Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended ~~September 30~~March 31, ~~2009~~2010

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

Commission File Number: 1-10662

XTO Energy Inc.

(Exact name of registrant as specified in its charter)


Delaware		75-2347769
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

(817) 870-2800

(Registrant’s telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if change since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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


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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Class		Outstanding as of ~~October~~April 30, ~~2009~~2010
Common stock, $.01 par value		~~580~~584,~~337~~360,~~963~~301

XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended ~~September~~March 3031, ~~2009~~2010

TABLE OF CONTENTS

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets at September 30, 2009 and December 31, 2008	3
	Consolidated Balance Sheets at March 31, 2010 and December 31, 2009	3
	Consolidated Income Statements for the Three and Nine Months Ended September 30, 2009 and 2008	4
	Consolidated Income Statements for the Three Months Ended March 31, 2010 and 2009	4
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2009 and 2008	5
	Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2010 and 2009	5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008	6
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	6
	Consolidated Statements of Stockholders’ Equity for the Nine Months Ended September 30, 2009 and 2008	7
	Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2010 and 2009	7
	Notes to Consolidated Financial Statements	8
	Report of Independent Registered Public Accounting Firm	2320
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2421
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3228
Item 4.	Controls and Procedures	3228
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	3329
Item 1A.	Risk Factors	3330
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3431
Item 6.	Exhibits	3532
	Signatures	3633

PART I. FINANCIAL INFORMATION

XTO ENERGY INC.

Consolidated Balance Sheets

	September 30,2009			December 31,2008
	March 31,2010			December 31,2009
(in millions, except shares)	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	2433		$	259
Accounts receivable, net		~~813~~1,050			~~1,217~~965
Derivative fair value		1,~~226~~451			21,~~735~~222
Current income tax receivable		41101			57170
Other		~~189~~185			~~224~~182
Total Current Assets		2,~~293~~820			42,~~258~~548
Property and Equipment, at cost – successful efforts method:
Proved properties		3335,~~560~~002			3034,~~994~~180
Unproved properties		3,~~740~~435			3,~~907~~691
Other		2,~~712~~878			2,~~239~~810
Total Property and Equipment		4041,~~012~~315			3740,~~140~~681
Accumulated depreciation, depletion and amortization		(89,~~094~~318	)		(58,~~859~~747	)
Net Property and Equipment		31,~~918~~997			31,~~281~~934
Other Assets:
Derivative fair value		~~262~~117			~~1,023~~68
Acquired gas gathering contracts, net of accumulated amortization		9996			~~105~~97
Goodwill		1,475			1,~~447~~475
Other		~~138~~137			~~140~~133
Total Other Assets		1,~~974~~825			21,~~715~~773
TOTAL ASSETS	$	36,~~185~~642		$	3836,~~254~~255
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,~~421~~445		$	1,~~912~~482
Payable to royalty trusts		2131			1328
Current maturities of long-term debt		250			—250
Derivative fair value		~~186~~158			35167
Deferred income tax payable		~~443~~424			~~940~~342
Other		4736			3032
Total Current Liabilities		2,~~368~~344			2,~~930~~301
Long-term Debt		109,~~135~~955			1110,~~959~~237
Other Liabilities:
Derivative fair value		527			—6
Deferred income taxes payable		5,~~404~~650			5,~~200~~522
Asset retirement obligation		~~771~~813			~~735~~783
Other		7972			8380
Total Other Liabilities		6,~~306~~542			6,~~018~~391
Commitments and Contingencies (Note 4)
Commitments and Contingencies (Note 5)
Stockholders’ Equity:
Common stock ($.01 par value, 1,000,000,000 shares authorized, 586,127,049 and 585,094,847 shares issued)		6			6
Common stock ($.01 par value, 1,000,000,000 shares authorized, 590,629,915 and 589,361,021 shares issued)		6			6
Additional paid-in capital		8,~~434~~517			8,~~315~~471
Treasury stock, at cost (5,819,436 and 5,563,247 shares)		(155	)		(147	)
Treasury stock, at cost (6,410,213 and 6,345,697 shares)		(179	)		(177	)
Retained earnings		78,~~853~~574			68,~~588~~317
Accumulated other comprehensive income (loss)		~~1,238~~883			~~2,585~~709
Total Stockholders’ Equity		17,~~376~~801			17,~~347~~326
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	36,~~185~~642		$	3836,~~254~~255

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Income Statements (Unaudited)

(in millions, except per share data)	Three Months EndedSeptember 30							Nine Months EndedSeptember 30
	Three Months EndedMarch 31
	2009			2008				2009		2008
(in millions, except per share data)	2010				2009
REVENUES
Gas and natural gas liquids	$	1,~~605~~448		$	~~1,586~~$	1,491		$	~~4,659~~	$	~~4,333~~
Oil and condensate		~~654~~535			~~495~~	618			~~1,947~~		~~1,298~~
Gas gathering, processing and marketing		2820			43	54			~~109~~		~~103~~
Other		1(2	)		1	(2	)		7		—
Total Revenues		2,~~288~~001			~~2,125~~	2,161			~~6,722~~		~~5,734~~
EXPENSES
Production		~~248~~255			~~262~~	256			~~751~~		~~670~~
Taxes, transportation and other		~~174~~186			~~206~~	161			~~502~~		~~554~~
Exploration		1013			30	34			64		62
Depreciation, depletion and amortization		~~811~~753			~~498~~	699			~~2,293~~		~~1,294~~
Accretion of discount in asset retirement obligation		10			7	10			30		21
Gas gathering and processing		3436			25	29			92		70
General and administrative		8098			83	97			~~275~~		~~261~~
Derivative fair value (gain) loss		2(6	)		45	(6	)		17		3
Total Expenses		1,~~369~~345			~~1,156~~	1,280			~~4,024~~		~~2,935~~
OPERATING INCOME		~~919~~656			~~969~~	881			~~2,698~~		~~2,799~~
OTHER EXPENSE
Interest expense, net		~~136~~139			~~132~~	126			~~388~~		~~325~~
INCOME BEFORE INCOME TAX		~~783~~517			~~837~~	755			~~2,310~~		~~2,474~~
INCOME TAX EXPENSE (BENEFIT)
INCOME TAX EXPENSE
Current		9677			~~(65~~	)118			~~338~~		~~155~~
Deferred		~~187~~110			~~381~~	151			~~490~~		~~758~~
Total Income Tax Expense		~~283~~187			~~316~~	269			~~828~~		~~913~~
NET INCOME	$	~~500~~330		$	~~521~~$	486		$	~~1,482~~	$	~~1,561~~
EARNINGS PER COMMON SHARE
Basic	$	0.8656		$	~~0.95~~$	0.84		$	~~2.56~~	$	~~3.00~~
Diluted	$	0.8656		$	~~0.94~~$	0.83		$	~~2.54~~	$	~~2.96~~
DIVIDENDS DECLARED PER COMMON SHARE	$	0.125		$	~~0.12~~$	0.125		$	~~0.375~~	$	~~0.36~~

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Statements of Comprehensive Income (Unaudited)

(in millions)	Three Months EndedSeptember 30						Nine Months EndedSeptember 30
	Three Months EndedMarch 31
	2009			2008			2009			2008
(in millions)	2010			2009
Net Income	$	~~500~~330		$	~~521~~486		$	~~1,482~~		$	~~1,561~~
Other comprehensive income (loss):
Change in hedge derivative fair value		16609			31,~~149~~363			~~1,126~~			~~769~~
Realized (gain) loss on hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income (loss)		(1,096	)		276			(3,257	)		760
Realized (gain) loss on hedge derivative contract settlements reclassified into earnings from other comprehensive income		(335	)		(1,027	)
Net unrealized hedge derivative (loss) gain		(1,080	)		3,425			(2,131	)		1,529
Net unrealized hedge derivative gain		274			336
Realized loss on funded status of post-retirement plan reclassified into earnings from accumulated other comprehensive income (loss)		8			—			8			—
Income tax expense		(100	)		(123	)
Total change in comprehensive income (loss)		(1,072	)		3,425			(2,123	)		1,529
Total other comprehensive income		174			213
Income tax benefit (expense)		392			(1,252	)		776			(559	)
Total comprehensive income	$	504		$	699
Total other comprehensive (loss) income		(680	)		2,173			(1,347	)		970
Total comprehensive (loss) income	$	(180	)	$	2,694		$	135		$	2,531

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)

(in millions)	Nine Months EndedSeptember 30
	Three Months EndedMarch 31
	2009			2008
(in millions)	2010			2009
OPERATING ACTIVITIES
Net income	$	~~1,482~~330		$	~~1,561~~486
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		~~2,293~~753			~~1,294~~699
Accretion of discount in asset retirement obligation		3010			2110
Non-cash incentive compensation		~~109~~38			~~110~~40
Dry hole expense		353			720
Deferred income tax		~~490~~110			~~758~~151
Non-cash derivative fair value (gain) loss		~~122~~(13	)		~~(11~~79	)
Gain on extinguishment of debt		~~(17~~—	)		—(9	)
Other non-cash items		~~(12~~4	)		12(5	)
Changes in operating assets and liabilities net of effects of acquisitionof corporation (a)		708			(2	)
Changes in operating assets and liabilities (a)		(7	)		1,971
Cash Provided by Operating Activities		51,~~240~~228			3,~~750~~442
INVESTING ACTIVITIES
Proceeds from sale of property and equipment		3—			—2
Property acquisitions		(~~199~~44	)		(~~7,621~~94	)
Development costs, capitalized exploration costs and dry hole expense		(~~2,565~~670	)		(21,~~494~~076	)
Other property and asset additions		(~~493~~88	)		(~~637~~209	)
Cash Used by Investing Activities		(~~3,254~~802	)		(101,~~752~~377	)
FINANCING ACTIVITIES
Proceeds from long-term debt		62,~~046~~354			132,~~481~~115
Payments on long-term debt		(72,~~601~~636	)		(93,~~011~~979	)
Dividends		(~~215~~73	)		(~~181~~69	)
Debt costs		(2	)		(32	)
Proceeds from exercise of stock options and warrants		9			1
Net proceeds from common stock offerings		—			2,612
Payments upon exercise of stock options		(2	)		—
Proceeds from exercise of stock options and warrants		9			23
Excess tax benefit on exercise of stock options or vesting of stock awards		2			—
Payments upon exercise of stock options		(3	)		(70	)
Other, primarily decrease in cash overdrafts		(56	)		(149	)
Excess tax benefit on exercise of stock options or vesting of stock awards		5			64
Cash Used by Financing Activities		(402	)		(2,081	)
Other, primarily (decrease) increase in cash overdrafts		(226	)		135
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		24			(16	)
Cash (Used) Provided by Financing Activities		(1,987	)		7,021
Cash and Cash Equivalents, Beginning of Period		9			25
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(1	)		19
Cash and Cash Equivalents, End of Period	$	33		$	9
Cash and Cash Equivalents, Beginning of Period		25			—
Cash and Cash Equivalents, End of Period	$	24		$	19
(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	~~409~~(84	)	$	~~(370~~258	)
Other current assets		5063			59138
Other operating assets and liabilities		(1721	)		(520	)
Current liabilities		1535			~~314~~(63	)
Change in current assets from early settlement of hedges, net of amortization		~~251~~—			—1,658
	$	~~708~~(7	)	$	(21,971	)

See accompanying notes to consolidated financial statements.

XTO ENERGY INC.

Consolidated Statements of Stockholders’ Equity (Unaudited)

(in millions, except per share amounts)	CommonStock		AdditionalPaid-inCapital		TreasuryStock			RetainedEarnings			AccumulatedOtherComprehensiveIncome (Loss)			Total	~~Total~~
Balances, December 31, 2008	$	6	$	8,315	$	(147	)	$	6,588		$	2,585			$	17,347
Balances, December 31, 2009	$	6	$	8,471	$	(177	)	$	8,317		$	709		$	17,326
Net income		—		—		—			~~1,482~~330			—			330	~~1,482~~
Other comprehensive loss		—		—		—			—			(1,347	)			(1,347	)
Other comprehensive income		—		—		—			—			174			174
Issuance/vesting of stock awards, including income tax benefits		—		7135		(82	)		—			—			33	63
Expensing of stock options		—		393		—			—			—			3	39
Stock option and warrant exercises, including income tax benefits		—		98		—			—			—			8	9
Common stock dividends ($0.375 per share)		—		—		—			(217	)		—				(217	)
Common stock dividends ($0.125 per share)		—		—		—			(73	)		—			(73	)
Balances, September 30, 2009	$	6	$	8,434	$	(155	)	$	7,853		$	1,238			$	17,376
Balances, March 31, 2010	$	6	$	8,517	$	(179	)	$	8,574		$	883		$	17,801
Balances, December 31, 2007	$	5	$	3,172	$	(134	)	$	4,938		$	(40	)		$	7,941
Balances, December 31, 2008	$	6	$	8,315	$	(147	)	$	6,588		$	2,585		$	17,347
Net income		—		—		—			~~1,561~~486			—			486	~~1,561~~
Other comprehensive income		—		—		—			—			~~970~~213			213	~~970~~
Issuance/vesting of stock awards, including income tax benefits		—		5426		—(1	)		—			—			25	54
Expensing of stock options		—		5714		—			—			—			14	57
Stock option and warrant exercises, including income tax benefits		—		251		—			—			—			1	25
Issuance of common stock for acquisition of corporation or properties		—		2,338		—			—			—				2,338
Common stock dividends ($0.125 per share)		—		—		—			(72	)		—			(72	)
Common stock offerings		1		2,611		—			—			—				2,612
Balances, March 31, 2009	$	6	$	8,356	$	(148	)	$	7,002		$	2,798		$	18,014
Common stock dividends ($0.36 per share)		—		—		—			(192	)		—				(192	)
Balances, September 30, 2008	$	6	$	8,257	$	(134	)	$	6,307		$	930			$	15,366

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~~2009, have not been audited by independent registered public accountants. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at ~~September~~March 3031, ~~2009,~~2010 and our income, ~~and~~ comprehensive income ~~for the three and nine months ended September 30~~, ~~2009 and 2008 and~~ cash flows and stockholders’ equity for the ~~nine~~three months ended ~~September~~ March 3031, ~~2009~~2010 and ~~2008~~2009. All such adjustments are of a normal recurring nature. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results. ~~Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation.~~

The financial data for the three- ~~and nine-~~month periods ended ~~September~~March 3031, ~~2009~~2010 and ~~2008~~2009 included herein have been subjected to a limited review by KPMG LLP, our independent registered public accountants. The accompanying review report of independent registered public accountants is not a report within ~~the~~ 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~~ read with the consolidated financial statements included in our ~~2008~~2009 Annual Report on Form 10-K.

