- Quarterly Report (10-Q)

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 June 30, 2009

¨	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 July 31, 2009
Common stock, $.01 par value		580,199,764

XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended June 30, 2009

TABLE OF CONTENTS


		Page
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets at June 30, 2009 and December 31, 2008	3

	Consolidated Income Statements for the Three and Six Months Ended June 30, 2009 and 2008	4

	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2009 and 2008	5

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008	6

	Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2009 and 2008	7

	Notes to Consolidated Financial Statements	8

	Report of Independent Registered Public Accounting Firm	23

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32

Item 4.	Controls and Procedures	32

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 4.	Submission of Matters to a Vote of Security Holders	33

Item 6.	Exhibits	35

	Signatures	36

PART I. FINANCIAL INFORMATION

XTO ENERGY INC.

Consolidated Balance Sheets


	June 30, 2009			December 31, 2008
*(in millions, except shares)*	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	7		$	25
Accounts receivable, net		850			1,217
Derivative fair value		1,312			2,735
Current income tax receivable		—			57
Other		178			224

Total Current Assets		2,347			4,258

Property and Equipment, at cost – successful efforts method:
Proved properties		32,840			30,994
Unproved properties		3,770			3,907
Other		2,647			2,239

Total Property and Equipment		39,257			37,140
Accumulated depreciation, depletion and amortization		(7,289	)		(5,859	)

Net Property and Equipment		31,968			31,281

Other Assets:
Derivative fair value		565			1,023
Acquired gas gathering contracts, net of accumulated amortization		101			105
Goodwill		1,453			1,447
Other		145			140

Total Other Assets		2,264			2,715

TOTAL ASSETS	$	36,579		$	38,254

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,405		$	1,912
Payable to royalty trusts		20			13
Derivative fair value		236			35
Deferred income tax payable		709			940
Current income tax payable		9			—
Other		34			30

Total Current Liabilities		2,413			2,930

Long-term Debt		10,364			11,959

Other Liabilities:
Derivative fair value		9			—
Deferred income taxes payable		5,345			5,200
Asset retirement obligation		756			735
Other		92			83

Total Other Liabilities		6,202			6,018

Commitments and Contingencies (Note 4)
Stockholders’ Equity:
Common stock ($.01 par value, 1,000,000,000 shares authorized, 585,940,305 and 585,094,847 shares issued)		6			6
Additional paid-in capital		8,405			8,315
Treasury stock, at cost (5,801,789 and 5,563,247 shares)		(154	)		(147	)
Retained earnings		7,425			6,588
Accumulated other comprehensive income (loss)		1,918			2,585

Total Stockholders’ Equity		17,600			17,347

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	36,579		$	38,254

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Income Statements (Unaudited)


*(in millions, except per share data)*	Three Months Ended June 30					Six Months Ended June 30
*(in millions, except per share data)*	2009		2008			2009		2008
REVENUES
Gas and natural gas liquids	$	1,563	$	1,473		$	3,054	$	2,747
Oil and condensate		675		424			1,293		803
Gas gathering, processing and marketing		27		40			81		60
Other		8		(1	)		6		(1	)

Total Revenues		2,273		1,936			4,434		3,609

EXPENSES
Production		247		215			503		408
Taxes, transportation and other		167		194			328		348
Exploration		20		14			54		32
Depreciation, depletion and amortization		783		413			1,482		796
Accretion of discount in asset retirement obligation		10		7			20		14
Gas gathering and processing		29		24			58		45
General and administrative		98		89			195		178
Derivative fair value (gain) loss		21		(26	)		15		(42	)

Total Expenses		1,375		930			2,655		1,779

OPERATING INCOME		898		1,006			1,779		1,830

OTHER EXPENSE
Interest expense, net		126		102			252		193

INCOME BEFORE INCOME TAX		772		904			1,527		1,637

INCOME TAX EXPENSE
Current		124		105			242		220
Deferred		152		224			303		377

Total Income Tax Expense		276		329			545		597

NET INCOME	$	496	$	575		$	982	$	1,040

EARNINGS PER COMMON SHARE
Basic	$	0.86	$	1.12		$	1.69	$	2.06

Diluted	$	0.85	$	1.11		$	1.68	$	2.03

DIVIDENDS DECLARED PER COMMON SHARE	$	0.125	$	0.12		$	0.25	$	0.24

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Statements of Comprehensive Income (Unaudited)


*(in millions)*	Three Months Ended June 30						Six Months Ended June 30
*(in millions)*	2009			2008			2009			2008
Net Income	$	496		$	575		$	982		$	1,040

Other comprehensive income (loss):
Change in hedge derivative fair value		(253	)		(1,516	)		1,110			(2,380	)
Realized (gain) loss on hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income (loss)		(1,134	)		430			(2,161	)		484

Net unrealized hedge derivative loss		(1,387	)		(1,086	)		(1,051	)		(1,896	)
Income tax benefit		507			397			384			693

Total other comprehensive loss		(880	)		(689	)		(667	)		(1,203	)

Total comprehensive (loss) income	$	(384	)	$	(114	)	$	315		$	(163	)

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)


*(in millions)*	Six Months Ended June 30
*(in millions)*	2009			2008
OPERATING ACTIVITIES
Net income	$	982		$	1,040
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		1,482			796
Accretion of discount in asset retirement obligation		20			14
Non-cash incentive compensation		82			73
Dry hole expense		30			2
Deferred income tax		303			377
Non-cash derivative fair value (gain) loss		107			(49	)
Gain on extinguishment of debt		(17	)		—
Other non-cash items		(14	)		4
Changes in operating assets and liabilities (a)		1,338			(161	)

Cash Provided by Operating Activities		4,313			2,096

INVESTING ACTIVITIES
Proceeds from sale of property and equipment		2			—
Property acquisitions		(148	)		(3,020	)
Development costs, capitalized exploration costs and dry hole expense		(1,904	)		(1,536	)
Other property and asset additions		(381	)		(349	)

Cash Used by Investing Activities		(2,431	)		(4,905	)

