- Annual Report (10-K)

2008

United States Securities and Exchange Commission

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 1-10662

XTO ENERGY INC.

(Exact name of registrant as specified in its charter)

Delaware

75-2347769

810 Houston Street, Fort Worth, Texas

76102

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

(Address of principal executive offices)

(Zip Code)

Registrant’s telephone number, including area code (817) 870-2800

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, $.01 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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

Large accelerated filer x 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 Exchange Act Rule 12b-2). Yes ¨ No x

As of June 30, 2008, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $33.3 billion based on the closing price as reported on the New York Stock Exchange.

Number of Shares of Common Stock outstanding as of February 20, 2009 – 579,689,791

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Part III of this Report is incorporated by reference from the Registrant’s definitive Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 30, 2009.

XTO ENERGY INC.

ANNUAL REPORT ON FORM 10-K

2008

TABLE OF CONTENTS


ITEM		PAGE

PART I
1. and 2.	Business and Properties	1
1A.	Risk Factors	14
1B.	Unresolved Staff Comments	20
3.	Legal Proceedings	21
4.	Submission of Matters to a Vote of Security Holders	22

PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
6.	Selected Financial Data	24
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
7A.	Quantitative and Qualitative Disclosures about Market Risk	41
8.	Financial Statements and Supplementary Data	42
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	42
9A.	Controls and Procedures	42
9B.	Other Information	42

PART III
10.	Directors, Executive Officers and Corporate Governance	43
11.	Executive Compensation	43
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	43
13.	Certain Relationships and Related Transactions, and Director Independence	43
14.	Principal Accountant Fees and Services	43

PART IV
15.	Exhibits and Financial Statement Schedules	44

PART I

Items 1 and 2

Business And Properties

GENERAL

XTO Energy Inc. and its subsidiaries (“the Company”) are engaged in the acquisition, development, exploitation and exploration of both producing oil and gas properties and unproved properties, and in the production, processing, marketing and transportation of oil and natural gas. The Company was formerly known as Cross Timbers Oil Company and changed its name to XTO Energy Inc. in June 2001.

Our corporate internet web site is www.xtoenergy.com. We make available free of charge, on or through the investor relations section of our web site, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. We also make available all of our press releases and investor presentations on our website.

We have grown through acquisition of proved oil and gas reserves and unproved properties, development and exploitation activities and purchases of additional interests in or near our acquired properties. We expect growth in the future to continue to be accomplished through a combination of acquisitions and development. During 2009, our primary emphasis will be on development of our existing property base. We will also continue to review acquisition opportunities including property divestitures by major energy related companies, public exploration and development companies and private energy companies. Completion of additional acquisitions will depend on the quality of properties available, commodity prices, competitive factors and public capital markets.

Our corporate headquarters are located in Fort Worth, Texas at 810 Houston Street (telephone 817-870-2800). Our proved reserves are principally located in relatively long-lived fields with an extensive base of hydrocarbons in place and, in most cases, well-established production histories concentrated in the following areas:

–

Eastern Region, including the East Texas Basin, Haynesville Shale, northwestern Louisiana and Mississippi;

–

North Texas Region, including the Barnett Shale;

–

Mid-Continent and Rocky Mountain Region, including the Fayetteville, Woodford and Bakken Shales;

–

San Juan Region;

–

Permian Region;

–

South Texas and Gulf Coast Region, including the offshore Gulf of Mexico; and

–

Other, including Marcellus Shale and North Sea.

We use the following volume abbreviations throughout this Form 10-K. “Equivalent” volumes are computed with oil and natural gas liquid quantities converted to Mcf, or natural gas converted to Bbls, on an energy equivalent ratio of one barrel to six Mcf.

– Bbl

Barrel (of oil or natural gas liquids)

– Bcf

Billion cubic feet (of natural gas)

– Bcfe

Billion cubic feet of natural gas equivalent

– BOE

Barrels of oil equivalent

– MBbls

Thousand barrels (of oil or natural gas liquids)

– Mcf

Thousand cubic feet (of natural gas)

– Mcfe

Thousand cubic feet of natural gas equivalent

– MMBtu

One million British Thermal Units, a common energy measurement

– Tcf

Trillion cubic feet (of natural gas)

– Tcfe

Trillion cubic feet equivalent


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Our estimated proved reserves at December 31, 2008 were 11.80 Tcf of natural gas, 76 million Bbls of natural gas liquids and 268 million Bbls of oil, based on December 31, 2008 prices of $4.66 per Mcf for gas, $18.26 per Bbl for natural gas liquids and $38.12 per Bbl for oil. On an energy equivalent basis, our proved reserves were 13.86 Tcfe at December 31, 2008, a 23% increase from proved reserves of 11.29 Tcfe at the prior year end. Increased proved reserves during 2008 were primarily the result of acquisitions and development and exploitation activities. On an Mcfe basis, 64% of proved reserves were proved developed reserves at December 31, 2008. During 2008, our average daily production was 1.91 Bcf of gas, 15.6 MBbls of natural gas liquids and 56.0 MBbls of oil. Fourth quarter 2008 average daily production was 2.17 Bcf of gas, 15.4 MBbls of natural gas liquids and 63.5 MBbls of oil.

Our properties typically have relatively long reserve lives and predictable production profiles. Based on December 31, 2008 proved reserves and projected 2009 production from properties owned as of December 31, 2008, the average reserve-to-production index of our proved reserves is 15.8 years. The projected 2009 production is from proved developed producing reserves as of December 31, 2008. In general, our properties have extensive production histories and production enhancement opportunities. Within each of our geographical regions, we have one or more core areas in which our major producing fields are concentrated. For example, the core area in the North Texas region is the Barnett Shale. This allows for substantial economies of scale in production and cost-effective application of reservoir management techniques gained from prior operations. As of December 31, 2008, we owned interests in 33,285 gross (18,235.7 net) producing wells, and we operated wells representing 86% of the present value of cash flows before income taxes (discounted at 10%) from estimated proved reserves. The high proportion of operated properties allows us to exercise more control over expenses, capital allocation and the timing of development and exploitation activities in our fields.

We have a substantial inventory of between 11,100 and 12,220 identified potential drilling locations. Of these locations, approximately 4,100 have proved undeveloped reserves attributed to them. Drilling plans are primarily dependent upon product prices, available cash flow, the availability and pricing of drilling equipment and supplies, and gathering, processing and transmission infrastructure.

We employ a disciplined acquisition program refined by senior management to expand our reserve base in core areas and to add new core areas. Our engineers and geologists use their expertise and experience gained through the management of existing core properties to target properties to be acquired with similar geologic and reservoir characteristics. We then use our development and technological knowledge to increase the reserves of acquired properties.

We operate gas gathering, treating and compression facilities in several of our core producing areas. We also operate three gas processing plants, and we own small interests in other nonoperated gas processing plants and facilities. Our gas gathering and processing operations are only in areas where we have production and are considered activities that facilitate our natural gas production and sales operations.

We market our gas production and the gas output of our gathering and processing systems. A large portion of our natural gas is processed, with most of the resultant natural gas liquids being marketed by unaffiliated third parties. We use commodities future contracts, collars and price and basis swap agreements, fixed-price physical sales and other price risk management instruments to hedge pricing risks.