Other

~~Inventory~~On December 13, 2009, we entered into a definitive merger agreement with Exxon Mobil Corporation under which we would become a wholly owned subsidiary of ~~tubular~~ExxonMobil. ~~goods~~As ~~and~~a ~~equipment~~result ~~for~~of ~~future~~the ~~use~~merger, oneach outstanding share of our ~~producing~~common ~~properties~~stock iswill ~~included~~be inconverted ~~other~~into ~~current~~0.7098 ~~assets~~shares inof ExxonMobil common stock. Completion of the ~~consolidated balance~~merger ~~sheets~~remains subject to certain conditions, ~~with~~including ~~balances~~the adoption of ~~$148~~the ~~million~~merger atagreement ~~September 30~~by our stockholders, ~~2009~~as ~~and~~well ~~$182~~as ~~million~~certain atgovernmental ~~December 31~~approvals. We currently expect to complete the merger in the second quarter of 2010, ~~2008.~~however, no assurance can be given as to when, or if, the merger will occur.

~~Our effective~~Inventory ~~income tax rates for the three- and nine- month periods ended September 30, 2009 and 2008 are higher than the maximum federal statutory rate~~ of ~~35%~~tubular ~~primarily~~goods ~~because of state~~ and ~~local~~equipment ~~taxes.~~for ~~The~~future ~~current~~use ~~income~~on ~~tax provision exceeds~~ our ~~actual~~producing ~~cash~~properties ~~tax~~is ~~expense~~included ~~by the benefit realized upon exercising of stock options or vesting of stock awards~~ in ~~excess~~other ofcurrent ~~amounts~~assets ~~expensed~~ in the ~~financial~~consolidated ~~statements.~~balance ~~This benefit~~sheets, ~~which~~with isbalances ~~recorded~~of ~~in additional paid-in capital, was~~ $5147 million ~~for~~ ~~the~~at ~~first~~March 31, ~~nine~~2010 ~~months of 2009~~ and ~~$71~~December 31, ~~million for the first nine months of 2008~~2009.

~~Accounting~~Our effective ~~Pronouncements~~income tax rates for the three-month 2010 and 2009 periods are higher than the maximum federal statutory rate of 35% primarily because of state and local taxes. The current income tax provision exceeds our actual cash tax expense by the benefit realized upon exercising of stock options or vesting of stock awards in excess amounts expensed in the financial statements. This benefit, which is recorded in additional paid-in capital, was $2 million for first quarter 2010 and less than $1 million for first quarter 2009.

In May 2009, the Financial Accounting Standards Board established 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 issued2. ~~The~~Related ~~new~~Party ~~rule~~Transactions sets forth the period after the balance sheet date during which management should evaluate any events or transactions for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize such events or transactions in its financial statements, and the disclosures that an entity should make about such events or transactions. We have evaluated subsequent events through November 4, 2009.

InJack ~~December~~Randall, ~~2008~~one of our nonemployee directors, ~~the~~was ~~Securities~~a co-founder and ~~Exchange~~ ~~Commission~~director ~~(SEC)~~of ~~released~~Randall & ~~Final~~Dewey ~~Rule~~Partners, ~~Modernization~~L.P., ofwhich ~~Oil~~was acquired ~~and~~by ~~Gas~~Jefferies ~~Reporting~~Group, Inc. ~~The~~in ~~new~~2005 ~~disclosure~~and ~~requirements~~now ~~include~~operates ~~provisions~~as ~~that~~Jefferies & ~~permit~~Company, ~~the~~Inc. ~~use~~Jefferies served as one of ~~new~~our ~~technologies~~financial toadvisors ~~determine~~in ~~proved~~connection ~~reserves~~with ifthe ~~those~~announced ~~technologies~~merger with ExxonMobil. If the merger is completed, we have ~~been~~agreed to ~~demonstrated~~pay ~~empirically~~Jefferies a transaction fee of $24 million. In addition, we agreed to ~~lead~~reimburse Jefferies for all reasonable and documented out-of-pocket expenses, including legal fees, incurred in connection with the services it provides to us in connection with the merger and have agreed to indemnify Jefferies against certain liabilities.

~~reliable conclusions about reserves volumes~~3. ~~The~~Asset ~~new~~Retirement ~~requirements~~Obligation also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements call for 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.

InOur ~~September~~asset ~~2009,~~retirement ~~the~~obligation ~~Financial~~primarily ~~Accounting~~represents ~~Standards Board issued an exposure draft to update~~ the ~~Extractive~~estimated ~~Industries—Oil~~present ~~and~~value ~~Gas Topic~~ of the ~~FASB~~amount ~~Accounting~~we ~~Standards~~will ~~Codification.~~incur ~~The objective of the update is~~ to ~~align~~plug, ~~the~~abandon ~~oil~~ and remediate ~~gas~~our ~~reserve~~proved ~~estimation~~producing ~~and~~properties ~~disclosure~~at ~~requirements~~the end of ~~the~~their ~~financial~~productive ~~accounting~~lives, ~~standards~~in accordance with ~~the~~applicable ~~SEC’s~~state ~~final~~laws. ~~rule~~We ~~discussed~~determine ~~above.~~our ~~The proposed~~asset ~~amendments~~retirement ~~would~~obligation beby ~~effective~~calculating ~~for~~the ~~financial~~present ~~statements~~value ~~for~~of ~~fiscal~~estimated ~~years~~cash ~~ending~~flows onrelated orto ~~after~~the ~~December 31, 2009~~liability. The ~~These~~following ~~amendments~~is ~~are~~a ~~not~~summary ~~expected~~of toasset ~~have~~retirement aobligation ~~significant~~activity ~~effect~~for onthe ~~our~~three ~~current~~months orended ~~prior~~March 31, ~~financial~~2010: ~~position or earnings.~~

2. Asset Retirement Obligation


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

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

Asset retirement obligation, long term	$	813

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 laws4. WeDebt 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 nine months ended September 30, 2009:

(in millions)	March 31,2010			December 31,2009
Asset retirement obligation, December 31, 2008	$	759
Bank debt:
Revision in estimated cash flows		(7	)
Commercial paper, 0.3% at March 31, 2010 and December 31, 2009	$	340		$	622
Liability incurred upon acquiring and drilling wells		38
Revolving credit facility due April 1, 2013		—			—
Liability settled upon plugging and abandoning wells		(20	)
Term loan due April 1, 2013, 0.6% at March 31, 2010 and 0.7% at December 31, 2009		500			500
Accretion of discount expense		30
Term loan due February 5, 2013, 0.6% at March 31, 2010 and December 31, 2009		100			100
Asset retirement obligation, September 30, 2009		800
Senior notes:
Less current portion		(29	)
5.00%, due August 1, 2010		250			250
Asset retirement obligation, long-term	$	771
7.50%, due April 15, 2012		350			350
5.90%, due August 1, 2012		550			550
6.25%, due April 15, 2013		400			400
4.625%, due June 15, 2013		400			400
5.75%, due December 15, 2013		500			500
4.90%, due February 1, 2014		500			500
5.00%, due January 31, 2015		348			348
5.30%, due June 30, 2015		400			400
5.65%, due April 1, 2016		400			400
6.25%, due August 1, 2017		735			735
5.50%, due June 15, 2018		773			773
6.50%, due December 15, 2018		1,000			1,000
6.10%, due April 1, 2036		591			591
6.75%, due August 1, 2037		1,399			1,399
6.375%, due June 15, 2038		704			704
Net discount on senior notes		(35	)		(35	)
Total debt		10,205			10,487
Less current portion		(250	)		(250	)
Long-term debt	$	9,955		$	10,237

3Because 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. ~~Debt~~Before the stated maturities of April 2013, we may renegotiate the revolving credit agreement and term loans to increase the borrowing commitment and/or extend the maturity. Maturities of long-term debt as of March 31, 2010, excluding net discounts, are as follows:

(in millions)	~~September 30,2009~~			~~December 31,2008~~
Bank debt:
2010	$	250
Commercial paper, 0.4% at September 30, 2009 and 3.0% at December 31, 2008	$	520		$	72
2011		—
Revolving credit agreement due April 1, 2013, 2.4% at December 31, 2008		—			1,825
2012		900
Term loan due April 1, 2013, 0.7% at September 30, 2009 and 1.9% at December 31, 2008		500			500
2013		2,240
Term loan due February 5, 2013, 0.6% at September 30, 2009 and 2.3% at December 31, 2008		100			100
2014		500
Senior notes:
Remaining		6,350
5.00% due August 1, 2010		250			250
Total	$	10,240
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		(35	)		(38	)
Total debt		10,385			11,959
Less current portion		(250	)		—
Long-term debt	$	10,135		$	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 debt as of September 30, 2009, excluding net discounts, are as follows:

(in millions)
2009	$	—
2010		250
2011		—
2012		900
2013		2,420
Remaining		6,850
Total	$	10,420

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 ~~September~~March 3031, ~~2009~~2010, borrowings under our commercial paper program were $~~520~~340 million at a weighted average interest rate of 0.43%.

Bank Debt

On ~~September~~ March 3031, ~~2009~~2010, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $2.325 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%, then the interest rate on our borrowings is increased by 0.05%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing commitments, which is 0.09%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 65%.

We have unsecured and uncommitted lines of credit with commercial banks totaling $~~300~~100 million. As of ~~September~~March 3031, ~~2009~~2010, there were no borrowings under these lines.

~~Repurchase of~~ Senior Notes

InWe ~~the~~are ~~first~~required ~~and~~to ~~second~~offer ~~quarters~~to ofpurchase ~~2009,~~at ~~we repurchased $200 million total face amount of senior notes, including $2 million of our 5.0~~101% ~~senior~~ ~~notes due 2015, $15 million~~ of ~~our~~par ~~6.25% senior notes due 2017, $27 million of~~ our 57.550% senior notes due ~~2018,~~2012 $9and ~~million of~~ our 6.125% senior notes due ~~2036,~~2013 ~~$51~~if ~~million~~we ofare ~~our~~the subject ~~6.75% senior notes due 2037 and $96 million~~ of ~~our 6.375% senior notes due 2038. In connection with these repurchases, we recognized~~ a ~~$17~~change ~~million gain on extinguishment of debt~~ in ~~the first nine months of 2009~~control, ~~net~~such ofas ~~unamortized discounts and~~ the ~~write-off~~proposed ofmerger ~~deferred~~with ~~debt offering costs~~ExxonMobil. ~~These~~Our ~~gains~~other ~~were netted~~senior ~~against~~notes ~~interest~~are ~~expense~~not insubject ~~the~~to ~~consolidated~~this ~~income statements~~provision. ~~There were no repurchases of senior notes in third quarter 2009.~~

45. Commitments and Contingencies

Litigation

OnIn ~~October 17,~~July ~~1997,~~2005 ana ~~action,~~predecessor ~~styled~~company ~~United~~that ~~States~~we ofacquired, ~~America~~Antero exResources ~~rel.~~Corporation, ~~Grynberg~~was v.served ~~Cross~~with ~~Timbers~~a ~~Oil~~lawsuit styled Threshold Development Company, et al., ~~was filed in the U~~v.S. ~~District~~Antero ~~Court~~Resources ~~for the Western District of Oklahoma by Jack J~~Corp., ~~Grynberg~~which onlawsuit ~~behalf~~was offiled ~~the~~in ~~United States under~~ the ~~qui~~District ~~tam~~Court ~~provisions~~ of ~~the~~Wise ~~U.S.~~County, ~~False Claims Act against the Company and certain of our subsidiaries~~Texas. The ~~plaintiff~~plaintiffs ~~alleges~~are ~~that~~surface weowners, ~~underpaid~~royalty ~~royalties~~owners ~~on natural gas produced from federal leases~~ and ~~lands~~prior ~~owned~~working byinterest ~~Native~~owners ~~Americans~~ in ~~amounts~~several inoil ~~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~~leases ~~plaintiff~~as ~~seeks treble~~well ~~damages~~as ~~for~~parties ~~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~~contractual ~~were~~agreements ~~consolidated~~under inwhich ~~the~~Antero ~~United~~Resources ~~States~~Corporation ~~District~~owned ~~Court~~an ~~for Wyoming~~interest. InAntero ~~October~~Resources ~~2002~~Corporation, the ~~court granted a motion to dismiss the plaintiff’s royalty valuation claims~~defendant, ~~and the plaintiff’s appeal of this decision~~ was ~~dismissed~~acquired ~~for lack of appellate jurisdiction in May 2003. In response to a motion to dismiss filed~~ by us ~~and~~on ~~other defendants~~April 1, in2005. ~~October~~The ~~2006~~claims ~~the~~related ~~district judge held that the plaintiff failed~~ to ~~establish~~alleged ~~jurisdictional~~events ~~requirements~~pre-dating ~~to maintain~~ the acquisition ~~action against us~~ and ~~other~~concern ~~defendants~~non-payment ~~and dismissed the action for lack~~ of ~~subject matter jurisdiction. In September 2007, the district judge dismissed those claims against us~~

royalties, improper calculation of royalties, improper pricing related to royalties, trespass, failure to develop and breach of contract. We settled all claims related to the payment of royalties and trespass. Under the remaining claims, the plaintiffs sought both damages and termination of the existing oil and gas leases covering their interests. In October 2008, the trial court granted our motion for summary judgment, resulting in the dismissal of the plaintiffs’ remaining claims. The plaintiffs have appealed the court’s judgment. Based on a review of the current facts and circumstances with counsel, management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter. While acknowledging the uncertainties of litigation, management believes that the ultimate outcome of this matter will not have a material effect on our earnings, cash flows or financial position.

