Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

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, 2010

¨	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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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, 2010
Common stock, $.01 par value		584,360,301

XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended March 31, 2010

TABLE OF CONTENTS


		Page
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets at March 31, 2010 and December 31, 2009	3

	Consolidated Income Statements for the Three Months Ended March 31, 2010 and 2009	4

	Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2010 and 2009	5

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	6

	Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2010 and 2009	7

	Notes to Consolidated Financial Statements	8

	Report of Independent Registered Public Accounting Firm	20

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28

Item 4.	Controls and Procedures	28

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	29

Item 1A.	Risk Factors	30

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31

Item 6.	Exhibits	32

	Signatures	33

PART I. FINANCIAL INFORMATION

XTO ENERGY INC.

Consolidated Balance Sheets


	March 31, 2010			December 31, 2009
*(in millions, except shares)*	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	33		$	9
Accounts receivable, net		1,050			965
Derivative fair value		1,451			1,222
Current income tax receivable		101			170
Other		185			182

Total Current Assets		2,820			2,548

Property and Equipment, at cost – successful efforts method:
Proved properties		35,002			34,180
Unproved properties		3,435			3,691
Other		2,878			2,810

Total Property and Equipment		41,315			40,681
Accumulated depreciation, depletion and amortization		(9,318	)		(8,747	)

Net Property and Equipment		31,997			31,934

Other Assets:
Derivative fair value		117			68
Acquired gas gathering contracts, net of accumulated amortization		96			97
Goodwill		1,475			1,475
Other		137			133

Total Other Assets		1,825			1,773

TOTAL ASSETS	$	36,642		$	36,255

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,445		$	1,482
Payable to royalty trusts		31			28
Current maturities of long-term debt		250			250
Derivative fair value		158			167
Deferred income tax payable		424			342
Other		36			32

Total Current Liabilities		2,344			2,301

Long-term Debt		9,955			10,237

Other Liabilities:
Derivative fair value		7			6
Deferred income taxes payable		5,650			5,522
Asset retirement obligation		813			783
Other		72			80

Total Other Liabilities		6,542			6,391

Commitments and Contingencies (Note 5)
Stockholders’ Equity:
Common stock ($.01 par value, 1,000,000,000 shares authorized, 590,629,915 and 589,361,021 shares issued)		6			6
Additional paid-in capital		8,517			8,471
Treasury stock, at cost (6,410,213 and 6,345,697 shares)		(179	)		(177	)
Retained earnings		8,574			8,317
Accumulated other comprehensive income (loss)		883			709

Total Stockholders’ Equity		17,801			17,326

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	36,642		$	36,255

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)*	2010			2009
REVENUES
Gas and natural gas liquids	$	1,448		$	1,491
Oil and condensate		535			618
Gas gathering, processing and marketing		20			54
Other		(2	)		(2	)

Total Revenues		2,001			2,161

EXPENSES
Production		255			256
Taxes, transportation and other		186			161
Exploration		13			34
Depreciation, depletion and amortization		753			699
Accretion of discount in asset retirement obligation		10			10
Gas gathering and processing		36			29
General and administrative		98			97
Derivative fair value (gain) loss		(6	)		(6	)

Total Expenses		1,345			1,280

OPERATING INCOME		656			881

OTHER EXPENSE
Interest expense, net		139			126

INCOME BEFORE INCOME TAX		517			755

INCOME TAX EXPENSE
Current		77			118
Deferred		110			151

Total Income Tax Expense		187			269

NET INCOME	$	330		$	486

EARNINGS PER COMMON SHARE
Basic	$	0.56		$	0.84

Diluted	$	0.56		$	0.83

DIVIDENDS DECLARED PER COMMON SHARE	$	0.125		$	0.125

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended March 31
*(in millions)*	2010			2009
Net Income	$	330		$	486

Other comprehensive income (loss):
Change in hedge derivative fair value		609			1,363
Realized (gain) loss on hedge derivative contract settlements reclassified into earnings from other comprehensive income		(335	)		(1,027	)

Net unrealized hedge derivative gain		274			336
Income tax expense		(100	)		(123	)

Total other comprehensive income		174			213

Total comprehensive income	$	504		$	699

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)


	Three Months Ended March 31
*(in millions)*	2010			2009
OPERATING ACTIVITIES
Net income	$	330		$	486
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		753			699
Accretion of discount in asset retirement obligation		10			10
Non-cash incentive compensation		38			40
Dry hole expense		3			20
Deferred income tax		110			151
Non-cash derivative fair value (gain) loss		(13	)		79
Gain on extinguishment of debt		—			(9	)
Other non-cash items		4			(5	)
Changes in operating assets and liabilities (a)		(7	)		1,971

Cash Provided by Operating Activities		1,228			3,442

INVESTING ACTIVITIES
Proceeds from sale of property and equipment		—			2
Property acquisitions		(44	)		(94	)
Development costs, capitalized exploration costs and dry hole expense		(670	)		(1,076	)
Other property and asset additions		(88	)		(209	)

Cash Used by Investing Activities		(802	)		(1,377	)

FINANCING ACTIVITIES
Proceeds from long-term debt		2,354			2,115
Payments on long-term debt		(2,636	)		(3,979	)
Dividends		(73	)		(69	)
Proceeds from exercise of stock options and warrants		9			1
Payments upon exercise of stock options		(2	)		—
Excess tax benefit on exercise of stock options or vesting of stock awards		2			—
Other, primarily decrease in cash overdrafts		(56	)		(149	)

Cash Used by Financing Activities		(402	)		(2,081	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		24			(16	)
Cash and Cash Equivalents, Beginning of Period		9			25

Cash and Cash Equivalents, End of Period	$	33		$	9

(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	(84	)	$	258
Other current assets		63			138
Other operating assets and liabilities		(21	)		(20	)
Current liabilities		35			(63	)
Change in current assets from early settlement of hedges, net of amortization		—			1,658