HISTORY OF THE COMPANY

The Company was incorporated in Delaware in 1990 to ultimately acquire the business and properties of predecessor entities that were created from 1986 through 1989. Our initial public offering of common stock was completed in May 1993.

During 1991, we formed Cross Timbers Royalty Trust by conveying a 90% net profits interest in substantially all of the royalty and overriding royalty interests that we then owned in Texas, New Mexico and Oklahoma, and a 75% net profits interest in seven nonoperated working interest properties in Texas and Oklahoma. Cross Timbers Royalty Trust units are listed on the New York Stock Exchange under the symbol “CRT.” We have no ownership interest in this trust.

In December 1998, we formed the Hugoton Royalty Trust by conveying an 80% net profits interest in principally gas-producing operated working interests in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These net profits interests were conveyed to the trust in exchange for 40 million units of beneficial interest. Hugoton Royalty Trust units are listed on the New York Stock Exchange under the symbol “HGT.” We sold 17 million units in the trust’s initial public offering in 1999 and issued 1.3 million units pursuant to an employee incentive plan in 1999 and 2000. In January 2006, the Board of Directors declared a dividend of 0.047688 trust units for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all of the remaining 21.7 million trust units were distributed on May 12, 2006.

INDUSTRY OPERATING ENVIRONMENT

The oil and gas industry is affected by many factors that we generally cannot control. Governmental regulations, particularly in the areas of taxation, energy, climate change and the environment, can have a significant impact on operations and profitability. Crude oil prices are determined by global supply and demand and regional storage and refining capacity. Oil supply is significantly influenced by production


2		XTO ENERGY		\|		2008 form 10-K

levels of OPEC member countries, while demand is largely driven by the condition of worldwide economies, as well as weather. Natural gas prices are generally determined by North American supply and demand and are affected by imports of liquefied natural gas. Weather has a significant impact on demand for natural gas since it is a primary heating resource. Its increased use for electrical generation has kept natural gas demand elevated throughout the year, removing some of the seasonal swing in prices. See “Significant Events, Transactions and Conditions – Product Prices” in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, regarding recent price fluctuations and their effect on our results.

BUSINESS STRATEGY

The primary components of our business strategy are:

–

increasing production and reserves through efficient management of operations and through development, exploitation and exploration activities,

–

acquiring long-lived, operated oil and gas properties, including undeveloped leases,

–

hedging a portion of our production to provide adequate cash flow to fund our development budget and protect the economic return on development projects and acquisitions, and

–

retaining management and technical staff that have substantial experience in our core areas.

Increasing Production and Reserves. A principal component of our strategy is to increase production and reserves through aggressive management of operations and low-risk development. We believe that our principal properties possess geologic and reservoir characteristics that make them well suited for production increases through drilling and other development programs. Additionally, we review operations and mechanical data on operated properties to determine if actions can be taken to reduce operating costs or increase production. Such actions include installing, repairing and upgrading lifting equipment, redesigning downhole equipment to improve production from different zones, modifying gathering and other surface facilities and conducting restimulations and recompletions. We may also initiate, upgrade or revise existing secondary recovery operations.

Exploration Activities. During 2009, we plan to focus our exploration activities on projects that are near currently owned productive fields. We believe that we can prudently and successfully add growth potential through exploratory activities given improved technology, our experienced technical staff and our expanded base of operations. We have allocated approximately $75 million of our $2.75 billion 2009 development budget for exploration activities. These exploration activities do not include low risk exploration costs that are classified as development costs for budget purposes.

Acquiring Long-Lived, Operated Properties. We seek to acquire long-lived, operated producing properties that:

–

contain complex, multiple-producing horizons with the potential for increases in reserves and production,

–

produce from nonconventional sources, including tight natural gas reservoirs, coal bed methane and natural gas- and oil-producing shale formations,

–

are in core operating areas or in areas with similar geologic and reservoir characteristics, and

–

provide opportunities to improve operating efficiencies.

We believe that the properties we acquire provide opportunities to increase production and reserves through the implementation of mechanical and operational improvements, workovers, behind-pipe completions, secondary recovery operations, new development wells and other development activities. We also seek to acquire facilities related to gathering, processing, marketing and transporting oil and gas in areas where we own reserves. Such facilities can enhance profitability, reduce costs, and provide marketing flexibility and access to additional markets. Our ability to successfully purchase properties is dependent upon, among other things, competition for such purchases and the availability of financing to supplement internally generated cash flow.

We also seek to acquire undeveloped properties that potentially have the same attributes as targeted producing properties.

Hedging Activities. To reduce production price risk, we may enter futures contracts, collars and price and basis swap agreements, as well as fixed-price physical delivery contracts. Our policy is to consider hedging a portion of our production at commodity prices management deems attractive. While there is a risk we may not be able to realize the full benefit of rising prices, management plans to continue its hedging strategy because of the benefits provided by predictable, stable cash flow, including:

–

ability to more efficiently plan and execute our development program, which facilitates predictable production growth,

–

ability to help assure the economic return on acquisitions,


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–

ability to enter long-term arrangements with drilling contractors, allowing us to continue development projects when product prices decline,

–

more consistent returns on investment, and

–

better utilization of our personnel.

Experienced Management and Technical Staff. Most senior management and technical staff have worked together for over 20 years and have substantial experience in our core operating areas. Bob R. Simpson, Chairman of the Board and Founder, was previously an executive officer of Southland Royalty Company, one of the largest U.S. independent oil and gas producers prior to its acquisition by Burlington Northern, Inc. in 1985. Keith A. Hutton, our Chief Executive Officer, and Vaughn O. Vennerberg, our President, have each been with the Company since 1987.

Other Strategies. We may also acquire working interests in nonoperated producing properties if such interests otherwise meet our acquisition criteria. We attempt to acquire nonoperated interests in fields where the operators have a significant interest to protect, including potential undeveloped reserves that will be exploited by the operator. We may also acquire nonoperated interests in order to ultimately accumulate sufficient ownership interests to operate the properties.

We also attempt to acquire a portion of our reserves as royalty interests. Royalty interests have few operational liabilities because they do not participate in operating activities and do not bear production or development costs.

Royalty Trusts and Publicly Traded Partnerships. We have created and sold units in publicly traded royalty trusts. Sales of royalty trust units allow us to more efficiently capitalize our mature, lower-growth properties. We may create and distribute or sell interests in additional royalty trusts or publicly traded partnerships in the future.

Business Goals. In February 2009, we announced a strategic goal for 2009 of increasing production by 14% over 2008 levels. To achieve this target, we plan to drill about 1,000 (800 net) development wells and perform approximately 800 (700 net) workovers and recompletions in 2009.

We have budgeted $2.75 billion for our 2009 development program, which is expected to be funded by cash flow from operations. We plan to spend approximately $875 million in the Eastern Region, $725 million in the North Texas Region, $375 million in the Mid-Continent and Rocky Mountain Region, $250 million in the South Texas and Gulf Coast Region, $275 million in the Permian Region, $175 million in the San Juan Region and $75 million for exploration activities. An additional $450 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities that are critical to the transportation and sale of production in several operating regions.

In 2009, given our hedge position and current commodity strip pricing, we expect to generate enough cash flow from operations to fund our $3.2 billion capital budget and reduce our debt to between $10.0 billion and $10.5 billion. In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight of our financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which was used to reduce outstanding debt.

