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 June 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		(I.R.S. Employer
incorporation or organization)		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 July 30, 2004
Common stock, $.01 par value		258,932,131

XTO ENERGY INC.

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

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

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

	Consolidated Income Statements for the Three and Six Months Ended June 30, 2004 and 2003	4

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003	5

	Notes to Consolidated Financial Statements	6

	Report of Independent Registered Public Accounting Firm	17

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	25

Item 4.	Controls and Procedures	26

PART II. OTHER INFORMATION

Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	27

Item 4.	Submission of Matters to a Vote of Security Holders	27

Item 6.	Exhibits and Reports on Form 8-K	28

	Signatures	30

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

XTO ENERGY INC.

Consolidated Balance Sheets


(in thousands, except shares)	June 30, 2004			December 31, 2003
ASSETS	(Unaudited)
Current Assets:
Cash and cash equivalents	$	14,589		$	6,995
Accounts receivable, net		267,134			193,666
Derivative fair value		8,639			11,351
Current income tax receivable		8,215			4,503
Deferred income tax benefit		48,116			32,455
Other		27,978			12,193

Total Current Assets		374,671			261,163

Property and Equipment, at cost – successful efforts method:
Producing properties		5,493,884			4,253,221
Undeveloped properties		29,458			12,627
Other		85,320			70,494

Total Property and Equipment		5,608,662			4,336,342
Accumulated depreciation, depletion and amortization		(1,199,055	)		(1,024,275	)

Net Property and Equipment		4,409,607			3,312,067

Other Assets:
Derivative fair value		6,327			646
Other		51,294			37,258

Total Other Assets		57,621			37,904

TOTAL ASSETS	$	4,841,899		$	3,611,134


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	271,431		$	219,056
Payable to royalty trusts		9,374			4,848
Derivative fair value		136,451			96,653

Total Current Liabilities		417,256			320,557

Long-term Debt		1,393,847			1,252,000

Other Long-term Liabilities:
Derivative fair value		35,339			18,044
Deferred income taxes payable		588,356			426,730
Asset retirement obligation		119,354			93,379
Other		39,255			34,782

Total Other Long-term Liabilities		782,304			572,935

Commitments and Contingencies (Note 5)
Stockholders’ Equity:
Common stock ($.01 par value, 500,000,000 shares authorized, 259,791,249 and 234,251,352 shares issued)		2,598			2,343
Additional paid-in capital		1,401,380			753,900
Treasury stock, at cost (906,510 and -0- shares)		(23,907	)		—
Retained earnings		950,928			762,640
Accumulated other comprehensive income (loss)		(82,507	)		(53,241	)

Total Stockholders’ Equity		2,248,492			1,465,642

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,841,899		$	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 June 30					Six Months Ended June 30
	2004			2003		2004			2003
REVENUES
Gas and natural gas liquids	$	381,605		$	244,349	$	731,737		$	458,519
Oil and condensate		58,907			32,085		99,823			67,549
Gas gathering, processing and marketing		4,526			4,002		8,400			7,852
Other		(289	)		1,723		(447	)		1,723

Total Revenues		444,749			282,159		839,513			535,643

EXPENSES
Production		53,748			39,172		102,929			76,018
Taxes, transportation and other		38,260			24,640		74,823			47,834
Exploration		1,649			300		2,670			814
Depreciation, depletion and amortization		93,021			66,770		174,925			127,783
Accretion of discount in asset retirement obligation		1,716			1,258		3,322			2,483
Gas gathering and processing		1,382			2,370		3,719			4,673
General and administrative		67,227			26,367		113,981			37,725
Derivative fair value (gain) loss		(13	)		7,375		6,362			10,232

Total Expenses		256,990			168,252		482,731			307,562

OPERATING INCOME		187,759			113,907		356,782			228,081

OTHER EXPENSE
Loss on extinguishment of debt		—			9,601		—			9,601
Interest expense, net		22,242			15,770		41,879			30,787

Total Other Expense		22,242			25,371		41,879			40,388

INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		165,517			88,536		314,903			187,693

INCOME TAX
Current		8,209			1,719		14,966			6,364
Deferred		58,219			29,482		106,712			59,542

Total Income Tax Expense		66,428			31,201		121,678			65,906

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		99,089			57,335		193,225			121,787
Cumulative effect of accounting change, net of tax		—			—		—			1,778

NET INCOME	$	99,089		$	57,335	$	193,225		$	123,565

EARNINGS PER COMMON SHARE
Basic:
Net income before cumulative effect of accounting change	$	0.41		$	0.25	$	0.81		$	0.56
Cumulative effect of accounting change, net of tax		—			—		—			0.01

Net income	$	0.41		$	0.25	$	0.81		$	0.57

Diluted:
Net income before cumulative effect of accounting change	$	0.40		$	0.25	$	0.80		$	0.55
Cumulative effect of accounting change, net of tax		—			—		—			0.01

