered into a second bank revolving credit agreement that permits us to borrow up to an additional $100 million on the same terms and conditions provided in our original bank revolving credit agreement. On September 30, 2004, there

were no borrowings outstanding under this second agreement that was terminated on October 29, 2004. Unused borrowing capacity at September 30, 2004 totaled $695 million.

Our revolving credit agreement requires us to maintain a debt-to-total capitalization of not more than 60%. There have been no changes in our debt covenants since we entered our current revolving credit agreement in February 2004.

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 and to reduce bank debt. The notes mature on February 1, 2014 and interest is payable each February 1 and August 1.

In May 2004, we completed a public offering of 23.8 million shares of common stock. Net proceeds from the offering, after underwriting discount and offering expenses, were $580 million, and were used to reduce bank borrowings that funded our producing property acquisitions from ExxonMobil Corporation and our deposit on the pending ChevronTexaco acquisition.

In September 2004, we sold $350 million of 5% senior notes that were issued at 99.918% of par to yield 5.011% to maturity. The notes mature in January 2015 and interest is payable each January 31 and July 31 beginning January 31, 2005. The 5% notes are recorded net of unamortized discount of $287,000 at September 30, 2004. Net proceeds of approximately $347 million were used to reduce bank debt associated with our recent acquisitions.

Stockholders’ equity at September 30, 2004 increased $877.8 million from year end because of earnings of $334 million for the nine months ended September 30, 2004 and an increase in common stock and additional paid-in capital of $652.4 million related to the sale of common stock, the exercise of stock options and issuance of performance shares, partially offset by an increase in accumulated other comprehensive loss of $66.5 million, an increase in treasury stock of $24.1 million related to income tax withholding for performance share vesting, and common stock dividends declared of $18 million. The increase in accumulated other comprehensive loss was primarily attributable to an increase in the fair value loss of hedge derivatives related to higher natural gas prices, partially offset by cash settlements of hedge derivatives during the first nine months of 2004.

See Notes 4 and 8 to Consolidated Financial Statements.

Common Stock Dividends

In August 2004, the Board of Directors increased the quarterly dividend from $0.01 to $0.05 per share. The third quarter 2004 dividend was paid on October 15, 2004 to stockholders of record on September 30, 2004.

Accounting Pronouncements

In September 2004, the Financial Accounting Standards Board issued FASB Staff Position No. 142-2, Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities. This FASB Staff Position effectively states that entities that comply with accounting prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, should report and disclose drilling and mineral rights in accordance with SFAS No. 19, rather than SFAS No. 142. As prescribed by SFAS No. 19, we include drilling and mineral rights as property costs in our consolidated balance sheets. Therefore, issuance of this FASB Staff Position does not affect our financial reporting.

Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities,” was effective for calendar year companies as of January 1, 2004. Because we do not have interests in variable interest

entities, this pronouncement has no effect on our consolidated financial statements and currently is not expected to have a significant effect in the future.

Forward-Looking Statements

Certain information included in this quarterly report and other materials filed or to be filed by the Company with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by the Company, contain projections and forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Company’s operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures, cash flow, drilling activity, drilling locations, acquisition and development activities and funding thereof, pricing differentials, production and reserve growth, reserve potential, operating costs, operating margins, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, unused borrowing capacity, estimated stock award vesting periods, completion of pipelines and processing facilities, regulatory matters and competition. Such forward-looking statements are based on management’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “predicts,” “anticipates,” “believes,” “estimates,” “goal,” “should,” “could,” “assume,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. In particular, the factors discussed below and in our Annual Report on Form 10-K could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. The cautionary statements contained in our Annual Report on Form 10-K are incorporated herein by reference in addition to the following cautionary statements.

