- Quarterly Report (10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2008

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

Commission File Number: 1-10662

XTO Energy Inc.

(Exact name of registrant as specified in its charter)


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

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

(817) 870-2800

(Registrant’s telephone number, including area code)

NONE

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

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

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


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

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

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


Class		Outstanding as of September 30, 2008
Common stock, $.01 par value		576,817,767

XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended September 30, 2008

TABLE OF CONTENTS


		Page
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets at September 30, 2008 and December 31, 2007	3

	Consolidated Income Statements for the Three and Nine Months Ended September 30, 2008 and 2007	4

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007	5

	Notes to Consolidated Financial Statements	6

	Report of Independent Registered Public Accounting Firm	22

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33

Item 4.	Controls and Procedures	33

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34

Item 6.	Exhibits	35

	Signatures	36

PART I. FINANCIAL INFORMATION

XTO ENERGY INC.

Consolidated Balance Sheets


	September 30, 2008			December 31, 2007
*(in millions, except shares)*	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	19		$	—
Accounts receivable, net		1,446			852
Derivative fair value		1,048			199
Current income tax receivable		7			118
Deferred income tax benefit		—			20
Other		181			98

Total Current Assets		2,701			1,287

Property and Equipment, at cost – successful efforts method:
Proved properties		29,144			18,671
Unproved properties		3,567			1,050
Other		2,068			1,376

Total Property and Equipment		34,779			21,097
Accumulated depreciation, depletion and amortization		(5,169	)		(3,897	)

Net Property and Equipment		29,610			17,200

Other Assets:
Derivative fair value		541			—
Acquired gas gathering contracts, net of accumulated amortization		107			112
Goodwill		1,452			215
Other		137			108

Total Other Assets		2,237			435

TOTAL ASSETS	$	34,548		$	18,922

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	2,119		$	1,264
Payable to royalty trusts		28			30
Derivative fair value		102			239
Deferred income tax payable		345			—
Other		30			4

Total Current Liabilities		2,624			1,537

Long-term Debt		11,122			6,320

Other Liabilities:
Derivative fair value		2			4
Deferred income taxes payable		4,641			2,610
Asset retirement obligation		721			450
Other		72			60

Total Other Liabilities		5,436			3,124

Commitments and Contingencies (Note 5)
Stockholders’ Equity:
Common stock ($.01 par value, 1,000,000,000 shares authorized, 582,005,096 and 490,434,003 shares issued)		6			5
Additional paid-in capital		8,257			3,172
Treasury stock, at cost (5,187,329 and 5,140,230 shares)		(134	)		(134	)
Retained earnings		6,307			4,938
Accumulated other comprehensive income (loss)		930			(40	)

Total Stockholders’ Equity		15,366			7,941

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	34,548		$	18,922

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Income Statements (Unaudited)


	Three Months Ended September 30						Nine Months Ended September 30
*(in millions, except per share data)*	2008			2007			2008		2007
REVENUES
Gas and natural gas liquids	$	1,586		$	1,090		$	4,333	$	2,981
Oil and condensate		495			310			1,298		865
Gas gathering, processing and marketing		43			25			103		77
Other		1			(4	)		—		(4	)

Total Revenues		2,125			1,421			5,734		3,919

EXPENSES
Production		262			165			670		440
Taxes, transportation and other		206			124			554		312
Exploration		30			22			62		33
Depreciation, depletion and amortization		498			326			1,294		831
Accretion of discount in asset retirement obligation		7			5			21		16
Gas gathering and processing		25			21			70		62
General and administrative		83			48			261		156
Derivative fair value (gain) loss		45			3			3		(10	)

Total Expenses		1,156			714			2,935		1,840

OPERATING INCOME		969			707			2,799		2,079

OTHER EXPENSE
Interest expense, net		132			64			325		158

INCOME BEFORE INCOME TAX		837			643			2,474		1,921

INCOME TAX EXPENSE
Current		(65	)		100			155		307
Deferred		381			131			758		387

Total Income Tax Expense		316			231			913		694

NET INCOME	$	521		$	412		$	1,561	$	1,227

EARNINGS PER COMMON SHARE
Basic	$	0.95		$	0.86		$	3.02	$	2.62

Diluted	$	0.94		$	0.84		$	2.98	$	2.58

DIVIDENDS DECLARED PER COMMON SHARE	$	0.12		$	0.12		$	0.36	$	0.36

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic		546.6			481.1			517.3		468.2

Diluted		552.2			489.2			524.4		475.9

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended September 30
*(in millions)*	2008			2007
OPERATING ACTIVITIES
Net income	$	1,561		$	1,227
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		1,294			831
Accretion of discount in asset retirement obligation		21			16
Non-cash incentive compensation		110			38
Dry hole expense		7			10
Deferred income tax		758			387
Non-cash change in derivative fair value (gain) loss		(11	)		42
Other non-cash items		12			7
Changes in operating assets and liabilities net of effects of acquisition of corporation (a)		(2	)		83

Cash Provided by Operating Activities		3,750			2,641

INVESTING ACTIVITIES
Proceeds from sale of property and equipment		—			1
Property acquisitions, including acquisitions of corporations		(7,846	)		(3,256	)
Development costs, capitalized exploration costs and dry hole expense		(2,354	)		(1,956	)
Other property and asset additions		(552	)		(507	)

Cash Used by Investing Activities		(10,752	)		(5,718	)

FINANCING ACTIVITIES
Proceeds from long-term debt		13,481			5,751
Payments on long-term debt		(9,011	)		(3,098	)
Dividends		(181	)		(124	)
Senior note offerings and debt costs		(32	)		(19	)
Net proceeds from common stock offerings		2,612			1,009
Proceeds from exercise of stock options and warrants		23			26
Payments upon exercise of stock options		(70	)		(44	)
Excess tax benefit on exercise of stock options		64			48
Other, primarily increase in cash overdrafts		135			27

Cash Provided by Financing Activities		7,021			3,576

INCREASE IN CASH AND CASH EQUIVALENTS		19			499
Cash and Cash Equivalents, Beginning of Period		—			5

Cash and Cash Equivalents, End of Period	$	19		$	504

(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	(370	)	$	(40	)
Other current assets		59			3
Other operating assets and liabilities		(5	)		(5	)
Current liabilities		314			125

	$	(2	)	$	83

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Notes to Consolidated Financial Statements (Unaudited)

1. Interim Financial Statements

The accompanying consolidated financial statements of XTO Energy Inc. (formerly named Cross Timbers Oil Company), with the exception of the consolidated balance sheet at December 31, 2007, have not been audited by independent public accountants. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at September 30, 2008, our income for the three and nine months ended September 30, 2008 and 2007 and cash flows for the nine months ended September 30, 2008 and 2007. All such adjustments are of a normal recurring nature. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

The financial data for the three- and nine-month periods ended September 30, 2008 and 2007 included herein have been subjected to a limited review by KPMG LLP, our independent registered public accountants. The accompanying review report of independent registered public accountants is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the independent registered public accountant’s liability under Section 11 does not extend to it.

Certain disclosures have been condensed or omitted from these financial statements. Accordingly, these financial statements should be read with the consolidated financial statements included in our 2007 Annual Report on Form 10-K.

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

Other

Inventory of tubular goods and equipment for future use on our producing properties is included in other current assets in the consolidated balance sheets, with balances of $96 million at September 30, 2008 and $60 million at December 31, 2007.