	$	(7	)	$	1,971

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Statements of Stockholders’ Equity (Unaudited)


*(in millions, except per share amounts)*	Common Stock		Additional Paid-in Capital		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)		Total
Balances, December 31, 2009	$	6	$	8,471	$	(177	)	$	8,317		$	709	$	17,326
Net income		—		—		—			330			—		330
Other comprehensive income		—		—		—			—			174		174
Issuance/vesting of stock awards, including income tax benefits		—		35		(2	)		—			—		33
Expensing of stock options		—		3		—			—			—		3
Stock option and warrant exercises, including income tax benefits		—		8		—			—			—		8
Common stock dividends ($0.125 per share)		—		—		—			(73	)		—		(73	)

Balances, March 31, 2010	$	6	$	8,517	$	(179	)	$	8,574		$	883	$	17,801


Balances, December 31, 2008	$	6	$	8,315	$	(147	)	$	6,588		$	2,585	$	17,347
Net income		—		—		—			486			—		486
Other comprehensive income		—		—		—			—			213		213
Issuance/vesting of stock awards, including income tax benefits		—		26		(1	)		—			—		25
Expensing of stock options		—		14		—			—			—		14
Stock option and warrant exercises, including income tax benefits		—		1		—			—			—		1
Common stock dividends ($0.125 per share)		—		—		—			(72	)		—		(72	)

Balances, March 31, 2009	$	6	$	8,356	$	(148	)	$	7,002		$	2,798	$	18,014

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, 2009, have not been audited by independent registered public accountants. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at March 31, 2010 and our income, comprehensive income, cash flows and stockholders’ equity for the three months ended March 31, 2010 and 2009. 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, 2010 and 2009 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 2009 Annual Report on Form 10-K.

Other

On December 13, 2009, we entered into a definitive merger agreement with Exxon Mobil Corporation under which we would become a wholly owned subsidiary of ExxonMobil. As a result of the merger, each outstanding share of our common stock will be converted into 0.7098 shares of ExxonMobil common stock. Completion of the merger remains subject to certain conditions, including the adoption of the merger agreement by our stockholders, as well as certain governmental approvals. We currently expect to complete the merger in the second quarter of 2010, however, no assurance can be given as to when, or if, the merger will occur.

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 $147 million at March 31, 2010 and December 31, 2009.

Our effective income tax rates for the three-month 2010 and 2009 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 exercising of stock options or vesting of stock awards in excess amounts expensed in the financial statements. This benefit, which is recorded in additional paid-in capital, was $2 million for first quarter 2010 and less than $1 million for first quarter 2009.

2. Related Party Transactions

Jack Randall, one of our nonemployee directors, was a co-founder and director of Randall & Dewey Partners, L.P., which was acquired by Jefferies Group, Inc. in 2005 and now operates as Jefferies & Company, Inc. Jefferies served as one of our financial advisors in connection with the announced merger with ExxonMobil. If the merger is completed, we have agreed to pay Jefferies a transaction fee of $24 million. In addition, we agreed to reimburse Jefferies for all reasonable and documented out-of-pocket expenses, including legal fees, incurred in connection with the services it provides to us in connection with the merger and have agreed to indemnify Jefferies against certain liabilities.

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, 2010:


*(in millions)*
Asset retirement obligation, December 31, 2009	$	812
Revisions in estimated cash flows		26
Liability incurred upon acquiring and drilling wells		7
Liability settled upon plugging and abandoning wells		(9	)
Accretion of discount expense		10

Asset retirement obligation, March 31, 2010	$	846
Less current portion		(33	)

Asset retirement obligation, long term	$	813

4. Debt


*(in millions)*	March 31, 2010			December 31, 2009
Bank debt:
Commercial paper, 0.3% at March 31, 2010 and December 31, 2009	$	340		$	622
Revolving credit facility due April 1, 2013		—			—
Term loan due April 1, 2013, 0.6% at March 31, 2010 and 0.7% at December 31, 2009		500			500
Term loan due February 5, 2013, 0.6% at March 31, 2010 and December 31, 2009		100			100
Senior notes:
5.00%, due August 1, 2010		250			250
7.50%, due April 15, 2012		350			350
5.90%, due August 1, 2012		550			550
6.25%, due April 15, 2013		400			400
4.625%, due June 15, 2013		400			400
5.75%, due December 15, 2013		500			500
4.90%, due February 1, 2014		500			500
5.00%, due January 31, 2015		348			348
5.30%, due June 30, 2015		400			400
5.65%, due April 1, 2016		400			400
6.25%, due August 1, 2017		735			735
5.50%, due June 15, 2018		773			773
6.50%, due December 15, 2018		1,000			1,000
6.10%, due April 1, 2036		591			591
6.75%, due August 1, 2037		1,399			1,399
6.375%, due June 15, 2038		704			704
Net discount on senior notes		(35	)		(35	)

Total debt		10,205			10,487
Less current portion		(250	)		(250	)

Long-term debt	$	9,955		$	10,237

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. Maturities of long-term debt as of March 31, 2010, excluding net discounts, are as follows:


*(in millions)*
2010	$	250
2011		—
2012		900
2013		2,240
2014		500
Remaining		6,350

Total	$	10,240

Commercial Paper

Our commercial paper program availability is $2.84 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, 2010, borrowings under our commercial paper program were $340 million at a weighted average interest rate of 0.3%.

Bank Debt

On March 31, 2010, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $2.5 billion net of our commercial paper borrowings. We use the facility for general corporate purposes and as a backup facility for our commercial paper program. We have the option, with bank approval, to increase the commitment up to an additional $660 million. The interest rate on any borrowing is generally based on LIBOR plus 0.40%. When utilization of available commitments is greater than 50%, then the interest rate on our borrowings is increased by 0.05%. 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 have unsecured and uncommitted lines of credit with commercial banks totaling $100 million. As of March 31, 2010, there were no borrowings under these lines.

