Xto Energy Inc - Quarterly Report (10-Q)

Three Months Ended
March 31

(in millions)

Income tax

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2008

¨	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 þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer	þ	Accelerated filer ¨
Non-accelerated filer	¨ (Do not check if smaller reporting company)	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

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 April 30, 2008
Common stock, $.01 par value		510,716,211

XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended March 31, 2008

TABLE OF CONTENTS


		Page
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets at March 31, 2008 and December 31, 2007	3

	Consolidated Income Statements for the Three Months Ended March 31, 2008 and 2007	4

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007	5

	Notes to Consolidated Financial Statements	6

	Report of Independent Registered Public Accounting Firm	18

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27

Item 4.	Controls and Procedures	27

PART II.	OTHER INFORMATION

Item 1A.	Risk Factors	28

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28

Item 6.	Exhibits	29

	Signatures	30

PART I. FINANCIAL INFORMATION

XTO ENERGY INC.

Consolidated Balance Sheets


	March 31, 2008			December 31, 2007
*(in millions, except shares)*	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	142		$	—
Accounts receivable, net		1,065			852
Derivative fair value		22			199
Current income tax receivable		58			118
Deferred income tax benefit		335			20
Other		120			98

Total Current Assets		1,742			1,287

Property and Equipment, at cost—successful efforts method:
Proved properties		20,128			18,671
Unproved properties		1,716			1,050
Other		1,505			1,376

Total Property and Equipment		23,349			21,097
Accumulated depreciation, depletion and amortization		(4,278	)		(3,897	)

Net Property and Equipment		19,071			17,200

Other Assets:
Derivative fair value		47			—
Acquired gas gathering contracts, net of amortization		111			112
Goodwill		215			215
Other		108			108

Total Other Assets		481			435

TOTAL ASSETS	$	21,294		$	18,922

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,386		$	1,264
Payable to royalty trusts		40			30
Derivative fair value		908			239
Other		4			4

Total Current Liabilities		2,338			1,537

Long-term Debt		6,468			6,320

Other Long-term Liabilities:
Derivative fair value		1			4
Deferred income taxes payable		2,781			2,610
Asset retirement obligation		532			450
Other		66			60

Total Other Long-term Liabilities		3,380			3,124

Commitments and Contingencies (Note 6)
Stockholders’ Equity:
Common stock ($.01 par value, 1,000,000,000 shares authorized, 515,760,273 and 490,434,003 shares issued)		5			5
Additional paid-in capital		4,450			3,172
Treasury stock, at cost (5,145,877 and 5,140,230 shares)		(134	)		(134	)
Retained earnings		5,341			4,938
Accumulated other comprehensive loss		(554	)		(40	)

Total Stockholders’ Equity		9,108			7,941

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	21,294		$	18,922

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Income Statements (Unaudited)


	Three Months Ended March 31
*(in millions, except per share data)*	2008			2007
REVENUES
Gas and natural gas liquids	$	1,274		$	872
Oil and condensate		379			274
Gas gathering, processing and marketing		20			22
Other		—			1

Total Revenues		1,673			1,169

EXPENSES
Production		193			129
Taxes, transportation and other		154			81
Exploration		18			4
Depreciation, depletion and amortization		383			240
Accretion of discount in asset retirement obligation		7			5
Gas gathering and processing		21			19
General and administrative		89			56
Derivative fair value (gain) loss		(16	)		(12	)

Total Expenses		849			522

OPERATING INCOME		824			647

OTHER EXPENSE
Interest expense, net		91			47

INCOME BEFORE INCOME TAX		733			600

INCOME TAX EXPENSE
Current		115			106
Deferred		153			111

Total Income Tax Expense		268			217

NET INCOME	$	465		$	383

EARNINGS PER COMMON SHARE
Basic	$	0.94		$	0.83

Diluted	$	0.92		$	0.82

DIVIDENDS DECLARED PER COMMON SHARE	$	0.12		$	0.096

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		496.3			458.4

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)


	Three Months Ended March 31
*(in millions, except per share data)*	2008			2007
OPERATING ACTIVITIES
Net income	$	465		$	383
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		383			240
Accretion of discount in asset retirement obligation		7			5
Non-cash incentive compensation		41			17
Dry hole expense		1			2
Deferred income tax		153			111
Non-cash derivative fair value (gain) loss		(14	)		36
Other non-cash items		4			(1	)
Changes in operating assets and liabilities (a)		(83	)		58

Cash Provided by Operating Activities		957			851

INVESTING ACTIVITIES
Property acquisitions		(1,260	)		(235	)
Development costs, capitalized exploration costs and dry hole expense		(767	)		(599	)
Other property and asset additions		(151	)		(136	)

Cash Used by Investing Activities		(2,178	)		(970	)

FINANCING ACTIVITIES
Proceeds from long-term debt		2,762			1,176
Payments on long-term debt		(2,610	)		(1,018	)
Dividends		(58	)		(33	)
Senior note and debt offering costs		(1	)		(1	)
Net proceeds from common stock offering		1,224			—
Proceeds from exercise of stock options and warrants		13			15
Payments upon exercise of stock options		(62	)		(10	)
Excess tax benefit on exercise of stock options		57			13
Other, including purchases of treasury stock		38			(13	)

Cash Provided by Financing Activities		1,363			129

INCREASE IN CASH AND CASH EQUIVALENTS		142			10
Cash and Cash Equivalents, Beginning of Period		—			5

Cash and Cash Equivalents, End of Period	$	142		$	15

*(a)* Changes in Operating Assets and Liabilities
Accounts receivable	$	(213	)	$	(18	)
Other current assets		39			66
Other operating assets and liabilities		3			(4	)
Current liabilities		88			14

	$	(83	)	$	58

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, 2007, have not been audited by independent public accountants. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at March 31, 2008 and our income and cash flows for the three months ended March 31, 2008 and 2007. All such adjustments are of a normal recurring nature. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

The financial data for the three-month periods ended March 31, 2008 and 2007 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 2007 Annual Report on Form 10-K.

All common stock shares and per share amounts in the accompanying financial statements have been adjusted for the five-for-four stock split effected on December 13, 2007.

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 $60 million at March 31, 2008 and December 31, 2007.