Net income	$	0.40		$	0.25	$	0.80		$	0.56

DIVIDENDS DECLARED PER COMMON SHARE	$	0.010		$	0.008	$	0.020		$	0.016

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		244,656			225,206		239,601			218,489

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)


(in thousands)	Six Months Ended June 30
	2004			2003
OPERATING ACTIVITIES
Net income	$	193,225		$	123,565
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		174,925			127,783
Accretion of discount in asset retirement obligation		3,322			2,483
Non-cash incentive compensation		63,823			11,215
Deferred income tax		106,712			59,542
Non-cash derivative fair value loss		5,597			9,777
Cumulative effect of accounting change, net of tax		—			(1,778	)
Loss on extinguishment of debt		—			9,601
Other non-cash items		137			4,881
Changes in operating assets and liabilities (a)		(50,223	)		(12,067	)

Cash Provided by Operating Activities		497,518			335,002

INVESTING ACTIVITIES
Property acquisitions		(912,050	)		(472,031	)
Development costs		(243,986	)		(219,508	)
Other property and asset additions		(17,403	)		(14,211	)

Cash Used by Investing Activities		(1,173,439	)		(705,750	)

FINANCING ACTIVITIES
Proceeds from long-term debt		1,731,710			1,314,000
Payments on long-term debt		(1,590,000	)		(1,173,170	)
Dividends		(4,223	)		(2,964	)
Net proceeds from common stock offering		579,999			247,972
Net proceeds from exercise of stock options		5,909			4,516
Subordinated note redemption costs		—			(7,139	)
Senior note and debt offering costs		(10,334	)		(7,797	)
Purchases of treasury stock and other		(29,546	)		(5,977	)

Cash Provided by Financing Activities		683,515			369,441

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		7,594			(1,307	)
Cash and Cash Equivalents, Beginning of Period		6,995			14,954

Cash and Cash Equivalents, End of Period	$	14,589		$	13,647

(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	(64,911	)	$	(49,721	)
Other current assets		(19,178	)		569
Other operating assets		1,157			361
Accounts payable, accrued liabilities and payable to royalty trusts		32,709			30,604
Other current liabilities		—			6,120

	$	(50,223	)	$	(12,067	)

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 June 30, 2004, our income for the three and six months ended June 30, 2004 and 2003, and our cash flows for the six months ended June 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 six-month periods ended June 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 supplies and equipment for future use on our producing properties is included in other current assets in the consolidated balance sheets, with balances of $19.5 million at June 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 $21.7 million at June 30, 2004 and $11.5 million at December 31, 2003.

Our effective income tax rates for the three-month and six-month 2004 and 2003 periods are different from the 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 decreases to 0.55% after cumulative acquisitions exceed $800 million. As of June 30, 2004, total fees paid under these agreements were $2.8 million. A final payment under these agreements of $6.9 million is expected to be paid upon closing of the ChevronTexaco acquisition in August 2004 (Note 13).

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:


	Six Months Ended June 30
(in thousands)	2004			2003
Asset retirement obligation, January 1	$	93,379		$	75,256
Revision in estimated cash flows		5,978			—
Liability incurred upon acquiring and drilling wells		17,035			8,955
Liability settled upon plugging and abandoning wells		(360	)		(251	)
Accretion of discount expense		3,322			2,483

Asset retirement obligation, June 30	$	119,354		$	86,443

4.	Long-term Debt

Our long-term debt consists of the following:


(in thousands)	June 30, 2004		December 31, 2003
Senior debt-
Bank debt under revolving credit agreement due February 2009	$	147,000	$	502,000
7½% senior notes due April 15, 2012		350,000		350,000
6¼% senior notes due April 15, 2013		400,000		400,000
4.9% senior notes due February 1, 2014, net of discount		496,847		—

Total long-term debt	$	1,393,847	$	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 beginning August 1, 2004. The 4.9% notes are recorded net of unamortized discount of $3.153 million at June 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 new agreement provides for an initial commitment amount of $800 million, which was increased to the maximum of $1 billion on June 16, 2004, and an interest rate based on the London Interbank Offered Rate plus 1%. On June 30, 2004, borrowings under the revolving credit agreement with commercial banks were $147 million at a weighted average interest rate of 2.44%, with unused borrowing capacity of $853 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 June 30, 2004, there were no borrowings outstanding under this second agreement that will terminate on November 10, 2004. Unused borrowing capacity at June 30, 2004 totaled $953 million. Remaining funding requirements upon closing of the ChevronTexaco acquisition in August 2004 (Note 13) are estimated to be $840 million to $890 million which will be funded through our bank revolving credit agreements.