Our effective income tax rates for the three- and nine- month periods ended September 30, 2008 and 2007 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 from the intrinsic value of stock options at their exercise date. This is not the same grant date fair value that is expensed under United States generally accepted accounting principles. This benefit, which is recorded in additional paid-in capital, was $71 million for the first nine months of 2008 and $48 million for the first nine months of 2007.

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

2. Related Party Transactions

A firm, affiliated with one of our nonemployee directors, has performed property acquisition advisory services for the Company. A division of this firm also performed co-manager services on our February and August 2008 common stock offerings (Note 8) and our April and July 2008 senior note offerings (Note 4). We have paid this firm total fees of $11.8 million in 2008. Of this amount, $8 million was included in accounts payable and accrued liabilities in the Consolidated Balance Sheets at September 30, 2008.

In February 2007, in recognition of the Chairman and Chief Executive Officer of the Company and as part of a charitable giving program to support higher education, the Board of Directors approved a conditional

contribution of $6.8 million to assist in building an athletics and academic center at Baylor University. This contribution was paid in two equal installments of $3.4 million. The first payment was made May 2007 and the second was paid in July 2008. Since this is a conditional contribution, the first payment was included as general and administrative expense in second quarter 2007, and the second payment was included in general and administrative expense when the condition was satisfied in second quarter 2008. Concurrently, our Chairman and Chief Executive Officer made a $3.2 million pledge for the same project. In return for these contributions, the Company and our Chairman and Chief Executive Officer obtained naming rights for the building and certain facilities within the building.

3. Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of the asset retirement obligation activity for the nine months ended September 30, 2008:


*(in millions)*
Asset retirement obligation, December 31, 2007	$	453
Revision in estimated cash flows		52
Liability incurred upon acquiring and drilling wells		227
Liability settled upon plugging and abandoning wells		(7	)
Accretion of discount expense		21

Asset retirement obligation, September 30, 2008		746
Less current portion		(25	)

Asset retirement obligation, long-term	$	721

4. Long-term Debt

Our long-term debt consists of the following:


*(in millions)*	September 30, 2008		December 31, 2007
Bank debt:
Commercial paper, 3.6% at September 30, 2008	$	1,059	$	772
Revolving credit agreement due April 1, 2013		—		—
Term loan due April 1, 2013, 2.9% at September 30, 2008		500		300
Term loan due February 5, 2013, 2.9% at September 30, 2008		100		—
Senior notes:
5.00%, due August 1, 2010, net of discount		250		—
7.50%, due April 15, 2012		350		350
5.90%, due August 1, 2012, plus premium		553		553
6.25%, due April 15, 2013		400		400
4.625%, due June 15, 2013, net of discount		400		—
5.75%, due December 15, 2013, net of discount		500		—
4.90%, due February 1, 2014, net of discount		498		497
5.00%, due January 31, 2015, net of discount		350		350
5.30%, due June 30, 2015, net of discount		399		399
5.65%, due April 1, 2016, net of discount		400		400
6.25%, due August 1, 2017, plus premium		753		753
5.50%, due June 15, 2018, net of discount		796		—
6.50%, due December 15, 2018, net of discount		997		—
6.10%, due April 1, 2036, net of discount		596		596
6.75%, due August 1, 2037, net of discount		1,422		950
6.375%, due June 15, 2038, net of discount		799		—

Total long-term debt	$	11,122	$	6,320

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

Commercial Paper

In third quarter 2008, we increased our commercial paper program availability to $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 30, 2008, borrowings under our commercial paper program were $1.06 billion at a weighted average interest rate of 3.6%.

Bank Debt

On September 30, 2008, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $1.78 billion net of our commercial paper borrowings. In February 2008, we amended this agreement to, among other things, extend the maturity date to April 1, 2013. In third quarter 2008, we increased the borrowing capacity to $2.84 billion. We have annual options to request successive one-year extensions and the option to increase the commitment up to an additional $0.66 billion. The interest rate on any borrowing is generally based on LIBOR plus 0.40%. If our utilization of available commitments is greater than 50%, then the interest rate on our borrowings will be 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 use the facility for general corporate purposes and as a backup facility for our commercial paper program. During the nine months ended September 30, 2008, we had not borrowed under our revolving credit facility. Recent events in global financial markets have resulted in distortions in the commercial paper markets. In response, in fourth quarter 2008, we have used a combination of commercial paper and borrowings under our revolving credit facility to meet our short-term funding needs.

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

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

We have unsecured and uncommitted lines of credit with commercial banks totaling $300 million. As of September 30, 2008, there were no borrowings under these lines.

Senior Notes

In April 2008, we sold $400 million of 4.625% senior notes due June 15, 2013, $800 million of 5.50% senior notes due June 15, 2018 and $800 million of 6.375% senior notes due June 15, 2038. The 4.625% senior notes were issued at 99.888% of par to yield 4.651% to maturity. The 5.50% senior notes were issued at 99.539% of par to yield 5.561% to maturity. The 6.375% senior notes were issued at 99.864% of par to yield 6.386% to maturity. Net proceeds of $1.98 billion were used to fund property acquisitions that closed during the second and third quarters of 2008 (Note 13), to pay down outstanding commercial paper borrowings and for general corporate purposes.

In August 2008, we sold $250 million of 5.00% senior notes due August 1, 2010, $500 million of 5.75% senior notes due December 15, 2013, $1.0 billion of 6.50% senior notes due December 15, 2018 and $500 million of 6.75% senior notes due August 1, 2037. The notes due 2037 constitute a further issuance of the 6.75% senior notes issued in July 2007. The 5.00% senior notes were issued at 99.988% of par to yield 5.007% to maturity. The 5.75% senior notes were issued at 99.931% of par to yield 5.767% to maturity. The 6.50% senior notes were issued at 99.713% of par to yield 6.540% to maturity. The 6.75% senior notes were issued at 94.391% of par to yield 7.214% to maturity. Net proceeds of $2.2 billion were used to partially fund the cash portion of the Hunt acquisition (Note 13).

5. Commitments and Contingencies

Litigation

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al. , was filed in the U.S. District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against the Company and certain of our subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other companies were consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. In response to a motion to dismiss filed by us and other defendants, in October 2006 the district judge held that Grynberg failed to establish jurisdictional requirements to maintain the action against us and other defendants and dismissed the action for lack of subject matter jurisdiction. In September 2007, the district judge dismissed those claims against us pertaining to the royalty value of carbon dioxide. Grynberg has filed appeals of these decisions. While we are unable to predict the final outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

In July 2005 a predecessor company, Antero Resources Corporation, was served with a lawsuit styled Threshold Development Company, et al. v. Antero Resources Corp., which lawsuit was filed in the District Court of Wise County, Texas. The plaintiffs are surface owners, royalty owners and prior working interest owners in several oil and gas leases as well as other contractual agreements under which Antero Resources Corporation owned an interest. Antero Resources Corporation, the defendant, was acquired by us on April 1, 2005. The claims relate to alleged events pre-dating the acquisition and concern non-payment of royalties, improper calculation of royalties, improper pricing related to royalties, trespass, failure to develop and breach of contract. We settled all claims related to the payment of royalties and trespass. Under the remaining claims, the plaintiffs were seeking both damages and termination of the existing oil and gas leases covering their interests. In October 2008, the trial judge advised the parties that he was granting our motion for summary judgment, which will result in the dismissal of the plaintiffs’ remaining claims. The final order has not been entered. Based on a review of the current facts and circumstances with counsel, management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter. While acknowledging the uncertainties of litigation, management believes that the ultimate outcome of this matter will not have a material effect on our earnings, cash flows or financial position.