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

In September 2008, a class action lawsuit was filed against the Company styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. We removed the case to federal court in Wichita, Kansas. The plaintiffs allege that we have improperly taken post-production costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma, and Colorado. The plaintiffs also seek to represent all royalty owners in these three states as a class. We have answered, denying all claims, and have filed motions to dismiss a portion of the claims. The federal court recently granted our motion for summary judgment concerning prior settled class actions that overlap plaintiff’s proposed class action. The court also granted our motion to dismiss those portions of plaintiff’s class that are currently being prosecuted in another case. Based on a review of the current facts and circumstances with counsel, management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter. While acknowledging the uncertainties of litigation, management believes that the ultimate outcome of this matter will not have a material effect on our earnings, cash flows or financial position.

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

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

~~pertaining~~Eleven toputative shareholder class actions were filed in the ~~royalty~~District ~~value~~Courts of ~~carbon~~Tarrant County, ~~dioxide~~Texas between December 14, 2009, and January 6, 2010. ~~The~~Those ~~plaintiff~~cases are styled: (i) Mary Pappas, et al. v. XTO Energy Inc., et al., No. 342-242403-09, filed anon ~~appeal~~December 14, of2009; ~~this~~(ii) Sanjay ~~decision~~Israni, toet al. ~~the~~v. ~~United~~XTO ~~States~~Energy ~~Tenth~~Inc., ~~Circuit~~et ~~Court~~al., ofNo. 017-242424-09, ~~Appeals~~filed on December 15, 2009; (iii) Michael Walsh, et al. Inv. ~~March~~XTO Energy Inc., et al., No. 153-242432-09, filed on December 15, 2009; (iv) Ronald Gross, ~~the~~et ~~Tenth~~al. ~~Circuit~~v. ~~affirmed~~XTO Energy Inc., et al., No. 141-242460-09, filed on December 16, 2009; (v) Jeffrey Fink, et al. v. Bob R. Simpson, et al., No. 048-242500-09, filed on December 17, 2009; (vi) Lawrence ~~the~~Treppel, ~~trial~~et ~~court’s~~al. ~~dismissal~~v. ofXTO ~~the~~Energy ~~case~~Inc., ~~but~~et ~~reversed~~al., ~~and~~No. 342-242523-09, ~~remanded~~filed ~~the~~on ~~carbon~~December 18, ~~dioxide~~2009; ~~portion~~(vii) Nicholas ofWeil, ~~the~~et ~~case~~al. tov. ~~the~~XTO ~~trial~~Energy ~~court~~Inc., ~~The~~et ~~United~~al., ~~States~~No. 096-242526-09, ~~Supreme~~filed ~~Court~~on ~~denied~~December 18, ~~the~~2009; (viii) Charles ~~plaintiff’s~~Kreps, ~~application~~et ~~for~~al. ~~appeal~~v. WeXTO ~~have~~Energy ~~entered~~Inc., ~~into~~et anal., ~~agreement~~Case No. 352-242548-09, filed on December 21, 2009; (ix) Murray Silver, et al. v. XTO Energy Inc., et al., No. 342-242630-09, filed on December 22, 2009; ~~with~~(x) William ~~the~~Stratton, ~~plaintiff~~et ~~whereby~~al. wev. XTO Energy Inc., et al., No. 096-242775-09, filed on December 30, 2009; and ~~the~~(xi) United ~~plaintiff~~Food ~~are~~and ~~dismissing~~Commercial ~~all~~Workers ~~claims~~Union ~~against~~Local ~~each~~880-Retail ~~other~~Food Employers Joint Pension Fund v. ~~The~~XTO Energy Inc., et al., No. 342-242849-10, filed on January 6, 2010. On January 12, 2010, the court ~~granted~~entered orders consolidating the ~~dismissal~~eleven cases filed as of that date under the ~~claims~~caption onIn ~~November 3,~~re ~~2009,~~XTO ~~effectively~~Energy ~~ending~~Shareholder ~~this~~Class ~~case~~Action Litigation.

InTwo ~~September~~putative ~~2008,~~shareholder weclass ~~acquired~~actions ~~Hunt~~were ~~Petroleum~~filed ~~Corporation~~in ~~and~~the ~~other~~United ~~associated~~States ~~entities.~~District ~~One~~Court offor the ~~entities~~Northern District ~~that~~of weTexas ~~acquired~~between ~~owns properties~~December 28, ~~that~~2009 ~~are~~and ~~subject~~January 5, to2010. aThose ~~lawsuit~~cases are styled ~~USA~~(i) James exHarrison, ~~rel~~et al. ~~Grynberg~~ v. ~~Columbia~~XTO ~~Gas~~Energy ~~Transmission Company~~Inc., et al., ~~This~~No. 4:09-cv-768-Y, ~~lawsuit~~filed ison ~~one~~December 28, of2009 ~~the~~and ~~lawsuits~~(ii) Walt Schumann, ~~that~~et ~~were~~al. ~~filed~~v. ~~by Jack J~~Bob R. ~~Grynberg~~Simpson, ~~and~~et ~~that~~al., ~~were~~No. 4:10-cv-007-Y, ~~consolidated~~filed inon ~~the~~January 5, ~~United States District Court of Wyoming~~2010. ~~The~~On ~~issues~~February 5, ~~and~~2010, ~~disposition are~~ the ~~same~~plaintiffs ~~as those discussed~~ in the ~~Grynberg~~two ~~action~~federal ~~against~~actions ~~XTO~~filed ~~Energy~~an ~~described~~unopposed ~~above~~motion ~~except~~to ~~that~~consolidate ~~Hunt~~the ~~Petroleum did not have a carbon dioxide related claim against it~~cases. ~~This case is concluded.~~

InSeveral ~~July~~putative ~~2005~~shareholders afiled ~~predecessor~~an ~~company,~~individual ~~Antero~~action ~~Resources~~in ~~Corporation,~~the ~~was~~United ~~served~~States ~~with~~District aCourt ~~lawsuit~~for ~~styled Threshold Development Company, et al. v. Antero Resources Corp., which lawsuit was filed in~~ the Northern District ~~Court~~ of ~~Wise County,~~ Texas. ~~The plaintiffs are surface owners~~on February 11, ~~royalty~~2010 ~~owners~~alleging ~~and~~violations ~~prior~~of ~~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,~~federal ~~was~~securities ~~acquired~~laws bybased us on ~~April 1, 2005. The claims related to~~ alleged ~~events~~false ~~pre-dating the acquisition~~ and ~~concern non-payment~~material ofmisrepresentations ~~royalties,~~or ~~improper~~omissions ~~calculation~~in ofthe ~~royalties,~~preliminary ~~improper~~proxy ~~pricing~~filed ~~related~~with tothe ~~royalties,~~Securities ~~trespass, failure to develop~~ and ~~breach~~Exchange ofCommission ~~contract.~~in Weconnection ~~settled~~with ~~all claims related to~~ the ~~payment~~proposed merger. ofThat ~~royalties~~case ~~and~~is ~~trespass.~~styled ~~Under~~Mary ~~the remaining claims~~Pappas, ~~the~~et ~~plaintiffs~~al. ~~sought~~v. ~~both~~Bob ~~damages and termination of the existing oil and gas leases covering their interests~~R. ~~In October 2008~~Simpson, ~~the~~et ~~trial court granted our motion for summary judgment~~al., ~~resulting in the dismissal of the plaintiffs’ remaining claims~~No. 4:10-cv-00094-A, ~~The~~filed ~~plaintiffs appealed the court’s judgment. Based on a review of the current facts and circumstances with counsel~~February 11, ~~management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter~~2010. ~~While~~This ~~acknowledging~~case ~~the~~was ~~uncertainties~~consolidated ofinto ~~litigation, management believes that~~ the ~~ultimate~~Harrison ~~outcome~~case ofdescribed ~~this matter will not have a material effect on our earnings, cash flows or financial position~~above.

InOn ~~November~~April ~~2008~~21, an2010, ~~action~~the ~~was~~parties ~~filed~~to ~~against~~all of the ~~Company~~shareholder ~~and~~litigations ~~our~~challenging ~~directors~~the ~~styled~~merger ~~Freedman~~entered v.into ~~Adams~~a stipulation of settlement, which, etif ~~al.~~finally inapproved by the ~~Delaware~~Tarrant County District Court, will resolve all of ~~Chancery~~ the litigations challenging the merger. ~~The~~On ~~plaintiff~~April 22, is2010, ~~alleged~~the toTarrant beCounty aDistrict ~~stockholder~~Court ~~and~~presiding ~~brings~~over the ~~suit~~Texas asstate court litigation preliminarily approved a ~~derivative~~proposed ~~action~~settlement onof ~~behalf~~all claims made in all of the ~~Company.~~cases ~~The~~that ~~plaintiff~~are ~~seeks~~pending anin ~~equitable~~all ~~accounting~~jurisdictions ~~for~~against XTO Energy and ExxonMobil related to the ~~alleged~~proposed ~~losses~~merger. byThe basis of the ~~Company~~settlement ~~and~~relates ~~injunctions~~to ~~mandating~~certain ~~that~~modified adisclosures that ~~Section 162(m)~~have ~~plan~~been beand ~~submitted~~will tobe ~~our~~made ~~stockholders~~in ~~for~~filings ~~their~~with ~~approval~~the Securities and ~~against~~Exchange ~~further~~Commission, ~~non-deductible~~as ~~payments,~~well ~~along~~as ~~with~~a anconfirmation ~~award~~letter ofrelating ~~accountants~~to Barclays Capital’s opinion letter, ~~experts’~~to ~~and~~be ~~attorneys’~~delivered ~~fees.~~by WeBarclays ~~have~~Capital, ~~filed~~after aits ~~motion~~review toof ~~dismiss~~certain additional materials. ~~While~~The ~~we did~~cases ~~not~~are ~~have~~being insettled ~~place~~as a ~~Section 162(m)~~settlement ~~plan~~class atunder the ~~time~~class ~~the~~action ~~suit~~laws ~~was~~of ~~filed,~~ the ~~Board~~State of ~~Directors~~Texas. ~~approved~~Under asuch ~~Section 162(m)~~laws, ~~plan~~certain innotifications ~~February~~will ~~2009~~be ~~that~~made ~~was~~to ~~approved~~the byclass, ~~our~~and ~~stockholders~~a atfairness ~~our~~hearing ~~annual~~is ~~meeting~~currently inscheduled ~~May~~for ~~2009.~~October ~~Although~~1, ~~we are~~2010. ~~unable~~Further toinformation ~~predict~~concerning the ~~final~~settlement ~~outcome~~will ofbe ~~this~~provided ~~case,~~in wethe ~~believe~~definitive ~~that~~proxy ~~the~~statement/prospectus ~~allegations~~to ofbe ~~this~~filed ~~lawsuit~~with ~~are~~the ~~without~~Securities ~~merit~~and Exchange Commission and ~~intend~~mailed to ~~vigorously~~XTO ~~defend~~Energy stockholders in connection with the ~~action.~~proposed merger.