While we expect to focus primarily on development activities in 2009, we will continue to review acquisition opportunities. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, issuance of public or private debt or equity, or asset sales. Strategic property acquisitions may alter the amount budgeted for development and exploration. Our total budget for acquisitions, development and exploration is subject to change to focus on opportunities offering the highest rates of return. We also may reevaluate our budget and drilling programs as a result of the significant changes in oil and gas prices. Our ability to achieve production goals depends on the success of our planned drilling programs or property acquisitions made in place of a portion of the drilling program.

Raw material shortages and strong global demand for steel continued to tighten steel supplies and caused prices to significantly increase in 2008. With demand decreasing due to sharply lower oil and natural gas prices and slowing global growth, we expect steel 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 2009 development program. In addition, we have secured or expect to secure the rigs necessary to support our current drilling program.

Acquisitions

During 2004, we acquired proved properties for a total cost of $1.9 billion. In January 2004, we acquired proved properties in East Texas and northwestern Louisiana for $243 million from multiple parties. From February through April, we purchased $223 million of properties located primarily in the Barnett Shale of North Texas and in the Arkoma Basin. Two of these acquisitions were purchases of corporations


4		XTO ENERGY		\|		2008 form 10-K

that primarily owned producing and nonproducing properties. Purchase accounting adjustments related to these acquisitions included a $72 million deferred income tax step-up adjustment. During April, we acquired predominantly oil-producing properties in the Permian Basin of West Texas and gas-producing properties in the Powder River Basin of Wyoming from ExxonMobil Corporation for $336 million. In August, we acquired properties from ChevronTexaco Corporation for a purchase price of $958 million, as adjusted for subsequent purchase of properties that were subject to preferential purchase rights. These properties expanded our operations in our Eastern Region, the Permian Basin and the Mid-Continent Region and added new coal bed methane properties in the Rocky Mountains and new properties in South Texas. Our 2004 acquisitions increased reserves by approximately 716.5 Bcf of natural gas, 2.9 million Bbls of natural gas liquids and 98.2 million Bbls of oil.

During 2005, we acquired proved properties for a total cost of $1.7 billion. In April 2005, we acquired Antero Resources Corporation, which operated in the Barnett Shale in the Fort Worth Basin. The purchase price was approximately $689 million. In May, we acquired proved properties in East Texas and northwestern Louisiana from Plains Exploration & Production Company for an adjusted purchase price of $336 million. In July 2005, we acquired proved properties in the Permian Basin of West Texas and New Mexico from ExxonMobil Corporation for an adjusted purchase price of $200 million. Our 2005 acquisitions increased reserves by approximately 803.4 Bcf of natural gas, 2.8 million Bbls of natural gas liquids and 31.1 million Bbls of oil.

During 2006, we acquired proved properties for a total cost of $561 million. In February 2006, we acquired proved and unproved properties in East Texas and Mississippi from Total E&P USA, Inc. for $300 million. In June 2006, we acquired Peak Energy Resources, Inc., which operated gas-producing properties and owned unproved properties in the Barnett Shale in the Fort Worth Basin. The purchase price was $108 million, which was primarily funded by issuance of 3.2 million shares of common stock valued at $102 million, $5 million cash for additional leasehold interests and $1 million cash for other transaction costs. After recording estimated deferred taxes of $36 million and other liabilities, the purchase price allocated to proved properties was $97 million and unproved properties was $53 million. Our 2006 acquisitions increased reserves by approximately 157.9 Bcf of natural gas, 4.2 million Bbls of natural gas liquids and 3.3 million Bbls of oil.

During 2007, we acquired proved reserves for a total of $3.2 billion. We also acquired $831 million of unproved properties in 2007. In July 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 an asset retirement obligation of $32 million, other liabilities and transaction costs of $18 million, the purchase price allocated to proved properties was $2.5 billion and unproved properties was $38 million. In October 2007, we announced acquisitions from multiple parties of both producing and unproved properties in the Barnett Shale for approximately $550 million. Our 2007 acquisitions increased reserves by approximately 1.3 Tcf of natural gas, 2.7 million Bbls of natural gas liquids and 11.3 million Bbls of oil.

During 2008, we acquired proved reserves for a total of $7.9 billion. We also acquired $3.1 billion of unproved properties in 2008. 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. 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. 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. Also, 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 and was funded by cash of $1.05 billion and the issuance of 11.7 million shares of common stock to the sellers valued at $742 million. In September 2008, we acquired Hunt Petroleum Corporation and other associated entities for approximately $4.2 billion, funded by cash of $2.6 billion and the issuance of 23.5 million shares of common stock to the sellers valued at $1.6 billion. Hunt Petroleum owned natural gas and oil producing properties primarily concentrated in our Eastern Region, including East Texas and central and north Louisiana. 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. Including $337 million of debt assumed, $1.1 billion recorded on the step-up of deferred taxes, $155 million recorded for the asset retirement obligation and the assumption of $356 million of other liabilities, the total purchase price plus liabilities assumed was $6.1 billion. This amount was allocated to assets acquired including $4.2 billion to proved properties, $160 million to unproved properties, $1.2 billion to goodwill and $551 million to other assets. In October 2008, we acquired 12,900 acres in the Barnett Shale for approximately $800 million. All 2008 property acquisitions are subject to typical post-closing adjustments. Our 2008 acquisitions increased reserves by approximately 1.5 Tcf of natural gas, 19.9 million Bbls of natural gas liquids and 57.6 million Bbls of oil.


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Significant Properties

The following table summarizes proved reserves and discounted present value, before income tax, of proved reserves by major operating areas at December 31, 2008:


	PROVED RESERVES				DISCOUNTED PRESENT VALUE BEFORE INCOME TAX OF PROVED RESERVES(a)
(in millions)	GAS (MCF)	NATURAL GAS LIQUIDS (BBLS)	OIL (BBLS)	NATURAL GAS EQUIVALENTS (MCFE)
Eastern Region	4,506.8	26.6	22.9	4,803.6	$	6,516	38%
North Texas Region	3,137.2	3.6	0.2	3,159.9		2,993	17%
Mid-Continent and Rocky Mountain Region	2,184.8	—	52.1	2,497.3		2,413	14%
San Juan Region	1,146.4	39.0	2.2	1,393.5		1,589	9%
Permian Region	223.9	1.7	169.1	1,248.6		2,006	12%
South Texas and Gulf Coast Region	484.1	4.9	9.7	571.4		1,332	8%
Other	119.7	—	11.3	188.1		316	2%
Total	11,802.9	75.8	267.5	13,862.4	$	17,165	100%
Total, including hedge instruments(b)	11,802.9	75.8	267.5	13,862.4	$	21,435

(a)

We believe that the discounted present value of estimated future net cash flows before income tax is a useful supplemental disclosure to the standardized measure, or after-tax amount, of $12.8 billion. While the standardized measure is dependent on the unique tax situation of each company, the pre-tax discounted amount is based on prices and discount factors that are consistent for all companies. Because of this, the pre- tax discounted amount can be used within the industry and by securities analysts to evaluate estimated future net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the pre-tax discounted amount is the discounted estimated future income tax of $4.4 billion at December 31, 2008.