We are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on our financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year.

Transportation Contracts

We have entered firm transportation contracts with various pipelines. Under these contracts we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. We have generally delivered at least minimum volumes under our firm transportation contracts, therefore avoiding payment for deficiencies. As of September 30, 2008, maximum commitments under our transportation contracts were as follows:


*(in millions)*
2008	$	29
2009		122
2010		121
2011		116
2012		107
Remaining		417

Total	$	912

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

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

In October 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 Trunkline Pipeline, Mississippi. Upon the pipeline’s completion, we will transport gas volumes for a transportation fee of up to $1.25 million per month plus fuel, currently expected to be 0.86% of the sales price.

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

Drilling Contracts

As of September 30, 2008, we have contracts with various drilling contractors to use 99 drilling rigs with terms of up to three years and minimum future commitments of $96 million in 2008, $202 million in 2009, $48 million in 2010 and $11 million in 2011. Early termination of these contracts at September 30, 2008 would have required us to pay maximum penalties of $159 million. Based upon our planned drilling activities, we do not expect to pay any early termination penalties related to these contracts.

Other

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

See Note 7 regarding commodity sales commitments.

6. Financial Instruments

Derivatives

We use commodity-based and financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also may enter gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts. Therefore, these contracts are not recorded in the financial statements.

All derivatives are recorded on the balance sheet at estimated fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or the value confirmed by the counterparty. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), which is later transferred to earnings when the hedged transaction occurs (Note 10). Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of the hedge derivatives, are recorded in derivative fair value (gain) loss in the income statement. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged.

Derivative Fair Value (Gain) Loss

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


	Three Months Ended September 30						Nine Months Ended September 30
*(in millions)*	2008			2007			2008			2007
Change in fair value of derivatives that do not qualify for hedge accounting	$	58		$	(7	)	$	(5	)	$	(4	)
Ineffective portion of derivatives qualifying for hedge accounting		(13	)		10			8			(6	)

Derivative fair value (gain) loss	$	45		$	3		$	3		$	(10	)

The fair value (gain) loss in 2008 includes a $38 million loss ($24 million after-tax) on certain natural gas futures that no longer qualify for hedge accounting due to the September 2008 bankruptcy filing of Lehman Brothers Holdings Inc., the parent company of one of our counterparties. The remaining loss in the 2008 quarterly period and the gain in the 2008 year-to-date period and in the 2007 periods related to derivatives that do not qualify for hedge accounting and are primarily related to natural gas basis swap agreements. Except to the extent basis swap agreements are utilized in conjunction with NYMEX future contracts, they cannot qualify for hedge accounting.

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


	Three Months Ended September 30					Nine Months Ended September 30
*(in millions)*	2008		2007			2008			2007
Net cash paid to (received from) counterparties	$	7	$	(3	)	$	14		$	(52	)
Non-cash change in derivative fair value		38		6			(11	)		42

Derivative fair value (gain) loss	$	45	$	3		$	3		$	(10	)

Fair Value Measurements

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

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

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

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

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

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

The fair value of our derivative contracts are measured using Level II inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices. In accordance with SFAS No. 157, counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are generally A- or better rated companies, given the current financial environment, the fair value of our derivative contracts have been adjusted to account for the risk of nonperformance by the counterparty.

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

The estimated fair values of derivatives included in the consolidated balance sheets at September 30, 2008 and December 31, 2007 are summarized below. The change in the net derivative liability at December 31, 2007 to a net derivative asset at September 30, 2008 is primarily attributable to the effect of lower natural gas, natural gas liquids and crude oil prices and by cash settlements of derivatives.


	Fair Value Measurements
	September 30, 2008						December 31, 2007
*(in millions)*	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Derivative Assets:
Fixed-price natural gas futures and basis swaps	$	898		$	—		$	198		$	—
Fixed-price crude oil futures and differential swaps		691			—			1			—
Derivative Liabilities:
Fixed-price natural gas futures and basis swaps		(18	)		—			(13	)		—
Fixed-price crude oil futures and differential swaps		(84	)		—			(208	)		—
Fixed-price natural gas liquids futures		(2	)		—			(22	)		—

Net derivative asset (liability)	$	1,485		$	—		$	(44	)	$	—

Asset retirement obligation	$	—		$	(746	)	$	—		$	(453	)

Concentrations of Credit Risk

Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated companies. Letters of credit or other appropriate security are obtained as considered necessary to mitigate risk of loss. Financial and commodity-based swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, and we have master netting agreements with most counterparties that provide for offsetting payables against receivables from separate derivative contracts. As discussed above in “Derivative Fair Value (Gain) Loss”, in September 2008, the parent company of one of our counterparties filed for bankruptcy, and we recognized a loss on the related derivative contracts with this counterparty in derivative fair value (gain) loss in the income statement. Our allowance for uncollectible receivables was $12 million at September 30, 2008 and $7 million at December 31, 2007.

7. Commodity Sales Commitments

Our policy is to routinely hedge 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 plans to continue this strategy 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 and crude oil sales. When actual commodity prices exceed the fixed price provided by these contracts, we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We have hedged a portion of our exposure to variability in future cash flows from natural gas liquids sales through December 2008 and from natural gas sales and crude oil sales through December 2010.

Natural Gas

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


Production Period		Mcf per Day	Weighted Average NYMEX Price Per Mcf
2008	October to December	1,503,000	$	8.73	(a)
2009	January to December	1,640,000	$	8.91
2010	January to December	650,000	$	8.72

(a)

Includes swap agreements for 30,000 Mcf per day acquired in the Hunt Petroleum acquisition (Note 13) at the September 2, 2008 mark-to-market price of $8.37 per Mcf, which is the price used for cash flow hedge accounting purposes. The weighted average cash settlement contract price is $8.45 per Mcf.

In the Hunt Petroleum acquisition, we acquired natural gas collars comprised of the following put and call options. The contracts are not designated as cash flow hedges. Changes in the fair market value of these options are recorded as a derivative fair value (gain) loss in our consolidated income statement.


		Put Options			Call Options
Production Period		Mcf per Day	Weighted Average NYMEX Price Per Mcf		Mcf per Day	Weighted Average NYMEX Price Per Mcf
2008	October to December	20,000	$	7.76	20,000	$	9.55

The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered basis swap agreements that effectively fix the basis adjustment as shown below. Not all of our sell basis swap agreements are designated as hedges for hedge accounting purposes. Our fourth quarter 2008 sell basis swap agreements do not include approximately 865,000 Mcf per day of physical delivery contracts tied to indices at various delivery points. The settlement of these physical delivery contracts is recognized in either gas revenue or in the gas gathering and processing margin.


Production Period		Mcf per Day	Weighted Average Sell Basis per Mcf *(a)*
2008	October (b)	620,000	$	0.40
	November (b)	852,500	$	0.55
	December (b)	882,500	$	0.60
2009	January to March (b)	832,500	$	0.57
	April to October (b)	465,000	$	0.73
	November to December (b)	190,000	$	0.83
2010	January to October	70,000	$	0.18
	November to December	50,000	$	0.27

(a)

Reductions to NYMEX gas prices for delivery location.