FINANCING ACTIVITIES
Proceeds from long-term debt		4,131			6,783
Payments on long-term debt		(5,706	)		(5,101	)
Dividends		(142	)		(120	)
Debt costs		(2	)		(17	)
Net proceeds from common stock offering		—			1,224
Proceeds from exercise of stock options and warrants		6			21
Payments upon exercise of stock options		(2	)		(68	)
Excess tax benefit on exercise of stock options or vesting of stock awards		4			64
Other, primarily (decrease) increase in cash overdrafts		(189	)		72

Cash (Used) Provided by Financing Activities		(1,900	)		2,858

(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(18	)		49
Cash and Cash Equivalents, Beginning of Period		25			—

Cash and Cash Equivalents, End of Period	$	7		$	49

(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	373		$	(538	)
Other current assets		115			11
Other operating assets and liabilities		(19	)		1
Current liabilities		(85	)		365
Change in current assets from early settlement of hedges, net of amortization		954			—

	$	1,338		$	(161	)

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, 2008	$	6	$	8,315	$	(147	)	$	6,588		$	2,585		$	17,347
Net income		—		—		—			982			—			982
Other comprehensive income (loss)		—		—		—			—			(667	)		(667	)
Issuance/vesting of stock awards, including income tax benefits		—		53		(7	)		—			—			46
Expensing of stock options		—		31		—			—			—			31
Stock option and warrant exercises, including income tax benefits		—		6		—			—			—			6
Common stock dividends ($0.25 per share)		—		—		—			(145	)		—			(145	)

Balances, June 30, 2009	$	6	$	8,405	$	(154	)	$	7,425		$	1,918		$	17,600


Balances, December 31, 2007	$	5	$	3,172	$	(134	)	$	4,938		$	(40	)	$	7,941
Net income		—		—		—			1,040			—			1,040
Other comprehensive income (loss)		—		—		—			—			(1,203	)		(1,203	)
Issuance/vesting of stock awards, including income tax benefits		—		30		—			—			—			30
Expensing of stock options		—		43		—			—			—			43
Stock option and warrant exercises, including income tax benefits		—		22		—			—			—			22
Common stock offering		—		1,224		—						—			1,224
Common stock dividends ($0.24 per share)		—		—		—			(123	)		—			(123	)

Balances, June 30, 2008	$	5	$	4,491	$	(134	)	$	5,855		$	(1,243	)	$	8,974

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, 2008, 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 June 30, 2009, our income and comprehensive income for the three and six months ended June 30, 2009 and 2008 and cash flows and stockholders’ equity for the six months ended June 30, 2009 and 2008. 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- and six-month periods ended June 30, 2009 and 2008 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 2008 Annual Report on Form 10-K.

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 $140 million at June 30, 2009 and $182 million at December 31, 2008.

Our effective income tax rates for the three- and six- month periods ended June 30, 2009 and 2008 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 of amounts expensed in the financial statements. This benefit, which is recorded in additional paid-in capital, was $5 million for the first six months of 2009 and $69 million for the first six months of 2008.

Accounting Pronouncements

In May 2009, SFAS No. 165, Subsequent Events, was issued. SFAS No. 165 provides guidance to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS No. 165 is effective for interim and annual periods ending after June 15, 2009, and accordingly, we adopted this Standard during the second quarter of 2009. We have evaluated subsequent events through August 5, 2009.

In December 2008, the Securities and Exchange Commission (SEC) released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but is not expected to have a significant effect on our current or prior financial position or earnings.

2. 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 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 the asset retirement obligation activity for the six months ended June 30, 2009:


*(in millions)*
Asset retirement obligation, December 31, 2008	$	759
Revision in estimated cash flows		(7	)
Liability incurred upon acquiring and drilling wells		30
Liability settled upon plugging and abandoning wells		(17	)
Accretion of discount expense		20

Asset retirement obligation, June 30, 2009		785
Less current portion		(29	)

Asset retirement obligation, long-term	$	756

3. Long-term Debt

Our long-term debt consists of the following:


*(in millions)*	June 30, 2009			December 31, 2008
Bank debt:
Commercial paper, 0.6% at June 30, 2009 and 3.0% at December 31, 2008	$	500		$	72
Revolving credit agreement due April 1, 2013, 2.4% at December 31, 2008		—			1,825
Term loan due April 1, 2013, 0.7% at June 30, 2009 and 1.9% at December 31, 2008		500			500
Term loan due February 5, 2013, 0.7% at June 30, 2009 and 2.3% at December 31, 2008		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			350
5.30%, due June 30, 2015		400			400
5.65%, due April 1, 2016		400			400
6.25%, due August 1, 2017		735			750
5.50%, due June 15, 2018		773			800
6.50%, due December 15, 2018		1,000			1,000
6.10%, due April 1, 2036		591			600
6.75%, due August 1, 2037		1,399			1,450
6.375%, due June 15, 2038		704			800
Net discount on senior notes		(36	)		(38	)

Total long-term debt	$	10,364		$	11,959

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 June 30, 2009, excluding net discounts, are as follows:


*(in millions)*
2009	$	—
2010		250
2011		—
2012		900
2013		2,400
Remaining		6,850

Total	$	10,400

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 June 30, 2009, borrowings were $500 million at a weighted average interest rate of 0.6%.

Bank Debt

On June 30, 2009, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $2.34 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 the one-month LIBOR plus 0.40%. When utilization of available commitments is greater than 50%, 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 $300 million. As of June 30, 2009, there were no borrowings under these lines.

Repurchase of Senior Notes

In first quarter 2009, we repurchased $114 million total face amount of senior notes, including $2 million of our 5.0% senior notes due 2015, $15 million of our 6.25% senior notes due 2017, $27 million of our 5.5% senior notes due 2018, $5 million of our 6.1% senior notes due 2036, $51 million of our 6.75% senior notes due 2037 and $14 million of our 6.375% senior notes due 2038. In connection with these repurchases, we recognized a $9 million gain on extinguishment of debt in the first quarter 2009, net of unamortized discounts and the write-off of deferred debt offering costs.

In April 2009, we repurchased an additional $86 million total face amount of senior notes, including $4 million of our 6.1% senior notes due 2036 and $82 million of our 6.375% senior notes due 2038. In connection with these additional repurchases, we recognized an $8 million gain on extinguishment of debt in the second quarter 2009, net of unamortized discounts and the write-off of deferred offering costs. These gains were netted against interest expense in the consolidated income statements.