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 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 more than 300 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 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 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 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

Through July 2004, we have acquired approximately 47,000 net undeveloped acres in the Barnett Shale of North Texas with an estimated value of $32 million (Note 13) 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 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 June 30					Six Months Ended June 30
	2004			2003		2004			2003
Change in fair value of Btu swap contracts	$	581		$	5,054	$	2,722		$	7,380
Change in fair value of other derivatives that do not qualify for hedge accounting		(296	)		1,403		(1,330	)		(1,895	)
Ineffective portion of derivatives qualifying for hedge accounting		(298	)		918		4,970			4,747

Derivative fair value (gain) loss	$	(13	)	$	7,375	$	6,362		$	10,232

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


(in thousands)	June 30, 2004			December 31, 2003
Derivative Assets:
Fixed-price natural gas futures and swaps	$	12,241		$	11,997
Fixed-price crude oil futures and differential swaps		2,725			—
Derivative Liabilities:
Fixed-price natural gas futures and swaps		(148,255	)		(96,702	)
Fixed-price crude oil futures and differential swaps		(2,818	)		—
Btu swap contracts		(20,717	)		(17,995	)

Net derivative liability	$	(156,824	)	$	(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. Because of declining credit ratings of some of our customers, we have greater concentrations of credit with a few large integrated energy companies with investment grade ratings. Financial and commodity-based swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, 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 June 30, 2004, our allowance for uncollectible receivables was $4.2 million, reflecting a reduction of $2.1 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.


	Base Production			Acquisition- Related Production			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 August to December	400,000	$	4.77	50,000	$	6.34	450,000	$	4.94
2005 January to December	100,000	$	5.21	50,000	$	6.34	150,000	$	5.59

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
August
Mcf per day		70,000			220,000			60,000			10,000			65,000		425,000
Basis per Mcf (a)	$	(0.12	)	$	(0.06	)	$	(0.26	)	$	(0.68	)	$	(0.67	)
September to October
Mcf per day		70,000			220,000			60,000			10,000			65,000		425,000
Basis per Mcf (a)	$	(0.12	)	$	(0.07	)	$	(0.26	)	$	(0.68	)	$	(0.67	)
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)	$	(0.05	)	$	(0.21	)		—		$	(0.71	)	$	(0.67	)
April to June
Mcf per day		—			220,000			—			5,000			30,000		255,000
Basis per Mcf (a)		—		$	(0.15	)		—		$	(0.75	)	$	(0.68	)
July to August
Mcf per day		—			220,000			—			5,000			30,000		255,000
Basis per Mcf (a)		—		$	(0.12	)		—		$	(0.75	)	$	(0.68	)
September
Mcf per day		—			200,000			—			5,000			30,000		235,000
Basis per Mcf (a)		—		$	(0.12	)		—		$	(0.75	)	$	(0.68	)
October
Mcf per day		—			220,000			—			5,000			30,000		255,000
Basis per Mcf (a)		—		$	(0.15	)		—		$	(0.75	)	$	(0.68	)
November to December
Mcf per day		—			220,000			—			10,000			40,000		270,000
Basis per Mcf (a)		—		$	(0.17	)		—		$	(0.75	)	$	(0.68	)

(a)

Reductions to NYMEX gas prices for delivery location.

In the first six months of 2004, net losses on futures and basis swap hedge contracts decreased gas revenue by $61 million. In the first six months of 2003, net losses on futures and basis swap hedge contracts decreased gas revenue by $153.6 million. As of June 30, 2004, an unrealized pre-tax derivative fair value loss of $131 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income. Based on June 30 mark-to-market prices, $121.9 million of this fair value loss is expected to be reclassified into earnings through June 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 July 2004 gas production resulted in reduced gas revenue of approximately $15.8 million, or $0.64 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.

There were no hedging activities related to the first six months of 2004 oil production. In the first half of 2003, net losses on futures hedge contracts decreased oil revenue by $3.7 million. As of June 30, 2004, an unrealized pre-tax derivative fair value loss of less than $200,000, related to cash flow hedges of oil price risk, was recorded in accumulated other comprehensive income. Based on June 30 mark-to-market prices, a $2.5 million fair value loss related to oil price hedges is expected to be reclassified into earnings through June 2005, followed by a $2.3 million gain in the last half of 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.

On May 25, 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 pending ChevronTexaco acquisition (Note 13).

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 June 30
	2004					2003
	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	99,089	244,656	$	0.41	$	57,335	225,206	$	0.25

Effect of dilutive securities:
Stock options		—	2,255				—	3,206

Diluted	$	99,089	246,911	$	0.40	$	57,335	228,412	$	0.25


(in thousands, except per share data)	Six Months Ended June 30
	2004					2003
	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	193,225	239,601	$	0.81	$	123,565	218,489	$	0.57

Effect of dilutive securities:
Stock options		—	2,121				—	2,960

Diluted	$	193,225	241,722	$	0.80	$	123,565	221,449	$	0.56

10.