(b)

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

In the first nine months of 2008, net losses on futures and basis swap hedge contracts reduced gas revenue by $421 million. In the first nine months of 2007, net gains on these contracts increased gas revenue by $479 million. As of September 30, 2008, an unrealized pre-tax derivative fair value gain of $866 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). Of this fair value gain, $660 million is expected to be reclassified into earnings through September 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

Crude Oil

We have entered into crude oil futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments.


Production Period		Bbls per Day	Weighted Average NYMEX Price per Bbl
2008	October to December	59,600	$	97.18	(a)
2009	January to December	62,500	$	118.85
2010	January to December	27,500	$	126.65

(a)

Includes swap agreements for 3,000 Bbls per day acquired in the Hunt Petroleum acquisition (Note 13) at the September 2, 2008 mark-to-market price of $116.19 per Bbl, which is the price used for cash flow hedge accounting purposes. The weighted average cash settlement contract price is $72.65 per Bbl.

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

In the first nine months of 2008, net losses on futures, swaps and differential swap hedge contracts reduced oil revenue by $311 million. In the first nine months of 2007, net gains on these contracts increased oil revenue by $77 million. As of September 30, 2008, an unrealized pre-tax derivative fair value gain of $613 million related to cash flow hedges of oil price risk was recorded in accumulated other comprehensive income (loss). Of this fair value gain, $291 million is expected to be reclassified into earnings through September 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

Natural Gas Liquids

We have entered into natural gas liquids futures contracts that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments.


Production Period		Bbls per Day	Weighted Average Price per Bbl
2008	October to December	5,000	$	44.22

In the first nine months of 2008, net losses on futures contracts reduced natural gas liquids revenue by $26 million. As of September 30, 2008, an unrealized pre-tax derivative fair value loss of $2 million, related to cash flow hedges of natural gas liquids price risk, was recorded in accumulated other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2008. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

Transportation Contracts

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


Production Period		Mcf per Day	Weighted Average Purchase Basis per Mcf *(a)*
2008	October	60,000	$	1.56
	November	90,000	$	1.29
	December	30,000	$	1.23
2009	January to March	30,000	$	1.63

(a)

Reductions to NYMEX gas prices for purchase location.

8. Equity

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

In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 million, net proceeds of $1.2 billion were used to fund a portion of the $2.3 billion of property acquisitions closed in the first six months of 2008 (Note 13) and to repay indebtedness under our commercial paper program.

Our acquisition of properties from Headington Oil Company in July 2008 was partially funded through issuance to the seller of 11.7 million shares of our common stock (Note 13). We registered these shares under our shelf registration statement.

In August 2008, we completed a public offering of 29.9 million common shares at $48.00 per share. After underwriting discount and other offering costs of $48 million, net proceeds of $1.4 billion were used to fund property acquisitions (Note 13) and to pay down outstanding commercial paper borrowings.

Our acquisition of Hunt Petroleum Corporation and other associated entities in September 2008 was partially funded through issuance to the seller of 23.5 million shares of our common stock (Note 13). We registered these shares under our shelf registration statement.

See Note 12.

9. Earnings per Share

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


	Three Months Ended September 30
	2008					2007
*(in millions, except per share data)*	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	521	546.6	$	0.95	$	412	481.1	$	0.86

Effect of dilutive securities:
Stock awards			4.1					6.7
Warrants			1.5					1.4

Diluted	$	521	552.2	$	0.94	$	412	489.2	$	0.84


	Nine Months Ended September 30
	2008					2007
	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	1,561	517.3	$	3.02	$	1,227	468.2	$	2.62

Effect of dilutive securities:
Stock awards			5.5					6.3
Warrants			1.6					1.4

Diluted	$	1,561	524.4	$	2.98	$	1,227	475.9	$	2.58

Certain options to purchase shares of our common stock have been excluded from the 2008 diluted calculations because the options are anti-dilutive. Anti-dilutive shares of 1.7 million in the three-month period and 1.6 million in the nine-month period were excluded.

10. Comprehensive Income (Loss)

The following are components of comprehensive income (loss):


	Three Months Ended September 30						Nine Months Ended September 30
*(in millions)*	2008			2007			2008			2007
Net income	$	521		$	412		$	1,561		$	1,227

Other comprehensive income (loss):
Change in hedge derivative fair value		3,149			123			769			53
Realized (gain) loss on hedge derivative contract settlements reclassified into earnings from other comprehensive income (loss) (a)		276			(242	)		760			(574	)

Net unrealized hedge derivative contract settlements		3,425			(119	)		1,529			(521	)
Income tax (expense) benefit		(1,252	)		44			(559	)		193

Total other comprehensive income (loss)		2,173			(75	)		970			(328	)

Total comprehensive income	$	2,694		$	337		$	2,531		$	899

(a)

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

11. Supplemental Cash Flow Information

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


	Nine Months Ended September 30
*(in millions)*	2008		2007
Interest	$	319	$	152
Income tax	$	6	$	223

The accompanying consolidated statements of cash flows exclude the following non-cash transactions during the nine-month periods ended September 30, 2008 and 2007:

•

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 (Note 13).

•

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 13).

•

The following non-cash stock award transactions (Note 12):

•

Grants of 182,000 restricted shares, vesting of 17,000 restricted shares and forfeitures of 43,000 restricted shares in 2008. Grants of 57,000 restricted shares, vesting of 4,000 restricted shares and forfeitures of 32,000 restricted shares in 2007.

•

Grants of 490,000 performance shares in 2008. Vesting of 87,000 performance shares and forfeitures of 15,000 performance shares in 2007.

•

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

•

Common shares delivered or attested to in satisfaction of the exercise price of employee stock options totaled 1.5 million shares at a weighted average exercise price of $56.75 per share in 2008 and 1.0 million shares at a weighted average exercise price of $48.29 per share in 2007.

12. Employee Benefit Plans

Stock awards under the 2004 Stock Incentive Plan include stock options, performance shares, restricted shares and unrestricted shares. In May 2008, stockholders approved certain amendments and restatements to the 2004 Plan including increasing the shares available for grants of stock awards by 12 million shares, of which 6 million can be granted as full-value awards. Also, the compensation committee of our board of directors is now authorized to grant full-value awards to our executive officers. The table below summarizes stock incentive compensation expense included in the consolidated financial statements and other information for the three- and nine-month 2008 and 2007 periods:


	Three Months Ended September 30				Nine Months Ended September 30
*(in millions)*	2008		2007		2008		2007
Non-cash stock option compensation expense	$	14	$	4	$	57	$	23
Non-cash performance share and unrestricted share compensation expense		13		—		24		3
Non-cash restricted stock compensation expense		10		4		29		12
Related tax benefit recorded in income statement		13		3		40		14
Intrinsic value of stock option exercises		4		86		202		134
Income tax benefit on exercise of stock options (a)		2		31		71		48

(a)

Recorded as additional paid-in capital

During the first nine months of 2008, 1.8 million stock options were granted to employees at a weighted average exercise price of $68.02 per share. Of these stock options, 0.8 million vest when the stock price closes at or above $90.00 and the remainder vest ratably over three years. A total of 5.4 million stock options were exercised at a weighted average exercise price of $19.96 per share. As a result of these exercises, outstanding common stock increased by 2.7 million shares and stockholders’ equity increased by a net $24 million.