4. Commitments and Contingencies

Litigation

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al. , was filed in the U.S. District Court for the Western District of Oklahoma 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. 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 the plaintiff 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 the plaintiff’s royalty valuation claims, and the plaintiff’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 the plaintiff 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. The plaintiff filed an appeal of this decision to the United States Tenth Circuit Court of Appeals. In March 2009, the Tenth Circuit affirmed the trial court’s dismissal of the case but reversed and remanded the carbon dioxide portion of the case to the trial court. The plaintiff is seeking review of the Tenth Circuit’s decision with the United States Supreme Court. 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 September 2008, we acquired Hunt Petroleum Corporation and other associated entities. One of the entities that we acquired owns properties that are subject to a lawsuit styled USA ex rel. Grynberg v. Columbia Gas Transmission Company, et al. This lawsuit is one of the lawsuits that were filed by Jack J. Grynberg and that were consolidated in the United States District Court of Wyoming. The issues and disposition are the same as those discussed in the Grynberg action against XTO Energy described above except that Hunt Petroleum did not have a carbon dioxide related claim against it. 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 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 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 its 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, 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 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 and denied all claims. 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 its 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 June 30, 2009, maximum commitments under our transportation contracts were as follows:


*(in millions)*
2009	$	70
2010		150
2011		161
2012		162
2013		156
Remaining		594

Total	$	1,293

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. Upon the pipeline’s completion in third quarter 2009, we will transport gas volumes for a minimum transportation fee of $2 million per month plus fuel not to exceed 1.2% of the sales price, depending on receipt point and other conditions.

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 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 June 30, 2009, we have contracts with various drilling contractors to use 53 drilling rigs with terms of up to three years and minimum future commitments of $104 million in 2009, $86 million in 2010, $22 million in 2011 and $1 million in 2012. Early termination of these contracts at June 30, 2009 would have required us to pay maximum penalties of $117 million. Based upon our planned drilling activities, we do not expect to pay significant early termination penalties.

See Note 6 regarding commodity sales commitments.

5. 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 until the physical delivery occurs. Most of our derivative contracts are designated as cash flow hedges for hedge accounting purposes. At June 30, 2009, certain crude oil swap agreements and 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, as well as any deferred gain or loss realized upon early termination of effective hedge derivatives, are recorded as a component of accumulated other comprehensive income (loss). When the hedged transaction occurs, the realized gain or loss, as well as any deferred 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, gas and natural gas liquids revenues, and realized gains and losses on interest hedge derivatives are recorded as adjustments to interest expense.

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


	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
*(in millions)*	June 30, 2009		December 31, 2008		June 30, 2009		December 31, 2008
Derivatives designated as hedging instruments under SFAS 133:
Natural gas futures and basis swaps	$	1,297	$	1,917	$	(20)	$	(17)
Crude oil futures and differential swaps		568		1,772		(188)		(12)

Total derivatives designated as hedging instruments under SFAS 133		1,865		3,689		(208)		(29)

Derivatives not designated as hedging instruments under SFAS 133:
Natural gas futures and basis swaps		12		9		(17)		(6)
Crude oil futures and differential swaps		—		60		(20)		—

Total derivatives not designated as hedging instruments under SFAS 133		12		69		(37)		(6)

Total derivatives	$	1,877	$	3,758	$	(245)	$	(35)

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


	Three Months Ended June 30
	Change in Hedge Derivative Fair Value				Realized (Gain) Loss Reclassified from OCI into Revenue *(a)*
*(in millions)*	2009		2008		2009		2008
Natural gas futures and basis swaps	$	57	$	(1,012)	$	(815)	$	277
Crude oil futures and differential swaps		(310)		(481)		(319)		143
Natural gas liquids futures		—		(23)		—		10

Total	$	(253)	$	(1,516)	$	(1,134)	$	430


	Six Months Ended June 30
	Change in Hedge Derivative Fair Value				Realized (Gain) Loss Reclassified from OCI into Revenue *(a)*
*(in millions)*	2009		2008		2009		2008
Natural gas futures and basis swaps	$	1,366	$	(1,821)	$	(1,439)	$	260
Crude oil futures and differential swaps		(256)		(536)		(722)		207
Natural gas liquids futures		—		(23)		—		17

Total	$	1,110	$	(2,380)	$	(2,161)	$	484

(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 June 30
	(Gain) Loss Recognized in Income (Non-Hedge)					(Gain) Loss Recognized in Income (Ineffective Portion)					Derivative Fair Value (Gain) Loss
*(in millions)*	2009		2008			2009			2008		2009		2008
Natural gas futures and basis swaps	$	16	$	(34	)	$	(11	)	$	6	$	5	$	(28	)
Crude oil futures and differential swaps		18		—			(2	)		1		16		1
Natural gas liquids futures		—		—			—			1		—		1

Total	$	34	$	(34	)	$	(13	)	$	8	$	21	$	(26	)


	Six Months Ended June 30
	(Gain) Loss Recognized in Income (Non-Hedge)					(Gain) Loss Recognized in Income (Ineffective Portion)					Derivative Fair Value (Gain) Loss
*(in millions)*	2009		2008			2009			2008		2009			2008
Natural gas futures and basis swaps	$	21	$	(63	)	$	(30	)	$	19	$	(9	)	$	(44	)
Crude oil futures and differential swaps		15		—			9			1		24			1
Natural gas liquids futures		—		—			—			1		—			1

Total	$	36	$	(63	)	$	(21	)	$	21	$	15		$	(42	)

Derivative Fair Value (Gain) Loss

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


*(in millions)*	Three Months Ended June 30						Six Months Ended June 30
*(in millions)*	2009			2008			2009			2008
Net cash (received from) paid to counterparties	$	(7	)	$	9		$	(92	)	$	7
Non-cash change in derivative fair value		28			(35	)		107			(49	)

Derivative fair value (gain) loss	$	21		$	(26	)	$	15		$	(42	)

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 June 30, 2009 and December 31, 2008. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:


	Asset (Liability)
	June 30, 2009						December 31, 2008
*(in millions)*	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Net derivative asset	$	1,632		$	1,632		$	3,723		$	3,723

Long-term debt	$	(10,364	)	$	(10,861	)	$	(11,959	)	$	(11,421	)

The fair value of our long-term debt is based upon current market quotes and is the estimated amount required to purchase our long-term 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, as defined by SFAS 157, Fair Value Measurements (as amended).