(b)

The total, including hedge instruments, includes the effect from our contractual arrangements related to our hedge instruments that are being accounted for as cash flow hedges under SFAS No. 133. The cash flows from these hedges will be reported in revenues in future periods (future cash inflows) as the related production occurs. The hedge prices were applied to the reserves disclosed above, with no change in volumetric measurements related to the increased prices from our contractual arrangements.

Eastern Region

We began operations in East Texas and northwestern Louisiana in 1998. These properties produce from various formations. Subsequent acquisitions and development activity have significantly increased reserves here since we began operations, including the Hunt Petroleum acquisition in 2008. Approximately 35% of our total proved reserves are in this region. We have 3,300 to 3,600 identified potential drilling locations in this area. We have expanded our gathering facilities to increase treating capacity to 1.06 Bcf per day. We also operate a gas processing plant in the Cotton Valley Field of Louisiana. In 2009, we plan to drill between 350 and 360 wells in the Eastern Region.

Our primary focus in the Eastern Region is in the Freestone Trend where we have an interest in approximately 381,000 net acres. The trend consists of the Freestone, Bald Prairie, Oaks, Luna, Teague, Dew, Farrar and Bear Grass fields and was our most active gas development area in 2008. Other areas in the region include the Sabine Uplift and Cotton Valley areas of East Texas and northwestern Louisiana and the Haynesville Shale of which we own an interest in approximately 156,000 net acres.

North Texas Region

Our operations in the Barnett Shale of North Texas began in January 2004 and, with our 2005 acquisition of Antero Resources Corporation, 2006 acquisition of Peak Energy Resources and various 2007 and 2008 acquisitions, we are one of the largest producers in the area. We own approximately 277,000 net acres, 57% of which is in the core productive area, and gas gathering and pipeline assets. We have 2,400 to 2,600 identified potential drilling locations in this area and plan to drill approximately 240 to 260 wells in 2009. We also own 555,000 Mcf per day of treating capacity allowing us to add new wells as they are completed.

Mid-Continent and Rocky Mountain Region

Our Mid-Continent and Rocky Mountain Region includes fields in Wyoming, Montana, North Dakota, Kansas, Oklahoma and Arkansas. We have operations in the Anadarko Basin, Fayetteville and Woodford Shales, Fontenelle area, Powder River Basin, Bakken Shale and the Arkoma Basin. During 2009, we plan to continue drilling activities in the Fayetteville Shale in Arkansas and the Woodford Shale in Southeast Oklahoma and the Bakken Shale in Montana and North Dakota. While most of our production in the region is from conventional sources, we are developing coal bed methane in the Powder River Basin of Wyoming and shale gas in Arkansas and Oklahoma. We have 2,450 to 2,850 identified potential drilling locations in this area. A portion of our properties in the Mid-Continent Region are subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust in December 1998.


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We operate a gathering system in Major County, Oklahoma, a gas plant in Texas County, Oklahoma, and its associated gathering system and a gas plant and associated gathering system in the Bakken Shale area of North Dakota. We also own and operate a gas gathering and water disposal system in the Hartzog Draw area of Wyoming to service our coal bed methane wells.

San Juan Region

Our San Juan Region includes properties in the San Juan and Raton Basins of New Mexico and Colorado, as well as properties in the Uinta Basin of Utah. As a result of the 2007 Dominion acquisition, we significantly expanded our holdings in the Uinta Basin. Production is from conventional as well as coal bed methane sources. We have 1,500 to 1,600 identified potential drilling locations to develop these complex, multi-pay basins.

Permian Region

The Permian Region is made up of properties in West Texas and southeastern New Mexico. In 2004 and 2005, we significantly expanded our holdings in the area through acquisitions and trades with ChevronTexaco, ExxonMobil, Dominion and others. Our activities on these properties have increased oil production by returning shut-in wells to production, optimizing existing well performance, using fracture stimulation and drilling. We have also experienced successful results in multiple fields including Yates, University Block 9, Goldsmith, Russell, Prentice and Cornell. We have 1,150 to 1,200 identified potential drilling locations in this area.

South Texas and Gulf Coast Region

The South Texas and Gulf Coast Region includes properties is south Texas, southern Mississippi, Louisiana and Alabama and the Gulf of Mexico. In 2007, we significantly expanded our holdings in South Texas with the Dominion acquisition and, in 2008, we expanded our Gulf Coast holdings and entered into the Gulf of Mexico with the acquisition of Hunt Petroleum Corporation. Most of our properties in the Gulf of Mexico are mature fields located on the shelf. We have experienced successful results in these areas, including the Jeffress, Lopeno, Main Pass and South Marsh Island fields. We have identified 100 to 150 potential drilling locations in this region.

Other

The other category includes properties acquired in 2008 in the Appalachia Region and the North Sea. In July 2008, we purchased 152,000 net acres of Marcellus Shale leasehold in western Pennsylvania and West Virginia along with producing properties. In September 2008, in the Hunt Petroleum acquisition, we acquired non-operating interests, comprising approximately 300,000 net acres in the North Sea.

Reserves

The following terms are used in our disclosures of oil and natural gas reserves. For the complete detailed definitions of proved, proved developed and proved undeveloped oil and gas reserves applicable to oil and gas registrants, reference is made to Rule 4-10(a)(2)(3)(4) of Regulation S-X of the Securities and Exchange Commission, available at its web site http://www.sec.gov/about/forms/regs-x.pdf.

Proved reserves – Estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.

Proved developed reserves – Proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped reserves – Proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.

Estimated future net revenues – Also referred to herein as “estimated future net cash flows.” Computational result of applying current prices of oil and gas (with consideration of price changes only to the extent provided by existing contractual arrangements) to estimated future production from proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves.

Present value of estimated future net cash flows – The computational result of discounting estimated future net revenues at a rate of 10% annually. The present value of estimated future net cash flows after income tax is also referred to herein as “standardized measure of discounted future net cash flows” or “standardized measure.”


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The following are estimated quantities of proved reserves and related cash flows as of December 31, 2008, 2007 and 2006:


	DECEMBER 31
(in millions)	2008		2007		2006
Proved developed:
Gas (Mcf)		7,290.3		6,031.5		4,481.6
Natural gas liquids (Bbls)		52.5		52.9		40.1
Oil (Bbls)		205.0		184.8		167.3
Mcfe		8,835.4		7,457.7		5,725.9
Proved undeveloped:
Gas (Mcf)		4,512.6		3,409.6		2,462.6
Natural gas liquids (Bbls)		23.3		13.9		12.9
Oil (Bbls)		62.5		56.4		47.1
Mcfe		5,027.0		3,831.3		2,822.7
Total proved:
Gas (Mcf)		11,802.9		9,441.1		6,944.2
Natural gas liquids (Bbls)		75.8		66.8		53.0
Oil (Bbls)		267.5		241.2		214.4
Mcfe		13,862.4		11,289.0		8,548.6
Estimated future net cash flows:
Before income tax(a)	$	34,210	$	57,949	$	32,259
After income tax	$	26,308	$	39,526	$	22,008
Present value of estimated future net cash flows, discounted at 10%:
Before income tax(a)	$	17,165	$	29,169	$	16,228
After income tax	$	12,793	$	19,538	$	10,828
Estimated future net cash flows, including hedge instruments(b):
Before income tax(a)	$	38,793	$	58,102	$	33,385
After income tax	$	29,216	$	39,623	$	22,722
Present value of estimated future net cash flows, discounted at 10%, including hedge instruments(b):
Before income tax(a)	$	21,435	$	29,315	$	17,298
After income tax	$	15,502	$	19,631	$	11,507