InWe ~~September~~are ~~2008,~~involved ain ~~class~~various ~~action~~other ~~lawsuit~~lawsuits ~~was~~and ~~filed~~certain ~~against~~governmental ~~the~~proceedings ~~Company~~arising ~~styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc.~~ in the ~~District~~ordinary ~~Court~~course of ~~Kearny County, Kansas~~business. WeOur ~~removed~~management ~~the~~and ~~case~~legal tocounsel ~~federal~~do ~~court~~not inbelieve ~~Wichita, Kansas. The plaintiffs allege~~ that ~~we have improperly taken post-production costs from royalties paid to~~ the ~~plaintiffs~~ultimate ~~from~~resolution ~~wells~~of ~~located~~these ~~in Kansas~~claims, ~~Oklahoma,~~including ~~and~~the ~~Colorado.~~lawsuits ~~The~~described ~~plaintiffs also seek to represent all royalty owners in these three states as a class. We have answered~~above, ~~denying~~will ~~all claims, and~~ have ~~filed motions to dismiss~~ a ~~portion~~material ofeffect ~~the claims. Based~~ on aour ~~review~~financial ofposition ~~the~~or ~~current facts and circumstances with counsel~~liquidity, ~~management~~although ~~has provided~~an ~~for~~unfavorable ~~what~~outcome iscould ~~believed~~have ~~to be~~ a material ~~reasonable~~adverse ~~estimate~~effect ofon the ~~loss~~operations ~~exposure for this matter. While acknowledging the uncertainties~~ of ~~litigation, management believes that the ultimate outcome of this matter will not have~~ a ~~material~~given ~~effect~~interim onperiod ~~our earnings, cash flows~~ or ~~financial position~~year.

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~~ 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 ~~September~~March 3031, ~~2009~~2010, maximum commitments under our transportation contracts were as follows:

(in millions)
2009	$	41
2010	$	165
2010		173
2011		231
2011		185
2012		232
2012		185
2013		227
2013		179
2014		223
Remaining		~~723~~777
Total	$	1,~~486~~855

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

Drilling Contracts

As of ~~September~~March 3031, ~~2009~~2010, we have contracts with various drilling contractors to use 45 65 drilling rigs with terms of up to three years and minimum future commitments of $48103 million in ~~2009~~2010, $9134 million in ~~2010~~2011, $2211 million in ~~2011~~2012 and $21 million in ~~2012~~ 2013. Early termination of these contracts at ~~September~~March 3031, ~~2009~~2010 would have required us to pay maximum penalties of $8985 million. Based upon our planned drilling activities, we do not expect to pay significant early termination penalties.

See Note 67 regarding commodity sales commitments.

56. 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 ~~September~~ March 3031, ~~2009~~2010, certain crude oil swap agreements and certain natural gas basis swap agreements did not qualify for hedge accounting. Except to the extent basis swap agreements are utilized in conjunction with NYMEX future contracts, they cannot qualify for hedge accounting. Whether or not designated as cash flow hedges, all of our derivative contracts are used to hedge against changes in cash flows related to commodity prices.

All derivatives are recorded at estimated fair value and recorded as derivative fair value in both current and non-current assets and liabilities in the consolidated balance sheets. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or the value confirmed by the counterparty. Realized and unrealized gains and losses on derivatives that are not

~~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.

Derivative Instruments

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

(in millions)	Fair Value of Derivative Instruments
	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30,2009		December 31,2008		September 30,2009			December 31,2008
(in millions)	March 31,2010		December 31,2009		March 31,2010			December 31,2009
Derivatives designated as hedging instruments:
Natural gas futures and basis swaps	$	~~907~~1,248	$	~~1,917~~836	$	(~~121~~36	)	$	(1752	)
Crude oil futures and differential swaps		~~566~~313		~~1,772~~442		(99107	)		(12105	)
Total derivatives designated as hedging instruments		1,~~473~~561		31,~~689~~278		(~~220~~143	)		(29157	)
Derivatives not designated as hedging instruments:
Natural gas futures and basis swaps		147		912		(14	)		(68	)
Crude oil futures and differential swaps		1—		60—		(48	)		—(8	)
Total derivatives not designated as hedging instruments		157		6912		(1822	)		(616	)
Total derivatives	$	1,~~488~~568	$	31,~~758~~290	$	(~~238~~165	)	$	(35173	)

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

	Three Months Ended September 30
	Three Months Ended March 31
	Change inHedge Derivative FairValue					Realized (Gain) LossReclassified fromOCI into Revenue (a)
	Change inHedge DerivativeFair Value					Realized (Gain) LossReclassified fromOCI into Revenue (a)
(in millions)	~~2009~~2010			~~2008~~2009		~~2009~~2010			~~2008~~2009
Natural gas futures and basis swaps	$	~~(30~~642	)	$	21,~~083~~309	$	(~~826~~230	)	$	~~164~~(624	)
Crude oil futures and differential swaps		46(33	)		~~1,049~~54		(~~270~~105	)		~~103~~(403	)
Natural gas liquids futures		—			17		—			9
Total	$	609		$	1,363	$	(335	)	$	(1,027	)
Total	$	16		$	3,149	$	(1,096)		$	276

(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.

	Nine Months Ended September 30
	Change inHedge DerivativeFair Value						Realized (Gain) LossReclassified fromOCI into Revenue (a)
(in millions)	2009			2008			2009			2008
Natural gas futures and basis swaps	$	1,336		$	262		$	(2,265	)	$	424
Crude oil futures and differential swaps		(210	)		513			(992	)		310
Natural gas liquids futures		—			(6	)		—			26
Total	$	1,126		$	769		$	(3,257	)	$	760

(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 September 30
	Three Months Ended March 31
	(Gain) LossRecognized in Income(Non-Hedge)						(Gain) LossRecognized in Income(Ineffective Portion)						Derivative FairValue (Gain) Loss
(in millions)	~~2009~~2010			2009	~~2008~~		~~2009~~2010			~~2008~~2009			~~2009~~2010			~~2008~~2009
Natural gas futures and basis swaps	$	912		$	$5	58	$	(513	)	$	(919	)	$	4(1	)	$	49(14	)
Crude oil futures and differential swaps		(71	)		(3	—)		5(6	)		(311	)		(25	)		(38	)
Natural gas liquids futures		—				—		—			(1	)		—			(1	)
Total	$	13		$	2		$	(19	)	$	(8	)	$	(6	)	$	(6	)
Total	$	2			$	58	$	—		$	(13	)	$	2		$	45

	Nine Months Ended September 30
	(Gain) LossRecognized in Income(Non-Hedge)					(Gain) LossRecognized in Income(Ineffective Portion)						Derivative FairValue (Gain) Loss
(in millions)	2009		2008			2009			2008			2009			2008
Natural gas futures and basis swaps	$	30	$	(5	)	$	(35	)	$	10		$	(5	)	$	5
Crude oil futures and differential swaps		8		—			14			(2	)		22			(2	)
Total	$	38	$	(5	)	$	(21	)	$	8		$	17		$	3

Derivative Fair Value (Gain) Loss

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

(in millions)	Three Months ~~EndedSeptember~~EndedMarch 3031						~~Nine Months EndedSeptember 30~~
	2009			2008			2009			2008
	2010			2009
Net cash (received from) paid to counterparties	$	(13	)	$	7		$	(105	)	$	14
Net cash paid to (received from) counterparties	$	7		$	(85	)
Non-cash change in derivative fair value		15(13	)		3879			~~122~~			~~(11~~	)
Derivative fair value (gain) loss	$	2(6	)	$	45(6	)	$	17		$	3

15See Note 7.

Fair Value of Financial Instruments

Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at ~~September~~March 3031, ~~2009~~2010 and December 31, ~~2008~~2009. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:

Asset (Liability)

September 30, 2009

December 31, 2008

March 31, 2010

December 31, 2009

(in millions)

CarryingAmount

Fair Value

CarryingAmount

Fair Value

Net derivative asset

1,~~250~~403

31,~~723~~117

Total debt

(10,~~385~~205

)

(11,~~081~~281

)

(1110,~~959~~487

)

(11,~~421~~526

)

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

Fair Value Measurements

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

Fair Value Measurements

September 30, 2009

December 31, 2008

March 31, 2010

December 31, 2009

(in millions)

SignificantOtherObservableInputs(Level 2)

SignificantUnobservableInputs(Level 3)

SignificantOtherObservableInputs(Level 2)

SignificantUnobservableInputs(Level 3)

Net derivative asset

1,~~250~~403

—

31,~~723~~117

—

Asset retirement obligation

—

(~~800~~846

)

—

(~~759~~812

)

~~See~~The ~~Note~~fair 2value of our derivative contracts are measured using Level II inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a ~~rollforward~~broker or other market-corroborated prices. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are generally A- or better rated companies, the ~~asset~~fair ~~retirement~~value ~~obligation~~of our derivative contracts have been adjusted to account for the risk of nonperformance by the counterparty.

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

Concentrations of Credit Risk

Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated companies. Letters of credit or other appropriate security are obtained as considered necessary to ~~limit~~mitigate risk of loss. Financial and commodity-based swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, and we have master netting agreements with most counterparties that provide for offsetting payables against receivables from separate derivative contracts. None of our derivative contracts contain credit-risk -related contingent features that would require collateralization based on any triggering events. ~~Our allowance for uncollectible receivables was $15 million at September 30, 2009 and $13 million at December 31, 2008.~~

67. Commodity Sales Commitments

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

In addition to selling gas under fixed price physical delivery contracts, we enter futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on natural gas, crude oil and natural gas liquids sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We have hedged most of our crude oil sales through December 2010 and a portion of our natural gas sales through December 2011.

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

Natural Gas

We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 56 regarding accounting for commodity hedges.

Production Period		Mcf per Day		Weighted AverageNYMEX Priceper Mcf	~~Weighted AverageNYMEX Priceper Mcf~~
2009 October to December		1,745,000	(a)		$	8.79	(a)
2010	April to December	1,250,000		$	7.49
2010 January to December		1,250,000			$	7.49
2011	January to December	250,000		$	7.02
2011 January to December		250,000			$	7.02

(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 AverageSell Basisper Mcf (a)
2009	October to December	905,000	$	0.53
2010	April to October	610,000	$	0.31
2010	January to March	622,500	$	0.43
	November to December	475,000	$	0.27
	April to October	600,000	$	0.31
2011	January to October	200,000	$	0.19
	November to December	~~325~~170,000	$	0.3217
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 ~~September~~March 3031, ~~2009~~2010, ana ~~unrealized~~ pre-tax derivative fair value gain of approximately $1.2 billion, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). Based on ~~September~~March 3031 mark-to-market prices, $1.1 billion of this gain is expected to be reclassified into earnings through ~~September~~March ~~2010~~2011. 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 2010 crude oil swap agreements are designated as hedges for hedge accounting purposes. See Note 6 regarding accounting for commodity hedges.


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

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

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

Purchase Basis Swaps

We have entered purchase basis swap agreements that effectively fix the basis adjustment as shown below. Some of our purchase basis swap agreements are used to offset our physical delivery basis contracts. This effectively converts the fixed price to a floating price. The remaining purchase basis swap agreements are related to potential purchase of gas volumes to be transported in connection with our commitments under our transportation contracts (Note 45). Purchase basis swap agreements are not designated as hedges for hedge accounting purposes.

Period		Mcf per Day	Weighted AveragePurchase Basisper Mcf (a)
2009	October to December	70,000	$	0.76
2010	April to December	120,000	$	0.14
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	30,000	$	0.14
2013	January to May	20,000	$	0.16

(a)

Reductions to NYMEX gas prices for purchase location.

~~Crude~~8. ~~Oil~~Earnings per Share

WeThe ~~have~~following ~~entered~~reconciles ~~into~~earnings ~~crude oil futures contracts~~ and ~~swap~~shares ~~agreements~~used ~~that~~in ~~effectively fix prices for~~ the ~~production~~computation ~~and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because~~ of ~~location,~~basic ~~quality~~ and ~~other~~diluted ~~adjustments.~~earnings ~~Not~~per ~~all~~common ofshare: ~~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 AverageNYMEX Priceper Bbl
(in millions, except per share data)	Three Months Ended March 31
2009	October to December		62,500	(a)		$	117.11	(a)
	2010									2009
2010	January to December		70,000			$	95.70
	Earnings				Shares			Earningsper Share		Earnings			Shares		Earningsper Share
Total	$	330			584.2					$	486		579.7
Attributable to participating securities		(3	)		(4.8	)					(4	)	(4.7	)
Basic	$	327			579.4			$	0.56	$	482		575.0		$	0.84
Effect of dilutive securities:
Stock options		—			3.2						—		1.8
Warrants		—			1.1						—		1.0
Diluted	$	327			583.7			$	0.56	$	482		577.8		$	0.83

~~(a)~~Certain ~~Includes~~options ~~swap~~to ~~agreements~~purchase ~~for~~shares ~~57,000~~of ~~Bbls~~our ~~per~~common ~~day~~stock have ~~which~~been ~~were~~excluded ~~early~~from ~~settled~~the 2010 and ~~reset~~2009 atdiluted ~~current~~calculations ~~market~~because ~~prices. The price shown is~~ the ~~price~~options ~~that~~are ~~will~~anti-dilutive. beAnti-dilutive ~~used~~options for ~~cash~~7.5 million ~~flow~~shares ~~hedge~~with ~~accounting~~a ~~purposes~~weighted ~~and~~average ~~has~~exercise ~~been~~price ~~reduced~~of ~~for~~$52.70 ~~transaction~~were ~~costs~~excluded ~~related~~in to2010, ~~the~~and ~~early settlements~~8.0 million shares ~~The~~with a weighted average ~~cash settlement contract~~ price ~~for~~of ~~all contracts is~~ $5850.6498 ~~per~~were ~~Bbl.~~excluded ~~See~~in ~~“Early Settlement of Hedges” below~~2009.