Our effective income tax rates for the three-month 2008 and 2007 periods are higher than the maximum federal statutory rate of 35% primarily because of state and local taxes. The current income tax provision exceeds our actual cash tax expense by the benefit realized upon exercise of stock options not expensed in the financial statements. This benefit, which is recorded in additional paid-in capital, was $62 million for first quarter 2008 and $13 million for first quarter 2007.

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

2. Related Party Transactions

In February 2008, we paid $1.6 million to a division of a firm, affiliated with one of our directors, for services provided as one of 24 co-managers on our February 2008 common stock offering (Note 8).

In April 2008, we paid $0.5 million to a division of a firm, affiliated with one of our directors, for services provided as one of 25 co-managers on our April 2008 $2.0 billion senior note offering (Note 4).

3. Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of asset retirement obligation activity for the three months ended March 31, 2008:


*(in millions)*
Asset retirement obligation, December 31, 2007	$	453
Revisions in estimated cash flows		52
Liability incurred upon acquiring and drilling wells		24
Liability settled upon plugging and abandoning wells		(1	)
Accretion of discount expense		7

Asset retirement obligation, March 31, 2008	$	535
Less current portion		(3	)

Asset retirement obligation, long term	$	532

4. Long-term Debt

Our long-term debt consists of the following:


*(in millions)*	March 31, 2008		December 31, 2007
Bank debt:
Commercial paper, 3.9% at March 31, 2008	$	619	$	772
Revolving credit agreement due April 1, 2013		—		—
Term loan due April 1, 2013, 3.5% at March 31, 2008		500		300
Term loan due February 5, 2013, 3.5% at March 31, 2008		100		—
Senior notes:
7.50%, due April 15, 2012		350		350
5.90%, due August 1, 2012, plus premium		553		553
6.25%, due April 15, 2013		400		400
4.90%, due February 1, 2014, net of discount		498		497
5.00%, due January 31, 2015, net of discount		350		350
5.30%, due June 30, 2015, net of discount		399		399
5.65%, due April 1, 2016, net of discount		400		400
6.25%, due August 1, 2017, plus premium		753		753
6.10%, due April 1, 2036, net of discount		596		596
6.75%, due August 1, 2037, plus premium		950		950

Total long-term debt	$	6,468	$	6,320

Because we had both the intent and ability to refinance the commercial paper balance outstanding with borrowings under our revolving credit facility due in April 2013, we have classified these borrowings as long-term debt in our consolidated balance sheets. Before the stated maturities of April 2013, we may renegotiate the revolving credit agreement and term loans to increase the borrowing commitment and/or extend the maturity.

Commercial Paper

dollar-for-dollar basis. The commercial paper borrowings may have terms up to 397 days and bear interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. On March 31, 2008, borrowings were $619 million at a weighted average interest rate of 3.9%.

Bank Debt

On March 31, 2008, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $1.9 billion net of our commercial paper borrowings. In February 2008, we amended this agreement to, among other things, increase the borrowing capability to $2.5 billion and to extend the maturity date to April 1, 2013. We have annual options to request successive one-year extensions and the option to increase the commitment up to an additional $1.0 billion. The interest rate on any borrowing is generally based on the one-month LIBOR plus 0.40%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing commitments, which is 0.09%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 65%. We use the facility for general corporate purposes and as a backup facility for our commercial paper program. We have not made any borrowings under our revolving credit facility during 2008.

In February 2008, we also amended our $300 million term loan credit agreement to increase outstanding borrowings to $500 million and to extend the maturity date to April 1, 2013. The proceeds were used for general corporate purposes.

Additionally in February 2008, we entered into a new five-year unsecured term loan agreement that provided for a maximum loan amount of $100 million available in a single advance that matures February 5, 2013. The interest rate is currently based on LIBOR plus 0.34%, and interest is paid at least quarterly. Other terms and conditions are substantially the same as our term loan. The proceeds were used for general corporate purposes.

We have unsecured and uncommitted lines of credit with commercial banks totaling $300 million. As of March 31, 2008, there were no borrowings under these lines.

Senior Notes

In April 2008, we sold $400 million of 4.625% senior notes due June 15, 2013, $800 million of 5.50% senior notes due June 15, 2018 and $800 million of 6.375% senior notes due June 15, 2038. The 4.625% senior notes were issued at 99.888% of par to yield 4.651% to maturity. The 5.50% senior notes were issued at 99.539% of par to yield 5.561% to maturity. The 6.375% senior notes were issued at 99.864% of par to yield 6.386% to maturity. Net proceeds of $1.98 billion will be used to fund our pending property acquisitions (Note 13), which are scheduled to close during the second and third quarters of 2008, to pay down outstanding commercial paper borrowings and for general corporate purposes, including future 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 U.S. 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, attorney 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 were 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. In response to a motion to dismiss filed by us and other defendants, in October 2006 the district judge held that Grynberg failed to establish jurisdictional requirements to maintain the action against us and other defendants and dismissed the action for lack of subject matter jurisdiction. In September 2007, the district judge dismissed those claims against us pertaining to the royalty value of carbon dioxide. Grynberg has filed appeals of these decisions. While we are unable to predict the final outcome of this case, 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 July 2005 a predecessor company, Antero Resources Corporation, was served with a lawsuit styled Threshold Development Company, et al. v. Antero Resources Corp., which lawsuit was filed in the District Court of Wise County, Texas. The plaintiffs are surface owners, royalty owners and prior working interest owners in several oil and gas leases as well as other contractual agreements under which Antero Resources Corporation owned an interest. Antero Resources Corporation, the defendant, was acquired by us on April 1, 2005. The claims relate to alleged events pre-dating the acquisition and concern non-payment of royalties, improper calculation of royalties, improper pricing related to royalties, trespass, failure to develop and breach of contract. We have settled all claims related to the payment of royalties and trespass. Under the remaining claims, the plaintiffs are seeking both damages and termination of the existing oil and gas leases covering their interests. The court has ordered the parties to mediation, which has not been scheduled. While we are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Based on a review of the current facts and circumstances with counsel, management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter. While acknowledging the uncertainties of litigation, management believes that the ultimate outcome of this matter will not have a material effect on our earnings, cash flows or financial position.