Senior Notes

We are required to offer to purchase at 101% of par our 7.50% senior notes due 2012 and our 6.25% senior notes due 2013 if we are the subject of a change in control, such as the proposed merger with ExxonMobil. Our other senior notes are not subject to this provision.

5. Commitments and Contingencies

Litigation

In July 2005 a predecessor company that we acquired, 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 parties to 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 related 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 settled all claims related to the payment of royalties and trespass. Under the remaining claims, the plaintiffs sought both damages and termination of the existing oil and gas leases covering their interests. In October 2008, the trial court granted our motion for summary judgment, resulting in the dismissal of the plaintiffs’ remaining claims. The plaintiffs have appealed the court’s judgment. 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.

In November 2008, an action was filed against the Company and our directors styled Freedman v. Adams, et al. in the Delaware Court of Chancery. The plaintiff is alleged to be a stockholder and brings the suit as a derivative action on behalf of the Company. The plaintiff seeks an equitable accounting for the alleged losses by the Company and injunctions mandating that a Section 162(m) plan be submitted to our stockholders for their approval and against further non-deductible payments, along with an award of accountants’, experts’ and attorneys’ fees. We have filed a motion to dismiss. While we did not have in place a Section 162(m) plan at the time the suit was filed for cash payments, the Board of Directors approved a Section 162(m) plan in February 2009 that was approved by our stockholders at our annual meeting in May 2009. Although we are unable to predict the final outcome of this case, we believe that the allegations of this lawsuit are without merit, and we intend to vigorously defend the action.

In September 2008, a class action lawsuit was filed against the Company styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. We removed the case to federal court in Wichita, Kansas. The plaintiffs allege that we have improperly taken post-production costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma, and Colorado. The plaintiffs also seek to represent all royalty owners in these three states as a class. We have answered, denying all claims, and have filed motions to dismiss a portion of the claims. The federal court recently granted our motion for summary judgment concerning prior settled class actions that overlap plaintiff’s proposed class action. The court also granted our motion to dismiss those portions of plaintiff’s class that are currently being prosecuted in another case. 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.

On December 14, 2009, Exxon Mobil Corporation and XTO Energy announced that the companies had entered into a definitive agreement under which we would become a wholly owned subsidiary of ExxonMobil. As a result of this announcement, a number of putative shareholder class actions have been filed, alleging breaches of fiduciary duties by the individual members or our Board of Directors. Each lawsuit generally seeks, among other things, declaratory and injunctive relief concerning the alleged fiduciary breaches, injunctive relief prohibiting the defendants from consummating the merger, imposition of constructive trusts in favor of plaintiffs and putative class members and unspecified monetary damages. Several putative shareholders have also filed an individual lawsuit in federal court alleging violations of the federal securities laws based on alleged false and material misrepresentations or omissions in the preliminary proxy filed with the Securities and Exchange Commission in connection with the proposed merger. The federal individual action also seeks to enjoin the proposed merger.

Two putative shareholder class actions were filed in the Delaware Court of Chancery between December 17, 2009 and December 18, 2009. Those cases are styled as (i) Teamsters Allied Benefit Funds, et al. v. XTO Energy Inc., et al., Case No. 5150, filed on December 17, 2009 and (ii) Nicholas Lombardi v. XTO Energy Inc., et al., Case No. 5152, filed on December 18, 2009. On December 22, 2009, the Delaware Court of Chancery entered an order consolidating the complaints filed as of that date under the caption In re XTO Energy Inc. Shareholders Litigation.

Eleven putative shareholder class actions were filed in the District Courts of Tarrant County, Texas between December 14, 2009, and January 6, 2010. Those cases are styled: (i) Mary Pappas, et al. v. XTO Energy Inc., et al., No. 342-242403-09, filed on December 14, 2009; (ii) Sanjay Israni, et al. v. XTO Energy Inc., et al., No. 017-242424-09, filed on December 15, 2009; (iii) Michael Walsh, et al. v. XTO Energy Inc., et al., No. 153-242432-09, filed on December 15, 2009; (iv) Ronald Gross, et al. v. XTO Energy Inc., et al., No. 141-242460-09, filed on December 16, 2009; (v) Jeffrey Fink, et al. v. Bob R. Simpson, et al., No. 048-242500-09, filed on December 17, 2009; (vi) Lawrence Treppel, et al. v. XTO Energy Inc., et al., No. 342-242523-09, filed on December 18, 2009; (vii) Nicholas Weil, et al. v. XTO Energy Inc., et al., No. 096-242526-09, filed on December 18, 2009; (viii) Charles Kreps, et al. v. XTO Energy Inc., et al., Case No. 352-242548-09, filed on December 21, 2009; (ix) Murray Silver, et al. v. XTO Energy Inc., et al., No. 342-242630-09, filed on December 22, 2009; (x) William Stratton, et al. v. XTO Energy Inc., et al., No. 096-242775-09, filed on December 30, 2009; and (xi) United Food and Commercial Workers Union Local 880-Retail Food Employers Joint Pension Fund v. XTO Energy Inc., et al., No. 342-242849-10, filed on January 6, 2010. On January 12, 2010, the court entered orders consolidating the eleven cases filed as of that date under the caption In re XTO Energy Shareholder Class Action Litigation.

Two putative shareholder class actions were filed in the United States District Court for the Northern District of Texas between December 28, 2009 and January 5, 2010. Those cases are styled (i) James Harrison, et al. v. XTO Energy Inc., et al., No. 4:09-cv-768-Y, filed on December 28, 2009 and (ii) Walt Schumann, et al. v. Bob R. Simpson, et al., No. 4:10-cv-007-Y, filed on January 5, 2010. On February 5, 2010, the plaintiffs in the two federal actions filed an unopposed motion to consolidate the cases.