Comprehensive Income

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


	Three Months Ended June 30						Six Months Ended June 30
(in thousands)	2004			2003			2004			2003
Net income	$	99,089		$	57,335		$	193,225		$	123,565

Other comprehensive income (loss):
Change in hedge derivative fair value		(33,013	)		(77,230	)		(111,063	)		(228,982	)
Reclassification adjustments - realized (gain) loss upon contract settlements (a)		38,212			47,126			62,010			157,286

		5,199			(30,104	)		(49,053	)		(71,696	)
Income tax (expense) benefit		(1,924	)		10,537			18,150			25,094
Effect of increase in tax rate to 37%		2,723			—			1,637			—

Total other comprehensive income (loss)		5,998			(19,567	)		(29,266	)		(46,602	)

Total comprehensive income	$	105,087		$	37,768		$	163,959		$	76,963

(a)

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

11.

Supplemental Cash Flow Information

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


	Six Months Ended June 30
(in thousands)	2004		2003
Interest	$	31,112	$	28,665
Income tax		18,678		244

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

Grants of 1,346,000 performance shares and vesting of 2,427,000 performance shares in 2004 and grants of 578,000 performance shares and vesting of 679,000 performance shares in 2003 (Note 12).

12.

Employee Benefit Plans

During the first half of 2004, a total of 737,000 stock options were exercised at a weighted average exercise price of $10.89 per share. As a result of these exercises, outstanding common stock increased by 529,000 shares and stockholders’ equity increased by a net $6.7 million. During the first half of 2004, a total of 40,000 stock options were granted at a weighted average exercise price of $25.62 per share. Over 99% 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 1,332,000 performance shares to executive officers and other key employees and vesting of 2,413,000 performance shares, 15,000 performance shares that vest when the stock reaches $32.50 remained outstanding at June 30, 2004. Also during the first half 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 $63.8 million for the first six 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, performance awards for executive officers totaled 250,000 shares with vesting when the common stock price increases 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.

The Company historically has 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. Recent increases in the common stock price, coupled with the effects of the March 2004 stock split, have resulted in more frequent vesting of stock-based performance awards. Because of this, management has concluded that it is able to reasonably estimate a probable vesting period for stock-based performance awards granted since May 2004 with a $1.00 or less incremental target price at the grant date. Accordingly, as of the grant date, a vesting period has been estimated for accruing compensation related to these awards. For all future stock-based performance awards, when management is able to reasonably estimate a probable vesting period, compensation will be recognized ratably over the estimated vesting period or at actual vesting, if earlier.

During the first half of 2004, 475,000 cash-equivalent performance shares were issued to executive officers. During the first six months of 2004, 225,000 cash-equivalent performance shares vested, and the remaining 250,000 shares outstanding at June 30, 2004 vested when the common stock price reached $30.86 on July 8, 2004. Cash-equivalent performance share compensation expense recognized in the first six months of 2004 totaled $7.1 million, which included $600,000 accrued compensation for the shares that vested on July 8, based on a three-month vesting period as estimated at the grant date. Remaining compensation for these shares of $7.1 million will be recorded in third quarter 2004. On July 8, 2004, 250,000 cash-equivalent performance shares were granted to executive officers that vest when the common stock price reaches $31.86. Compensation of $8 million related to this grant will be recorded at the earlier of actual vesting or ratably accrued over three months, the estimated vesting period at the grant date.

The following are pro forma net income and earnings per share for the three and six months ended June 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 June 30						Six Months Ended June 30
	2004			2003			2004			2003
Net income as reported	$	99,089		$	57,335		$	193,225		$	123,565
Add:
Stock-based compensation expense included in the income statement, net of related tax effects		23,768			7,119			44,699			7,290
Deduct:
Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects		(19,714	)		(5,239	)		(53,675	)		(5,809	)

Pro forma net income	$	103,143		$	59,215		$	184,249		$	125,046

Earnings per common share:
Basic As reported	$	0.41		$	0.25		$	0.81		$	0.57

Pro forma	$	0.42		$	0.26		$	0.77		$	0.57

Diluted As reported	$	0.40		$	0.25		$	0.80		$	0.56

Pro forma	$	0.42		$	0.26		$	0.76		$	0.56

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).

Two of the 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 $62.7 million step-up adjustment for deferred income taxes, the cost of all properties acquired in the first six months of 2004 was $974.7 million.

In April 2003, we entered into a definitive 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 unaudited pro forma results of operations for the six months ended June 30, 2004 and 2003 and the year ended December 31, 2003, as if the 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)	Six Months Ended June 30				Year Ended December 31, 2003
	2004		2003		Year Ended December 31, 2003
Revenues	$	862,168	$	615,213	$	1,305,884

Net income before cumulative effect of accounting change	$	199,452	$	136,987	$	310,183

Net income	$	199,452	$	138,765	$	311,961

Earnings per common share:
Basic	$	0.80	$	0.60	$	1.31

Diluted	$	0.80	$	0.59	$	1.30

Weighted average shares outstanding:
Basic		248,256		231,473		237,732

Diluted		250,377		234,433		240,797

In May 2004, we entered an agreement with ChevronTexaco Corporation to acquire producing properties for a stated purchase price of $1.1 billion. We expect to close the transaction no later than August 16, 2004. After adjustments for other acquisition costs, estimated cash flows from the effective date of January 1, 2004, preferential purchase right elections and customary post-closing adjustments, we estimate the purchase price at closing to be between $950 million and $1 billion. We paid $110 million in May toward this purchase price, which has been recorded in producing properties in the accompanying consolidated balance sheet at June 30, 2004. The estimated remaining amount due is expected to be funded by bank borrowings.