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.

Transportation Contracts

We have entered firm transportation contracts with various pipelines. Under these contracts we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. We have generally delivered at least minimum volumes under our firm transportation contracts, therefore avoiding payment for deficiencies. As of March 31, 2008, maximum commitments under our transportation contracts were as follows:


*(in millions)*
2008	$	89
2009		122
2010		121
2011		116
2012		107
Remaining		417

Total	$	972

In December 2006, we entered into a ten-year firm transportation contract that commences upon completion of a new 502-mile pipeline spanning from southeast Oklahoma to east Alabama. This contract was amended in April 2008 to increase the gas volumes we will transport. Upon the pipeline’s completion, currently expected in first quarter 2009, we will transport gas volumes for a minimum transportation fee of $4 million per month plus fuel not to exceed 1.2% of the sales price, depending on receipt point and other conditions.

In April 2008, we entered into an agreement that obligates us to enter into a ten-year firm transportation contract, contingent upon obtaining regulatory approvals and completion of a new pipeline that connects the Fayetteville Shale to Kosciusko, Mississippi. Upon the pipeline’s completion, we will transport gas volumes for up to $3 million per month plus fuel not to exceed 1.15% of the sales price.

The potential effect of these agreements is not included in the above summary of our transportation contract commitments since our commitments are contingent upon completion of the pipelines.

Drilling Contracts

As of March 31, 2008, we have contracts with various drilling contractors to use 80 drilling rigs with terms of up to three years and minimum future commitments of $133 million in 2008, $75 million in 2009 and $16 million in 2010. Early termination of these contracts at March 31, 2008 would have required us to pay maximum penalties of $133 million. Based upon our planned drilling activities, we do not expect to pay any early termination penalties related to these contracts.

Other

To secure tubular goods required to support our drilling program, we provide a forecast to a tubular goods supplier who commits to deliver, at market prices, our next quarter’s tubular products. There is no minimum order requirement, and the forecast can be adjusted 60 to 90 days prior to shipment.

See Note 7 regarding commodity sales commitments.

6. Financial Instruments

We use commodity-based and financial 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. We also may enter gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts. Therefore, these contracts are not recorded in the financial statements.

All derivatives are recorded on the balance sheet at estimated 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 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. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged.

Derivative Fair Value (Gain) Loss

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


	Three Months Ended March 31
*(in millions)*	2008			2007
Change in fair value of derivatives that do not qualify for hedge accounting	$	(29	)	$	2
Ineffective portion of derivatives qualifying for hedge accounting		13			(14	)

Derivative fair value (gain) loss	$	(16	)	$	(12	)

The fair value (gain) loss in 2008 and 2007 related to derivatives that do not qualify for hedge accounting are primarily related to natural gas basis swap agreements. Except to the extent basis swap agreements are utilized in conjunction with NYMEX future contracts, they cannot qualify for hedge accounting.

Derivative fair value (gain) loss comprises the following realized and unrealized components related to non-hedge derivatives and the ineffective portion of hedge derivatives:


	Three Months Ended March 31
*(in millions)*	2008			2007
Net cash received from counterparties	$	(2	)	$	(48	)
Non-cash change in derivative fair value		(14	)		36

Derivative fair value (gain) loss	$	(16	)	$	(12	)

Fair Value Measurements

SFAS No. 157, Fair Value Measurements (as amended), defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on inputs used to measure fair value and enhances disclosure requirements for fair value measurements. We have not applied the provisions of SFAS No. 157 to nonrecurring, nonfinancial assets and liabilities as allowed under FSP No. 157-2.

Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

Beginning January 1, 2008, assets and liabilities recorded at fair value in the Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels—defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities—are as follows:

Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

The fair value of our derivative contracts are measured using Level II inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

Our asset retirement obligation is measured using primarily Level III inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging and abandonment costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. See Note 3 for a rollforward of the asset retirement obligation.

The estimated fair values of derivatives included in the consolidated balance sheets at March 31, 2008 and December 31, 2007 are summarized below. The increase in the net derivative liability from December 31, 2007 to March 31, 2008 is primarily attributable to the effect of higher natural gas and oil prices and cash settlements of derivatives during the period, partially offset by new derivatives entered during the period.


	Fair Value Measurements
	March 31, 2008						December 31, 2007
*(in millions)*	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Derivative Assets:
Fixed-price natural gas futures and basis swaps	$	57		$	—		$	198		$	—
Fixed-price crude oil futures and differential swaps		12			—			1			—
Derivative Liabilities:					—						—
Fixed-price natural gas futures and basis swaps		(684	)		—			(13	)		—
Fixed-price crude oil futures and differential swaps		(209	)		—			(208	)		—
Fixed-price natural gas liquids futures		(16	)		—			(22	)		—

Net derivative liability	$	(840	)	$	—		$	(44	)	$	—

Asset retirement obligation	$	—		$	(535	)	$	—		$	(453	)

Concentrations of Credit Risk

Although our cash equivalents, accounts receivable and derivative assets are exposed to the risk of credit loss, we do not believe such risk to be significant. Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of our receivables are from a diverse group of companies including major energy companies, financial institutions, pipeline companies, local distribution companies and end-users in various industries. We currently have the majority of our credit exposure with several A- or better rated 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 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. Our allowance for uncollectible receivables was $7 million at March 31, 2008 and December 31, 2007.

7. Commodity Sales Commitments

Our policy is to consider hedging a portion of our production at commodity prices management deems attractive. While there is a risk we may not be able to realize the benefit of rising prices, management may enter into hedging agreements because of the benefits of predictable, stable cash flows.

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, crude oil and natural gas liquids 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 2009 and from natural gas liquids sales through December 2008.

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. See Note 6 regarding accounting for commodity hedges.


Production Period		Mcf per Day	Weighted Average NYMEX Price per Mcf
2008	April to June	100,000	$	10.10
	April to December	1,200,000	$	8.32
2009	January to December	200,000	$	9.70

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 sell basis swap agreements that effectively fix the basis adjustment as shown below. Not all of our sell basis swap agreements are designated as hedges for hedge accounting purposes.