(a)

We believe that the estimated future net cash flows before income tax and the discounted present value of estimated future net cash flows before income tax are useful supplemental disclosures to the after-tax estimated future net cash flows and the standardized measure, or after-tax amount. While the after-tax estimated future net cash flows and the standardized measure are dependent on the unique tax situation of each company, the pre-tax measures are based on prices and discount factors that are consistent for all companies. Because of this, the pre-tax measures can be used within the industry and by securities analysts to evaluate estimated future net cash flows from proved reserves on a more comparable basis. The difference between the after-tax and the pre-tax estimates of future net cash flows is estimated future income tax of $7.9 billion at December 31, 2008, $18.4 billion at December 31, 2007 and $10.3 billion at December 31, 2006. The difference between the standardized measure and the pre-tax discounted amount is the discounted estimated future income tax of $4.4 billion at December 31, 2008, $9.6 billion at December 31, 2007 and $5.4 billion at December 31, 2006.

(b)

The estimated future net cash flows and present value of estimated future net cash flows, discounted at 10%, including hedge instruments, includes the effect from our contractual arrangements related to our hedge instruments that are being accounted for as cash flow hedges under SFAS No. 133. The cash flows from these hedges will be reported in revenues in future periods (future cash inflows) as the related production occurs. The hedge prices were applied to the reserves disclosed above, with no change in volumetric measurements related to the increased prices from our contractual arrangements.

Miller and Lents, Ltd., an independent petroleum engineering firm, prepared the estimates of our proved reserves and the future net cash flows (and related present value) attributable to proved reserves at December 31, 2008, 2007 and 2006. As prescribed by the Securities and Exchange Commission, such proved reserves were estimated using oil and gas prices and production and development costs as of December 31 of each such year, without escalation. None of our natural gas liquid proved reserves are attributable to gas plant ownership.

Estimated future net cash flows, and the related 10% discounted present value, of year-end 2008 proved reserves are lower than at year-end 2007 because of lower commodity prices used in estimation of year-end proved reserves partially offset by increased reserves related to acquisitions and development. Year-end 2008 average realized prices used in the estimation of proved reserves were $4.66 per Mcf for gas, $18.26 Bbl for natural gas liquids and $38.12 per Bbl for oil. Year-end 2007 product prices were $6.39 per Mcf for gas, $60.24 per Bbl for natural gas liquids and $91.19 per Bbl for oil. See Note 16 to Consolidated Financial Statements for additional information regarding estimated proved reserves.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of


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any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates.

During 2008, we filed estimates of oil and gas reserves as of December 31, 2007 with the U.S. Department of Energy on Form EIA-23 and Form EIA-28. These estimates are consistent with the reserve data reported for the year ended December 31, 2007 in Note 16 to Consolidated Financial Statements, with the exception that Form EIA-23 includes only reserves from properties that we operate.

Exploration and Production Data

For the following data, “gross” refers to the total wells or acres in which we own a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by us. Although many wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the ratio of oil to gas production.

Producing Wells

The following table summarizes producing wells as of December 31, 2008, substantially all of which are located in the United States (a):


	OPERATED WELLS		NONOPERATED WELLS		TOTAL(b)
	GROSS	NET	GROSS	NET	GROSS	NET
Gas	14,958	13,035.8	9,395	1,636.6	24,353	14,672.4
Oil	3,339	2,813.7	5,593	749.6	8,932	3,563.3
Total	18,297	15,849.5	14,988	2,386.2	33,285	18,235.7

(a)

Included in the table are 21 gross (1.5 net) nonoperated gas wells located in the North Sea.

(b)

1,030 gross (815.7 net) gas wells and 35 gross (28.1 net) oil wells are dual completions.

Drilling Activity

The following table summarizes the number of wells drilled during the years indicated. As of December 31, 2008, we were in the process of drilling 935 gross (546.2 net) wells. No wells were drilled outside of the United States in 2008, 2007 or 2006.


	YEAR ENDED DECEMBER 31
	2008		2007		2006
	GROSS	NET	GROSS	NET	GROSS	NET
Development wells:
Completed as-
Gas wells	1,682	1,069.3	1,275	901.2	1,148	725.1
Oil wells	218	130.0	269	139.3	316	169.1
Non-productive	15	8.7	12	7.6	11	3.3
Total	1,915	1,208.0	1,556	1,048.1	1,475	897.5
Exploratory wells:
Completed as-
Gas wells	41	32.0	51	17.4	22	8.1
Oil wells	1	—	1	1.0	—	—
Non-productive	9	7.0	9	6.8	10	7.2
Total	51	39.0	61	25.2	32	15.3
Total(a)	1,966	1,247.0	1,617	1,073.3	1,507	912.8

(a)

Included in totals are 717 gross (122.8 net) wells in 2008, 535 gross (106.0 net) wells in 2007 and 581 gross (119.5 net) wells in 2006, drilled on nonoperated interests.


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Acreage

The following table summarizes developed and undeveloped leasehold acreage in which we own a working interest as of December 31, 2008. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.


	DEVELOPED ACRES(a)(b)		UNDEVELOPED ACRES
(in thousands)	GROSS	NET	GROSS	NET
U.S.
Texas	1,399	957	785	583
Arkansas	897	477	171	159
Montana	767	397	167	85
Louisiana	732	198	69	41
Oklahoma	722	445	244	186
New Mexico	601	390	19	19
Utah	287	167	141	93
Kansas	211	168	—	—
West Virginia	147	88	48	29
Colorado	113	87	6	6
Wyoming	99	67	65	58
Pennsylvania	94	65	27	16
North Dakota	51	33	32	32
Other	150	120	85	62
Total U.S. onshore	6,270	3,659	1,859	1,369
U.S. offshore	241	123	107	56
Total U.S.	6,511	3,782	1,966	1,425
North Sea-offshore	349	27	823	264
Grand Total	6,860	3,809	2,789	1,689

(a)

Developed acres are acres spaced or assignable to productive wells.

(b)

Certain acreage in Oklahoma and Texas is subject to a 75% net profits interest conveyed to the Cross Timbers Royalty Trust, and in Oklahoma, Kansas and Wyoming is subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust.

Most of our undeveloped acreage is subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. We do not expect to lose any significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.