Several putative shareholders filed an individual action in the United States District Court for the Northern District of Texas on February 11, 2010 alleging violations of the federal securities laws based on alleged false and material misrepresentations or omissions in the preliminary proxy filed with the Securities and Exchange Commission in connection with the proposed merger. That case is styled Mary Pappas, et al. v. Bob R. Simpson, et al., No. 4:10-cv-00094-A, filed February 11, 2010. This case was consolidated into the Harrison case described above.

On April 21, 2010, the parties to all of the shareholder litigations challenging the merger entered into a stipulation of settlement, which, if finally approved by the Tarrant County District Court, will resolve all of the litigations challenging the merger. On April 22, 2010, the Tarrant County District Court presiding over the Texas state court litigation preliminarily approved a proposed settlement of all claims made in all of the cases that are pending in all jurisdictions against XTO Energy and ExxonMobil related to the proposed merger. The basis of the settlement relates to certain modified disclosures that have been and will be made in filings with the Securities and Exchange Commission, as well as a confirmation letter relating to Barclays Capital’s opinion letter, to be delivered by Barclays Capital, after its review of certain additional materials. The cases are being settled as a settlement class under the class action laws of the State of Texas. Under such laws, certain notifications will be made to the class, and a fairness hearing is currently scheduled for October 1, 2010. Further information concerning the settlement will be provided in the definitive proxy statement/prospectus to be filed with the Securities and Exchange Commission and mailed to XTO Energy stockholders in connection with the proposed merger.

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, 2010, maximum commitments under our transportation contracts were as follows:


*(in millions)*
2010	$	165
2011		231
2012		232
2013		227
2014		223
Remaining		777

Total	$	1,855

In November 2008, we completed an agreement to enter into a twelve-year firm transportation contract, contingent upon obtaining regulatory approvals and completion of a new pipeline that connects the Fayetteville Shale to ANR Pipeline and Trunkline Pipeline in Quitman County, Mississippi. Upon the pipeline’s completion, currently expected in fourth quarter 2010, we will transport gas volumes for a transportation fee of up to $1.25 million per month plus fuel, currently expected to be 0.86% of the sales price. The potential effect of this agreement is not included in the above summary of our transportation contract commitments since our commitment is contingent upon completion of the pipeline.

Drilling Contracts

As of March 31, 2010, we have contracts with various drilling contractors to use 65 drilling rigs with terms of up to three years and minimum future commitments of $103 million in 2010, $34 million in 2011, $11 million in 2012 and $1 million in 2013. Early termination of these contracts at March 31, 2010 would have required us to pay maximum penalties of $85 million. Based upon our planned drilling activities, we do not expect to pay significant early termination penalties.

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 normal sales contracts. Therefore, these contracts are not recorded in the financial statements. Most of our derivative contracts are designated as cash flow hedges for hedge accounting purposes. At March 31, 2010, certain crude oil swap agreements and certain natural gas basis swap agreements did not qualify for hedge accounting. Except to the extent basis swap agreements are utilized in conjunction with NYMEX future contracts, they cannot qualify for hedge accounting. Whether or not designated as cash flow hedges, all of our derivative contracts are used to hedge against changes in cash flows related to commodity prices.

All derivatives are recorded at estimated fair value and recorded as derivative fair value in both current and non-current assets and liabilities in the consolidated balance sheets. 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. Realized and unrealized gains and losses on derivatives that are not

designated as hedges, as well as on the ineffective portion of hedge derivatives, are recorded as a derivative fair value gain or loss in the consolidated income statements. 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. Unrealized gains and losses on effective cash flow hedge derivatives are recorded as a component of accumulated other comprehensive income (loss). When the hedged transaction occurs, the realized gain or loss on the hedge derivative is transferred from accumulated other comprehensive income (loss) to earnings. Realized gains and losses on commodity hedge derivatives are recognized in oil and gas revenues, and realized gains and losses on interest hedge derivatives are recorded as adjustments to interest expense.

Derivative Instruments

The fair value of our derivative contracts consists of the following:


	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
*(in millions)*	March 31, 2010		December 31, 2009		March 31, 2010			December 31, 2009
Derivatives designated as hedging instruments:
Natural gas futures and basis swaps	$	1,248	$	836	$	(36	)	$	(52	)
Crude oil futures and differential swaps		313		442		(107	)		(105	)

Total derivatives designated as hedging instruments		1,561		1,278		(143	)		(157	)

Derivatives not designated as hedging instruments:
Natural gas futures and basis swaps		7		12		(14	)		(8	)
Crude oil futures and differential swaps		—		—		(8	)		(8	)

Total derivatives not designated as hedging instruments		7		12		(22	)		(16	)

Total derivatives	$	1,568	$	1,290	$	(165	)	$	(173	)

The effects of our cash flow hedges on accumulated other comprehensive income (loss) on the consolidated balance sheets are summarized below.


	Three Months Ended March 31
	Change in Hedge Derivative Fair Value					Realized (Gain) Loss Reclassified from OCI into Revenue *(a)*
*(in millions)*	2010			2009		2010			2009
Natural gas futures and basis swaps	$	642		$	1,309	$	(230	)	$	(624	)
Crude oil futures and differential swaps		(33	)		54		(105	)		(403	)

Total	$	609		$	1,363	$	(335	)	$	(1,027	)

(a)

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

The effects of our non-hedge derivatives and the ineffective portion of our hedge derivatives on the consolidated income statements are summarized below.