During the first nine months of 2008, 490,000 performance shares were granted, half of which vest when the stock price closes at or above $77.00 and half of which vest when the stock price closes at or above $85.00. In February 2008, each nonemployee director received 4,166 shares for a total of approximately 25,000 unrestricted common shares that cannot be sold for two years following the date of grant.

As of September 30, 2008, nonvested stock options had remaining unrecognized compensation expense of $47 million. Total deferred compensation at September 30, 2008 related to performance shares was $6 million and related to restricted shares was $72 million. For these nonvested stock awards, we estimate that stock incentive compensation for service periods after September 30, 2008 will be $29 million in 2008, $64 million in 2009, $29 million in 2010 and $3 million in 2011. The weighted average remaining vesting period is 0.8 years for stock options, 0.3 years for performance shares and 1.9 years for restricted shares.

As part of the Hunt Petroleum acquisition, we acquired a pension plan covering certain Hunt employees. The plan was fully funded at the time of the acquisition and is in the process of being terminated. We expect to complete the termination in third quarter 2009.

13. Acquisitions

During the first six months of 2008, we completed acquisitions of both producing and unproved properties for approximately $2.3 billion. These acquisitions included bolt-on acquisitions of additional producing properties, mineral interests and undeveloped leasehold primarily in our Eastern and San Juan Regions and the Barnett, Fayetteville, Woodford and Marcellus shales. These acquisitions were funded by commercial paper borrowings, proceeds from the February 2008 common stock offering (Note 8) and proceeds from the April 2008 issuance of senior notes (Note 4) and are subject to typical post-closing adjustments.

Additionally, in May 2008, we acquired producing properties, leasehold acreage and gathering infrastructure in the Fayetteville Shale from Southwestern Energy Company for approximately $520 million, subject to typical post-closing adjustments. The purchase price was allocated primarily to unproved properties. The acquisition was funded by proceeds from the April 2008 issuance of senior notes (Note 4).

In July 2008, we acquired producing properties, leasehold acreage and pipeline and gathering infrastructure in the Marcellus Shale in western Pennsylvania and West Virginia from Linn Energy, LLC for approximately $600 million, subject to typical post-closing adjustments. The purchase price was allocated primarily to proved and unproved properties. The acquisition was funded in part by proceeds from the April 2008 issuance of senior notes (Note 4) as well as commercial paper borrowings.

In July 2008, we acquired producing and undeveloped acreage located in the Bakken Shale in Montana and North Dakota from Headington Oil Company. The total purchase price was $1.8 billion, subject to typical post-closing adjustments, and was funded by cash of $1.05 billion and the issuance of 11.7 million shares of common stock to the seller valued at $742 million (Note 8). The purchase price was allocated primarily to proved properties. The cash portion of the transaction was funded by a combination of operating cash flow and commercial paper.

primarily concentrated in our Eastern Region, including East Texas and central and north Louisiana. Additional producing properties, both onshore and offshore, are along the Gulf Coast of Texas, Louisiana, Mississippi and Alabama. Non-operating interests, including producing and undeveloped acreage in the North Sea, were also conveyed in the transaction. 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 (Note 4).

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


*(in millions)*
Consideration issued to Hunt owners:
23.5 million shares of common stock (at fair value of $67.95 per share)	$	1,597
Cash paid		2,588

Total purchase price		4,185
Fair value of liabilities assumed:
Current liabilities		353
Long-term debt		337
Asset retirement obligation		155
Other long-term liabilities		3
Deferred income taxes		1,079

Total purchase price plus liabilities assumed	$	6,112

Fair value of assets acquired:
Cash and cash equivalents	$	198
Other current assets		292
Proved properties		4,155
Unproved properties		160
Other property and equipment		70
Goodwill (non-deductible for income taxes)		1,237

Total fair value of assets acquired	$	6,112

In October 2008, we acquired 12,900 acres in the Barnett Shale for approximately $800 million, subject to typical post-closing adjustments. The acquisition was funded through proceeds from the August 2008 common stock offering (Note 8), our commercial paper program and our revolving credit facility.

On July 31, 2007, we acquired both producing and unproved properties from Dominion Resources, Inc. for $2.5 billion. These properties are located in the Rocky Mountain Region, the San Juan Basin and South Texas. The acquisition was funded by the issuance of 21.6 million shares of our common stock in June 2007 for net proceeds of $1.0 billion, the issuance of $1.25 billion of senior notes in July 2007 and with borrowings under our commercial paper program, which was repaid with a portion of the proceeds from the issuance of $1.0 billion of senior notes in August 2007. After recording asset retirement obligation of $32 million, other liabilities and transaction costs of $18 million, $2.5 billion was allocated to proved properties and $38 million to unproved properties.

The Hunt and Dominion acquisitions were 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 2007 and the year ended December 31, 2007, as if the Hunt acquisition was made at the beginning of each period and the Dominion acquisition was made at the beginning of 2007. These pro forma results are not necessarily indicative of future results.


	Pro Forma
	Nine Months Ended September 30				Year Ended December 31
*(in millions, except per share data)*	2008		2007		2007
Revenues	$	6,488	$	4,815	$	6,648
Net Income	$	1,739	$	1,308	$	1,811
Earnings per common share:
Basic	$	3.23	$	2.59	$	3.59
Diluted	$	3.19	$	2.56	$	3.54
Weighted average shares outstanding:
Basic		538.3		504.1		504.7
Diluted		545.4		511.8		511.7

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 30, 2008, the related consolidated income statements for the three- and nine-month periods ended September 30, 2008 and 2007, and the related consolidated statements of cash flow for the nine-month periods ended September 30, 2008 and 2007. 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, 2007, and the related consolidated statements of income, stockholders’ equity, and cash flows for the year then ended (not presented herein), included in the Company’s 2007 Annual Report on Form 10-K, and in our report dated February 25, 2008, we expressed an unqualified opinion on those statements. Our report on those statements referred to a change in accounting for share-based payments in 2006. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007 is fairly stated, in all material respects, in relation to the consolidated balance sheet included in the Company’s 2007 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Fort Worth, Texas

November 4, 2008

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2007 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

Gas, Natural Gas Liquids and Oil Production and Prices


	Three Months Ended September 30						Nine Months Ended September 30
	2008		2007		Increase (Decrease)		2008		2007		Increase (Decrease)
Total production
Gas (Mcf)		179,348,090		143,584,304	25	%		498,123,918		378,404,737	32	%
Natural gas liquids (Bbls)		1,427,555		1,257,984	13	%		4,298,364		3,613,286	19	%
Oil (Bbls)		5,302,631		4,379,439	21	%		14,659,078		12,678,526	16	%
Mcfe		219,729,206		177,408,842	24	%		611,868,570		476,155,609	29	%

Average daily production
Gas (Mcf)		1,949,436		1,560,699	25	%		1,817,971		1,386,098	31	%
Natural gas liquids (Bbls)		15,517		13,674	13	%		15,687		13,235	19	%
Oil (Bbls)		57,637		47,603	21	%		53,500		46,441	15	%
Mcfe		2,388,361		1,928,357	24	%		2,233,097		1,744,160	28	%

Average sales price
Gas per Mcf	$	8.42	$	7.20	17	%	$	8.22	$	7.48	10	%
Natural gas liquids per Bbl	$	53.65	$	45.29	18	%	$	55.14	$	41.22	34	%
Oil per Bbl	$	93.40	$	70.73	32	%	$	88.55	$	68.17	30	%

Average sales price before hedging
Gas per Mcf	$	9.31	$	5.48	70	%	$	9.07	$	6.22	46	%
Natural gas liquids per Bbl	$	60.51	$	45.29	34	%	$	61.21	$	41.22	48	%
Oil per Bbl	$	113.09	$	71.63	58	%	$	109.78	$	62.13	77	%

Average NYMEX prices
Gas per MMBtu	$	10.24	$	6.16	66	%	$	9.73	$	6.83	42	%
Oil per Bbl	$	118.52	$	75.21	58	%	$	113.49	$	66.21	71	%

Bbl—Barrel

Mcf—Thousand cubic feet

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

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

Production increases from 2007 to 2008 for the three- and nine-month periods are primarily because of development activity and acquisitions, partially offset by natural decline.