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 June 30, 2004, and the related consolidated income statements for the three- and six-month periods ended June 30, 2004 and 2003, and the consolidated cash flow statements for the six-month periods ended June 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

July 30, 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 June 30			Six Months Ended June 30
	2004	2003	Increase (Decrease)	2004	2003	Increase (Decrease)
Total production
Gas (Mcf)	73,093,864	57,433,670	27%	143,295,112	110,660,135	29%
Natural gas liquids (Bbls)	679,163	578,202	17%	1,294,859	1,044,545	24%
Oil (Bbls)	1,609,104	1,169,069	38%	2,834,876	2,374,505	19%
Mcfe	86,823,466	67,917,296	28%	168,073,522	131,174,435	28%
Average daily production
Gas (Mcf)	803,229	631,139	27%	787,336	611,382	29%
Natural gas liquids (Bbls)	7,463	6,354	17%	7,115	5,771	23%
Oil (Bbls)	17,682	12,847	38%	15,576	13,119	19%
Mcfe	954,104	746,344	28%	923,481	724,721	27%
Average sales price
Gas per Mcf	$ 5.00	$ 4.07	23%	$ 4.90	$ 3.95	24%
Natural gas liquids per Bbl	$23.43	$18.41	27%	$22.86	$20.63	11%
Oil per Bbl	$36.61	$27.45	33%	$35.21	$28.45	24%
Average NYMEX prices
Gas per MMBtu	$ 5.99	$ 5.40	11%	$ 5.84	$ 6.00	(3%)
Oil per Bbl	$38.27	$28.96	32%	$36.69	$31.42	17%

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 six-month periods are primarily because of acquisitions and development activity, partially offset by natural decline.

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 have supported higher prices in the first six months of 2004. Prices in 2004 will continue to be affected by weather, the recovery of the domestic 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 July 2004 was $6.14 per MMBtu. At July 30, 2004, the average NYMEX futures price for the following twelve months was $6.43 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 to record high prices over $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. The average NYMEX price for July 2004 was $40.70 per Bbl. At July 30, 2004, the average NYMEX futures price for the following twelve months was $41.02 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 second quarter 2004, our hedging activities decreased gas revenue by $37.8 million, or $0.52 per Mcf. For the first half of 2004, our hedging activities decreased gas revenue by $61 million, or $0.43 per Mcf. During second quarter 2003, our hedging activities decreased gas revenue by $47.1 million, or $0.82 per Mcf. For the first half of 2003, our hedging activities decreased gas revenue by $153.6 million, or $1.39 per Mcf and oil revenue by $3.7 million or $1.56 per Bbl. There were no oil hedge gains or losses in second quarter 2003 or in the first half of 2004.

Results of Operations

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

Net income for second quarter 2004 was $99.1 million compared to $57.3 million for second quarter 2003. Second quarter 2004 earnings include the net after-tax effects of stock-based incentive compensation of $23.8 million (of which $19.3 million is non-cash) and a total of $11.7 million in special bonuses related to acquisitions announced in second quarter 2004. Second quarter 2003 earnings include the net after-tax effects of non-cash incentive compensation of $7.1 million, loss on extinguishment of debt of $6.2 million, a $4.8 million fair value loss on certain derivatives that do not qualify for hedge accounting and a non-cash contingency gain of $1.1 million.

Total revenues for second quarter 2004 were $444.7 million, a 58% increase from second quarter 2003 revenues of $282.2 million. Operating income for the quarter was $187.8 million, a 65% increase from second quarter 2003 operating income of $113.9 million. Gas and natural gas liquids revenues increased $137.3 million (56%) because of the 27% increase in gas volumes and the 17% increase in natural gas liquids volumes, as well as the 23% increase in gas prices and the 27% increase in natural gas liquids prices. Oil revenue increased $26.8 million (84%) because of the 38% increase in production and the 33% increase in oil prices. Second quarter gas gathering, processing and marketing revenues increased $500,000 from second quarter 2003 primarily because of increased margins and prices.

Expenses for second quarter 2004 totaled $257 million, a 53% increase from second quarter 2003 expenses of $168.3 million. Production expense increased $14.6 million (37%) primarily because of increased production, labor, maintenance and workover costs. Taxes, transportation and other increased $13.6 million (55%) from the second quarter of 2003 primarily because of a corresponding increase in revenues. Depreciation, depletion and amortization increased $26.3 million (39%) because of increased production and higher acquisition and drilling costs. General and administrative expense increased $40.9 million (155%) primarily because of a $26.8 million increase in stock-based incentive compensation from $11 million to $37.7 million, of which $30.6 million is non-cash. General and administrative expense for the 2004 quarter also includes a total of $11.7 million in special bonuses related to the ChevronTexaco and ExxonMobil acquisitions announced during the quarter.