	Three Months Ended March 31
	(Gain) Loss Recognized in Income (Non-Hedge)					(Gain) Loss Recognized in Income (Ineffective Portion)						Derivative Fair Value (Gain) Loss
*(in millions)*	2010		2009			2010			2009			2010			2009
Natural gas futures and basis swaps	$	12	$	5		$	(13	)	$	(19	)	$	(1	)	$	(14	)
Crude oil futures and differential swaps		1		(3	)		(6	)		11			(5	)		8

Total	$	13	$	2		$	(19	)	$	(8	)	$	(6	)	$	(6	)

Derivative Fair Value (Gain) Loss

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


*(in millions)*	Three Months Ended March 31
*(in millions)*	2010			2009
Net cash paid to (received from) counterparties	$	7		$	(85	)
Non-cash change in derivative fair value		(13	)		79

Derivative fair value (gain) loss	$	(6	)	$	(6	)

See Note 7.

Fair Value of Financial Instruments

Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at March 31, 2010 and December 31, 2009. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:


	Asset (Liability)
	March 31, 2010						December 31, 2009
*(in millions)*	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Net derivative asset	$	1,403		$	1,403		$	1,117		$	1,117

Total debt	$	(10,205	)	$	(11,281	)	$	(10,487	)	$	(11,526	)

The fair value of our debt is based upon current market quotes and is the estimated amount required to purchase our debt on the open market. The estimated value does not include any redemption premium.

Fair Value Measurements

The following table summarizes our fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall.


	Fair Value Measurements
	March 31, 2010					December 31, 2009
*(in millions)*	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Net derivative asset	$	1,403	$	—		$	1,117	$	—

Asset retirement obligation	$	—	$	(846	)	$	—	$	(812	)

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. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are generally A- or better rated companies, the fair value of our derivative contracts have been adjusted to account for the risk of nonperformance by the counterparty.

Our asset retirement obligation is measured using primarily Level III inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation 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.

Concentrations of Credit Risk

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, pipeline companies, local distribution companies, financial institutions and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated companies. Letters of credit or other appropriate security are obtained as considered necessary to mitigate risk of loss. Financial and commodity-based swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, and we have master netting agreements with most counterparties that provide for offsetting payables against receivables from separate derivative contracts. None of our derivative contracts contain credit-risk-related contingent features that would require collateralization based on any triggering events.

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 most of our crude oil sales through December 2010 and a portion of our natural gas sales through December 2011.

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
2010	April to December	1,250,000	$	7.49
2011	January to December	250,000	$	7.02

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. The table below does not include our physical delivery contracts tied to indices at various delivery points.


Production Period		Mcf per Day	Weighted Average Sell Basis per Mcf *(a)*
2010	April to October	610,000	$	0.31
	November to December	475,000	$	0.27
2011	January to October	200,000	$	0.19
	November to December	170,000	$	0.17
2012	January to December	50,000	$	0.27

(a)

Reductions to NYMEX gas prices for delivery location.

As of March 31, 2010, a pre-tax derivative fair value gain of approximately $1.2 billion, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). Based on March 31 mark-to-market prices, $1.1 billion of this gain is expected to be reclassified into earnings through March 2011. The actual reclassification to earnings will be based on the mark-to-market prices at the 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. Not all of our 2010 crude oil swap agreements are designated as hedges for hedge accounting purposes. See Note 6 regarding accounting for commodity hedges.


Production Period		Bbls per Day	Weighted Average NYMEX Price per Bbl
2010	April to December	70,000	$	95.70

We have entered into crude differential swaps that effectively fix the sweet and sour oil differential at $3.43 per Bbl for 23,000 Bbls per day for April to December 2010.

As of March 31, 2010, a pre-tax derivative fair value gain of approximately $205 million, related to cash flow hedges of oil price risk, was recorded in accumulated other comprehensive income (loss). Based on March 31 mark-to-market prices, this fair value gain is expected to be reclassified into earnings in 2010. The actual reclassification to earnings will be based on the mark-to-market prices at the settlement date.

Purchase Basis Swaps

We have entered purchase basis swap agreements that effectively fix the basis adjustment as shown below. Some of our purchase basis swap agreements are used to offset our physical delivery basis contracts. This effectively converts the fixed price to a floating price. The remaining purchase basis swap agreements are related to potential purchase of gas volumes to be transported in connection with our commitments under our transportation contracts (Note 5). Purchase basis swap agreements are not designated as hedges for hedge accounting purposes.


Period		Mcf per Day	Weighted Average Purchase Basis per Mcf *(a)*
2010	April to December	120,000	$	0.14
2011	January to October	120,000	$	0.14
	November to December	70,000	$	0.13
2012	January to December	30,000	$	0.14
2013	January to May	20,000	$	0.16

(a)

Reductions to NYMEX gas prices for purchase location.

8. Earnings per Share

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


*(in millions, except per share data)*	Three Months Ended March 31
	2010							2009
	Earnings			Shares		Earnings per Share		Earnings			Shares		Earnings per Share
Total	$	330		584.2				$	486		579.7
Attributable to participating securities		(3	)	(4.8	)				(4	)	(4.7	)

Basic	$	327		579.4		$	0.56	$	482		575.0		$	0.84

Effect of dilutive securities:
Stock options		—		3.2					—		1.8
Warrants		—		1.1					—		1.0

Diluted	$	327		583.7		$	0.56	$	482		577.8		$	0.83

Certain options to purchase shares of our common stock have been excluded from the 2010 and 2009 diluted calculations because the options are anti-dilutive. Anti-dilutive options for 7.5 million shares with a weighted average exercise price of $52.70 were excluded in 2010, and 8.0 million shares with a weighted average price of $50.98 were excluded in 2009.

9. 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 10) during the three-month periods ended March 31, 2010 and 2009:

•

Vesting of 2,500 restricted shares and forfeitures of 26,000 restricted shares in 2010. Grants of 2,000 restricted shares, vesting of 2,000 restricted shares and forfeitures of 29,000 restricted shares in 2009.

•

Grants of 40,000 performance shares in 2010 and 46,000 performance shares in 2009.

•

Grants and immediate vesting of 110,000 unrestricted common shares to our Chairman of the Board and Founder in 2010 and 2009.