Production Period		Mcf per Day	Weighted Average Sell Basis per Mcf *(a)*
2008	April (b)	410,000	$	0.53
	May (b)	460,000	$	0.48
	June (b)	410,000	$	0.53
	July to October (b)	330,000	$	0.60
	November to December (b)	230,000	$	0.82
2009	January to March (b)	160,000	$	0.97
	April to December (b)	150,000	$	1.02
2010	January to December	50,000	$	0.27

(a)

Reductions to NYMEX gas prices for delivery location.

(b)

2008 and 2009 amounts include 100,000 Mcf per day at $1.39 to be delivered in the Rocky Mountain Region.

Net settlements on futures and sell basis swap hedge contracts increased gas revenues by $17 million in first quarter 2008 and $114 million in first quarter 2007. As of March 31, 2008, an unrealized pre-tax net derivative fair value loss of $649 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive loss. Of this net fair value loss, $690 million is expected to be reclassified into earnings through March 2009. The difference between the net fair value loss and the amount to be reclassified into earnings over the next year relates to net fair value gains that are expected to be recognized from April 2009 through December 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

Crude Oil

We have entered into crude oil 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. See Note 6 regarding accounting for commodity hedges.


Production Period		Bbls per Day	Weighted Average NYMEX Price per Bbl
2008	April to June	5,000	$	106.85
	April to December	30,000	$	74.20
2009	January to December	5,000	$	101.10

We have entered crude sweet and sour differential swaps of $4.00 per Bbl for 10,000 Bbls per day of sour crude oil production for April to December 2008.

In first quarter 2008, net losses on futures, swaps and differential swap hedge contracts reduced oil revenue by $64 million. In the first quarter 2007, net gains on these contracts increased oil revenue by $50 million. As of March 31, 2008, an unrealized pre-tax net derivative fair value loss of $197 million related to cash flow hedges of oil price risk was recorded in accumulated other comprehensive loss. Of this net fair value loss, $205 million is expected to be reclassified into earnings through March 2009. The difference between the net fair value loss and the amount to be reclassified into earnings over the next year relates to net fair value gains that are expected to be recognized from April 2009 through December 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

Natural Gas Liquids

We have entered into natural gas liquids futures contracts 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		Bbls per Day	Weighted Average Price per Bbl
2008	April to December	5,000	$	44.22

In first quarter 2008, net losses on futures contracts reduced natural gas liquids revenue by $6 million. As of March 31, 2008, an unrealized pre-tax derivative fair value loss of $16 million, related to cash flow hedges of natural gas liquids price risk, was recorded in accumulated other comprehensive loss. This fair value loss is expected to be reclassified into earnings in 2008. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

Transportation Contracts

In connection with our commitments under our transportation contracts (Note 5), we have entered purchase basis swap agreements related to potential purchase of gas volumes to be transported. Purchase basis swap agreements are not designated as hedges for hedge accounting purposes.


Period		Mcf per Day	Weighted Average Purchase Basis per Mcf *(a)*
2008	April	60,000	$	0.86
	May	75,000	$	1.11
	June to December	60,000	$	1.09
2009	January to March	50,000	$	1.23

(a)

Reductions to NYMEX gas prices for purchase location.

8. Equity

We effected a five-for-four stock split on December 13, 2007. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect this stock split.

In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 million, net proceeds of $1.2 billion were used to fund a portion of the $1.3 billion of property acquisitions closed in first quarter 2008 (Note 13) and to repay indebtedness under our commercial paper program.

See Note 12.

9. Earnings per Share

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


	Three Months Ended March 31
	2008					2007
*(in millions, except per share data)*	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	465	496.3	$	0.94	$	383	458.4	$	0.83

Effect of dilutive securities:
Stock awards		—	5.9				—	5.6
Warrants		—	1.6				—	1.2

Diluted	$	465	503.8	$	0.92	$	383	465.2	$	0.82

10. Comprehensive Income (Loss)

The following are components of comprehensive income (loss):


	Three Months Ended March 31
*(in millions)*	2008			2007
Net income	$	465		$	383

Other comprehensive income (loss):
Change in hedge derivative fair value		(864	)		(296	)
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive loss (a)		54			(171	)

Net unrealized hedge derivative loss		(810	)		(467	)
Income tax benefit		296			173

Total other comprehensive loss		(514	)		(294	)

Total comprehensive (loss) income	$	(49	)	$	89

(a)

For realized gains upon contract settlements, the reduction to comprehensive income is offset by contract proceeds generally recorded as gas, natural gas liquids or oil revenue. For realized losses upon contract settlements, the increase to comprehensive income is offset by contract proceeds generally recorded as reductions to gas, natural gas liquids or oil revenue.

11. Supplemental Cash Flow Information

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

The accompanying consolidated statements of cash flows exclude the following non-cash stock award transactions (Note 12) during the three-month periods ended March 31, 2008 and 2007:

•

Grants of 9,000 restricted shares and forfeitures of 5,000 restricted shares in 2008. Forfeitures of 9,000 restricted shares in 2007.

•

Vesting of 87,000 performance shares and forfeitures of 9,000 performance shares in 2007.

•

Grants and immediate vesting of 25,000 unrestricted common shares to nonemployee directors in 2008 and 2007.

•

Common shares delivered or attested to in satisfaction of the exercise price of employee stock options totaled 1.5 million shares at a weighted average exercise price of $56.36 per share in 2008 and 194,000 shares at a weighted average exercise price of $42.40 per share in 2007.

12. Employee Benefit Plans

Stock awards under the 2004 Stock Incentive Plan include stock options, performance shares, restricted shares and unrestricted shares that may limit the ability of nonemployee directors to sell for two years following the date of grant. The table below summarizes stock incentive compensation expense included in the consolidated financial statements and other information for each three-month period:


	Three Months Ended March 31
*(in millions)*	2008		2007
Non-cash stock option compensation expense	$	31	$	10
Non-cash performance share and unrestricted share compensation expense		1		3
Non-cash restricted stock compensation expense		9		4
Related tax benefit recorded in income statement		15		6
Intrinsic value of stock option exercises		177		35
Income tax benefit on exercise of stock options (a)		62		13

(a)

Recorded as additional paid-in-capital

During the first three months of 2008, 65,000 stock options were granted to employees at a weighted average exercise price of $54.40 per share. A total of 4.8 million stock options were exercised at a weighted average exercise price of $19.75 per share. As a result of these exercises, outstanding common stock increased by 2.3 million shares and stockholders’ equity increased by a net $13 million. In February 2008, each nonemployee director received 4,166 shares for a total of approximately 25,000 unrestricted common shares that cannot be sold for two years following the date of grant.