We recorded a derivative fair value gain of $13,000 in the second quarter of 2004 as compared with a derivative fair value loss of $7.4 million in second quarter 2003. The 2003 quarter loss was primarily because of the effect of higher gas prices on derivatives that do not qualify for hedge accounting. See Note 6 to Consolidated Financial Statements.

Interest expense increased $6.5 million (41%) primarily because of a 52% increase in weighted average borrowings to partially fund acquisitions, which was partially offset by an 11% decrease in the weighted average interest rate.

The effective income tax rate for the 2004 quarter was 40.1%, as compared with 35.2% for second quarter 2003. The higher rate is because of increased state income taxes and compensation exceeding tax deductible limits.

Six Months Ended June 30, 2004 Compared with Six Months Ended June 30, 2003

Net income for the six months ended June 30, 2004 was $193.2 million, compared to $123.6 million for the same 2003 period. Earnings for the first six months include the net after-tax effects of stock-based incentive compensation of $44.7 million (of which $40.2 million is non-cash), special bonuses totaling $11.7 million related to acquisitions announced in second quarter 2004, and a $4 million fair value loss on certain derivatives that do not qualify for hedge accounting. Earnings for the first half 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 $6.7 million fair value loss on certain derivatives that do not qualify for hedge accounting, a non-cash contingency gain of $1.1 million 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 obligation.

Total revenues for the first half of 2004 were $839.5 million, or $303.9 million (57%) higher than revenues of $535.6 million for the first half of 2003. Operating income for the first half of 2004 was $356.8 million, a 56% increase from operating income of $228.1 million for the comparable 2003 period. Gas and natural gas liquids revenues increased $273.2 million (60%) primarily because of the 29% increase in gas production and the 24% increase in natural gas liquids production, as well as the 24% increase in gas prices and the 11% increase in natural gas liquids prices. Oil revenue increased $32.3 million (48%) because of the 19% increase in production and the 24% increase in prices. Gas gathering, processing and marketing revenues increased $500,000 (7%) primarily because of increased margins and prices.

Expenses for the first half of 2004 totaled $482.7 million, a 57% increase from total expenses for the first half of 2003 of $307.6 million. Production expense increased $26.9 million (35%) primarily because of increased production, labor, workover and maintenance costs. Taxes, transportation and other increased $27 million (56%) primarily because of a corresponding increase in revenues. Depreciation, depletion and amortization increased $47.1 million (37%) because of increased production and higher acquisition costs.

General and administrative expense increased $76.3 million (202%) primarily because of a $59.7 million increase in stock-based incentive compensation from $11.2 million to $70.9 million, of which $63.8 million is non-cash. Stock-based incentive compensation was approximately 3.9% of the increase in our market capitalization for the first six 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 six months of 2004 was $6.4 million compared to the year-to-date 2003 derivative fair value loss of $10.2 million. 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 $11.1 million (36%) primarily because of a 38% increase in the weighted average borrowings to partially fund property acquisitions. During the first half of 2003, we recognized a $9.6 million loss on extinguishment of debt related to the redemption of our 8¾% senior subordinated notes.

The 2004 year-to-date effective income tax rate was 38.6%, as compared with a 35.1% effective rate for the six-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:


	Quarter Ended June 30					Six Months Ended June 30
	2004		2003		Increase (Decrease)	2004		2003		Increase (Decrease)
Production	$	0.62	$	0.58	7%	$	0.61	$	0.58	5%
Taxes, transportation and other		0.44		0.36	22%		0.45		0.36	25%
Depreciation, depletion and amortization (DD&A)		1.07		0.98	9%		1.04		0.97	7%
General and administrative (G&A) (a)		0.20		0.23	(13%)		0.19		0.20	(5%)
Interest		0.26		0.23	13%		0.25		0.23	9%

(a)

Excludes the following:

In the 2004 quarter, stock-based incentive compensation of $37.7 million ($0.43 per Mcfe) and special acquisition-related bonuses of $11.7 million ($0.14 per Mcfe)

In the 2003 quarter, stock-based incentive compensation of $11 million ($0.16 per Mcfe)

In the 2004 six-month period, stock-based incentive compensation of $70.9 million ($0.42 per Mcfe) and special acquisition-related bonuses of $11.7 million ($0.07 per Mcfe)

In the 2003 six-month period, stock-based incentive compensation of $11.2 million ($0.09 per Mcfe)

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

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

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

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

G&A - Decreased G&A for the quarter is because of increased production, through acquisitions and development, outpacing increased personnel and other expenses related to Company growth. Decreased G&A for the six-month period is primarily because of a reduction in bad debt expense related to a $2.1 million decrease in our estimated allowance for uncollectible receivables in the first half of 2004.