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Oil and Gas Production, Sales Prices and Production Costs

The following table shows the total and average daily production, the average sales prices per unit of production and the production expense and taxes, transportation and other expense per Mcfe for the indicated periods:


	YEAR ENDED DECEMBER 31
	2008		2007		2006
Total production:
Gas (Mcf)		697,392,186		532,097,846		433,010,577
Natural gas liquids (Bbls)		5,718,295		4,943,781		4,326,853
Oil (Bbls)		20,505,178		17,172,191		16,440,079
Mcfe		854,733,024		664,793,678		557,612,169
Average daily production:
Gas (Mcf)		1,905,443		1,457,802		1,186,330
Natural gas liquids (Bbls)		15,624		13,545		11,854
Oil (Bbls)		56,025		47,047		45,041
Mcfe		2,335,336		1,821,353		1,527,705
Average realized sales prices:
Gas (per Mcf)	$	7.81	$	7.50	$	7.69
Natural gas liquids (per Bbl)	$	48.76	$	45.37	$	37.03
Oil (per Bbl)	$	87.59	$	70.08	$	60.96
Average realized sales price before hedging:
Gas (per Mcf)	$	8.04	$	6.26	$	6.26
Natural gas liquids (per Bbl)	$	52.05	$	45.37	$	37.03
Oil (per Bbl)	$	93.17	$	68.68	$	60.79
Average NYMEX prices:
Gas per MMbtu	$	9.03	$	6.86	$	7.23
Oil per Bbl	$	99.75	$	72.39	$	66.22

Production expense per Mcfe	$	1.10	$	0.93	$	0.88
Taxes, transportation and other expense per Mcfe	$	0.82	$	0.67	$	0.67

Delivery Commitments and Marketing

Our natural gas, crude oil and natural gas liquids production is sold under both long-term and short-term agreements at prices negotiated with third parties. Because our production is sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. Our production is sold to various purchasers, based on their credit rating and the location of our production. For the year ended December 31, 2008, sales to one purchaser were approximately 16% of total revenues. We believe that alternative purchasers are available, if necessary, to purchase production at prices substantially similar to those received from this significant purchaser. We market our gas, as well as some gas produced by third parties, to brokers, local distribution companies and end-users. We have also entered into physical delivery contracts which require us to deliver fixed volumes of gas. We believe our production and reserves are adequate to meet these delivery commitments.

Competition and Markets

We compete with other oil and gas companies in all aspects of our business, including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and obtaining goods, services and labor. Some of our competitors have substantially larger financial and other resources. Factors that affect our ability to acquire producing properties include available funds, available information about the property and our standards established for minimum projected return on investment. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gathering systems. Competition is also presented by alternative fuel sources, including heating oil, imported liquefied natural gas and other fossil fuels. Because of the long-lived, high margin nature of our oil and gas reserves and management’s experience and expertise in exploiting these reserves, management believes that it effectively competes in the market.

Federal and State Laws and Regulations

There are numerous federal and state laws and regulations governing the oil and gas industry that are often changed in response to the current political or economic environment. Compliance with existing laws often is difficult and costly and may carry substantial penalties for noncompliance. The following are some specific laws and regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives.


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Federal Regulation of Natural Gas

The interstate transportation and certain sales for resale of natural gas, including transportation rates charged and various other matters, are subject to federal regulation by the Federal Energy Regulatory Commission. Federal wellhead price controls on all domestic gas were terminated on January 1, 1993, and none of our gathering systems are currently subject to FERC regulation. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated new regulations to implement the Energy Policy Act. We cannot predict the impact of future government regulation on any natural gas facilities.

Although FERC’s regulations should generally facilitate the transportation of gas produced from our properties and the direct access to end-user markets, the future impact of these regulations on marketing our production or on our gas transportation business cannot be predicted. We, however, do not believe that we will be affected differently than competing producers and marketers.

Federal Regulation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. A significant part of our oil production is transported by pipeline. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. These rules have had little effect on our oil transportation cost.

In December 2007, the President signed into law the Energy Independence & Security Act of 2007 (PL 110-140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline, or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder. We cannot predict the impact of future government regulation on any natural gas facilities.

State Regulation

Oil and gas operations are subject to various types of regulation at the state and local levels. Such regulation includes requirements for drilling permits, the method of developing new fields, the spacing and operation of wells and waste prevention. The production rate may be regulated and the maximum daily production allowable from oil and gas wells may be established on a market demand or conservation basis. These regulations may limit production by well and the number of wells that can be drilled. In addition, some states have adopted regulation or are considering regulations that are designed to protect water supplies, and we cannot predict the effect of the regulations that have been adopted or whether these regulations will be adopted or, if adopted, the effect these rules may have on our operations.

We may become a party to agreements relating to the construction or operations of pipeline systems for the transportation of natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the state’s administrative authority charged with regulating pipelines. The rates that can be charged for gas, the transportation of gas, and the construction and operation of such pipelines would be subject to the regulations governing such matters. Two of our gathering subsidiaries are designated gas utilities and are subject to such state regulations. Certain states have recently adopted regulations with respect to gathering systems, and other states are considering similar regulations. New regulations have not had a material effect on the operations of our gathering systems, but we cannot predict whether any further rules will be adopted or, if adopted, the effect these rules may have on our gathering systems.

Federal, State or Native American Leases

Our operations on federal, state or Native American oil and gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service and other agencies.

Environmental Regulations

Various federal, state and local laws relating to protection of the environment directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters of the United States, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas. In some jurisdictions, the laws and regulations are constantly being revised, creating the potential for delays in development plans.


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Although we have used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released onto or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, petroleum hydrocarbons or wastes may have been disposed of or released by prior operators of properties we are acquiring as well as by current third party operators of properties in which we have an ownership interest. Properties impacted by any such disposal or releases could be subject to costly and stringent investigatory or remedial requirements under environmental laws, some of which impose strict, joint and several liability without regard to fault or the legality of the original conduct, including the Comprehensive Environmental Response, Compensation, and Liability Act, also known as “CERCLA” or the “Superfund” law and analogous state laws.

We are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations. We have made and will continue to make expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or operations. However, due to continuing changes in these laws and regulations and judicial construction of same, we are unable to predict with any reasonable degree of certainty our future costs of complying with these governmental requirements. We have been able to plan for and comply with new initiatives without materially changing our operating strategies.

There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Various regulatory bodies have announced their intent to regulate GHG emissions. As these regulations are under development, we are unable to predict the total impact of the potential regulations upon our business, and it is possible that we could face increases in operating costs in order to comply with GHG emissions legislation. We are reviewing, through our Climate Change Committee, issues involving GHG emissions, including assisting management in monitoring the science of climate change and making recommendations to help develop emission reduction programs. In 2008, we published our calendar year 2007 GHG emissions estimates.

We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. We are not fully insured against all environmental risks, and no coverage is maintained with respect to any penalty or fine required to be paid by us.

Future Laws and Regulations

The oil and gas industry is highly regulated and, from time to time, Congress and state legislatures consider broad and sweeping policy changes that may affect the industry. We cannot predict the impact of such future legislative or regulatory initiatives.

Employees

We had 3,129 employees as of December 31, 2008. We consider our relations with our employees to be good.

Executive Officers of the Company

The executive officers of the Company are elected by and serve until their successors are elected by the Board of Directors.

Bob R. Simpson, 60, was a founder of the Company and has been Chairman of the Board since July 1, 1996. Mr. Simpson served as Chief Executive Officer of the Company from 1986 to December 2008. Mr. Simpson was Vice President of Finance and Corporate Development (1979-1986) and Tax Manager (1976-1979) of Southland Royalty Company.

Keith A. Hutton, 50, has been Chief Executive Officer since December 1, 2008. Prior thereto, Mr. Hutton served as President, Executive Vice President-Operations or held similar positions with the Company since 1987. From 1982 to 1987, Mr. Hutton was a Reservoir Engineer with Sun Exploration & Production Company.

Vaughn O. Vennerberg II, 54, has been President since December 1, 2008. Prior thereto, Mr. Vennerberg served as Senior Executive Vice President and Chief of Staff, Executive Vice President-Administration or held similar positions with the Company since 1987. Prior to that time, Mr. Vennerberg was employed by Cotton Petroleum Corporation and Texaco Inc. (1979-1986).