Realized gas prices and average NYMEX gas prices increased from 2007 to 2008. As a result of tighter storage levels and higher oil prices, gas prices reached as high as $13.00 per MMBtu in July 2008. Due to concerns of oversupply from shale gas development, falling oil prices and a mild summer which led to increased gas in storage, recent gas prices have declined. Prices will continue to be affected by weather, the level of North American production, oil prices, the U.S. economy and the level of liquified natural gas imports. Natural gas prices are expected to remain volatile. At October 31, 2008, the average NYMEX futures price for the following twelve months was $7.21 per MMBtu.

Realized oil prices and average NYMEX oil prices increased from 2007 to 2008. As a result of narrowing excess worldwide capacity, weakness in the dollar and continuing tension in the Middle East, oil reached a record above $147.00 per Bbl in July 2008. However, rising crude oil supplies, the tightened credit markets and the potential for lower demand in slowing U.S. and global economies have caused recent oil prices to decline. Oil prices are expected to remain volatile. At October 31, 2008, the average NYMEX futures price for the following twelve months was $71.28 per Bbl.

We use price hedging arrangements, including fixed-price physical delivery contracts, to reduce price risk on a portion of our natural gas, natural gas liquids and oil production. We have hedged a portion of our exposure to variability in future cash flows from natural gas liquids sales through December 2008 and from natural gas and oil sales through December 2010. See Note 7 to Consolidated Financial Statements.

Results of Operations

Quarter Ended September 30, 2008 Compared with Quarter Ended September 30, 2007

Net income for third quarter 2008 was $521 million compared to $412 million for third quarter 2007. Third quarter 2008 earnings include the net after-tax effect of a $24 million non-cash derivative fair value loss. Third quarter 2007 earnings include the net after-tax effects of a $4 million non-cash derivative fair value loss.

Total revenues for third quarter 2008 were $2.13 billion, a 50% increase from third quarter 2007 revenues of $1.42 billion. Operating income for the quarter was $969 million, a 37% increase from third quarter 2007 operating income of $707 million. Gas and natural gas liquids revenues increased $496 million because of the 25% increase in gas production and the 13% increase in natural gas liquids production, as well as the 17% increase in gas prices and the 18% increase in natural gas liquids prices. Oil revenue increased $185 million because of the 21% increase in production and the 32% increase in oil prices.

Expenses for third quarter 2008 totaled $1.16 billion, a 62% increase from third quarter 2007 expenses of $714 million. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $97 million primarily because of increased overall production, increased power and fuel costs as well as certain one-time and discretionary items related to recent property acquisitions including increased compression, maintenance, and workover costs. Taxes, transportation and other increased $82 million from the third quarter of 2007 primarily because of higher product prices and higher transportation costs related to higher throughput volumes. Exploration expense increased $8 million primarily because of increased seismic costs in the Gulf of Mexico. Depreciation, depletion and amortization increased $172 million because of increased production and higher acquisition, development and facility costs. General and administrative expense increased $35 million because of a $29 million increase in non-cash incentive award compensation and increased other general and administrative expense primarily due to higher employee expenses related to Company growth.

The derivative fair value loss for third quarter 2008 was $45 million compared to $3 million in the same 2007 period. The loss in 2008 is primarily related to the $38 million loss recorded on certain natural gas futures that no longer qualify for hedge accounting due to the September 2008 bankruptcy filing of the parent company of one of our counterparties. See Note 6 to Consolidated Financial Statements.

Interest expense increased $68 million primarily because of a 94% increase in weighted average borrowings incurred primarily to fund acquisitions. The effective income tax rate for third quarter 2008 was 37.8% compared with 35.9% for third quarter 2007. The higher 2008 rate is primarily related to a change in our estimated permanent differences in 2008 and the benefit of a lower Texas state rate in 2007.

Nine Months Ended September 30, 2008 Compared with Nine Months Ended September 30, 2007

Net income for the nine months ended September 30, 2008 was $1.56 billion, compared to $1.23 billion for the same 2007 period. Earnings for the first nine months of 2008 include the net after-tax effects of a $7 million non-cash derivative fair value gain. Earnings for the first nine months of 2007 include the net after-tax effects of a $27 million non-cash derivative fair value loss.

Total revenues for the first nine months of 2008 were $5.73 billion, 46% higher than revenues of $3.92 billion for the first nine months of 2007. Operating income for the first nine months of 2008 was $2.80 billion, a 35% increase from operating income of $2.08 billion for the comparable 2007 period. Gas and natural gas liquids revenues increased $1.35 billion primarily because of the 32% increase in gas production and the 19% increase in natural gas liquids production, as well as the 10% increase in gas prices and the 34% increase in natural gas liquids prices. Oil revenue increased $433 million because of the 16% increase in production and the 30% increase in prices.

Expenses for the first nine months of 2008 totaled $2.94 billion, a 60% increase from total expenses for the first nine months of 2007 of $1.84 billion. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $230 million primarily because of increased production and increased compression, maintenance, workover, water disposal and power and fuel costs. Taxes, transportation and other increased $242 million primarily because of higher product prices and higher transportation costs related to higher throughput volumes. Exploration expense increased $29 million primarily because of increased seismic costs in the Gulf of Mexico and the Woodford and Fayetteville shales. Depreciation, depletion and amortization increased $463 million because of increased production and higher acquisition, development and facility costs. General and administrative expense increased $105 million because of a $72 million increase in non-cash incentive award compensation and increased other general and administrative expense primarily due to higher employee expenses related to Company growth.

The derivative fair value loss for the first nine months of 2008 was $3 million compared to a $10 million gain in the same 2007 period. The 2008 loss is primarily related to the $38 million loss recorded on certain natural gas futures that no longer qualify for hedge accounting due to the September 2008 bankruptcy filing of the parent company of one of our counterparties as well as the loss related to the ineffective portion of hedge derivatives. These were partially offset by the gain on natural gas basis swaps that do not qualify for hedge accounting. The 2007 gain is primarily related to the ineffective portion of hedge derivatives. See Note 6 to Consolidated Financial Statements.

Interest expense increased $167 million primarily because of a 101% increase in the weighted average borrowings incurred primarily to fund acquisitions. The 2008 year-to-date effective income tax rate was 36.9% compared with a 36.1% effective rate for the nine-month 2007 period. The higher 2008 rate is primarily related to a change in our estimated permanent differences in 2008 and the benefit of a lower Texas state rate in 2007.