	Fair Value Measurements
	June 30, 2009					December 31, 2008
*(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	$	1,632	$	—		$	3,723	$	—

Asset retirement obligation	$	—	$	(785	)	$	—	$	(759	)

See Note 2 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 limit 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. Our allowance for uncollectible receivables was $14 million at June 30, 2009 and $13 million at December 31, 2008.

6. 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 may 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 2010.

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 5 regarding accounting for commodity hedges.


Production Period	Mcf per Day		Weighted Average NYMEX Price per Mcf
2009 July to December	1,745,000	(a)	$	8.79	(a)
2010 January to December	730,000		$	8.67

(a)

Includes swap agreements for 1,273,000 Mcf per day which were early settled and reset at current market prices. The price shown is the price that will be used for cash flow hedge accounting purposes and has been reduced for transaction costs related to the early settlements. The weighted average cash settlement contract price for all contracts is $6.35 per Mcf. See “Early Settlement of Hedges” below.

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)
2009	July to October	964,000	$	0.50
	November to December	775,000	$	0.60
2010	January to March	355,000	$	0.59
	April to October	310,000	$	0.39
	November to December	160,000	$	0.40
2011	January to October	60,000	$	0.28
	November to December	30,000	$	0.28
2012	January to December	50,000	$	0.27

(a)

Reductions to NYMEX gas prices for delivery location.

As of June 30, 2009, an unrealized pre-tax derivative fair value gain of $2.0 billion, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). Based on June 30 mark-to-market prices, $1.7 billion of this gain is expected to be reclassified into earnings through June 2010. The actual reclassification to earnings will be based on the amortization of the early settled hedges (see “Early Settlement of Hedges” below) and on 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 2009 and 2010 crude oil swap agreements are designated as hedges for hedge accounting purposes. See Note 5 regarding accounting for commodity hedges.


Production Period		Bbls per Day		Weighted Average NYMEX Price per Bbl
2009	July to December	62,500	(a)	$	117.11	(a)
2010	January to December	70,000		$	95.70

(a)

Includes swap agreements for 57,000 Bbls per day which were early settled and reset at current market prices. The price shown is the price that will be used for cash flow hedge accounting purposes and has been reduced for transaction costs related to the early settlements. The weighted average cash settlement contract price for all contracts is $58.64 per Bbl. See “Early Settlement of Hedges” below.

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

As of June 30, 2009, an unrealized pre-tax derivative fair value gain of $1.0 billion, related to cash flow hedges of oil price risk, was recorded in accumulated other comprehensive income (loss). Based on June 30 mark-to-market prices, $755 million of this is expected to be reclassified into earnings through June 2010. The actual reclassification to earnings will be based on the amortization of the early settled hedges (see “Early Settlement of Hedges” below) and on mark-to-market prices at the settlement date.

Early Settlement of Hedges

In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight financial counterparties covering our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after tax) which was used to reduce outstanding debt. Of this amount, $2.2 billion ($1.4 billion after tax) was received in 2009.

Transportation Contracts

In connection with our commitments under our transportation contracts (Note 4), 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)
2009	July to December	77,000	$	0.77
2010	January to March	103,000	$	0.24
	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	20,000	$	0.16
2013	January to May	20,000	$	0.16

(a)

Reductions to NYMEX gas prices for purchase location.

7. Earnings per Share

Effective January 1, 2009, we adopted the provisions of FASB Staff Position EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities . Under FSP 03-6-1, share-based payment awards that contain nonforfeitable rights to dividends, as is the case with our restricted and performance shares, are “participating securities” as defined by EITF 03-6 and therefore should be included in computing earnings per share using the two-class method. As a result of adoption, we retrospectively adjusted the calculation of our 2008 and prior earnings per share. The previously reported earnings per share for the three months ended June 30, 2008 were $1.13 basic and $1.11 diluted and for the six months ended June 30, 2008 were $2.07 basic and $2.04 diluted. The following reconciles earnings and shares used in the computation of basic and diluted earnings per common share:


	Three Months Ended June 30
*(in millions, except per share data)*	2009							2008
*(in millions, except per share data)*	Earnings			Shares		Earnings per Share		Earnings			Shares		Earnings per Share
Total	$	496		579.9				$	575		511.1
Attributable to participating securities		(4	)	(4.6	)				(3	)	(2.5	)

Basic	$	492		575.3		$	0.86	$	572		508.6		$	1.12

Effect of dilutive securities:
Stock options		—		2.6					—		6.3
Warrants		—		1.2					—		1.7

Diluted	$	492		579.1		$	0.85	$	572		516.6		$	1.11


	Six Months Ended June 30
*(in millions, except per share data)*	2009							2008
*(in millions, except per share data)*	Earnings			Shares		Earnings per Share		Earnings			Shares		Earnings per Share
Total	$	982		579.8				$	1,040		504.8
Attributable to participating securities		(8	)	(4.7	)				(5	)	(2.4	)

Basic	$	974		575.1		$	1.69	$	1,035		502.4		$	2.06

Effect of dilutive securities:
Stock options		—		2.2					—		5.8
Warrants		—		1.1					—		1.7

Diluted	$	974		578.4		$	1.68	$	1,035		509.9		$	2.03

Certain options to purchase shares of our common stock have been excluded from the 2009 diluted calculation because the options are anti-dilutive. Anti-dilutive options for 7.5 million shares in the three-month period with a weighted average exercise price of $52.60 and 7.8 million shares in the six-month period with a weighted average exercise price of $51.77 were excluded.

8. Supplemental Cash Flow Information

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


	Six Months Ended June 30
*(in millions)*	2009		2008
Interest	$	294	$	214
Income tax	$	175	$	6

The accompanying consolidated statements of cash flows exclude the following non-cash stock award transactions (Note 9) during the six-month periods ended June 30, 2009 and 2008:

•

Grants of 5,000 restricted shares, vesting of 57,000 restricted shares and forfeitures of 63,000 restricted shares in 2009. Grants of 168,000 restricted shares, vesting of 3,000 restricted shares and forfeitures of 27,000 restricted shares in 2008.