•

Grants and immediate vesting of 25,000 unrestricted common shares to nonemployee directors in 2010 and 2009.

•

Common shares delivered or attested to in satisfaction of the exercise price of employee stock options totaled 9,000 shares at a weighted average exercise price of $46.17 per share in 2010.

10. Employee Benefit Plans

Stock awards under the 2004 Stock Incentive Plan include stock options, performance shares, restricted shares and unrestricted shares. The table below summarizes stock incentive compensation expense included in the consolidated financial statements and other information for the three-month 2010 and 2009 periods:


	Three Months Ended March 31
*(in millions)*	2010		2009
Non-cash stock option compensation expense	$	3	$	14
Non-cash performance share and unrestricted share compensation expense		18		9
Non-cash restricted stock compensation expense		17		17
Related tax benefit recorded in income statement		14		15
Intrinsic value of stock option exercises		7		1
Income tax benefit on exercise of stock options (a)		2		—

(a)

Recorded as additional paid-in-capital

During the first three months of 2010, 2,500 stock options were granted to employees at a weighted average exercise price of $45.98 per share. A total of 341,000 stock options were exercised at a weighted average exercise price of $26.17 per share. As a result of these exercises, outstanding common stock increased by 288,000 shares and stockholders’ equity increased by a net $8 million.

In January 2010, our Chairman of the Board and Founder received 110,000 unrestricted common shares and 40,000 performance shares, half of which vest when the stock price closes at or above $50.00 and half of which vest when the stock price closes at or above $52.00. As a result of our announced merger agreement with ExxonMobil, these performance shares will vest at closing if the proposed merger with ExxonMobil is completed. If the merger is not completed, the vesting criteria would revert to the price vesting terms. In February 2010, 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 except in certain circumstances, including a merger such as our proposed merger with ExxonMobil.

As of March 31, 2010, nonvested stock options had remaining unrecognized compensation expense of $8 million. Total deferred compensation at March 31, 2010 related to nonvested restricted shares was $117 million and related to performance shares was $6 million. For these nonvested stock awards, we estimate that stock incentive compensation for service periods after March 31, 2010 will be $60 million in 2010, $45 million in 2011, $18 million in 2012 and $8 million in 2013. The weighted average remaining vesting period is 0.8 years for stock options, 2.2 years for restricted shares and 0.1 years for performance shares.

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, 2010, the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for the three-month periods ended March 31, 2010 and 2009. These consolidated financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of 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, 2009, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the year then ended (not presented herein), included in the Company’s 2009 Annual Report on Form 10-K, and in our report dated February 24, 2010, we expressed an unqualified opinion on those statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet included in the Company’s 2009 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Fort Worth, Texas

May 5, 2010

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 2009 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
	2010		2009		Increase (Decrease)
Total production
Gas (Mcf)		215,812,621		200,501,903	8	%
Natural gas liquids (Bbls)		1,798,214		1,647,278	9	%
Oil (Bbls)		5,789,435		5,906,614	(2	)%
Mcfe		261,338,515		245,825,255	6	%

Average daily production
Gas (Mcf)		2,397,918		2,227,799	8	%
Natural gas liquids (Bbls)		19,980		18,303	9	%
Oil (Bbls)		64,327		65,629	(2	)%
Mcfe		2,903,761		2,731,392	6	%

Average sales price
Gas per Mcf	$	6.35	$	7.24	(12	)%
Natural gas liquids per Bbl	$	43.18	$	23.84	81	%
Oil per Bbl	$	92.49	$	104.59	(12	)%

Average sales price before hedging
Gas per Mcf	$	5.28	$	4.15	27	%
Natural gas liquids per Bbl	$	43.18	$	23.84	81	%
Oil per Bbl	$	74.32	$	36.38	104	%

Average NYMEX prices
Gas per MMBtu	$	5.30	$	4.89	8	%
Oil per Bbl	$	78.54	$	43.18	82	%

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 2009 to 2010 primarily because of development activity, partially offset by natural decline.

Gas prices before hedging and average NYMEX gas prices increased from first quarter 2009 to first quarter 2010. Natural gas prices are affected by the level of North American production, weather, crude oil prices, the

U.S. economy, storage levels and import levels of liquefied natural gas. Natural gas competes with alternative energy sources as fuel for heating and the generation of electricity. Due to concerns of oversupply from shale gas development, declining demand due to the U.S. recession, falling oil prices and increased gas in storage, gas prices declined during the first nine months of 2009. However, signs of possible economic improvement, higher oil prices and a relatively cold winter led to increased gas prices in late 2009 and early 2010. Gas prices have weakened substantially in February and March 2010 due to renewed concerns of oversupply. Natural gas prices are expected to remain volatile. The NYMEX contract price for April 2010 was $3.84 per MMBtu. At April 30, 2010, the average NYMEX futures price for the following twelve months was $4.75 per MMBtu.

Oil prices before hedging and average NYMEX oil prices increased from first quarter 2009 to first quarter 2010. Crude oil prices are generally determined by global supply and demand. Lower demand as a result of the U.S. recession and slowing global economy, the tightened credit markets and rising crude oil supplies caused oil prices to decline sharply in 2008. However, signs of possible economic improvement have resulted in steadily higher oil prices during 2009 and early 2010. Oil prices are expected to remain volatile. The average NYMEX price for April 2010 was $84.52 per Bbl. At April 30, 2010, the average NYMEX futures price for the following twelve months was $90.76 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 most of our crude oil sales through December 2010 and a portion of our natural gas sales through December 2011; see Note 7 to Consolidated Financial Statements.

Results of Operations

Quarter Ended March 31, 2010 Compared with Quarter Ended March 31, 2009

Net income for first quarter 2010 was $330 million compared to $486 million for first quarter 2009. First quarter 2010 earnings include a $13 million ($8 million after-tax) non-cash derivative fair value gain. First quarter 2009 earnings include a $79 million ($51 million after-tax) non-cash derivative fair value loss and a $9 million ($6 million after-tax) gain on extinguishment of debt.