~~We have entered into crude differential swaps that effectively fix the sweet and sour oil differential at $3~~9.43 ~~per~~Supplemental ~~Bbl~~Cash ~~for~~Flow ~~23,000~~Information ~~Bbls per day for January to December 2010.~~

AsThe offollowing ~~September 30,~~are ~~2009,~~total aninterest ~~unrealized~~and ~~pre-tax derivative fair value gain of $794 million, related to cash flow hedges of oil price risk, was recorded in accumulated other comprehensive~~ income ~~(loss).~~tax ~~Based~~payments onduring ~~September 30~~each ~~mark-to-market prices, $665 million~~ of ~~this is expected to be reclassified into earnings through September 2010. The actual reclassification to earnings will be based on~~ the ~~amortization~~periods: ~~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.

7.The ~~Earnings~~accompanying ~~per~~consolidated ~~Share~~statements of cash flows exclude the following non-cash stock award transactions (Note 10) during the three-month periods ended March 31, 2010 and 2009:

~~Effective~~• ~~January 1,~~Vesting ~~2009, we adopted the provisions~~ of ~~the~~2,500 ~~new~~restricted ~~rules~~shares ~~found~~and inforfeitures ~~the Earning per Share Topic~~ of ~~the FASB Accounting Standards Codification regarding the computation of EPS using the two-class method. Under the rules~~26,000 ~~share-based payment awards that contain nonforfeitable rights to dividends, as is the case with our~~ restricted ~~and performance~~ shares, ~~are “participating securities” and therefore should be included~~ in ~~computing~~ ~~earnings per share using the two-class method~~2010. AsGrants ~~a result~~ of ~~adoption~~2,000 werestricted ~~retrospectively~~shares, ~~adjusted~~vesting ~~the calculation~~ of ~~our 2008 and prior periods’ earnings per share. The previously reported earnings per share for the three months ended September 30~~2,000 ~~2008~~restricted ~~were~~shares ~~$0.95 basic~~ and ~~$0.94~~forfeitures ~~diluted~~of ~~and for the nine months ended September 30~~29,000 ~~2008~~restricted ~~were $3.02 basic and $2.98 diluted. The following reconciles earnings and~~ shares ~~used~~ in ~~the computation of basic and diluted earnings per common share:~~ 2009.

(in millions, except per share data)	Three Months Ended September 30
	2009							2008
	Earnings			Shares		Earningsper Share		Earnings			Shares		Earningsper Share
Total	$	500		580.2				$	521		549.4
Attributable to participating securities		(4	)	(4.6	)				(3	)	(2.8	)
Basic	$	496		575.6		$	0.86	$	518		546.6		$	0.95
Effect of dilutive securities:
Stock options		—		2.8					—		4.1
Warrants		—		1.2					—		1.5
Diluted	$	496		579.6		$	0.86	$	518		552.2		$	0.94

•

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

(in millions, except per share data)	Nine Months Ended September 30
	2009							2008
	Earnings			Shares		Earningsper Share		Earnings			Shares		Earningsper Share
Total	$	1,482		579.9				$	1,561		519.8
Attributable to participating securities		(12	)	(4.6	)				(8	)	(2.5	)
Basic	$	1,470		575.3		$	2.56	$	1,553		517.3		$	3.00
Effect of dilutive securities:
Stock options		—		2.4					—		5.3
Warrants		—		1.1					—		1.6
Diluted	$	1,470		578.8		$	2.54	$	1,553		524.2		$	2.96

•

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

~~Certain~~• ~~options~~Grants ~~to purchase shares of our common stock have been excluded from the 2009~~ and ~~2008~~immediate ~~diluted~~vesting ~~calculations because the options are anti-dilutive. Anti-dilutive options for 7.6 million shares in the three-month 2009 period with a weighted average exercise price~~ of ~~$52.58~~25,000 ~~and~~unrestricted ~~7.7 million~~common shares into ~~the~~nonemployee ~~nine-month 2009~~directors ~~period with a weighted average exercise price of $52.03 were excluded. Anti-dilutive options for 1.7 million~~ in ~~the~~2010 ~~three-month 2008 period with a weighted average price of $68.68~~ and 12009.~~6 million shares in the nine-month 2008 period with a weighted average exercise price of $69.19 were excluded.~~

•

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

10. Employee Benefit Plans

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


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

(a)

Recorded as additional paid-in-capital

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

In January 2010, our Chairman of the Board and Founder received 110,000 unrestricted common shares and 40,000 performance shares, half of which vest when the stock price closes at or above $50.00 and half of which vest when the stock price closes at or above $52.00. As a result of our announced merger agreement with ExxonMobil, these performance shares will vest at closing if the proposed merger with ExxonMobil is completed. If the merger is not completed, the vesting criteria would revert to the price vesting terms. In February 2010, each nonemployee director received 4,166 shares for a total of approximately 25,000 unrestricted common shares that cannot be sold for two years following the date of grant except in certain circumstances, including a merger such as our proposed merger with ExxonMobil.

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

8. Supplemental Cash Flow Information

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

	Nine Months EndedSeptember 30
(in millions)	2009		2008
Interest	$	410	$	319
Income tax	$	319	$	6

The accompanying consolidated statements of cash flows exclude the following non-cash transactions during the nine-month periods ended September 30, 2009 and 2008:

• The following non-cash stock award transactions (Note 9):

• Grants of 22,000 restricted shares, vesting of 75,000 restricted shares and forfeitures of 75,000 restricted shares in 2009. Grants of 182,000 restricted shares, vesting of 17,000 restricted shares and forfeitures of 43,000 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.

• Grant 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 100,000 shares at a weighted average exercise price of $40.26 per share in 2009 and 1.5 million shares at a weighted average exercise price of $56.76 per share in 2008.

• Non-cash component of the July 2008 Headington Oil Company acquisition purchase price, including issuance to the seller of 11.7 million shares of common stock.

• Non-cash components of the September 2008 Hunt Petroleum acquisition purchase price, including issuance to the seller of 23.5 million shares of common stock and assumption of debt and other liabilities (Note 10).

9. Employee Benefit Plans

	Three Months EndedSeptember 30				Nine Months EndedSeptember 30
(in millions)	2009		2008		2009		2008
Non-cash stock option compensation expense	$	8	$	14	$	39	$	57
Non-cash performance share and unrestricted share compensation expense		3		13		21		24
Non-cash restricted stock compensation expense		16		10		49		29
Related tax benefit recorded in income statement		10		13		40		40
Intrinsic value of stock option exercises		2		4		11		202
Income tax benefit on exercise of stock options or vesting of stock awards (a)		—		2		5		71

(a) Recorded as additional paid-in capital

During the first nine 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 544,000 stock options were exercised at a weighted average exercise price of $20.81 per share. As a result of these exercises, outstanding common stock increased by 400,000 shares and stockholders’ equity increased by a net $9 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 nine months of 2009, we granted 369,000 performance shares. The table below shows the number of shares and vesting prices for outstanding performance shares at September 30, 2009.

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

As of September 30, 2009, nonvested stock options had remaining unrecognized compensation expense of $17 million. Total deferred compensation at September 30, 2009 related to restricted shares was $88 million. For these nonvested stock awards, we estimate that stock incentive compensation for service periods after September 30, 2009 will be $20 million in 2009, $58 million in 2010 and $27 million in 2011. The weighted average remaining vesting period is 0.8 years for stock options and 1.6 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 final 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.

(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		385
Long-term debt		337
Asset retirement obligation		168
Other long-term liabilities		5
Deferred income taxes		1,057
Total purchase price plus liabilities assumed	$	6,138
Fair value of assets acquired:
Cash and cash equivalents	$	198
Other current assets		295
Proved properties		4,065
Unproved properties		250
Other property and equipment		70
Goodwill (non-deductible for income taxes)		1,260
Total fair value of assets acquired	$	6,138

The acquisition was recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for the nine months ended September 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)	Nine MonthsEndedSeptember 30,2008		Year EndedDecember 31,2008
Revenues	$	6,488	$	8,450
Net Income	$	1,739	$	2,090
Earnings per common share:
Basic	$	3.22	$	3.80
Diluted	$	3.18	$	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 ~~September~~March 3031, ~~2009~~2010, the related consolidated statements of income, ~~and~~ comprehensive income ~~for the three- and nine-month periods ended September 30~~, ~~2009~~stockholders’ ~~and~~equity ~~2008,~~ and ~~the related consolidated statements of~~ cash flows ~~and stockholders’ equity~~ for the ~~nine~~three-month periods ended ~~September~~March 3031, ~~2009~~2010 and ~~2008~~2009. These consolidated financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of XTO Energy Inc. as of December 31, ~~2008~~ 2009, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the year then ended (not presented herein), included in the Company’s ~~2008~~2009 Annual Report on Form 10-K, and in our report dated February 2524, ~~2009~~2010, we expressed an unqualified opinion on those statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, ~~2008~~2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet included in the Company’s ~~2008~~2009 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Fort Worth, Texas

~~November~~May 45, ~~2009~~2010

2320

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~~2009 Annual Report on on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

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

Gas, Natural Gas Liquids and Oil Production and Prices

	Three Months Ended September 30						Nine Months Ended September 30
	Three Months Ended March 31
	2009		2008		Increase(Decrease)		2009		2008		Increase(Decrease)
	2010		2009		Increase(Decrease)
Total production
Gas (Mcf)		~~222~~215,~~691~~812,~~397~~621		~~179~~200,~~348~~501,~~090~~903	248	%		~~637,217,522~~		~~498,123,918~~	28	%
Natural gas liquids (Bbls)		21,~~024~~798,~~880~~214		1,~~427~~647,~~555~~278	429	%		~~5,557,962~~		~~4,298,364~~	29	%
Oil (Bbls)		65,~~055~~789,~~593~~435		5,~~302~~906,~~631~~614	14(2	)%		~~18,258,504~~		~~14,659,078~~	25	%
Mcfe		~~271~~261,~~174~~338,~~235~~515		~~219~~245,~~729~~825,~~206~~255	236	%		~~780,116,318~~		~~611,868,570~~	27	%
Average daily production
Gas (Mcf)		2,~~420~~397,~~559~~918		12,~~949~~227,~~436~~799	248	%		~~2,334,130~~		~~1,817,971~~	28	%
Natural gas liquids (Bbls)		2219,~~010~~980		1518,~~517~~303	429	%		~~20,359~~		~~15,687~~	30	%
Oil (Bbls)		6564,~~822~~327		5765,~~637~~629	14(2	)%		~~66,881~~		~~53,500~~	25	%
Mcfe		2,~~947~~903,~~546~~761		2,~~388~~731,~~361~~392	236	%		~~2,857,569~~		~~2,233,097~~	28	%
Average sales price
Gas per Mcf	$	6.9335	$	87.4224	(1812	)%	$	~~7.08~~	$	~~8.22~~	~~(14~~	)%
Natural gas liquids per Bbl	$	3043.5918	$	5323.6584	~~(43~~81	)%	$	~~26.87~~	$	~~55.14~~	~~(51~~	)%
Oil per Bbl	$	~~108~~92.0449	$	93104.4059	16(12	)%	$	~~106.61~~	$	~~88.55~~	20	%
Average sales price before hedging
Gas per Mcf	$	35.2228	$	94.3115	~~(65~~27	)%	$	~~3.52~~	$	~~9.07~~	~~(61~~	)%
Natural gas liquids per Bbl	$	3043.5918	$	6023.5184	~~(49~~81	)%	$	~~26.87~~	$	~~61.21~~	~~(56~~	)%
Oil per Bbl	$	6374.4832	$	~~113~~36.0938	~~(44~~104	)%	$	~~52.28~~	$	~~109.78~~	~~(52~~	)%
Average NYMEX prices
Gas per MMBtu	$	35.3930	$	104.2489	~~(67~~8	)%	$	~~3.93~~	$	~~9.73~~	~~(60~~	)%
Oil per Bbl	$	6878.2554	$	~~118~~43.5218	~~(42~~82	)%	$	~~57.09~~	$	~~113.49~~	~~(50~~	)%

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~~increased from ~~2008 to 2009 for~~ the ~~three-~~first ~~and~~quarter ~~nine-month~~of ~~periods~~2009 ~~are~~to 2010 primarily because of development activity ~~and acquisitions~~, partially offset by natural decline.