Comparative Expenses per Mcf Equivalent Production

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


	Three Months Ended September 30					Nine Months Ended September 30
	2008		2007		Increase (Decrease)	2008		2007		Increase (Decrease)
Production	$	1.19	$	0.93	28%	$	1.10	$	0.92	20%
Taxes, transportation and other		0.94		0.70	34%		0.90		0.65	38%
Depreciation, depletion and amortization (DD&A)		2.27		1.84	23%		2.12		1.74	22%
General and administrative (G&A):
Non-cash stock incentive compensation		0.17		0.05	240%		0.18		0.08	125%
All other G&A		0.21		0.22	(5)%		0.25		0.25	—
Interest		0.60		0.36	67%		0.53		0.33	61%

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

Production expenses —Increased production expense is primarily because of increased power and fuel costs as well as certain one-time and discretionary items related to recent property acquisitions including increased compression, maintenance and workover costs.

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

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

G&A —Increased stock incentive compensation is related to additional incentive award grants since last year including stock options, performance shares and restricted stock awards and accelerated vesting of options due to our common stock price closing above specified target prices. All other G&A expense decreased for the quarter because of increased production outpacing personnel and other expenses related to company growth.

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

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $3.75 billion for the first nine months of 2008, compared with $2.64 billion for the same 2007 period. Cash provided by operating activities for the first nine months of 2008 increased primarily because of increased production from development activity and acquisitions. Cash flow from operating activities was decreased by changes in operating assets and liabilities of $2 million in the first nine months of 2008 and increased by $83 million in the first nine months of 2007. Changes in operating assets and liabilities are primarily the result of timing of cash receipts and disbursements. Cash flow from operating activities was also reduced by exploration expense, excluding dry hole expense, of $55 million in the first nine months of 2008 and $23 million in the first nine months of 2007.

During the nine months ended September 30, 2008, cash provided by operating activities of $3.75 billion, proceeds from the February and July 2008 common stock offerings of $2.6 billion, proceeds from the April and August 2008 debt offerings of $4.18 billion and proceeds from other borrowings of $300 million were used to fund net property acquisitions, development costs and other net capital additions of $10.75 billion and dividends of $181 million. The increase in cash and cash equivalents for the period was $19 million.

Total current assets increased $1.41 billion during the first nine months of 2008 primarily because of an $849 million increase in derivative fair value as a result of lower natural gas, natural gas liquids and crude oil prices and a $594 million increase in accounts receivable due to increased revenue and receivables acquired from Hunt Petroleum. Total current liabilities increased $1.09 billion during the first nine months of 2008 primarily because of an $855 million increase in accounts payable and accrued liabilities due to increased activity and the payables assumed from the Hunt Petroleum acquisition as well as a $345 million increase in deferred income taxes related to the increase in derivative fair value current assets. These were partially offset by a $137 million decrease in derivative fair value liabilities due to the effect of lower natural gas, natural gas liquids and crude oil prices.

Working capital increased from a negative position of $250 million at December 31, 2007 to a positive position of $77 million at September 30, 2008. Excluding the effects of derivative fair value and deferred income tax current assets and liabilities, working capital decreased $294 million from a negative position of $230 million at December 31, 2007 to a negative position of $524 million at September 30, 2008. For a disclosure of the effect of changing commodity prices on the fair value of our derivative contracts, see Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.

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

Recent events in global financial markets have resulted in distortions in the commercial paper markets. In response, in fourth quarter 2008, we have used a combination of commercial paper and borrowings under our revolving credit facility to meet our short-term funding needs. We believe that our expected cash flow from operations, as well as our various funding facilities provide us with adequate liquidity to meet our current obligations. In 2009, given our hedge position and current commodity strip pricing, we expect to generate enough cash flow from operations to fund our capital expenditures and to pay down at least $1 billion of debt.

Acquisitions and Development

During the first six months of 2008, we completed acquisitions of both producing and unproved properties for approximately $2.3 billion. These acquisitions included bolt-on acquisitions of additional producing properties, mineral interests and undeveloped leasehold primarily in our Eastern and San Juan Regions and the Barnett, Fayetteville, Woodford and Marcellus shales. These acquisitions were funded by commercial paper borrowings, proceeds from the February 2008 common stock offering and proceeds from the April 2008 issuance of senior notes and are subject to typical post-closing adjustments (see “Debt and Equity” below).

In July 2008, we acquired producing and undeveloped acreage located in the Bakken Shale in Montana and North Dakota from Headington Oil Company. The total purchase price was $1.8 billion, subject to typical post- closing adjustments, and was funded by cash of $1.05 billion and the issuance of 11.7 million shares of common stock to the seller valued at $742 million. The purchase price was allocated primarily to proved properties. The cash portion of the transaction was funded by a combination of operating cash flow and commercial paper.

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 seller 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. Additional producing properties, both onshore and offshore, are along the Gulf Coast of Texas, Louisiana, Mississippi and Alabama. Non-operating interests, including producing and undeveloped acreage in the North Sea, were also conveyed in the transaction. 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 (see “Debt and Equity” below).

In October 2008, we acquired 12,900 acres in the Barnett Shale for approximately $800 million, subject to typical post-closing adjustments. The acquisition was funded through proceeds from the August 2008 common stock offering (see “Debt and Equity” below), our commercial paper program and our revolving credit facility.

Exploration and development expenditures for the first nine months of 2008 were $2.41 billion compared with $1.98 billion for the first nine months of 2007. Our 2008 development and exploration budget is $3.5 billion and our budget for construction of pipeline infrastructure and compression and processing facilities is $600 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 the significant changes in oil and gas prices.

Raw material shortages and strong global demand for steel continued to tighten steel supplies and caused prices to significantly increase in the first nine months of 2008. With demand decreasing due to slowing global growth as a result of the tightened credit markets, we expect prices to decline. We have negotiated supply contracts with our vendors to support our development program under which we expect to acquire adequate supplies to complete our development program.

Through the first nine months of 2008, we participated in drilling approximately 811 gas wells and 65 oil wells and performed 260 workovers. Our year-to-date drilling activity was concentrated in East Texas and the Barnett Shale. Workovers have focused on recompletions, artificial lift and wellhead compression. These projects generally have met or exceeded management expectations.

Debt and Equity

We have unsecured and uncommitted lines of credit with commercial banks totaling $300 million. As of September 30, 2008, there were no borrowings under these lines.

In April 2008, we sold $400 million of 4.625% senior notes due June 15, 2013, $800 million of 5.50% senior notes due June 15, 2018 and $800 million of 6.375% senior notes due June 15, 2038. The 4.625% senior notes were issued at 99.888% of par to yield 4.651% to maturity. The 5.50% senior notes were issued at 99.539% of par to yield 5.561% to maturity. The 6.375% senior notes were issued at 99.864% of par to yield 6.386% to maturity. Net proceeds of $1.98 billion were used to fund property acquisitions that closed during the second and third quarters of 2008 (see “Acquisitions and Development” above), to pay down outstanding commercial paper borrowings and for general corporate purposes.

In August 2008, we completed a public offering of 29.9 million common shares at $48.00 per share. After underwriting discount and other offering costs of $48 million, net proceeds of $1.4 billion were used to fund property acquisitions (see “Acquisitions and Development” above) and to pay down outstanding commercial paper borrowings.

In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 million, net proceeds of $1.2 billion were used to fund a portion of the $2.3 billion of property acquisitions closed in the first six months of 2008 (see “Acquisitions and Development” above) and to repay indebtedness under our commercial paper program.