As of March 31, 2008, nonvested stock options had remaining unrecognized compensation expense of $40 million. Total deferred compensation at March 31, 2008 related to nonvested restricted shares was $82 million. For these nonvested stock awards, we estimate that stock incentive compensation for service periods after March 31, 2008 will be $52 million in 2008, $47 million in 2009 and $23 million in 2010. The weighted average remaining vesting period is 0.9 years for stock options and 2.3 years for restricted shares.

13. Acquisitions

In first quarter 2008, we completed acquisitions of both producing and unproved properties for approximately $1.3 billion. These acquisitions include bolt-on acquisitions of additional producing properties, mineral interests and undeveloped leasehold primarily in the Barnett, Fayetteville and Woodford shales. These acquisitions were funded both by commercial paper borrowings and by proceeds from the February 2008 common stock offering (Note 8) and are subject to typical post-closing adjustments.

In April 2008, we entered into an agreement with Southwestern Energy Company to acquire producing properties, leasehold acreage and gathering infrastructure in the Fayetteville Shale for approximately $520 million, subject to typical closing and post-closing adjustments. The acquisition is expected to close in second quarter 2008 and will be funded by proceeds from the April 2008 issuance of $2.0 billion of senior notes (Note 4).

In April 2008, we also entered into an agreement with Linn Energy, LLC to acquire producing properties, leasehold acreage and pipeline and gathering infrastructure in the Marcellus Shale in western Pennsylvania and West Virginia for $600 million, subject to typical closing and post-closing adjustments. The acquisition is expected to close in third quarter 2008 and will be funded by proceeds from the April 2008 issuance of $2.0 billion of senior notes.

On July 31, 2007, we acquired both producing and unproved properties from Dominion Resources, Inc. for $2.5 billion, subject to typical post-closing adjustments. These properties are located in the Rocky Mountain Region, the San Juan Basin and South Texas. The acquisition was funded by the issuance of 21.6 million shares of our common stock in June 2007 for net proceeds of $1.0 billion, the issuance of $1.25 billion of senior notes in July 2007 and with borrowings under our commercial paper program, which was repaid with a portion of the proceeds from the issuance of $1.0 billion of senior notes in August 2007. After recording asset retirement obligation of $32 million, other liabilities and transaction costs of $18 million, $2.5 billion was allocated to proved properties and $73 million to unproved properties. The purchase price allocation is preliminary and subject to adjustment pending final determination of the fair value of certain assets and liabilities acquired.

The acquisition was recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for the three months ended March 31, 2007 and the year ended December 31, 2007, as if the Dominion acquisition was made at the beginning of each period. These pro forma results are not necessarily indicative of future results.


	Pro Forma (Unaudited)
	Three Months Ended March 31,		Year Ended December 31,
*(in millions, except per share data)*	2007		2007
Revenues	$	1,303	$	5,843

Net income	$	392	$	1,718

Earnings per common share:
Basic	$	0.82	$	3.57

Diluted	$	0.81	$	3.52

Weighted average shares outstanding:
Basic		480.0		481.2

Diluted		486.8		488.2

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. and its subsidiaries as of March 31, 2008, the related consolidated income statements for the three-month periods ended March 31, 2008 and 2007, and the consolidated cash flow statements for the three-month periods ended March 31, 2008 and 2007. 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 U.S. generally accepted accounting principles.

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, 2007, 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 2007 Annual Report on Form 10-K, and in our report dated February 25, 2008, we expressed an unqualified opinion on those statements. Our report on those statements referred to a change in accounting for share-based payments in 2006. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007 is fairly stated, in all material respects, in relation to the consolidated balance sheet included in the Company’s 2007 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Fort Worth, Texas

May 1, 2008

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 2007 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.

Gas, Natural Gas Liquids and Oil Production and Prices


	Three Months Ended March 31
	2008		2007		Increase (Decrease)

Total production
Gas (Mcf)		155,392,204		113,716,285	37	%
Natural gas liquids (Bbls)		1,453,601		973,006	49	%
Oil (Bbls)		4,690,096		4,108,425	14	%
Mcfe		192,254,386		144,204,871	33	%

Average daily production
Gas (Mcf)		1,707,607		1,263,514	35	%
Natural gas liquids (Bbls)		15,974		10,811	48	%
Oil (Bbls)		51,540		45,649	13	%
Mcfe		2,112,686		1,602,276	32	%

Average sales price
Gas per Mcf	$	7.70	$	7.37	4	%
Natural gas liquids per Bbl	$	52.98	$	35.97	47	%
Oil per Bbl	$	80.74	$	66.62	21	%

Average sales price before hedging
Gas per Mcf	$	7.59	$	6.36	19	%
Natural gas liquids per Bbl	$	57.36	$	35.97	59	%
Oil per Bbl	$	94.42	$	54.35	74	%

Average NYMEX prices
Gas per MMBtu	$	8.03	$	6.77	19	%
Oil per Bbl	$	97.68	$	58.33	67	%

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 increased from the first quarter of 2007 to 2008 primarily because of development activity and acquisitions, partially offset by natural decline.

Gas prices increased from first quarter 2007 to first quarter 2008. Although the winter began with above average gas in storage, a normal winter and lower liquified natural gas imports have led to higher gas prices which recently increased to over $11.00 per MMBtu. Prices will continue to be affected by weather, the U.S. economy, the level of North American production and liquified natural gas imports. Natural gas prices are expected to remain volatile. The NYMEX price for April 2008 was $9.58 per MMBtu. At April 30, 2008, the average NYMEX futures price for the following twelve months was $11.13 per MMBtu.

Oil prices increased from first quarter 2007 to first quarter 2008 primarily because of narrowing excess worldwide capacity, weakness in the dollar and continuing tension in the Middle East. Recent NYMEX oil prices have reached record levels of almost $120 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for April 2008 was $112.58 per Bbl. At April 30, 2008, the average NYMEX futures price for the following twelve months was $111.44 per Bbl.