Louis G. Baldwin, 59, has been Executive Vice President and Chief Financial Officer or held similar positions with the Company since 1986. Mr. Baldwin was Assistant Treasurer (1979-1986) and Financial Analyst (1976-1979) at Southland Royalty Company.


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Timothy L. Petrus, 54, has been Executive Vice President-Acquisitions since May 1, 2005. Prior thereto, Mr. Petrus served as Senior Vice President-Acquisitions or held similar positions with the Company since 1988. Prior to that time, Mr. Petrus was employed by Texas American Bank and Exxon Corporation.

Bennie G. Kniffen, 58, has been Senior Vice President and Controller or held similar positions with the Company since 1986. From 1976 to 1986, Mr. Kniffen held the position of Director of Auditing or similar positions with Southland Royalty Company.

Item 1A

Risk Factors

The following factors, among others, could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by management from time to time. Such factors, among others, may have a material adverse effect upon our business, financial condition, and results of operations.

The following discussion of our risk factors should be read in conjunction with the consolidated financial statements and related notes included herein. Because of these and other factors, past financial performance should not be considered an indication of future performance.

Oil, natural gas and natural gas liquids prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect our financial condition.

Our results of operations depend upon the prices we receive for our natural gas, oil and natural gas liquids. We sell most of our natural gas, oil and natural gas liquids at current market prices rather than through fixed-price contracts. Historically, the markets for natural gas, oil and natural gas liquids have been volatile and are likely to remain volatile in the future. The prices we receive depend upon factors beyond our control, which include:

•

weather conditions;

•

political instability or armed conflict in oil-producing regions, such as current conditions in the Middle East, Nigeria and Venezuela;

•

the supply of domestic and foreign oil, natural gas and natural gas liquids;

•

the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels;

•

the level of consumer demand;

•

worldwide economic conditions;

•

the price and availability of alternative fuels;

•

domestic and foreign governmental regulations and taxes;

•

the proximity to and capacity of transportation facilities; and

•

the effect of worldwide energy conservation measures.

Government regulations, such as regulations of natural gas transportation and price controls, can affect product prices in the long term. These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of oil and natural gas.

To the extent we have not hedged our production, any decline in natural gas and oil prices adversely affects our financial condition. If the oil and gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations or make planned capital expenditures.

Our use of hedging arrangements could result in financial losses or reduce our income.

To reduce our exposure to fluctuations in natural gas, oil and natural gas liquids prices, we have entered into and expect in the future to enter into hedging arrangements for a portion of our natural gas, oil and natural gas liquids production. However, we may not be able to hedge our future production at prices we deem attractive. These hedging arrangements expose us to risk of financial loss in some circumstances, including when:

•

production is less than expected;

•

the counterparty to the hedging contract defaults on its contractual obligations; or

•

there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in natural gas, oil and natural gas liquids prices.


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We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.

We make, and will continue to make, substantial capital expenditures for the acquisition, development, exploration and abandonment of our oil and natural gas reserves. We intend to finance our capital expenditures primarily through cash flow from operations, bank and commercial paper borrowings and public and private equity and debt offerings. Lower oil and natural gas prices, however, would reduce our cash flow and could affect our access to the capital markets. Costs of exploration and development were $3.9 billion in 2008, $2.8 billion in 2007 and $2.1 billion in 2006. During 2008, we spent $7.9 billion on proved property acquisitions and $3.1 billion on unproved property acquisitions. Our exploration and development budget for 2009 is $2.75 billion. An additional $450 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities in 2009.

We believe that, after debt service, we will have sufficient cash from operating activities to finance our exploration and development expenses through 2009. If revenues decrease, however, and we are unable to obtain additional debt or equity financing, we may lack the capital necessary to replace our reserves or to maintain production at current levels.

The current financial crisis may impact our business and financial condition in ways that we cannot predict.

The continued credit crisis and related uncertainties in the global financial system may continue to have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. We believe that our development and exploration budget allows us to fund our business with anticipated internally generated cash flow. However, if we were to need to access the capital markets, as a result of this crisis we may not have the ability to raise capital. Also, if the current economic conditions do not improve, it is possible that we could have additional receivables become uncollectible and counterparties under our hedging could be unable to perform their obligations or seek bankruptcy protection. Additionally, the current economic situation could lead to further reductions in demand for natural gas and oil, or lower prices for natural gas and oil, or both, which could have a negative impact on our revenues.

We have substantial indebtedness and may incur substantially more debt. Any failure to meet our debt obligations would adversely affect our business and financial condition.

We have incurred substantial debt. As a result of our indebtedness, we will need to use a portion of our cash flow to pay principal and interest, which will reduce the amount available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our bank revolving credit, term loans and commercial paper indebtedness is at a variable interest rate, so a rise in interest rates will generate greater interest expense to the extent we do not have interest rate protection hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

Together with our subsidiaries, we may incur substantially more debt in the future. The indentures governing our outstanding public debt do not contain restrictions on our incurrence of additional indebtedness. To the extent new debt is added to our current debt levels, the risks resulting from indebtedness could substantially increase. Also, if we repurchase or repay any of our term loans or public debt, we cannot re-borrow these funds and may not be able to enter into a new debt arrangement with similar terms or rates.

Our access to the commercial paper market is predicated on continued acceptable short-term ratings by Standard & Poors and Moody’s. Any downgrade in those ratings may impact our borrowing costs as well as our access to the commercial paper market. Additionally, any downgrade to our long-term ratings could increase our borrowing costs and limit our access to capital markets.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets or sell shares of common stock on terms that we do not find attractive if it can be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under the indebtedness, which could adversely affect our business, financial condition and results of operations.

Competition in the oil and natural gas industry is intense, and some of our competitors have greater financial, technological and other resources than we have.

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:

•

seeking to acquire desirable producing properties or new leases for future exploration;

•

marketing our oil and natural gas production;


15		XTO ENERGY		\|		2008 form 10-K

•

integrating new technologies;

•

seeking to acquire the equipment and expertise necessary to develop and operate our properties; and

•

hiring qualified people.

Some of our competitors have financial, technological and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

The failure to replace our reserves could adversely affect our financial condition.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when oil and natural gas are produced unless we continue to conduct successful exploitation, development or exploration activities or acquire properties containing proved reserves, or both. We may not be able to economically find, develop or acquire additional reserves. Furthermore, while our revenues may increase if oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions or changes in conditions could cause the quantities and net present value of our reserves to be overstated.

To prepare estimates of economically recoverable oil and natural gas reserves and future net cash flows, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geologic, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs. Actual results most likely will vary from our estimates. Any significant variance could reduce the estimated quantities and present value of reserves shown in this annual report.

One should not assume that the present value of future net cash flows from our proved reserves shown in this annual report is the current market value of our estimated oil and natural gas reserves. In accordance with Securities and Exchange Commission requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual current and future prices and costs may differ materially from those used in the net present value estimate, and as a result, net present value estimates using current prices and costs may be significantly less than the estimate which is provided in this annual report.

Producing and unproved property acquisitions are a component of our growth strategy, and our failure to complete future acquisitions successfully could reduce our earnings and slow our growth.