•

Grants of 369,000 performance shares and vesting of 389,000 performance shares in 2009. Grants of 490,000 performance shares in 2008.

•

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

•

Grants and immediate vesting of 25,000 unrestricted common shares to nonemployee directors in 2009 and 2008.

•

Common shares delivered or attested to in satisfaction of the exercise price of employee stock options totaled 62,000 shares at a weighted average exercise price of $41.97 per share in 2009 and 1.5 million shares at a weighted average exercise price of $56.76 per share in 2008.

9. 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- and six-month 2009 and 2008 periods:


	Three Months Ended June 30				Six Months Ended June 30
*(in millions)*	2009		2008		2009		2008
Non-cash stock option compensation expense	$	17	$	12	$	31	$	43
Non-cash performance share and unrestricted share compensation expense		9		10		18		11
Non-cash restricted stock compensation expense		16		10		33		19
Related tax benefit recorded in income statement		15		12		30		27
Intrinsic value of stock option exercises		8		21		9		198
Income tax benefit on exercise of stock options or vesting of stock awards (a)		5		7		5		69

(a)

Recorded as additional paid-in capital

During the first six months of 2009, 1.6 million stock options were granted to employees at a weighted average exercise price of $41.94 per share. Of these stock options, 375,000 vest when the stock price closes at or above $50 and 1.2 million vest ratably over three years. Of these 1.2 million shares, 400,000 have accelerated vesting when the stock price closes at or above $50 and 400,000 have accelerated vesting when the stock price closes at or above $54. A total of 431,000 stock options were exercised at a weighted average exercise price of $19.99 per share. As a result of these exercises, outstanding common stock increased by 300,000 shares and stockholders’ equity increased by a net $6 million.

In January 2009, our Chairman of the Board and Founder received 110,000 unrestricted common shares. In February 2009, 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.

In the first half of 2009, we granted 369,000 performance shares. The table below shows the number of shares and vesting prices for outstanding performance shares at June 30, 2009.


Performance Shares (in thousands)		Vesting Price
162		$46
20		$47
161		$50
245		$77
245		$85

As of June 30, 2009, nonvested stock options had remaining unrecognized compensation expense of $24 million. Total deferred compensation at June 30, 2009 related to performance shares was $2 million and related to restricted shares was $103 million. For these nonvested stock awards, we estimate that stock incentive compensation for service periods after June 30, 2009 will be $45 million in 2009, $57 million in 2010 and $27 million in 2011. The weighted average remaining vesting period is 1.0 years for stock options, 0.1 years for performance shares and 1.9 years for restricted shares.

10. Acquisitions

In September 2008, we acquired Hunt Petroleum Corporation and other associated entities for approximately $4.2 billion, funded by cash of $2.6 billion and the issuance of 23.5 million shares of common stock to the sellers valued at $1.6 billion. Hunt Petroleum owned natural gas and oil producing properties primarily concentrated in our Eastern Region, including East Texas and central and north Louisiana. The cash portion of the transaction was funded by a combination of operating cash flow, commercial paper and the August 2008 issuance of senior notes.

We believe that the overlap of Hunt Petroleum’s assets with ours, primarily in the Eastern Region, as well as the addition of new operating areas in the Gulf Coast and offshore Gulf of Mexico was a significant benefit of the Hunt acquisition. Another important contributing factor of the acquisition was the ability to secure intellectual talent to help exploit these areas as well as others.

The following is the preliminary calculation of the purchase price of Hunt Petroleum Corporation and the allocation to assets and liabilities as of September 2, 2008. The fair value of consideration issued was determined as of June 10, 2008, the date the acquisition was announced. The purchase price allocation is subject to adjustment, pending final determination of the tax bases and the fair value of certain assets acquired and liabilities assumed.


*(in millions)*
Consideration issued to Hunt owners:
23.5 million shares of common stock (at fair value of $67.95 per share)	$	1,597
Cash paid		2,589

Total purchase price		4,186
Fair value of liabilities assumed:
Current liabilities		368
Long-term debt		337
Asset retirement obligation		168
Other long-term liabilities		3
Deferred income taxes		1,059

Total purchase price plus liabilities assumed	$	6,121

Fair value of assets acquired:
Cash and cash equivalents	$	198
Other current assets		300
Proved properties		4,155
Unproved properties		160
Other property and equipment		70
Goodwill (non-deductible for income taxes)		1,238

Total fair value of assets acquired	$	6,121

The acquisition was recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for the six months ended June 30, 2008 and the year ended December 31, 2008, as if the Hunt acquisition was made at the beginning of each period. These pro forma results are not necessarily indicative of future results.


	Pro Forma (Unaudited)
*(in millions, except per share data)*	Six Months Ended June 30, 2008		Year Ended December 31, 2008
Revenues	$	4,194	$	8,450

Net Income	$	1,199	$	2,090

Earnings per common share:
Basic	$	2.27	$	3.80

Diluted	$	2.24	$	3.76

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 June 30, 2009, the related consolidated statements of income and comprehensive income for the three- and six-month periods ended June 30, 2009 and 2008, and the related consolidated statements of cash flow and stockholders’ equity for the six-month periods ended June 30, 2009 and 2008. 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, 2008, 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 2008 Annual Report on Form 10-K, and in our report dated February 25, 2009, 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, 2008 is fairly stated, in all material respects, in relation to the consolidated balance sheet included in the Company’s 2008 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Fort Worth, Texas

August 5, 2009

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 2008 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 June 30						Six Months Ended June 30
	2009		2008		Increase (Decrease)		2009		2008		Increase (Decrease)
Total production
Gas (Mcf)		214,024,222		163,383,624	31	%		414,526,125		318,775,828	30	%
Natural gas liquids (Bbls)		1,885,804		1,417,208	33	%		3,533,082		2,870,809	23	%
Oil (Bbls)		6,296,297		4,666,351	35	%		12,202,911		9,356,447	30	%
Mcfe		263,116,828		199,884,978	32	%		508,942,083		392,139,364	30	%