We use price hedging arrangements, including fixed-price physical delivery contracts, to reduce price risk on a portion of our production. We have hedged a portion of our natural gas and oil sales through December 2009 and our natural gas liquids sales through December 2008; see Note 7 to Consolidated Financial Statements.

Results of Operations

Quarter Ended March 31, 2008 Compared with Quarter Ended March 31, 2007

Net income for first quarter 2008 was $465 million compared to $383 million for first quarter 2007. First quarter 2008 earnings include the net after-tax effects of a $9 million non-cash derivative fair value gain. First quarter 2007 earnings include the net after-tax effects of a $23 million non-cash derivative fair value loss.

Total revenues for first quarter 2008 were $1.67 billion, a 43% increase from first quarter 2007 revenues of $1.17 billion. Operating income for the quarter was $824 million, a 27% increase from first quarter 2007 operating income of $647 million. Gas and natural gas liquids revenues increased $402 million because of the 37% increase in gas production and the 49% increase in natural gas liquids production, as well as the 4% increase in gas prices and the 47% increase in natural gas liquids prices. Oil revenue increased $105 million because of the 21% increase in oil prices and the 14% increase in production.

Expenses for first quarter 2008 totaled $849 million, a 63% increase from first quarter 2007 expenses of $522 million. Increased expenses are generally related to increased production from development and acquisitions, higher commodity prices and related Company growth. Production expense increased $64 million primarily because of increased overall production and increased maintenance and workover costs. Taxes, transportation and other increased $73 million from the first quarter of 2007 primarily because of higher product prices and higher transportation costs related to higher throughput volumes. Depreciation, depletion and amortization increased $143 million because of increased production and higher acquisition, development and facility costs. General and administrative expense increased $33 million because of a $24 million increase in non-cash incentive award compensation and increased other general and administrative expense primarily due to higher employee expenses related to Company growth.

The derivative fair value gain for first quarter 2008 was $16 million compared to $12 million for first quarter 2007. The gain in first quarter 2008 is primarily related to the change in fair value of natural gas basis swap agreements that do not qualify for hedge accounting partially offset by the ineffective portion of hedge derivatives. See Note 6 to Consolidated Financial Statements.

Interest expense increased $44 million primarily because of a 93% increase in weighted average borrowings incurred primarily to fund acquisitions. The effective income tax rate for first quarter 2008 was 36.6%, as compared with 36.2% for first quarter 2007.

Comparative Expenses per Mcf Equivalent Production

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


	Quarter Ended March 31
	2008		2007		Increase (Decrease)
Production	$	1.00	$	0.89	12	%
Taxes, transportation and other	$	0.80	$	0.57	40	%
Depreciation, depletion and amortization (DD&A)	$	1.99	$	1.66	20	%
General and administrative (G&A):
Non-cash stock incentive compensation	$	0.21	$	0.12	75	%
All other G&A	$	0.25	$	0.27	(7	%)
Interest	$	0.47	$	0.32	47	%

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

Production expenses— Increased production expense is primarily because of increased maintenance and workover costs.

Taxes, transportation and other —Most of these expenses vary with product prices. Increased taxes, transportation and other expense is primarily because of higher product prices and higher transportation costs related to increased third-party transportation.

DD&A —Increased DD&A is primarily because of higher acquisition, development and infrastructure costs per Mcfe.

G&A —Increased stock incentive compensation is related to additional incentive award grants since last year including restricted stock awards granted in November 2007 and accelerated vesting of options due to our common stock price closing above specified target prices. All other G&A expense decreased because of increased production outpacing personnel and other expenses related to Company growth.

Interest— Increased interest expense is primarily because of an increase in weighted average borrowings to fund recent acquisitions partially offset by increased production.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $957 million for first quarter 2008, compared with $851 million for the same 2007 period. Increased first quarter cash provided by operating activities is primarily because of production from development activity and acquisitions. Cash provided by operating activities was decreased by changes in operating assets and liabilities of $83 million in first quarter 2008 and increased by $58 million in first quarter 2007. 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, excluding dry hole expense, of $17 million in first quarter 2008 and $2 million in first quarter 2007.

During the quarter ended March 31, 2008, cash provided by operating activities of $957 million, proceeds from the February 2008 common stock offering of $1.2 billion and net debt proceeds of $152 million were used to fund net property acquisitions, development costs and other net capital additions of $2.2 billion and dividends of $58 million. The resulting increase in cash and cash equivalents for the period was $142 million.

Total current assets increased $455 million during the first quarter of 2008 primarily because of a $315 million increase in deferred income tax benefit due to the decrease in derivative fair value, increased accounts

receivable due to increased revenue and an increase in cash and cash equivalents primarily due to proceeds received from the February 2008 common stock offering. This was partially offset by a $177 million decrease in derivative fair value as a result of higher natural gas and crude oil prices and cash settlements of derivatives during the period. Total current liabilities increased $801 million during the first quarter of 2008 primarily because of a $669 million increase in derivative fair value liabilities due to the effect of higher natural gas and crude oil prices and a $122 million increase in accounts payable and accrued liabilities due to increased activity and higher commodity prices.

Working capital decreased from a negative position of $250 million at December 31, 2007 to a negative position of $596 million at March 31, 2008. Excluding the effects of derivative fair value and deferred tax current assets, working capital increased from a negative position of $230 million at December 31, 2007 to a negative position of $45 million at March 31, 2008.

Any payments due counterparties under our hedge derivative contracts should ultimately be funded by higher prices received from sale of our production. Production receipts, however, often lag payments to the counterparties by as much as 55 days. Any interim cash needs are funded by borrowings under either our revolving credit agreement, our other unsecured and uncommitted lines of credit, or our commercial paper program.

Acquisitions and Development

In first quarter 2008, we completed acquisitions of both producing and unproved properties for approximately $1.3 billion compared to $235 million for first quarter 2007. The 2008 property acquisitions include bolt-on acquisitions of additional producing properties, mineral interests and undeveloped leasehold primarily in the Barnett, Fayetteville and Woodford shales. These acquisitions were funded both by commercial paper borrowings and by proceeds from the February 2008 common stock offering and are subject to typical post-closing adjustments.