Interest - Increased interest is because of increased production lagging the increase in weighted average borrowings to fund acquisitions.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $497.5 million for the first six months of 2004, compared with $335 million for the same 2003 period. Cash provided by operating activities for the first half of 2004 increased primarily because of production from development activity and acquisitions and increased prices. Cash flow from operating activities was reduced by changes in operating assets and liabilities of $50.2 million in the first half of 2004 and $12.1 million in the first half 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 $2.7 million in the first half of 2004 and $800,000 in the first half of 2003.

During the six months ended June 30, 2004, cash provided by operating activities of $497.5 million, common stock offering proceeds of $580 million and net debt proceeds of $141.7 million were used to fund net property acquisitions, development costs and other net capital additions of $1.173 billion, dividends of $4.2 million, senior note and debt offering costs of $10.3 million and treasury stock purchases and other net costs of $23.7 million primarily related to performance share vesting and employee stock option exercises. The resulting increase in cash and cash equivalents for the period was $7.6 million.

Total current assets increased $113.5 million during the first half of 2004 primarily because of the increase in cash, a $73.5 million, or 38%, increase in accounts receivable related to increased production and product prices and a $15.8 million increase in other current assets primarily because of increased warehouse stock of tubular goods. Deferred income tax benefit increased $15.7 million because of higher gas prices and the resulting loss in net hedge derivatives. Total current liabilities increased $96.7 million during the first half of 2004 primarily because of a $39.8 million increase in derivative fair value liabilities attributable to the effect of higher gas prices, as well as a $52.4 million increase in accounts payable and accrued liabilities related to timing of interest payments and increased production and product prices.

Working capital increased $16.8 million from a negative position of $59.4 million at December 31, 2003 to negative working capital of $42.6 million at June 30, 2004. Excluding the effects of derivative fair value and deferred tax current assets and liabilities, working capital increased $43.6 million from a negative position of $6.5 million at December 31, 2003 to a positive $37.1 million at June 30, 2004.

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

Acquisitions and Development

$950 million and $1 billion. We paid $110 million in May toward the purchase price, which has been recorded in producing properties in the accompanying consolidated balance sheet at June 30, 2004. The estimated remaining amount due is expected to be funded by bank borrowings.

Exploration and development expenditures for the first six months of 2004 were $246.7 million, compared with $220.3 million for the first six months of 2003. Primarily as a result of our recent and pending 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 or are expected to close in 2004 currently total approximately $1.9 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 bank debt and public and private sales of equity and debt.

Through the first half of 2004, we participated in drilling 265 gas wells and 16 oil wells and performed 114 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 July 2004, we have acquired approximately 47,000 net undeveloped acres in the Barnett Shale of North Texas with an estimated value of $32 million (see Note 13 to Consolidated Financial Statements) 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.

The unused borrowing capacity of $953 million at June 30, 2004 under our revolving credit agreements is available to fund future acquisitions and development. As of July 30, 2004, our unused borrowing capacity was $1.04 billion. We expect to utilize this capacity to fund the estimated remaining amount due upon closing the ChevronTexaco acquisition in August 2004.

Debt and Equity

As of June 30, 2004, long-term debt increased by $141.8 million from the balance at December 31, 2003. 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 beginning August 1, 2004. In March 2004, Moody’s upgraded our senior unsecured note ratings to Baa3 from Ba1, with a stable outlook. Both Standard and Poor’s and Moody’s reaffirmed the rating and outlook after our announcement of the ChevronTexaco acquisition.

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 estimated 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.

Stockholders’ equity at June 30, 2004 increased $782.9 million from year end because of earnings of $193.2 million for the six months ended June 30, 2004 and an increase in common stock and additional paid-in capital of $647.8 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 $29.3 million, an increase in treasury stock of $23.9 million related to stock option exercises and performance share vesting, and common stock dividends declared of $4.9 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 half of 2004.

See Notes 4 and 8 to Consolidated Financial Statements.

Common Stock Dividends

In May 2004, the Board of Directors declared a second quarter 2004 dividend of $0.01 per share that was paid in July.

Accounting Pronouncements

An issue within the oil and gas industry has recently arisen regarding whether Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, require costs associated with mineral rights be accounted for and separately reported on the balance sheet as intangible assets. As is common practice in the oil and gas industry, we include leasehold acquisition costs as a component of both producing properties and undeveloped properties in our consolidated balance sheets. This question of SFAS No. 141 and SFAS No. 142 applicability has been referred to the Financial Accounting Standards Board.