Average daily production
Gas (Mcf)		2,351,915		1,795,424	31	%		2,290,200		1,751,516	31	%
Natural gas liquids (Bbls)		20,723		15,574	33	%		19,520		15,774	24	%
Oil (Bbls)		69,190		51,279	35	%		67,419		51,409	31	%
Mcfe		2,891,394		2,196,538	32	%		2,811,835		2,154,612	31	%

Average sales price
Gas per Mcf	$	7.08	$	8.51	(17	)%	$	7.16	$	8.11	(12	)%
Natural gas liquids per Bbl	$	25.52	$	58.87	(57	)%	$	24.74	$	55.88	(56	)%
Oil per Bbl	$	107.14	$	90.89	18	%	$	105.90	$	85.80	23	%

Average sales price before hedging
Gas per Mcf	$	3.24	$	10.20	(68	)%	$	3.68	$	8.93	(59	)%
Natural gas liquids per Bbl	$	25.52	$	65.89	(61	)%	$	24.74	$	61.57	(60	)%
Oil per Bbl	$	56.42	$	121.46	(54	)%	$	46.72	$	107.90	(57	)%

Average NYMEX prices
Gas per MMBtu	$	3.50	$	10.92	(68	)%	$	4.19	$	9.48	(56	)%
Oil per Bbl	$	59.83	$	124.28	(52	)%	$	51.51	$	110.98	(54	)%

Bbl—Barrel

Mcf—Thousand cubic feet

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

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

Production increases from 2008 to 2009 for the three- and six-month periods are primarily because of development activity and acquisitions, partially offset by natural decline.

Gas prices decreased from 2008 to 2009. 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 other energy sources as fuel for heating and the generation of electricity. In the first half of 2008, prices for natural gas increased significantly reaching as high as $13 per MMBtu in July 2008. Since that date, prices have dropped due to higher than average gas in storage caused by shale gas development and declining demand due to the U.S. recession. Natural gas prices are expected to remain volatile. The NYMEX contract price for July 2009 was $3.95 per MMBtu. At July 31, 2009, the average NYMEX futures price for the following twelve months was $5.27 per MMBtu.

Oil prices before hedging and average NYMEX oil prices decreased from 2008 to 2009. Crude oil prices are generally determined by global supply and demand. In the first half of 2008, prices for oil increased significantly reaching a record high above $147 per Bbl in July 2008. However, lower demand as a result of the global economic situation caused oil prices to decline to below $40 last winter. Signs of possible economic improvement have resulted in higher recent oil prices. Oil prices are expected to remain volatile. The average NYMEX price for July 2009 was $64.44 per Bbl. At July 31, 2009, the average NYMEX futures price for the following twelve months was $74.42 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 2010; see Note 6 to Consolidated Financial Statements.

Results of Operations

Quarter Ended June 30, 2009 Compared with Quarter Ended June 30, 2008

Net income for second quarter 2009 was $496 million compared to $575 million for second quarter 2008. Second quarter 2009 earnings include a $28 million ($18 million after tax) non-cash derivative fair value loss and an $8 million ($5 million after tax) gain on extinguishing of debt. Second quarter 2008 earnings include a $35 million ($22 million after tax) non-cash derivative fair value gain.

Total revenues for second quarter 2009 were $2.27 billion, a 17% increase from second quarter 2008 revenues of $1.94 billion. Operating income for the quarter was $898 million, an 11% decrease from second quarter 2008 operating income of $1.01 billion. Gas and natural gas liquids revenues increased $90 million because of the 31% increase in gas production and the 33% increase in natural gas liquids production, partially offset by the 17% decrease in gas prices and the 57% decrease in natural gas liquids prices. Oil revenue increased $251 million because of the 35% increase in production and the 18% increase in oil prices.

Expenses for second quarter 2009 totaled $1.38 billion, a 48% increase from second quarter 2008 expenses of $930 million. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $32 million primarily because of increased overall production, partially offset by decreased power, fuel and carbon dioxide injection costs. Taxes, transportation and other decreased $27 million from the second quarter of 2008 primarily because of lower production taxes and transportation costs due to lower product prices before hedging, partially offset by higher property taxes related to development and the 2008 acquisitions. Depreciation, depletion and amortization increased $370 million because of increased production and higher acquisition, development and facility costs. Exploration expense increased $6 million primarily because of increased dry hole expense. General and administrative expense increased $9 million primarily because of a $10 million increase in non-cash incentive award compensation.

The derivative fair value loss for second quarter 2009 was $21 million compared to a gain of $26 million in the same 2008 period. The loss in 2009 is primarily related to certain crude oil swap agreements and natural gas basis swap agreements that do not qualify for hedge accounting. See Note 5 to Consolidated Financial Statements.

Interest expense increased $24 million primarily because of a 25% increase in weighted average borrowings incurred primarily to fund our 2008 acquisitions, partially offset by an $8 million gain on extinguishment of debt. The effective income tax rate for second quarter 2009 was 35.8% compared with 36.4% for second quarter 2008. The lower effective income tax rate in 2009 is due to the expected benefits of permanent tax differences.

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

Net income for the six months ended June 30, 2009 was $982 million, compared to $1.04 billion for the same 2008 period. Earnings for the first half of 2009 include a $107 million ($69 million after tax) non-cash derivative fair value loss and a $17 million ($11 million after tax) gain on extinguishment of debt. Earnings for the first six months of 2008 include a $49 million ($31 million after tax) non-cash derivative fair value gain.

Total revenues for the first half of 2009 were $4.43 billion, 23% higher than revenues of $3.61 billion for the first half of 2008. Operating income for the first half of 2009 was $1.78 billion, a 3% decrease from operating income of $1.83 billion for the comparable 2008 period. Gas and natural gas liquids revenues increased $307 million primarily because of the 30% increase in gas production and the 23% increase in natural gas liquids production, partially offset by the 12% decrease in gas prices and the 56% decrease in natural gas liquids prices. Oil revenue increased $490 million because of the 30% increase in production and the 23% increase in oil prices.