Our acquisition of properties from Headington Oil Company in July 2008 was partially funded through issuance to the seller of 11.7 million shares of common stock (see “Acquisitions and Development” above). We registered these shares under our shelf registration statement.

Our acquisition of Hunt Petroleum Corporation and other associated entities in September 2008 was partially funded through issuance to the seller of 23.5 million shares of common stock (see “Acquisitions and Development” above). We registered these shares under our shelf registration statement.

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

Common Stock Dividends

In August 2008, the Board of Directors declared a third quarter 2008 dividend of $0.12 per share that was paid in October to stockholders of record on September 30, 2008.

Contractual Obligations and Commitments

The following summarizes our significant obligations and commitments to make future contractual payments as of September 30, 2008. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt or losses.


			Payments Due by Year
*(in millions)*	Total		2008		2009		2010		2011		2012		After 2012
Long-term debt	$	11,122	$	—	$	—	$	250	$	—	$	903	$	9,969
Operating leases		97		7		27		24		19		10		10
Drilling contracts		357		96		202		48		11		—		—
Purchase commitments		114		38		76		—		—		—		—
Transportation contracts		912		29		122		121		116		107		417
Derivative contract liabilities at September 30, 2008 fair value		104		97		7		—		—		—		—

Total	$	12,706	$	267	$	434	$	443	$	146	$	1,020	$	10,396

Long-Term Debt. At September 30, 2008, borrowings were $1.06 billion 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 $1.06 billion outstanding under the commercial paper program is reflected in the table above as due after 2012. Borrowings of $600 million under our term loans are due in 2013, and our senior notes, totaling $9.46 billion at September 30, 2008, are due 2010 through 2038. For further information regarding long-term debt, see Note 4 to Consolidated Financial Statements.

Transportation Contracts . We have entered firm transportation contracts with various pipelines for various terms through 2017. 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.

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

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

Derivative Contracts . We have entered into futures contracts and swaps to hedge our exposure to natural gas, crude oil and natural gas liquids 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 30, 2008, the current liability related to such contracts was $102 million and the noncurrent liability was $2 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts are received as much as 55 days after payment to counterparties and can result in draws on our revolving credit facility, our other unsecured and uncommitted lines of credit or our commercial paper program. See Note 6 to Consolidated Financial Statements.

Accounting Pronouncements

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

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

In December 2007, SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51, was issued. SFAS No. 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Among other requirements, this statement requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS No. 160 is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. The effect of adopting SFAS No. 160 is not expected to have an effect on our reported financial position or earnings.

In March 2008, SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement 133, was issued. SFAS No. 161 amends and expands SFAS No. 133 to enhance required disclosures regarding derivatives and hedging activities. It requires added disclosure regarding how an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position,

financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The effect of adopting SFAS No. 161 is not expected to have an effect on our reported financial position or earnings.

In June 2008, FASB Staff Position EITF 03-6-1 , Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities , was issued. FSP 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of earnings per share under the two-class method described in SFAS No. 128, Earnings per Share. Under FSP 03-6-1, share-based payment awards that contain nonforfeitable rights to dividends, as is the case with our restricted and performance shares, are “participating securities” as defined by EITF 03-6 and therefore should be included in computing earnings per share using the two-class method. FSP 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. The effect of adopting FSP 03-6-1 has not been determined, but it is not expected to have a significant effect on our reported financial position or earnings.

Forward-Looking Statements

Certain information included in this quarterly report and other materials filed or to be filed by the Company with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by the Company, contain projections and forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Company’s operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures, cash flow, drilling activity, drilling locations, acquisition and development activities and funding thereof, adjusted acquisition prices, pricing differentials, production and reserve growth, reserve potential, operating costs, operating margins, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, sources of capital, debt repayment, regulatory matters, competition, the impact of various accounting pronouncements and assumptions related to the expensing of stock options and performance shares. Such forward-looking statements are based on management’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “predicts,” “anticipates,” “believes,” “estimates,” “goal,” “should,” “could,” “assume,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. In particular, the factors discussed below and detailed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. The cautionary statements contained in our Annual Report on Form 10-K are incorporated herein by reference in addition to the following cautionary statements.

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

•

changes in commodity prices,

•

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

•

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

•

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

•

potential liability resulting from pending or future litigation,

•

changes in interest rates,

•

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

•

general domestic and international economic and political conditions.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2007 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

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

Interest Rate Risk

We are exposed to interest rate risk on debt with variable interest rates. At September 30, 2008, our variable rate debt had a carrying value of $1.7 billion, which approximated its fair value, and our fixed rate debt had a carrying value of $9.5 billion and an approximate fair value liability of $8.6 billion. Assuming a one percent, or 100-basis point, change in interest rates at September 30, 2008, the fair value of our fixed rate debt would change by approximately $576 million.

Commodity Price Risk

We hedge a portion of our price risks associated with our natural gas, crude oil and natural gas liquid sales. As of September 30, 2008, our outstanding futures contracts and swap agreements had a net fair value gain of $1.5 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 30, 2008. The hypothetical change in fair value could be a gain or a loss depending on whether prices increase or decrease.


*(in millions)*	Fair Value			Hypothetical Change in Fair Value
Natural gas futures, collars and sell basis swap agreements	$	893		$	463
Natural gas purchase basis swap agreements		(13	)		2
Crude oil futures and differential swaps		607			341
Natural gas liquids futures		(2	)		2

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

Item 4.

CONTROLS AND PROCEDURES

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

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

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

Not applicable.

Item 1A.

Risk Factors

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

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

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


Month	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July	—		$	—	—
August	3,536		$	50.90	—
September	—		$	—	—

Total	3,536	(2)	$	50.90	—	22,208,000

(1)

The Company has a repurchase program approved by the Board of Directors in August 2004 for the repurchase of up to 25,000,000 shares of the Company’s common stock.

(2)

Does not include performance or restricted share forfeitures. Includes 3,536 shares of common stock purchased during the quarter from employees in connection with the settlement of income tax withholding obligations upon vesting of restricted shares under the 2004 Stock Incentive Plan. These share purchases were not part of a publicly announced program to purchase common stock.

Items 3 through 5.

Not applicable.

Item 6.

Exhibits


Exhibit Number and Description
4.1		Third Supplemental Indenture dated as of August 7, 2008 between the Company and the Bank of New York Mellon Trust Company, N.A., as trustee for the 5% senior notes due 2010, 5.75% senior notes due 2013 and 6.50% senior notes due 2018 (incorporated by reference to Exhibit 4.3.4 to Form 8-K filed August 5, 2008)

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

15.1		Awareness letter of KPMG LLP re unaudited interim financial information

31.1		Chief Executive Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Chief Financial Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Chief Executive Officer and Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

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


	XTO ENERGY INC.

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

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

INDEX TO EXHIBITS

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


Exhibit No.	Description	Page
4.1	Third Supplemental Indenture dated as of August 7, 2008 between the Company and the Bank of New York Mellon Trust Company, N.A., as trustee for the 5% senior notes due 2010, 5.75% senior notes due 2013 and 6.50% senior notes due 2018 (incorporated by reference to Exhibit 4.3.4 to Form 8-K filed August 5, 2008)

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

15.1	Awareness letter of KPMG LLP re unaudited interim financial information

31.1	Chief Executive Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Chief Financial Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	Chief Executive Officer and Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002