In April 2008, we also entered into an agreement with Linn Energy, LLC to acquire producing properties, leasehold acreage and pipeline and gathering infrastructure in the Marcellus Shale in western Pennsylvania and West Virginia for $600 million, subject to typical closing and post-closing adjustments. The acquisition is expected to close in the third quarter 2008 and will be funded by proceeds from the April 2008 issuance of $2.0 billion of senior notes.

Exploration and development expenditures for the first three months of 2008 were $784 million compared with $601 million for the first three months of 2007. Our 2008 development and exploration budget has been increased from $2.6 billion to $3.0 billion and our budget for construction of pipeline infrastructure and compression and processing facilities has been increased from $400 million to $500 million. These increases were made to accommodate additional opportunities as a result of recent and pending acquisitions. We expect these expenditures to 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.

We will continue to evaluate additional acquisition opportunities during 2008. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, issuance of public or private debt or equity, or asset sales. Property acquisitions during 2008 may alter the amount currently budgeted for development and

exploration. Our expenditures for acquisitions, development and exploration will be adjusted throughout 2008 to focus on opportunities offering the highest rates of return. We also may reevaluate our budget and drilling programs in the event of significant changes in oil and gas prices.

Raw material shortages and strong global demand for steel have continued to tighten steel supplies and have caused prices to increase. In response, we have negotiated supply contracts with our vendors to support our development program. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting production growth and increasing development costs.

Through the first three months of 2008, we participated in drilling approximately 273 gas wells and 15 oil wells and performed 118 workovers. Our year-to-date drilling activity was concentrated in East Texas and the Barnett Shale. Workovers have focused on recompletions, artificial lift and wellhead compression. These projects generally have met or exceeded management expectations.

Debt and Equity

In February 2008, we increased our commercial paper program availability to $2.5 billion. Borrowings under the commercial paper program reduce our available capacity under the revolving credit facility on a dollar-for-dollar basis. The commercial paper borrowings may have terms up to 397 days and bear interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. On March 31, 2008, borrowings were $619 million at a weighted average interest rate of 3.9%.

We have unsecured and uncommitted lines of credit with commercial banks totaling $300 million. As of March 31, 2008, there were no borrowings under these lines.

maturity. Net proceeds of $1.98 billion will be used to fund our pending property acquisitions, which are scheduled to close during the second and third quarters of 2008, to pay down outstanding commercial paper borrowings and for general corporate purposes, including future acquisitions.

In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 million, net proceeds of $1.2 billion were used to fund a portion of the $1.3 billion of property acquisitions closed in first quarter 2008 and to repay indebtedness under our commercial paper program.

All common stock shares and per share amounts in the accompanying financial statements have been adjusted for the five-for-four stock split effected on December 13, 2007.

Dividends

In February 2008, the Board of Directors declared a first quarter 2008 dividend of $0.12 per share payable April 15, 2008 to stockholders of record on March 31, 2008.

Contractual Obligations and Commitments

The following summarizes our significant obligations and commitments to make future contractual payments as of March 31, 2008. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt or losses.


			Payments Due by Year
*(in millions)*	Total		2008		2009		2010		2011		2012		After 2012
Long-term debt	$	6,468	$	—	$	—	$	—	$	—	$	903	$	5,565
Operating leases		92		19		23		20		15		7		8
Drilling contracts		224		133		75		16		—		—		—
Purchase commitments		123		106		17		—		—		—		—
Transportation contracts		972		89		122		121		116		107		417
Derivative contract liabilities at March 31, 2008 fair value		909		887		22		—		—		—		—

Total	$	8,788	$	1,234	$	259	$	157	$	131	$	1,017	$	5,990

Long-Term Debt. At March 31, 2008, borrowings were $619 million under our commercial paper program. Because we had both the intent and ability to refinance the balance due with borrowings under our credit facility due in April 2013, the $619 million outstanding under the commercial paper program is reflected in the table above as due after 2012. Borrowings of $600 million under our term loans are due in February and April 2013, and our senior notes, totaling $5.2 billion are due 2012 through 2037. For further information regarding long-term debt, see Note 4 to Consolidated Financial Statements.

Transportation Contracts . We have entered firm transportation contracts with various pipelines for various terms through 2022. Under these contracts we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. We have generally delivered at least minimum volumes under these firm transportation contracts, therefore avoiding payment for deficiencies.

April 2008 to increase the gas volumes we will transport. Upon the pipeline’s completion, currently expected in first quarter 2009, we will transport gas volumes for a minimum transportation fee of $4 million per month plus fuel not to exceed 1.2% of the sales price, depending on receipt point and other conditions.

The potential effect of these agreements is not included in the above summary of our transportation contract commitments since our commitments are contingent upon completion of the pipelines.

Derivative Contracts . We have entered into futures contracts and swaps to hedge our exposure to natural gas, oil and natural gas liquids price fluctuations. As of March 31, 2008, the market prices generally exceeded fixed prices specified by these contracts, resulting in a derivative fair value net current liability of $886 million and a net long-term asset of $46 million. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of March 31, 2008, the current liability related to such contracts was $908 million and the noncurrent liability was $1 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts may be received as much as 55 days after payment to counterparties and can result in draws on our revolving credit facility, our other unsecured and uncommitted lines of credit or our commercial paper program. See Note 6 to Consolidated Financial Statements.

Accounting Pronouncements

In November 2007, FASB Staff Position No. 157-2 was issued. FSP No. 157-2 delays the effective date of adoption of SFAS No. 157, Fair Value Measurements (as amended), for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We adopted the non-deferred provisions of SFAS No. 157 on January 1, 2008. See Note 6 to Consolidated Financial Statements. FSP No. 157-2 defers the effective date to fiscal years beginning after November 15, 2008. The effect of adopting FSP No. 157-2 is not expected to have an effect on our reported financial position or earnings.