Expenses for the first half of 2009 totaled $2.66 billion, a 49% increase from total expenses for the first half of 2008 of $1.78 billion. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $95 million primarily because of increased production and increased maintenance costs, partially offset by lower power, fuel and decreased carbon dioxide injection costs. Taxes, transportation and other decreased $20 million primarily because of lower production taxes and transportation costs due to lower product prices before hedging, partially offset by higher property taxes related to development and the 2008 acquisitions. Depreciation, depletion and amortization increased $686 million because of increased production and higher acquisition, development and facility costs. General and administrative expense increased $17 million because of a $9 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 loss for the first six months of 2009 was $15 million compared to a gain of $42 million in the same 2008 period. The loss in 2009 is primarily related to the loss on certain crude oil swap agreements that do not qualify for hedge accounting. See Note 5 to Consolidated Financial Statements.

Interest expense increased $59 million primarily because of a 38% increase in the weighted average borrowings incurred primarily to fund our 2008 acquisitions, partially offset by a $17 million gain on extinguishment of debt. The 2009 year-to-date effective income tax rate was 35.7% compared with a 36.4% effective rate for the six-month 2008 period. The lower effective income tax rate in 2009 is due to the expected benefits of permanent tax differences.

Comparative Expenses per Mcf Equivalent Production

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


	Three Months Ended June 30						Six Months Ended June 30
	2009		2008		Increase (Decrease)		2009		2008		Increase (Decrease)
Production	$	0.94	$	1.08	(13	)%	$	0.99	$	1.04	(5	)%
Taxes, transportation and other		0.64		0.97	(34	)%		0.65		0.89	(27	)%
Depreciation, depletion and amortization (DD&A)		2.98		2.07	44	%		2.91		2.03	43	%
General and administrative (G&A):
Non-cash stock incentive compensation		0.16		0.16	—	%		0.16		0.19	(16	)%
All other G&A		0.21		0.29	(28	)%		0.22		0.27	(19	)%
Interest		0.48		0.51	(6	)%		0.50		0.49	2	%

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

Production expenses —Decreased production expense is primarily because of decreased power, fuel, carbon dioxide injection and water disposal costs. In the first half of 2009, these decreases were partially offset by higher maintenance costs.

Taxes, transportation and other —A portion of these expenses vary with product prices. Decreased taxes, transportation and other expense is primarily because of lower product prices, before hedging, partially offset by higher property taxes primarily due to development and the 2008 acquisitions.

DD&A —Increased DD&A is primarily because of higher acquisition, development and infrastructure costs per Mcfe as well as the effect of net downward revisions to proved oil and gas reserves due to lower commodity prices.

G&A —Decreased stock incentive compensation for the six-month period is due to increased production outpacing non-cash incentive compensation. All other G&A expense decreased because of increased production outpacing personnel and other expenses related to Company growth.

Interest —Interest expense decreased slightly for the quarter and increased slightly for the six months because the increase in weighted average borrowings to fund our 2008 acquisitions was offset by increased production and a gain on extinguishment of debt of $8 million in second quarter 2009 and $17 million in the first half of 2009.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $4.31 billion for the first six months of 2009, compared with $2.10 billion for the same 2008 period. Increased cash provided by operating activities is due in part to production from development activity and acquisitions. Also, 2009 benefited from the early settlement and reset arrangements with seven of our financial counterparties. 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. This has been partially offset by the amortization of these early settlements to oil and gas revenue. Cash provided by operating activities was increased by changes in operating assets and liabilities of $1.34 billion in first half 2009 and decreased by $161 million in first half 2008. Changes in operating assets and liabilities are primarily the result of the timing of cash receipts and disbursements. Cash flow from operating activities was also reduced by exploration expense, excluding dry hole expense, of $24 million in first half 2009 and $30 million in first half 2008.

During the six months ended June 30, 2009, cash provided by operating activities of $4.31 billion was used to fund net property acquisitions, development costs and other net capital additions of $2.43 billion, dividends of $142 million and to pay down $1.58 billion of debt. The resulting decrease in cash and cash equivalents for the period was $18 million.

Total current assets decreased $1.91 billion during the first half of 2009 primarily because of a $1.42 billion decrease in derivative fair value as a result of early cash settlements of derivatives during the period and decreased accounts receivable due to lower product prices, excluding hedges. Total current liabilities decreased $517 million during the first half of 2009 primarily because of decreased accounts payable and accrued liabilities due to lower commodity prices, excluding hedges, and lower drilling activity.

Working capital decreased from a positive position of $1.33 billion at December 31, 2008 to a negative position of $66 million at June 30, 2009. Excluding the effects of derivative fair value and deferred tax current liabilities, working capital was effectively flat with a negative position of $432 million at December 31, 2008 and

a negative position of $433 million at June 30, 2009. 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 six months of 2009 were $1.93 billion compared with $1.57 billion for the first six months of 2008. Our 2009 development and exploration budget has been increased to $3.1 billion and our budget for construction of pipeline infrastructure and compression and processing facilities has been increased to $500 million. 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 half 2009, we completed acquisitions of both producing and unproved properties for $148 million compared to $3.02 billion for first half of 2008. 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 2009, as a course of business, we 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 six months of 2009, we participated in drilling approximately 508 gas wells and 35 oil wells and performed 67 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

We have unsecured and uncommitted lines of credit with commercial banks totaling $300 million. As of June 30, 2009, there were no borrowings under these lines.

Repurchase of Senior Notes

Common Stock Dividends

In May 2009, the Board of Directors declared a second quarter 2009 dividend of $0.125 per share that was paid in July to stockholders of record on June 30, 2009.

Contractual Obligations and Commitments

The following summarizes our significant obligations and commitments to make future contractual payments as of June 30, 2009. 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.


*(in millions)*	Total		Payments Due by Year
*(in millions)*	Total		2009		2010		2011		2012		2013		After 2013
Long-term debt	$	10,400	$	—	$	250	$	—	$	900	$	2,400	$	6,850
Operating leases		90		16		28		22		13		7		4
Drilling contracts		213		104		86		22		1		—		—
Purchase commitments		36		36		—		—		—		—		—
Transportation contracts		1,293		70		150		161		162		156		594
Derivative contract liabilities at June 30, 2009 fair value		245		229		15		1		—		—		—

Total	$	12,277	$	455	$	529	$	206	$	1,076	$	2,563	$	7,448

Long-Term Debt. Long-term debt amounts represent scheduled maturities of our debt obligations at June 30, 2009, excluding $36 million of net discounts on our senior notes included in the carrying value of debt. At June 30, 2009, borrowings were $500 million under our commercial paper program. Because we had the intent and ability to refinance the balance due with borrowings under our credit facility due in April 2013, the $500 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 long-term debt, see Note 3 to Consolidated Financial Statements.