As specified in the pronouncement, SFAS No. 142 does not change the accounting prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. A proposed FASB Staff Position has been issued, stating that this exemption also includes the balance sheet classification and disclosures for mineral rights. Comments on this proposed FASB Staff Position are due by August 17, 2004. If the final FASB Staff Position is issued as written, no change in financial reporting for oil and gas mineral rights will be required. If it is ultimately determined that intangible asset accounting is required for oil and gas mineral rights, we would be required to reclassify, as intangible assets, $2.1 billion of net leasehold acquisition costs from net property and equipment in our consolidated balance sheet at June 30, 2004. Accounting for the costs of mineral rights as intangible assets under SFAS No. 141 and SFAS No. 142 would also require additional financial statement disclosures but would not affect our method of amortization or assessment of impairment. Therefore, any resulting accounting change would have no effect on our consolidated income statements or statements of cash flows.

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, 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 June 30, 2004, our variable rate debt had a carrying value of $147 million, which approximated its fair value, and our fixed rate debt had a carrying value of $1.247 billion and an approximate fair value liability of $1.283 billion. Assuming a one percent, or 100-basis point, change in interest rates at June 30, 2004, the fair value of our fixed rate debt would change by approximately $87.3 million.

Commodity Price Risk

We hedge a portion of our price risks associated with our natural gas and crude oil sales. As of June 30, 2004, outstanding gas futures contracts, swap agreements and gas basis swap agreements had a net fair value loss of $136 million. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $73.3 million in the fair value of these gas futures contracts, swap agreements and gas basis swap agreements at June 30, 2004. As of June 30, 2004, outstanding oil futures contracts and differential swaps had a net fair value loss of $100,000. The aggregate effect of a hypothetical 10% change in oil prices would result in a change of approximately $17.7 million in the fair value of these oil futures and differential swaps at June 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 June 30, 2004 was $20.7 million. The effect of a hypothetical 10% change in gas prices would result in a change of approximately $5.1 million in the fair value of these contracts, while a 10% change in crude oil prices would result in a change of approximately $3 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.

P A R T I I. O T H E R I N F O R M A T I O N

Item 1.

Not applicable.

Item 2.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

During the quarter ended June 30, 2004, the Company purchased the following 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.


Month	Total Number of Shares Purchased	Average Price Paid per Share
April	370,601	$	27.62
May	—	$	—
June	113,459	$	29.05

Total	484,060	$	27.96

Item 3.

Not applicable.

Item 4.

Submission of Matters to a Vote of Security Holders

The Annual Meeting of Shareholders of the Company was held on May 18, 2004. A total of 205,540,265 of the Company’s shares were present or represented by proxy at the meeting. This represented 88% of our outstanding shares at March 31, 2004, the record date for the meeting. The individuals listed below were elected as directors:


Name	Votes Received	Votes Withheld
Phillip R. Kevil	131,773,941	73,766,324
Scott G. Sherman	188,351,128	17,189,137
Bob R. Simpson	138,083,665	67,456,600

Other directors continuing in office are William H. Adams, Steffen E. Palko, Jack P. Randall and Herbert D. Simons. Louis G. Baldwin, Dr. Lane G. Collins, Keith A. Hutton and Vaughn O. Vennerberg II continue to serve as advisory directors.

Shareholders also voted to increase the number of authorized shares of common stock from 250 million to 500 million, based on the following vote tabulation:


For	Against	Abstain
188,230,064	17,224,916	85,285

Item 5.

Not applicable.

Item 6.

Exhibits and Reports on Form 8-K

(a) Exhibits


Exhibit Number and Description

3	Articles of Incorporation

	3.1	Restated Certificate of Incorporation of the Company, as restated on June 21, 2004

10	Material Contracts

	10.1*	Phantom Performance Share Award Agreement between the Company and Bob R. Simpson, dated April 23, 2004

	10.2*	Phantom Performance Share Award Agreement between the Company and Bob R. Simpson, dated June 18, 2004

	10.3*	Form of Agreement for Grant of Phantom Performance Shares between the Company and each of Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated June 24, 2004

	10.4*	Form of Agreement for Grant of Phantom Performance Shares between the Company and each of Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated July 8, 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

Management contract or compensatory plan

(b) Reports on Form 8-K

The Company filed the following reports on Form 8-K during the quarter ended June 30, 2004 and through August 9, 2004:

On May 6, 2004, we filed a report on Form 8-K dated May 3, 2004 to announce the purchase of long-lived producing properties in the Permian Basin of West Texas and in the Powder River Basin of Wyoming from ExxonMobil Corporation for a purchase price of $336 to $341 million.

On May 17, 2004, we filed a report on Form 8-K dated May 17, 2004 to announce we entered a definitive agreement with ChevronTexaco Corporation to acquire producing properties for $1.1 billion.

On May 20, 2004, we filed a report on Form 8-K dated May 20, 2004 to report the filing of a prospectus supplement and provided exhibits to the Prospectus, dated July 7, 2003.

On June 23, 2004, we filed a report on Form 8-K dated June 22, 2004 to announce commodity price hedges for future sales of oil and natural gas primarily related to our recent acquisitions.

We have furnished two reports on Form 8-K under Item 12 during this time period.

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: August 9, 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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