In December 2007, SFAS No. 141R, Business Combinations, was issued. Under SFAS No. 141R, a company is required to recognize the assets acquired, liabilities assumed, contractual contingencies, and any contingent consideration measured at their fair value at the acquisition date. It further requires that research and development assets acquired in a business combination that have no alternative future use to be measured at their acquisition-date fair value and then immediately charged to expense, and that acquisition-related costs are to be recognized separately from the acquisition and expensed as incurred. Among other changes, this statement also requires that “negative goodwill” be recognized in earnings as a gain attributable to the acquisition, and any deferred tax benefits resultant in a business combination are recognized in income from continuing operations in the period of the combination. SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning after December 15, 2008. The effect of adopting SFAS No. 141R has not been determined, but it is not expected to have a significant effect on our reported financial position or earnings.

In December 2007, SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51, was issued. SFAS No. 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Among other requirements, this statement requires consolidated net income to be reported at amounts that

include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS No. 160 is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. The effect of adopting SFAS No. 160 is not expected to have an effect on our reported financial position or earnings.

In March 2008, SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement 133, was issued. SFAS No. 161 amends and expands SFAS No. 133 to enhance required disclosures regarding derivatives and hedging activities. It requires added disclosure regarding how an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The effect of adopting SFAS No. 161 is not expected to have an effect on our reported financial position or earnings.

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, adjusted acquisition prices, 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, regulatory matters, competition and assumptions related to the expensing of stock options and performance shares. 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 detailed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007, 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 commodity prices,

•

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,

•

changes in interest rates,

•

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 2007 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 March 31, 2008, our variable rate debt had a carrying value of $1.2 billion, which approximated its fair value, and our fixed rate debt had a carrying value of $5.2 billion and an approximate fair value liability of $5.4 billion. Assuming a one percent, or 100-basis point, change in interest rates at March 31, 2008, the fair value of our fixed rate debt would change by approximately $417 million.

Commodity Price Risk

We hedge a portion of our price risks associated with our natural gas, crude oil and natural gas liquid sales. As of March 31, 2008, our outstanding futures contracts and swap agreements had a net fair value loss of $840 million. The following table shows the fair value of our derivative contracts and the hypothetical change in fair value that would result from a 10% change in commodities prices or basis prices at March 31, 2008. The hypothetical change in fair value could be a gain or a loss depending on whether prices increase or decrease.


*(in millions)*	Fair Value		Hypothetical Change in Fair Value
Natural gas futures and sell basis swap agreements	$	(623)	$	350
Natural gas purchase basis swap agreements		(4)		2
Crude oil futures and differential swaps		(197)		103
Natural gas liquids futures		(16)		8

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 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. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

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 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 to ensure that information required to be disclosed in reports filed with the Securities and Exchange Commission is recorded, processed, summarized and reported within the periods required and that this information is accumulated and communicated to allow timely decisions regarding required disclosures.

There were no 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.

Not applicable.

Item 1A.

Risk Factors

There have been no material changes in the risk factors disclosed under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

The following summarizes purchases of our common stock during first quarter 2008:


Month	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January	1,422,356		$	56.30	—
February	24,542		$	58.15	—
March	7,867		$	60.90	—

Total	1,454,765	(2)	$	56.36	—	22,208,000

(1)

The Company has a repurchase program approved by the Board of Directors in August 2004 for the repurchase of up to 25 million shares of the Company’s common stock.

(2)

Does not include restricted share forfeitures. Includes 1,454,493 shares of common stock delivered or attested to in satisfaction of the exercise price upon the exercise of employee stock options under both the 1998 and 2004 Stock Incentive plans. Also includes 272 shares of common stock purchased during the quarter from an employee in connection with the settlement of income tax withholding obligations upon vesting of restricted shares under the 2004 Stock Incentive Plan. These share purchases were not part of a publicly announced program to purchase common stock.

Items 3. through 5.

Not applicable.

Item 6.

Exhibits


Exhibit Number and Description
4.1		Second Supplemental Indenture dated as of April 18, 2008 between the Company and the Bank of New York Trust Company, N.A., as Trustee for the 4.625% senior notes due 2013, 5.50% senior notes due 2018 and 6.375% senior notes due 2038 (incorporated by reference to Exhibit 4.3.3 to Form 8-K filed April 16, 2008)

10.1		Fourth Amendment to 5-Year Revolving Credit Agreement dated February 6, 2008 between the Company and certain commercial banks names therein (incorporated by reference to Exhibit 10.39 to Form 10-K for the year ended December 31, 2007)

10.2		Fourth Amendment to Term Loan Agreement dated February 6, 2008 between the Company and certain banks named therein (incorporated by reference to Exhibit 10.44 to Form 10-K for the year ended December 31, 2007)

10.3		Form of Stock Grant Agreement (with restrictions) for Non-Employee Directors under Section 11 of the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.18 to Form 10-K for the year ended December 31, 2007)

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

15.1		Awareness letter of KPMG LLP re unaudited interim financial information

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

32.1		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: May 5, 2008	By	/s/ L OUIS G. B ALDWIN
		Louis G. Baldwin
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

	By	/s/ B ENNIE G. K NIFFEN
		Bennie G. Kniffen
		Senior Vice President and Controller
		(Principal Accounting Officer)

INDEX TO EXHIBITS

Documents filed prior to June 1, 2001 were filed with the Securities and Exchange Commission under our prior name, Cross Timbers Oil Company.


Exhibit No.	Description	Page
4.1	Second Supplemental Indenture dated as of April 18, 2008 between the Company and the Bank of New York Trust Company, N.A., as Trustee for the 4.625% senior notes due 2013, 5.50% senior notes due 2018 and 6.375% senior notes due 2038 (incorporated by reference to Exhibit 4.3.3 to Form 8-K filed April 16, 2008)

10.1	Fourth Amendment to 5-Year Revolving Credit Agreement dated February 6, 2008 between the Company and certain commercial banks names therein (incorporated by reference to Exhibit 10.39 to Form 10-K for the year ended December 31, 2007)

10.2	Fourth Amendment to Term Loan Agreement dated February 6, 2008 between the Company and certain banks named therein (incorporated by reference to Exhibit 10.44 to Form 10-K for the year ended December 31, 2007)

10.3	Form of Stock Grant Agreement (with restrictions) for Non-Employee Directors under Section 11 of the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.18 to Form 10-K for the year ended December 31, 2007)

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

15.1	Awareness letter of KPMG LLP re unaudited interim financial information

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

32.1	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