Gas prices ~~decreased~~before ~~from~~hedging ~~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~~average ~~levels~~NYMEX ~~of liquefied natural~~ gas. ~~Natural gas competes with other energy sources as fuel for heating and the generation of electricity. In the first part of 2008,~~ prices ~~for natural gas~~ increased ~~significantly~~from ~~reaching~~first asquarter ~~high~~2009 ~~as $13 per MMBtu in July 2008. Since that date, prices have dropped due~~ to ~~higher~~first ~~than~~quarter ~~average gas in storage caused by shale gas development and declining demand due to the U~~2010.~~S. recession.~~ Natural gas prices are ~~expected~~affected toby ~~remain~~the ~~volatile.~~level ~~The~~of ~~NYMEX~~North ~~contract~~American ~~price for October 2009 was $3.73 per MMBtu. At October 30~~production, ~~2009~~weather, ~~the~~crude ~~average~~oil ~~NYMEX~~prices, ~~futures price for~~ the ~~following twelve months was $5.61 per MMBtu.~~

2421

~~Oil~~ U.S. ~~prices~~economy, ~~before~~storage ~~hedging~~levels and ~~average~~import ~~NYMEX~~levels ~~oil~~of ~~prices~~liquefied ~~decreased~~natural ~~from~~gas. ~~2008~~Natural togas ~~2009.~~competes ~~Crude oil~~with ~~prices~~alternative ~~are~~energy ~~generally~~sources ~~determined~~as byfuel ~~global~~for ~~supply~~heating and ~~demand.~~the Ingeneration ~~the~~of ~~first~~electricity. ~~part~~Due to concerns of ~~2008~~oversupply from shale gas development, ~~prices~~declining ~~for~~demand ~~oil~~due ~~increased~~to ~~significantly~~the ~~reaching~~U.S. arecession, ~~record~~falling ~~high~~oil ~~above~~prices ~~$147~~and ~~per~~increased ~~Bbl~~gas in ~~July~~storage, ~~2008.~~gas ~~However,~~prices ~~lower~~declined ~~demand~~during asthe afirst ~~result~~nine months of ~~the~~2009. ~~global~~However, signs of possible economic ~~situation~~improvement, ~~caused~~higher oil prices toand ~~decline~~a relatively cold winter led to ~~below~~increased ~~$40~~gas ~~last~~prices ~~winter.~~in ~~Signs~~late of2009 ~~possible~~and ~~economic~~early ~~improvement~~2010. Gas prices have ~~resulted~~weakened substantially in ~~higher~~February ~~recent~~and ~~oil~~March ~~prices~~2010 due to renewed concerns of oversupply. ~~Oil~~Natural gas prices are expected to remain volatile. The ~~average~~ NYMEX contract price for ~~October~~April ~~2009~~2010 was $753.7084 per ~~Bbl~~ MMBtu. At ~~October~~April 30, ~~2009~~2010, the average NYMEX futures price for the following twelve months was $794.9175 per ~~Bbl~~MMBtu.

WeOil ~~use price~~prices before hedging ~~arrangements,~~and ~~including~~average ~~fixed-price~~NYMEX ~~physical~~oil ~~delivery~~prices ~~contracts,~~increased from first quarter 2009 to ~~reduce~~first ~~price~~quarter ~~risk~~2010. onCrude oil prices are generally determined by global supply and demand. Lower demand as a ~~portion~~result of ~~our~~the ~~production~~U.S. Werecession ~~have~~and ~~hedged~~slowing ~~most~~global ofeconomy, ~~our~~the tightened credit markets and rising crude oil ~~sales~~supplies ~~through~~caused ~~December~~oil ~~2010~~prices ~~and~~to adecline ~~portion~~sharply in 2008. However, signs of possible ~~our~~economic ~~natural~~improvement ~~gas~~have ~~sales~~resulted ~~through December~~in ~~2011;~~steadily ~~see~~higher ~~Note~~oil 6prices during 2009 and early 2010. Oil prices are expected to ~~Consolidated~~remain ~~Financial~~volatile. ~~Statements~~The average NYMEX price for April 2010 was $84.52 per Bbl. At April 30, 2010, the average NYMEX futures price for the following twelve months was $90.76 per Bbl.

We use price hedging arrangements, including fixed-price physical delivery contracts, to reduce price risk on a portion of our production. We have hedged most of our crude oil sales through December 2010 and a portion of our natural gas sales through December 2011; see Note 7 to Consolidated Financial Statements.

Results of Operations

Quarter Ended ~~September~~March 3031, ~~2009~~2010 Compared with Quarter Ended ~~September~~March 3031, ~~2008~~2009

Net income for ~~third~~first quarter ~~2009~~2010 was $~~500~~330 million compared to $~~521~~486 million for ~~third~~first quarter ~~2008~~2009. ~~Third~~First quarter ~~2009~~2010 earnings include a ~~$15~~ $13 million ($98 million after -tax) non-cash derivative fair value ~~loss~~gain. ~~Third~~First quarter ~~2008~~2009 earnings include a $3879 million ($2451 million after -tax) non-cash derivative fair value loss. ~~Operating~~and ~~income~~a ~~for~~$9 million ~~the quarter was~~ ($~~919~~6 million, aafter-tax) 5%gain ~~decrease~~on ~~from~~extinguishment ~~third quarter 2008 operating income~~ of ~~$969 million~~debt.

Total revenues for ~~third~~first quarter ~~2009~~2010 were $2.2900 billion, ana 87% ~~increase~~ decrease from ~~third~~first quarter ~~2008~~2009 revenues of $2.13 16 billion. Operating income for the quarter was $656 million, a 26% decrease from first quarter 2009 operating income of $881 million. Gas and natural gas liquids revenues ~~increased~~decreased $1943 million because of ~~the~~a 2412% ~~increase~~decrease in gas ~~production~~prices ~~and~~partially ~~the~~offset by 42an 8% increase in ~~natural~~ gas ~~liquids~~ production, ~~partially~~an ~~offset by the 18~~81% ~~decrease~~ increase in natural gas liquids prices and ~~the~~a 439% ~~decrease~~increase in natural gas liquids ~~prices~~production. Oil revenue ~~increased~~decreased $~~159~~83 million because of ~~the~~a 1412% ~~increase~~decrease in ~~production~~oil prices and ~~the~~a 162% ~~increase~~decrease in production. In addition, realized average gas and oil prices for the quarter decreased from first quarter 2009 due to the effect of hedges. In 2009, 2.12 billion cubic feet equivalent (Bcfe) per day of production was hedged at a natural gas equivalent price of $10.69 compared to 1.67 Bcfe per day of production hedged in 2010 at a natural gas equivalent price of $9.62.

Expenses for first ~~third~~ quarter ~~2009~~2010 totaled $1.3735 billion, ana 185% increase from ~~third~~first quarter ~~2008~~2009 expenses of $1.1628 billion. Increased expenses are generally related to increased production from development and ~~acquisitions and~~ related Company growth. Production expense decreased $14 1 million primarily because of lower ~~power, fuel,~~ compression, ~~workovers~~water disposal and ~~water~~power ~~disposable~~ costs, partially offset by increased overall production ~~and increased maintenance costs~~. Taxes, transportation and other ~~decreased~~increased $3225 million from the ~~third~~first quarter of ~~2008~~2009 primarily because of ~~lower~~ higher production taxes and transportation costs due to ~~lower~~higher product prices, ~~before~~excluding ~~hedging,~~the ~~partially~~effects ~~offset~~of byhedges, and higher ~~property~~gas ~~taxes~~volumes, ~~related~~partially tooffset ~~development~~by ~~and~~lower ~~the~~property ~~2008 acquisitions~~taxes. Depreciation, depletion and amortization increased $~~313~~54 million primarily because of ~~higher acquisition, development and facility costs and~~ increased production. Exploration expense decreased $2021 million primarily ~~because~~due ofto ~~decreased~~a ~~seismic~~$17 ~~costs~~million decrease in ~~the~~dry ~~Gulf~~hole ~~of Mexico~~expense. General and administrative expense ~~decreased~~increased $31 million ~~because of a $10 million decrease in non-cash incentive compensation, partially offset by increased other general and administrative expense~~ primarily due to ~~higher employee~~ expenses related to ~~Company~~the ~~growth~~pending merger with ExxonMobil.

~~The~~22 derivative fair value loss for third quarter 2009 was $2 million compared to $45 million in the same 2008 period. The loss in 2009 is primarily related to natural gas basis swaps that do not qualify for hedge accounting, partially offset by certain crude oil swap agreements that do not qualify for hedge accounting. See Note 5 to Consolidated Financial Statements.

Interest expense increased $4 million primarily because of a decrease in interest income. The effective income tax rate for third quarter 2009 was 36.1% compared with 37.8% for third quarter 2008. The lower 2009 rate is due to the expected benefits of permanent tax differences.

~~Nine~~The ~~Months~~derivative ~~Ended~~fair ~~September 30,~~value gain for first quarter 2010 and 2009 ~~Compared~~was ~~with~~$6 ~~Nine~~million. ~~Months~~The ~~Ended~~gain ~~September 30,~~in first ~~2008~~quarter 2010 is primarily related to the ineffective portion of hedge derivatives partially offset by the change in fair value of natural gas basis swap agreements that do not qualify for hedge accounting. See Note 6 to Consolidated Financial Statements.

~~Net~~Interest ~~income~~expense ~~for~~increased ~~the nine months ended September 30, 2008 was~~ $~~1.48~~13 ~~billion,~~million ~~compared~~primarily tobecause ~~$1.56 billion for the same 2008 period. Earnings for the first nine months~~ of ~~2009 include~~ a $~~122~~9 million ~~($78 million after tax) non-cash derivative fair value loss and a $17 million ($11 million after tax)~~ gain on extinguishment of debt. ~~Earnings~~in ~~for the first nine months of~~2009 ~~2008~~and ~~include~~lower ancapitalized ~~$11~~interest ~~million~~in ~~($7~~2010. ~~million~~The ~~after~~effective income tax) ~~non-cash~~rate ~~derivative fair value gain. Operating income~~ for ~~the~~ first ~~nine~~quarter ~~months~~2010 ~~of 2009~~ was $236.~~70 billion~~2%, aas 4%compared ~~decrease~~with ~~from operating income of $2~~35.806% ~~billion~~ for ~~the~~first ~~comparable~~quarter ~~2008 period~~2009.

Total revenues for the first nine months of 2009 were $6.72 billion, 17% higher than revenues of $5.73 billion for the first nine months of 2008. Gas and natural gas liquids revenues increased $326 million primarily because of the 28% increase in gas production and the 29% increase in natural gas liquids production, partially offset by the 14% decrease in gas prices and the 51% decrease in natural gas liquids prices. Oil revenue increased $649 million because of the 25% increase in production and the 20% increase in prices.

Expenses for the first nine months of 2009 totaled $4.02 billion, a 37% increase from total expenses for the first nine months of 2008 of $2.94 billion. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $81 million primarily because of increased overall production and increased maintenance costs, partially offset by decreased power, fuel and carbon dioxide injection costs. Taxes, transportation and other decreased $52 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 $999 million because of higher acquisition, development and facility costs and increased production. Exploration expense increased $2 million primarily because of increased dry hole expense, partially offset by decreased seismic costs. General and administrative expense increased $14 million because of increased other general and administrative expense primarily due to higher employee expenses related to Company growth.

The derivative fair value loss for the first nine months of 2009 was $17 million compared to a $3 million loss in the same 2008 period. The 2009 loss is primarily related to natural gas basis swaps and crude oil swap agreements that do not qualify for hedge accounting, partially offset by the ineffective portion of hedge derivatives.

Interest expense increased $63 million primarily because of a 23% increase in the weighted average borrowings incurred primarily to fund acquisitions, partially offset by a $17 million gain on extinguishment of debt. The 2009 year-to-date effective income tax rate was 35.8% compared with a 36.9% effective rate for the nine-month 2008 period. The lower 2009 rate 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 EndedSeptember 30						Nine Months EndedSeptember 30
	Three Months Ended March 31
	2009		2008		Increase(Decrease)		2009		2008		Increase(Decrease)
	2010		2009		Increase(Decrease)
Production	$	0.9298	$	1.1904	(236	)%	$	~~0.96~~	$	~~1.10~~	~~(13~~	)%
Taxes, transportation and other	$	0.6471	$	0.9465	~~(32~~9	)%		~~0.64~~		~~0.90~~	~~(29~~	)%
Depreciation, depletion and amortization (DD&A)	$	2.9988	$	2.2784	321	%		~~2.94~~		~~2.12~~	39	%
General and administrative (G&A):
Non-cash incentive compensation		0.10		0.17	(41	)%		0.14		0.18	(22	)%
Non-cash stock incentive compensation	$	0.15	$	0.16	(6	)%
All other G&A	$	0.1923	$	0.2123	~~(10~~—	)%		~~0.21~~		~~0.25~~	~~(16~~	)%
Interest	$	0.5053	$	0.6051	~~(17~~4	)%		~~0.50~~		~~0.53~~	(6	)%

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

Production expenses—Decreased production expense is primarily because of decreased ~~power, fuel,~~ compression, ~~carbon~~power ~~dioxide injection~~ and water disposal costs. ~~Power, fuel and carbon dioxide injection costs vary with product prices. Additionally, third quarter 2009 benefited from decreased workover costs.~~

Taxes, transportation and other—A portion of these expenses vary with product prices. ~~Decreased~~Increased taxes, transportation and other expense is primarily because of ~~lower~~higher product prices, ~~before~~excluding hedging, partially offset by ~~higher~~lower 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 ~~non-cash~~stock incentive compensation ~~and decreased all other G&A expense~~ is ~~due~~related to ~~increased~~a ~~production~~decrease ~~outpacing~~of ~~personnel~~$2 ~~and~~million ~~other~~in ~~expenses~~non-cash ~~related~~incentive toaward compensation ~~Company~~and ~~growth~~increased production.