Drilling Contracts. We have contracts with various drilling contractors to use 53 drilling rigs with terms of up to three years. Early termination of these contracts at June 30, 2009 would have required us to pay maximum penalties of $117 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.

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 oil and natural gas 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 June 30, 2009, the current liability related to such contracts was $236 million and the noncurrent liability was $9 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts are 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 5 to Consolidated Financial Statements.

Accounting Pronouncements

requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but is not expected to have a significant effect on our current or prior 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, the impact of various accounting pronouncements 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, 2008, 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 2008 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

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

Interest Rate Risk

We are exposed to interest rate risk on debt with variable interest rates. At June 30, 2009, our variable rate debt had a carrying value of $1.10 billion, which approximated its fair value, and our fixed rate debt had a carrying value of $9.26 billion and an approximate fair value liability of $9.76 billion. Assuming a one percent, or 100-basis point, change in interest rates at June 30, 2009, the fair value of our fixed rate debt would change by approximately $715 million.

Commodity Price Risk

We hedge a portion of our price risks associated with our natural gas and crude oil sales. As of June 30, 2009, our outstanding futures contracts and swap agreements had a net fair value gain of $1.63 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 June 30, 2009. 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	$	1,266	$	267
Natural gas purchase basis swap agreements		6		2
Crude oil futures and differential swaps		360		269

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 March 31, 2005, the Division of Air Quality of the Department of Environmental Conservation of the State of Alaska issued us a Notice of Violation regarding nitrogen oxide emissions from one of our cranes that exceed the limitations of our operational permit for one of our platforms in the Cook Inlet of Alaska. In February 2006, the Division of Air Quality proposed a fine of less than $100,000. On February 1, 2008, the Division of Air Quality issued us a Notice of Violation for leaving a portable diesel engine on one of our platforms for longer than permitted, even though the engine did not operate except for one hour of maintenance time. In June 2009, we paid a fine of $85,192 for these violations.

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, 2008.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following summarizes purchases of our common stock during second quarter 2009:


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
April	—		$	—	—
May	199,748		$	42.17	—
June	—		$	—	—

Total	199,748	(2 )	$	42.17	—	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 25,000,000 shares of the Company’s common stock.

(2)

Does not include performance or restricted share forfeitures. Includes 62,166 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 137,582 shares of common stock purchased during the quarter from employees in connection with the settlement of income tax withholding obligations upon vesting of restricted shares and performance shares under the 2004 Stock Incentive Plan. These share purchases were not part of a publicly announced program to purchase common stock.

Item 3.

Not applicable.

Item 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The 2009 Annual Meeting of Stockholders of the Company was held on May 19, 2009. A total of 477,689,932 of the Company’s shares of common stock were present in person or represented by proxy at the meeting. This represented 82.4% of the Company’s outstanding shares at March 31, 2009, the record date for the meeting.

The stockholders approved the amendment to the Company’s Bylaws with the affirmative vote of 99.45% of the shares entitled to vote, present in person or represented by proxy at the meeting. There were 475,045,441 votes for, 2,327,049 votes against and 317,441 votes abstaining on this matter.

The individuals listed below were elected as Class B directors to serve a two-year term based on the following tabulations:


Name	For	Against	Abstain
Phillip R. Kevil	458,744,242	18,343,902	601,788
Herbert D. Simons	312,309,895	162,596,943	2,783,093
Vaughn O. Vennerberg III	453,551,398	23,622,624	515,909

Other directors continuing in office are William H. Adams III, Lane G. Collins, Keith A. Hutton, Jack P. Randall, Scott G. Sherman and Bob R. Simpson. Louis G. Baldwin, Timothy L. Petrus and Gary D. Simpson continue to serve as non-voting advisory directors.

The stockholders approved the XTO Energy Inc. 2009 Executive Incentive Compensation Plan with the affirmative vote of 92.90% of the shares entitled to vote, present in person or represented by proxy at the meeting. There were 443,729,175 votes for, 31,708,802 votes against and 2,251,955 votes abstaining on this matter.

The stockholders ratified the appointment of KPMG LLP as the Company’s independent auditor for 2009 with the affirmative vote of 99.20% of the shares entitled to vote, present in person or represented by proxy at the meeting. There were 473,863,240 votes for, 3,394,764 votes against and 431,927 votes abstaining on this matter.

The stockholders approved a stockholder proposal concerning a stockholder advisory vote on executive compensation with the affirmative vote of 51.06% of the shares entitled to vote, present in person or represented by proxy at the meeting. There were 216,630,644 votes for, 204,359,057 votes against and 3,278,821 votes abstaining on this matter.

The stockholders did not approve a stockholder proposal concerning stockholder approval of executive benefits payable upon death with the proposal receiving the affirmative vote of 49.29% of the shares entitled to vote, present in person or represented by proxy at the meeting. There were 209,117,584 votes for, 205,281,386 votes against and 9,869,552 votes abstaining on this matter.

Item 5.

Not applicable.

Item 6.

EXHIBITS


Exhibit Number and Description
3.1		Amended and Restated Bylaws of XTO Energy Inc. as of May 19, 2009 (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 22, 2009)

10.1*		XTO Energy Inc. 2009 Executive Incentive Compensation Plan (incorporated by reference to Appendix C to the Proxy Statement dated April 17, 2009 for the Annual Meeting of Stockholders held May 19, 2009)

11		Computation of per share earnings (included in Note 7 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

101		The following financial statements from XTO Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, filed on August 6, 2009, 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.

Management contract or compensatory plan

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.


	XTO ENERGY INC.

Date: August 5, 2009	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
3.1	Amended and Restated Bylaws of XTO Energy Inc. as of May 19, 2009 (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 22, 2009)

10.1*	XTO Energy Inc. 2009 Executive Incentive Compensation Plan (incorporated by reference to Appendix C to the Proxy Statement dated April 17, 2009 for the Annual Meeting of Stockholders held May 19, 2009)

11	Computation of per share earnings (included in Note 7 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 June 30, 2009, filed on August 6, 2009, 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.