Among the factors that could cause actual results to differ materially are:

–

changes in interest rates,

–

our ability to identify prospects for drilling,

–

higher than expected costs and expenses, including production, drilling and well equipment costs,

–

potential delays or failure to achieve expected production from existing and future exploration and development projects,

–

basis risk and counterparty credit risk in executing commodity price risk management activities,

–

potential liability resulting from pending or future litigation,

–

competition in the oil and gas industry as well as competition from other sources of energy, and

–

general domestic and international economic and political conditions.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2003 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

Hypothetical changes in interest rates and prices chosen for the following estimated sensitivity effects are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Interest Rate Risk

We are exposed to interest rate risk on debt with variable interest rates. At September 30, 2004, our variable rate debt had a carrying value of $405 million, which approximated its fair value, and our fixed rate debt had a carrying value of $1.597 billion and an approximate fair value liability of $1.677 billion. Assuming a one percent, or 100-basis point, change in interest rates at September 30, 2004, the fair value of our fixed rate debt would change by approximately $117 million.

Commodity Price Risk

We hedge a portion of our price risks associated with our natural gas and crude oil sales. As of September 30, 2004, outstanding gas futures contracts, swap agreements and gas basis swap agreements had a net fair value loss of $149.2 million. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $65 million in the fair value of these gas futures contracts, swap agreements and gas basis swap agreements at September 30, 2004. As of September 30, 2004, outstanding oil futures contracts and differential swaps had a net fair value loss of $43 million. The aggregate effect of a hypothetical 10% change in oil prices would result in a change of approximately $18.6 million in the fair value of these oil futures and differential swaps at September 30, 2004.

Because most of our futures contracts and swap agreements have been designated as hedge derivatives, changes in their fair value generally are reported as a component of accumulated other comprehensive income (loss) until the related sale of production occurs. At that time, the realized hedge derivative gain or loss is transferred to product revenues in the consolidated income statement.

We had a physical delivery contract to sell 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. Because this gas sales contract was priced based on crude oil, which is not clearly and closely associated with natural gas prices, it was accounted for as a non-hedge derivative financial instrument. This contract (referred to as the Enron Btu swap contract) was terminated in December 2001 in conjunction with the bankruptcy filing of Enron Corporation. In November 2001, we entered derivative contracts to effectively defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. The net fair value loss on these contracts at September 30, 2004 was $19.3 million. The effect of a hypothetical 10% change in gas prices would result in a change of approximately $5.7 million in the fair value of these contracts, while a 10% change in crude oil prices would result in a change of approximately $3.7 million.

Item 4. CONTROLS AND PROCEDURES

We performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in our periodic filings with the Securities and Exchange Commission.

There have been no significant changes in our internal control over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds


Issuer Purchases of Equity Securities
Month	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (b)
July	—	$	—	—
August	—	$	—	—
September	5,468	$	32.64	—

Total	5,468	$	32.64	—	15,000,000

(a)

During the quarter ended September 30, 2004, the Company purchased shares of common stock as treasury shares to pay income tax withholding obligations in conjunction with vesting of performance shares under the 1998 Stock Incentive Plan. These share purchases were not part of a publicly announced program to purchase common shares.

(b)

The Company has a repurchase program approved by the Board of Directors for the repurchase of up to 15,000,000 shares of the Company’s common stock. The repurchase program was announced on August 18, 2004. No purchases were made pursuant to this program during third quarter 2004.

Item 3. through Item 5.

Not applicable.

Item 6. Exhibits



Exhibit Number and Description

10.1	Form of Amended and Restated Agreement for Grant (relating to change in control) between the Company and Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated October 15, 2004 (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 21, 2004)

11	Computation of per share earnings (included in Note 9 to Consolidated Financial Statements)

15	Letter re unaudited interim financial information

	15.1	Awareness letter of KPMG LLP

31	Rule 13a-14(a)/15d-14(a) Certifications

	31.1	Chief Executive Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2	Chief Financial Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32	Section 1350 Certifications

	32.1	Chief Executive Officer and Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

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.


	XTO ENERGY INC.

Date: November 5, 2004	By	/s/ LOUIS G. BALDWIN
		Louis G. Baldwin Executive Vice President and Chief Financial Officer (Principal Financial Officer)

	By	/s/ BENNIE G. KNIFFEN
		Bennie G. Kniffen Senior Vice President and Controller (Principal Accounting Officer)

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