Interest—~~Decreased~~Increased interest expense ~~for the third quarter~~ is ~~due~~primarily ~~to increased production. Interest expense decreased for the nine months~~ because of ~~increased production and~~ a $9 million gain on extinguishment of debt ofin ~~$17~~2009 ~~million,~~and ~~which~~lower ~~was~~capitalized ~~partially~~interest ~~offset by the 23% increase~~ in ~~weighted average borrowings to fund our 2008 acquisitions~~2010.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $51.2423 billion for ~~the~~ first ~~nine~~quarter ~~months of 2009~~2010, compared with $3.754 billion for the same ~~2008~~ 2009 period. Decreased ~~Increased~~first quarter cash provided by operating activities is primarily due ~~in part~~ to ~~production from development activity and acquisitions. Also, 2009 benefited from~~ the early settlement ~~and reset arrangements with seven~~ of ~~our~~hedges ~~financial~~in ~~counterparties~~2009. In January 2009, we entered into early settlement and reset arrangements with seven financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.2 billion which was used ~~primarily~~ 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~~decreased by changes in operating assets and liabilities of $~~708~~ 7 million in first ~~nine~~quarter ~~months~~2010 ~~2009~~ and ~~decreased~~increased by $2.0 ~~million~~billion in first ~~nine~~quarter ~~months 2008~~2009. 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 $29 million in first nine months 2009 and $55 million in first nine months 2008.

2723

~~During~~ and ~~the~~liabilities ~~nine~~are ~~months~~primarily ~~ended~~the ~~September 30,~~result ~~2009,~~of ~~cash~~timing ~~provided~~of bycash ~~operating~~receipts ~~activities of~~and $5disbursements.24 ~~billion~~Cash ~~was~~flow ~~used~~from tooperating ~~fund~~activities ~~development~~was ~~costs,~~also ~~net~~reduced ~~property~~by ~~acquisitions~~exploration ~~and~~expense, ~~other~~excluding ~~net~~dry ~~capital~~hole ~~additions of $3.25 billion~~expense, ~~dividends~~ of $~~215~~10 million ~~and~~in tofirst ~~pay~~quarter ~~down~~2010 and $~~1.56~~14 ~~billion~~million ~~of debt. The resulting decrease~~ in ~~cash~~first ~~and~~quarter ~~cash equivalents for the period was $1 million~~2009.

~~Total~~During ~~current~~the ~~assets~~quarter ~~decreased~~ended ~~$1.97~~March 31, ~~billion~~2010, ~~during~~cash provided ~~the~~by ~~first~~operating ~~nine~~activities ~~months~~ of ~~2009 primarily because of a~~ $1.5123 billion ~~decrease~~was inused ~~derivative~~to ~~fair~~fund ~~value~~net asproperty aacquisitions, ~~result~~development ofcosts ~~cash settlements of derivatives during the period~~ and ~~decreased~~other ~~accounts~~net ~~receivable~~capital ~~due~~additions toof ~~lower~~$802 ~~product prices~~million, ~~excluding~~dividends ~~hedges.~~of ~~Total current liabilities decreased~~ $~~562~~ 73 million ~~during~~and ~~the~~to ~~first~~pay ~~nine~~down ~~months~~$282 million of ~~2009~~debt. ~~primarily~~The ~~because~~resulting ofincrease ~~a decrease~~ in cash ~~deferred income taxes related to derivatives~~ and ~~decreased~~cash ~~accounts~~equivalents ~~payable~~for ~~and accrued liabilities due to lower commodity prices, excluding hedges, and lower drilling activity, partially offset by~~ the ~~increase~~period inwas ~~current~~$24 ~~maturities of long-term debt~~million.

~~Working~~Total ~~capital~~current ~~decreased~~assets ~~from~~increased ~~a positive position of~~ $~~1.33~~272 ~~billion~~million atduring ~~December 31,~~the ~~2008~~first quarter toof a2010 ~~negative~~primarily ~~position~~because of a $75229 million atincrease ~~September 30,~~in ~~2009.~~derivative ~~Excluding~~fair ~~the~~value ~~effects~~as ofa ~~derivative~~result ~~fair~~of ~~value~~a ~~and~~decrease ~~deferred~~in ~~tax~~future ~~current~~gas ~~liabilities~~prices, ~~working~~partially ~~capital~~offset ~~decreased~~by ~~from~~cash asettlements ~~negative position~~during ofthe ~~$432~~period. ~~million~~Total atcurrent ~~December 31,~~liabilities ~~2008~~increased to$43 amillion ~~negative~~during ~~position~~the first quarter of ~~$672~~2010 ~~million~~primarily atbecause ~~September 30,~~of ~~2009.~~increased ~~Any~~deferred ~~interim~~income ~~cash~~tax ~~needs~~payable ~~are~~due ~~funded~~to bythe ~~borrowings~~higher ~~under~~derivative ~~either~~fair ~~our~~value, ~~revolving~~partially ~~credit~~offset ~~agreement,~~by ~~our~~decreased ~~other~~accounts ~~unsecured~~payable and ~~uncommitted lines~~accrued ofliabilities ~~credit,~~due orto ~~our~~lower ~~commercial~~drilling ~~paper~~activity ~~program.~~and lower gas prices.

Working capital increased from a positive position of $247 million at December 31, 2009 to a positive position of $476 million at March 31, 2010. Excluding the effects of derivative fair value and deferred tax current liabilities, working capital improved from a negative position of $466 million at December 31, 2009 to a negative position of $393 million at March 31, 2010. Any interim cash needs are funded by borrowings under either our revolving credit agreement, our other unsecured and uncommitted lines of credit, or our commercial paper program.

Acquisitions and Development

Exploration and development expenditures for the first ~~nine~~three months of ~~2009~~2010 were $~~2.59~~680 ~~billion~~million compared with $21.551 billion for the first ~~nine~~ three months of ~~2008~~2009. ~~Our~~We ~~2009~~have budgeted $3.37 billion for the 2010 development and exploration ~~budget~~program isand ~~$3.1~~an ~~billion~~additional ~~and~~$530 ~~our~~million ~~budget~~ for construction of pipeline infrastructure and compression and processing facilities ~~is $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 ~~the~~ first ~~nine~~quarter ~~months of 2009~~2010, we completed acquisitions of both producing and unproved properties for $~~199~~ 44 million compared to $~~7.62~~94 ~~billion~~million for ~~the~~ first ~~nine~~quarter ~~months of 2008~~2009. These acquisitions were funded by cash provided by operating activities and are subject to typical post-closing adjustments.

While we expect to ~~continue~~focus ~~focusing~~ on development activities in ~~the remainder of 2009~~2010, aswe aplan ~~course~~to ofactively ~~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 ~~nine~~three months of ~~2009~~2010, we participated in drilling approximately ~~772~~165 gas wells and 6518 oil wells and performed ~~153~~ 32 workovers. Our year-to-date natural gas drilling activity was concentrated in East Texas and the Barnett, Fayetteville, Haynesville and Woodford shales,. ~~and~~Our ~~our~~ year-to-date ~~oil~~crude drilling activity was concentrated in the Permian Basin and Bakken Shale. Workovers have focused on recompletions, artificial lift and wellhead compression. These projects generally have met or exceeded management expectations.

Debt ~~and Equity~~

OnOur ~~September 30, 2009, we had no borrowings under our~~commercial ~~revolving~~paper ~~credit~~program ~~agreement~~availability ~~with~~is ~~commercial banks, and we had available borrowing capacity of~~ $2.3284 billion ~~net of our commercial paper borrowings~~. WeBorrowings ~~use~~under the ~~facility for general corporate purposes and as a backup facility for our~~ commercial paper program. Wereduce ~~have~~our ~~the~~available ~~option,~~capacity ~~with~~under ~~bank approval, to increase~~ the ~~commitment~~revolving upcredit tofacility anon ~~additional~~a ~~$660~~dollar-for-dollar ~~million~~basis. The ~~interest~~

2824

~~rate~~commercial onpaper ~~any~~borrowings ~~borrowing~~may ishave ~~generally~~terms ~~based~~up onto ~~the~~397 ~~one-month~~days ~~LIBOR~~and ~~plus~~bear ~~0.40%.~~interest ~~When~~at ~~utilization~~rates ofagreed ~~available~~to ~~commitments~~at isthe ~~greater~~time ~~than~~of ~~50%,~~ the borrowing. The interest rate onis ~~our~~based ~~borrowings~~on isa ~~increased~~standard ~~by 0.05%.~~index ~~Interest~~such isas ~~paid~~the atFederal Funds ~~maturity~~Rate, LIBOR, or ~~quarterly if~~ the ~~term~~money ismarket ~~for~~rate aas ~~period~~found ofon 90the ~~days~~commercial orpaper ~~more~~market. WeOn ~~also~~March 31, ~~incur~~2010, aborrowings ~~commitment~~under ~~fee~~our oncommercial ~~unused~~paper ~~borrowing~~program ~~commitments,~~were ~~which~~$340 ismillion ~~0.09%.~~at ~~The~~a ~~agreement~~weighted ~~requires~~average usinterest torate ~~maintain a debt-to-total capitalization ratio~~ of ~~not more than 65~~0.3%.

~~Our~~On March 31, 2010, we had no borrowings under our revolving credit agreement with commercial ~~paper~~banks, ~~program~~and ~~availability~~we ishad available borrowing capacity of $2.845 billion. ~~Borrowings~~net ~~under~~of ~~the~~our commercial paper ~~program~~ ~~reduce~~borrowings. ~~our~~We ~~available~~use ~~capacity~~the ~~under~~facility ~~the~~for ~~revolving~~general ~~credit~~corporate ~~facility~~purposes onand as a ~~dollar-for-dollar~~backup ~~basis.~~facility ~~The~~for our commercial paper ~~borrowings~~program. ~~may~~We have ~~terms~~the option, with bank approval, to increase the commitment up to an ~~397~~additional ~~days~~$660 ~~and~~million. ~~bear~~The interest atrate ~~rates~~on ~~agreed~~any toborrowing atis ~~the~~generally ~~time~~based ofon ~~the~~LIBOR ~~borrowing~~plus 0.40%. ~~The~~When ~~interest rate~~utilization of available commitments is ~~based~~greater than 50%, then the interest rate on aour ~~standard~~borrowings ~~index~~is ~~such~~increased asby ~~the~~0.05%. ~~Federal~~Interest ~~Funds~~is ~~Rate,~~paid ~~LIBOR~~at maturity, or quarterly if the ~~money~~term ~~market~~is ~~rate~~for asa ~~found~~period onof ~~the~~90 ~~commercial~~days ~~paper~~or ~~market~~more. OnWe ~~September 30,~~also ~~2009~~incur a commitment fee on unused borrowing commitments, ~~borrowings~~which ~~were~~is ~~$520~~0.09%. ~~million~~The atagreement arequires ~~weighted~~us ~~average~~to ~~interest~~maintain ~~rate~~a debt-to-total capitalization ratio of ~~0.4~~not more than 65%.

We have unsecured and uncommitted lines of credit with commercial banks totaling $~~300~~100 million. As of ~~September~~March 3031, ~~2009~~2010, there were no borrowings under these lines.

~~Repurchase of~~ Senior Notes

~~Common Stock~~ Dividends

In ~~August 2009~~February 2010, the Board of Directors declared a ~~third~~first quarter ~~2009~~2010 dividend of $0.125 per share ~~that~~payable ~~was~~April 15, ~~paid~~2010 ~~in October~~ to stockholders of record on ~~September~~March 3031, ~~2009~~2010. Under the terms of the merger agreement with ExxonMobil, during the period before the closing of the merger, we are prohibited from declaring, setting aside or paying any dividend or other distribution except for our regular quarterly cash dividend, which is not to exceed $0.125 per share. The merger agreement also provides that we will coordinate the declaration of dividends with ExxonMobil before the completion of the merger so that both our shareholders and the shareholders of ExxonMobil only receive, in any quarter, one dividend from each company.

Contractual Obligations and Commitments

The following summarizes our significant obligations and commitments to make future contractual payments as of ~~September~~ March 3031, ~~2009~~2010. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt or losses.

(in millions)			Payments Due by Year
			Payments Due by Year
	Total		2009		2010		2011		2012		2013		After 2013
(in millions)	Total		2010		2011		2012		2013		2014		After 2014
Debt	$	10,~~420~~240	$	—250	$	~~250~~—	$	—900	$	~~900~~2,240	$	~~2,420~~500	$	6,~~850~~350
Operating leases		8670		822		2923		2314		148		83		4—
Drilling contracts		~~163~~149		48103		9134		2211		21		—		—
Purchase commitments		3213		1413		18—		—		—		—		—
Transportation contracts		1,~~486~~855		41165		~~173~~231		~~185~~232		~~185~~227		~~179~~223		~~723~~777
Derivative contract liabilities at September 30, 2009 fair value		238		128		106		2		2		—		—
Derivative contract liabilities at March 31, 2010 fair value		165		157		5		3		—		—		—
Total	$	12,~~425~~492	$	~~239~~710	$	~~667~~293	$	~~232~~1,160	$	12,~~103~~476	$	~~2,607~~726	$	7,~~577~~127

~~Debt.~~25 Debt amounts represent scheduled maturities of our debt obligations at September 30, 2009, excluding $35 million of net discounts on our senior notes included in the carrying value of debt. At September 30, 2009,

Debt. Debt amounts represent scheduled maturities of our debt obligations at March 31, 2010, excluding $35 million of net discounts on our senior notes included in the carrying value of debt. At March 31, 2010, borrowings were $~~520~~340 million under our commercial paper program. Because we had both the intent and ability to refinance the balance due with borrowings under our credit facility due in April 2013, the $~~520~~340 million outstanding under the commercial paper program is reflected in the table above as due in 2013. Borrowings of $600 million under our term loans are due in 2013, and our senior notes, totaling $9.3 billion are due 2010 through 2038. For further information regarding debt, see Note 34 to Consolidated Financial Statements.