Total revenues for first quarter 2010 were $2.00 billion, a 7% decrease from first quarter 2009 revenues of $2.16 billion. Operating income for the quarter was $656 million, a 26% decrease from first quarter 2009 operating income of $881 million. Gas and natural gas liquids revenues decreased $43 million because of a 12% decrease in gas prices partially offset by an 8% increase in gas production, an 81% increase in natural gas liquids prices and a 9% increase in natural gas liquids production. Oil revenue decreased $83 million because of a 12% decrease in oil prices and a 2% decrease in production. In addition, realized average gas and oil prices for the quarter decreased from first quarter 2009 due to the effect of hedges. In 2009, 2.12 billion cubic feet equivalent (Bcfe) per day of production was hedged at a natural gas equivalent price of $10.69 compared to 1.67 Bcfe per day of production hedged in 2010 at a natural gas equivalent price of $9.62.

Expenses for first quarter 2010 totaled $1.35 billion, a 5% increase from first quarter 2009 expenses of $1.28 billion. Increased expenses are generally related to increased production from development and related Company growth. Production expense decreased $1 million primarily because of lower compression, water disposal and power costs, partially offset by increased overall production. Taxes, transportation and other increased $25 million from the first quarter of 2009 primarily because of higher production taxes and transportation costs due to higher product prices, excluding the effects of hedges, and higher gas volumes, partially offset by lower property taxes. Depreciation, depletion and amortization increased $54 million primarily because of increased production. Exploration expense decreased $21 million primarily due to a $17 million decrease in dry hole expense. General and administrative expense increased $1 million primarily due to expenses related to the pending merger with ExxonMobil.

The derivative fair value gain for first quarter 2010 and 2009 was $6 million. The gain in first quarter 2010 is primarily related to the ineffective portion of hedge derivatives partially offset by the change in fair value of natural gas basis swap agreements that do not qualify for hedge accounting. See Note 6 to Consolidated Financial Statements.

Interest expense increased $13 million primarily because of a $9 million gain on extinguishment of debt in 2009 and lower capitalized interest in 2010. The effective income tax rate for first quarter 2010 was 36.2%, as compared with 35.6% for first quarter 2009.

Comparative Expenses per Mcf Equivalent Production

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


	Three Months Ended March 31
	2010		2009		Increase (Decrease)
Production	$	0.98	$	1.04	(6	)%
Taxes, transportation and other	$	0.71	$	0.65	9	%
Depreciation, depletion and amortization (DD&A)	$	2.88	$	2.84	1	%
General and administrative (G&A):
Non-cash stock incentive compensation	$	0.15	$	0.16	(6	)%
All other G&A	$	0.23	$	0.23	—
Interest	$	0.53	$	0.51	4	%

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

Production expenses—Decreased production expense is primarily because of decreased compression, power and water disposal costs.

Taxes, transportation and other—A portion of these expenses vary with product prices. Increased taxes, transportation and other expense is primarily because of higher product prices, excluding hedging, partially offset by lower property taxes.

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

G&A—Decreased stock incentive compensation is related to a decrease of $2 million in non-cash incentive award compensation and increased production.

Interest—Increased interest expense is primarily because of a $9 million gain on extinguishment of debt in 2009 and lower capitalized interest in 2010.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $1.23 billion for first quarter 2010, compared with $3.4 billion for the same 2009 period. Decreased first quarter cash provided by operating activities is primarily due to the early settlement of hedges in 2009. In January 2009, we entered into early settlement and reset arrangements with seven financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.2 billion which was used to reduce outstanding debt. Cash provided by operating activities was decreased by changes in operating assets and liabilities of $7 million in first quarter 2010 and increased by $2.0 billion in first quarter 2009. 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 $10 million in first quarter 2010 and $14 million in first quarter 2009.

During the quarter ended March 31, 2010, cash provided by operating activities of $1.23 billion was used to fund net property acquisitions, development costs and other net capital additions of $802 million, dividends of $73 million and to pay down $282 million of debt. The resulting increase in cash and cash equivalents for the period was $24 million.

Total current assets increased $272 million during the first quarter of 2010 primarily because of a $229 million increase in derivative fair value as a result of a decrease in future gas prices, partially offset by cash settlements during the period. Total current liabilities increased $43 million during the first quarter of 2010 primarily because of increased deferred income tax payable due to the higher derivative fair value, partially offset by decreased accounts payable and accrued liabilities due to lower drilling activity and lower gas prices.

Working capital increased from a positive position of $247 million at December 31, 2009 to a positive position of $476 million at March 31, 2010. Excluding the effects of derivative fair value and deferred tax current liabilities, working capital improved from a negative position of $466 million at December 31, 2009 to a negative position of $393 million at March 31, 2010. 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

Exploration and development expenditures for the first three months of 2010 were $680 million compared with $1.1 billion for the first three months of 2009. We have budgeted $3.37 billion for the 2010 development and exploration program and an additional $530 million for construction of pipeline infrastructure and compression and processing facilities. 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 also may reevaluate our budget and drilling programs as a result of significant changes in oil and gas prices.

In first quarter 2010, we completed acquisitions of both producing and unproved properties for $44 million compared to $94 million for first quarter 2009. These acquisitions were funded by cash provided by operating activities and are subject to typical post-closing adjustments.

While we expect to focus on development activities in 2010, we plan to actively review acquisition opportunities. 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. Other than the requirement for us to maintain a debt-to-total capitalization ratio of not more than 65%, there are no restrictions under our revolving credit agreement that would affect our ability to use our remaining borrowing capacity.

Through the first three months of 2010, we participated in drilling approximately 165 gas wells and 18 oil wells and performed 32 workovers. Our year-to-date natural gas drilling activity was concentrated in East Texas and the Barnett, Fayetteville, Haynesville and Woodford shales. Our year-to-date crude drilling activity was concentrated in the Permian Basin and Bakken Shale. Workovers have focused on recompletions, artificial lift and wellhead compression. These projects generally have met or exceeded management expectations.

Debt

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, 2010, borrowings under our commercial paper program were $340 million at a weighted average interest rate of 0.3%.

We have unsecured and uncommitted lines of credit with commercial banks totaling $100 million. As of March 31, 2010, there were no borrowings under these lines.

Senior Notes

Dividends

In February 2010, the Board of Directors declared a first quarter 2010 dividend of $0.125 per share payable April 15, 2010 to stockholders of record on March 31, 2010. Under the terms of the merger agreement with ExxonMobil, during the period before the closing of the merger, we are prohibited from declaring, setting aside or paying any dividend or other distribution except for our regular quarterly cash dividend, which is not to exceed $0.125 per share. The merger agreement also provides that we will coordinate the declaration of dividends with ExxonMobil before the completion of the merger so that both our shareholders and the shareholders of ExxonMobil only receive, in any quarter, one dividend from each company.

Contractual Obligations and Commitments

The following summarizes our significant obligations and commitments to make future contractual payments as of March 31, 2010. 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		2010		2011		2012		2013		2014		After 2014
Debt	$	10,240	$	250	$	—	$	900	$	2,240	$	500	$	6,350
Operating leases		70		22		23		14		8		3		—
Drilling contracts		149		103		34		11		1		—		—
Purchase commitments		13		13		—		—		—		—		—
Transportation contracts		1,855		165		231		232		227		223		777
Derivative contract liabilities at March 31, 2010 fair value		165		157		5		3		—		—		—

Total	$	12,492	$	710	$	293	$	1,160	$	2,476	$	726	$	7,127

Debt. Debt amounts represent scheduled maturities of our debt obligations at March 31, 2010, excluding $35 million of net discounts on our senior notes included in the carrying value of debt. At March 31, 2010, borrowings were $340 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 $340 million outstanding under the commercial paper program is reflected in the table above as due in 2013. Borrowings of $600 million under our term loans are due in 2013, and our senior notes, totaling $9.3 billion are due 2010 through 2038. For further information regarding debt, see Note 4 to Consolidated Financial Statements.

Drilling Contracts. We have contracts with various drilling contractors to use 65 drilling rigs with terms of up to three years. Early termination of these contracts at March 31, 2010 would have required us to pay maximum penalties of $85 million. Based upon our planned drilling activities, we do not expect to pay significant early termination penalties.

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.

Derivative Contracts. We have entered into futures contracts and swaps to hedge our exposure to natural gas and oil price fluctuations. 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, 2010, the current liability related to such contracts was $158 million and the noncurrent liability was $7 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.

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, 2009, 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 2009 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, 2010, our variable rate debt had a carrying value of $940 million, which approximated its fair value, and our fixed rate debt had a carrying value of $9.3 billion and an approximate fair value liability of $10.3 billion. Assuming a one percent, or 100-basis point, change in interest rates at March 31, 2010, the fair value of our fixed rate debt would change by approximately $746 million.

Commodity Price Risk

We hedge a portion of our price risks associated with our natural gas and crude oil sales. As of March 31, 2010, our outstanding futures contracts and swap agreements had a net fair value gain of $1.4 billion. 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, 2010. 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	$	1,198	$	181
Natural gas purchase basis swap agreements		7		1
Crude oil futures		198		160

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. 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.

LEGAL PROCEEDINGS

On April 21, 2010, the parties to all of the shareholder litigations challenging the merger entered into a stipulation of settlement, which, if finally approved by the Tarrant County District Court, will resolve all of the litigations challenging the merger. On April 22, 2010, the Tarrant County District Court presiding over the Texas state court litigation preliminarily approved a proposed settlement of all claims made in all of the cases that are pending in all jurisdictions against XTO Energy and ExxonMobil related to the proposed merger. The basis of the settlement relates to certain modified disclosures that have been and will be made in filings with the Securities and Exchange Commission, as well as a confirmation letter relating to Barclays Capital’s opinion letter, to be delivered by Barclays Capital after its review of certain additional materials. The cases are being settled as a settlement class under the class action laws of the State of Texas. Under such laws, certain notifications will be made to the class, and a fairness hearing is currently scheduled for October 1, 2010. Further information concerning the settlement will be provided in the definitive proxy statement/prospectus to be filed with the Securities and Exchange Commission and mailed to XTO Energy stockholders in connection with the proposed merger.

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, 2009.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following summarizes purchases of our common stock during first quarter 2010:


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	38,374		$	47.37	—
February	846		$	46.09	—
March	8,346		$	46.11	—

Total	47,566	(2)	$	47.13	—	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 8,596 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 38,970 shares of common stock purchased during the quarter from employees in connection with the settlement of income tax withholding obligations upon vesting of unrestricted and 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
11		Computation of per share earnings (included in Note 8 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

101		The following financial statements from XTO Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, filed on May 6, 2010, formatted in XBRL; (i) Consolidated Balance Sheets, (ii) Consolidated Income Statements, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Stockholders’ Equity and (vi) the Notes to Consolidated Financial Statements, tagged as blocks of text.

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, 2010	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)

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. Except as otherwise specifically indicated, all documents are filed under Commission File Number 1-10662.


Exhibit No.	Description	Page
11	Computation of per share earnings (included in Note 8 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

101	The following financial statements from XTO Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, filed on May 6, 2010, formatted in XBRL; (i) Consolidated Balance Sheets, (ii) Consolidated Income Statements, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Stockholders’ Equity and (vi) the Notes to Consolidated Financial Statements, tagged as blocks of text.

Three Months Ended
March 31

(in millions)

Income tax

XTO ENERGY INC 10-Q