Drilling Contracts. We have contracts with various drilling contractors to use 4565 drilling rigs with terms of up to three years. Early termination of these contracts at ~~September~~March 3031, ~~2009~~2010 would have required us to pay maximum penalties of $8985 million. Based upon our planned drilling activities, we do not expect to pay significant early termination penalties.

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

Derivative Contracts. We have entered into futures contracts and swaps to hedge our exposure to ~~oil and~~ natural gas and oil price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of ~~September~~March 3031, ~~2009~~2010, the current liability related to such contracts was $~~186~~158 million and the noncurrent liability was $527 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts ~~are~~may be received as much as 55 days after payment to counterparties and can result in draws on our revolving credit facility, our other unsecured and uncommitted lines of credit or our commercial paper program. See Note 56 to Consolidated Financial Statements.

Accounting Pronouncements

In May 2009, the Financial Accounting Standards Board established 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. The new rule sets forth the period after the balance sheet date during which management should evaluate any events or transactions for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize such events or transactions in its financial statements, and the disclosures that an entity should make about such events or transactions. We have evaluated subsequent events through November 4, 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 call for 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.

In September 2009, the Financial Accounting Standards Board issued an exposure draft to update the Extractive Industries—Oil and Gas Topic of the FASB Accounting Standards Codification. The objective of the update is to align the oil and gas reserve estimation and disclosure requirements of the financial accounting standards with the SEC’s final rule discussed above. The proposed amendments would be effective for financial statements for fiscal years ending on or after December 31, 2009. These amendments are 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~~ 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.

words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. In particular, the factors discussed below and detailed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. The cautionary statements contained in our Annual Report on Form 10-K are incorporated herein by reference in addition to the following cautionary statements.

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

•

changes in commodity prices,

•

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

•

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

•

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

•

potential liability resulting from pending or future litigation,

•

changes in interest rates,

•

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

•

general domestic and international economic and political conditions.

3127

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~~2009 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this ~~Quarterly~~quarterly ~~Report~~report on Form 10-Q.

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

Interest Rate Risk

We are exposed to interest rate risk on debt with variable interest rates. At ~~September~~March 3031, ~~2009~~2010, our variable rate debt had a carrying value of $~~1.12~~940 ~~billion~~million, which approximated its fair value, and our fixed rate debt had a carrying value of $9.263 billion and an approximate fair value liability of $910.963 billion. Assuming a one percent, or 100-basis point, change in interest rates at ~~September~~ March 3031, ~~2009~~2010, the fair value of our fixed rate debt would change by approximately $~~724~~746 million.

Commodity Price Risk

We hedge a portion of our price risks associated with our natural gas and crude oil sales. As of ~~September~~March 3031, ~~2009~~2010, our outstanding futures contracts and swap agreements had a net fair value gain of $1.254 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 ~~September~~March 3031, ~~2009~~2010. The hypothetical change in fair value could be a gain or a loss depending on whether prices increase or decrease.

(in millions)	Fair Value		HypotheticalChange inFair Value
Natural gas futures and sell basis swap agreements	$	~~775~~1,198	$	~~331~~181
Natural gas purchase basis swap agreements		117		1
Crude oil futures and differential swaps		464		226
Crude oil futures		198		160

Because most of our futures contracts and swap agreements have been designated as hedge derivatives, changes in their fair value generally are reported as a component of accumulated other comprehensive income (loss) until the related sale of production occurs. At that time, the realized hedge derivative gain or loss is transferred to product revenues in the consolidated income statement. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

Item 4.

CONTROLS AND PROCEDURES

We performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed in reports filed with the Securities and Exchange Commission is recorded, processed, summarized and reported within the periods required and that this information is accumulated and communicated to allow timely decisions regarding required disclosures.

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

3228

PART II. OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

On ~~October~~December 1714, ~~1997~~2009, anExxon ~~action,~~Mobil ~~styled~~Corporation ~~United~~and ~~States~~XTO ofEnergy ~~America~~announced exthat ~~rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in~~ the ~~U.S.~~companies ~~District~~had ~~Court~~entered ~~for~~into ~~the~~a ~~Western~~definitive ~~District of Oklahoma by Jack J. Grynberg on behalf of~~agreement ~~the United States~~ under ~~the~~which ~~qui tam provisions of the U.S. False Claims Act against the Company and certain of our subsidiaries. The plaintiff alleges that~~ we ~~underpaid~~would ~~royalties~~become ona ~~natural~~wholly ~~gas produced from federal leases and lands~~ owned ~~by Native~~subsidiary ~~Americans in amounts in excess~~ of ~~20%~~ExxonMobil. asAs a result of ~~mismeasuring~~this ~~the volume of natural gas~~announcement, ~~incorrectly~~a ~~analyzing~~number ~~its~~of ~~heating~~putative ~~content~~shareholder ~~and~~class ~~improperly~~actions ~~valuing~~have ~~the~~been ~~natural~~filed, ~~gas.~~alleging ~~The~~breaches ~~plaintiff~~of ~~seeks~~fiduciary ~~treble~~duties ~~damages~~by ~~for~~ the ~~unpaid~~individual ~~royalties~~members ~~(with interest,~~or ~~attorney~~our ~~fees~~Board ~~and~~of Directors. ~~expenses),~~Each ~~civil~~lawsuit ~~penalties~~generally ~~between $5~~seeks,~~000~~ ~~and~~among ~~$10,000~~other ~~for each violation of the U.S. False Claims Act~~things, ~~and~~declaratory ~~an order for us to cease the allegedly improper measuring practices. This lawsuit against us~~ and ~~similar~~injunctive ~~lawsuits filed~~relief byconcerning the ~~plaintiff~~alleged ~~against~~fiduciary ~~more~~breaches, ~~than~~injunctive ~~300~~relief ~~other~~prohibiting ~~companies were consolidated in~~ the ~~United~~defendants ~~States~~from ~~District~~consummating ~~Court for Wyoming. In October 2002,~~ the ~~court granted a motion to dismiss the plaintiff’s royalty valuation claims~~merger, ~~and~~imposition ~~the plaintiff’s appeal~~ of ~~this~~constructive ~~decision~~trusts ~~was~~in favor ~~dismissed for lack~~ of ~~appellate~~plaintiffs ~~jurisdiction in May 2003. In response to a motion to dismiss filed by us~~ and ~~other~~putative ~~defendants,~~class inmembers ~~October 2006 the district judge held that the plaintiff failed to establish jurisdictional requirements to maintain the action against us~~ and ~~other~~unspecified ~~defendants~~monetary ~~and dismissed the action for lack of subject matter jurisdiction~~damages. InSeveral ~~September~~putative ~~2007,~~shareholders ~~the~~have ~~district~~also ~~judge dismissed those claims against us pertaining to the royalty value of carbon dioxide. The plaintiff~~ filed an ~~appeal~~individual oflawsuit ~~this~~in ~~decision~~federal tocourt ~~the~~alleging ~~United~~violations ~~States Tenth Circuit Court~~ of ~~Appeals. In March 2009,~~ the ~~Tenth~~federal ~~Circuit~~securities ~~affirmed~~laws ~~the~~based ~~trial~~on ~~court’s~~alleged ~~dismissal~~false ~~of the case but reversed~~ and ~~remanded the~~ ~~carbon~~material ~~dioxide~~misrepresentations ~~portion~~or ofomissions ~~the~~in ~~case to~~ the ~~trial~~preliminary ~~court.~~proxy ~~The~~filed ~~United~~with ~~States Supreme Court denied~~ the ~~plaintiff’s~~Securities ~~application~~and ~~for~~Exchange ~~appeal.~~Commission Wein ~~have~~connection ~~entered into an agreement~~ with the ~~plaintiff~~proposed ~~whereby we and the plaintiff are dismissing all claims against each other~~merger. The ~~court~~federal ~~granted~~individual ~~the~~action ~~dismissal~~also ofseeks ~~the~~to ~~claims~~enjoin onthe ~~November~~proposed ~~3, 2009, effectively ending this case~~merger.

~~In September~~Two ~~2008,~~putative weshareholder ~~acquired~~class ~~Hunt~~actions ~~Petroleum~~were ~~Corporation~~filed ~~and~~in ~~other~~the ~~associated~~Delaware ~~entities.~~Court ~~One~~ of ~~the~~Chancery ~~entities~~between ~~that~~December 17, we2009 ~~acquired~~and ~~owns~~December 18, 2009. ~~properties~~Those ~~that~~cases are ~~subject~~styled toas a(i) Teamsters ~~lawsuit~~Allied ~~styled~~Benefit ~~USA~~Funds, exet ~~rel~~al. ~~Grynberg~~ v. ~~Columbia~~XTO ~~Gas~~Energy ~~Transmission Company~~Inc., et al. ~~This~~, ~~lawsuit~~Case isNo. 5150, ~~one of the lawsuits that were~~ filed byon ~~Jack~~December 17, J.2009 ~~Grynberg~~ and ~~that~~(ii) Nicholas ~~were~~Lombardi ~~consolidated~~v. inXTO ~~the~~Energy ~~United~~Inc., ~~States~~et ~~District~~al., ~~Court~~Case ~~of Wyoming~~No. 5152, filed ~~The~~on ~~issues~~December 18, ~~and~~2009. ~~disposition~~On ~~are~~December 22, 2009, the ~~same~~Delaware asCourt ~~those~~of ~~discussed~~Chancery inentered ~~the~~an ~~Grynberg~~order ~~action~~consolidating ~~against~~the ~~XTO Energy~~complaints ~~described~~filed ~~above~~as ~~except~~of that ~~Hunt~~date ~~Petroleum~~under ~~did~~the ~~not~~caption ~~have~~In are ~~carbon~~XTO ~~dioxide~~Energy ~~related claim against it~~Inc. ~~This~~Shareholders ~~case is concluded~~Litigation.

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

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

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

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

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~~2009.

3330

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following summarizes purchases of our common stock during ~~third~~first quarter ~~2009~~2010:

Month	(a)Total Numberof SharesPurchased		(b)AveragePricePaid perShare		(c)Total Number ofShares Purchasedas Part ofPubliclyAnnounced Plansor Programs (1)	(d)MaximumNumber of Sharesthat May Yet BePurchased Underthe Plansor Programs
July			$		—
January	38,374		$	47.37	—
August	5,168		$	40.94	—
February	846		$	46.09	—
September			$		—
March	8,346		$	46.11	—
Total	547,~~168~~566	(2)	$	4047.9413	—	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~~ million shares of the Company’s common stock.

(2) Does not include ~~performance or~~ restricted share forfeitures. Includes 58,~~168~~596 shares of common stock delivered or attested to in satisfaction of the exercise price upon the exercise of employee stock options under both the 1998 and 2004 Stock Incentive Plans. Also includes 38,970 shares of common stock purchased during the quarter from employees in connection with the settlement of income tax withholding obligations upon vesting of ~~restricted~~unrestricted ~~shares~~ and ~~performance~~restricted shares under the 2004 Stock Incentive Plan. These share purchases were not part of a publicly announced program to purchase common stock.

~~Item~~Items 3. through 5.

Not applicable.

3431

Item 6.

EXHIBITS

Exhibit Number and Description
10.1*		Amendment to Employment Agreement between the Company and Bob R. Simpson, dated September 16, 2009
11		Computation of per share earnings (included in Note 8 to Consolidated Financial Statements)
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 ~~September~~March 3031, ~~2009~~2010, filed on ~~November~~May 56, ~~2009~~2010, formatted in XBRL; (i) Consolidated Balance Sheets, (ii) Consolidated Income Statements, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Stockholders’ Equity and (vi) the Notes to Consolidated Financial Statements, tagged as blocks of text.

*32 ~~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: November 4, 2009	By	/S/ LOUIS G. BALDWIN
Date: May 5, 2010	By	/S/ LOUIS G. BALDWIN
		Louis G. Baldwin
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)
	By	/S/ BENNIE G. KNIFFEN
		Bennie G. Kniffen
		Senior Vice President and Controller (Principal Accounting Officer)

3633

INDEX TO EXHIBITS

Documents filed prior to ~~September~~June 1, 2001 were filed with the Securities and Exchange Commission under our prior name, Cross Timbers ~~Oil~~ Oil Company. Except as otherwise specifically indicated, all documents are filed under Commission File Number 1-10662.

Exhibit No.	Description	Page
10.1*	Amendment to Employment Agreement between the Company and Bob R. Simpson, dated September 16, 2009
11	Computation of per share earnings (included in Note 8 to Consolidated Financial Statements)
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 ~~September~~March 3031, ~~2009~~2010, filed on ~~November~~May 56, ~~2009~~2010, formatted in XBRL; (i) Consolidated Balance Sheets, (ii) Consolidated Income Statements, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Stockholders’ Equity and (vi) the Notes to Consolidated Financial Statements, tagged as blocks of text.

*34 ~~Management contract or compensatory plan~~

Three Months Ended
March 31

(in millions)

Income tax

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