Our business strategy has emphasized growth through acquisitions, but we may not be able to continue to identify properties for acquisition or we may not be able to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our growth strategy may be hindered if we are not able to obtain financing or regulatory approvals. Our ability to grow through acquisitions and manage growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether significant acquisitions are completed in particular periods.


2008 form 10-K		\|		ANNUAL REPORT		16

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities.

Our recent growth is due in part to acquisitions of both producing and unproved properties, and we expect acquisitions will continue to contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, exploration and development potential, lease terms, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not allow us to become sufficiently familiar with the properties, and we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited.

We generally are not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities, on acquisitions. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. If material breaches are discovered by us prior to closing, we could require adjustments to the purchase price, or, if the claims are significant, we or the seller may have a right to terminate the agreement. We could also fail to discover breaches or defects prior to closing and incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, for which we would have limited or no contractual remedies or insurance coverage.

There are risks in acquiring both producing and unproved properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, and costs of increased scope, geographic diversity and complexity of our operations.

Increasing our reserve base through acquisitions is an important part of our business strategy. Our failure to integrate acquired businesses successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations.

Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.

Our development and exploratory drilling efforts and our operations of our wells may not be profitable or achieve our targeted returns.

We acquire significant amounts of unproved property in order to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells. Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas and crude oil, costs associated with producing natural gas and oil and our ability to add reserves at an acceptable cost. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether natural gas or oil is present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies.


17		XTO ENERGY		\|		2008 form 10-K

Drilling oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•

unexpected drilling conditions, including urban drilling;

•

title problems;

•

restricted access to land for drilling or laying pipeline;

•

pressure or irregularities in formations;

•

equipment failures or accidents;

•

adverse weather conditions, including hurricanes in the Gulf of Mexico; and

•

costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment.

The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities, as well as any delays in constructing new infrastructure facilities, could harm our business. We deliver oil and natural gas through gathering systems and pipelines that we do not own. These facilities may be temporarily unavailable due to market conditions or mechanical reasons, or may not be available to us in the future.

We are subject to complex federal, state, local and foreign laws and regulations that could adversely affect our business.

Extensive federal, state, local and foreign regulation of the oil and gas industry significantly affects our operations. In particular, our oil and natural gas exploration, development and production, and our storage and transportation of liquid hydrocarbons, are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other related facilities. These regulations may become more demanding in the future. Matters subject to regulation include:

•

discharge permits for drilling operations;

•

drilling bonds;

•

spacing of wells;

•

unitization and pooling of properties;

•

environmental protection;

•

reports concerning operations; and

•

taxation.

Under these laws and regulations, we could be liable for:

•

personal injuries;

•

property damage;

•

oil spills;


2008 form 10-K		\|		ANNUAL REPORT		18

•

discharge of hazardous materials;

•

reclamation costs;

•

remediation and clean-up costs; and

•

other environmental damages.

Although we believe that our operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could make it more expensive for us to conduct our business or cause us to limit or curtail some of our operations.

We currently own, lease or expect to acquire, and have in the past owned or leased, numerous properties that have been used for the exploration and production of oil and natural gas for many years. Although we have used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed or released on or under the properties owned or leased by us or on or under other locations where such wastes were taken for disposal. In addition, petroleum hydrocarbons or wastes may have been disposed or released by prior operators of properties that we are acquiring as well as by current third party operators of properties in which we have an ownership interest. Properties impacted by any such disposal or release could be subject to costly and stringent investigatory or remedial requirements under environmental laws, some of which impose strict joint and several liability without regard to fault or the legality of the original conduct. These laws include the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as “CERCLA” or the “Superfund” law, the federal Resource Conservation and Recovery Act and analogous state laws. Under these laws and any implementing regulations, we could be required to remediate contaminated properties and take actions to compensate for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damages allegedly caused by the release of petroleum hydrocarbons or wastes into the environment. We currently do not expect any remedial obligations imposed under environmental laws to have a significant effect on our operations.

Our operations in U.S. waters are subject to the federal Oil Pollution Act, which imposes a variety of requirements related to the prevention of oil spills and liability for damages resulting from such spills. The Oil Pollution Act imposes strict joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Liability limits for offshore facilities require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was caused by gross negligence or willful misconduct of the party, if the spill resulted from violation of a federal safety, construction or operation regulation, or if the party failed to report the spill or cooperate fully in any resulting cleanup. The Oil Pollution Act also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe that our operations are in substantial compliance with Oil Pollution Act requirements.

The Department of Transportation, through the Office of Pipeline Safety and Research and Special Programs Administration, has implemented a series of rules requiring operators of natural gas and hazardous liquid pipelines to develop integrity management plans for pipelines that, in the event of a failure, could impact certain high consequence areas. These rules also require operators to conduct baseline integrity assessments of all applicable pipeline segments located in the high consequence areas. We are currently in the process of identifying all of our pipeline segments that may be subject to these rules and are developing integrity management plans for all covered pipeline segments. We do not expect to incur significant costs in achieving compliance with these rules.

Our business involves many operating risks that may result in substantial losses, and insurance may be unavailable or inadequate to protect us against these risks.

Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:

•

fires;

•

natural disasters;

•

explosions;

•

pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion;

•

weather, including hurricanes in the Gulf of Mexico;

•

failure of oilfield drilling and service tools;


19		XTO ENERGY		\|		2008 form 10-K

•

changes in underground pressure in a formation that causes the surface to collapse or crater;

•

pipeline ruptures or cement failures; and

•

environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases.

Any of these risks can cause substantial losses resulting from:

•

injury or loss of life;

•

damage to and destruction of property, natural resources and equipment;

•

pollution and other environmental damage;

•

regulatory investigations and penalties;

•

suspension of our operations; and

•

repair and remediation costs.

We do not insure against the loss of oil or natural gas reserves as a result of operating hazards or insure against business interruption. Losses could occur from uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.

Terrorist activities and military and other actions could adversely affect our business.

On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scope, and the United States and others instituted military action in response. These conditions caused instability in world financial markets and generated global economic instability. The continued threat of terrorism and the impact of military and other action, including U.S. military operations in Afghanistan and Iraq, will likely lead to continued volatility in crude oil and natural gas prices and could affect the markets for our operations. In addition, future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund for their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns or lead to unexpected future costs.

Item 1B

Unresolved Staff Comments

As of December 31, 2008, we do not have any Securities and Exchange Commission staff comments that have been unresolved for more than 180 days.


2008 form 10-K		\|		ANNUAL REPORT		20

Item 3

Legal Proceedings

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 September 2008, we acquired Hunt Petroleum Corporation and other associated entities. One of the entities that we acquired owns properties that are subject to a lawsuit styled USA ex rel. Grynberg v. Columbia Gas Transmission Company, et al. This lawsuit is one of the lawsuits that were filed by Jack J. Grynberg and that were consolidated in the U.S. District Court of Wyoming. The issues and disposition are the same as those discussed in the Grynberg action against XTO Energy described above. While we are unable to predict the final outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

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

In November 2008, an action was filed against the Company and our directors styled Susan Freedman v. William H. Adams, III, et al. in the Delaware Court of Chancery. Plaintiff is alleged to be a shareholder and brings the suit as a derivative action on behalf of the Company. The suit alleges that XTO Energy’s Board of Directors has failed to implement an Internal Revenue Code Section 162(m) plan in order to make certain compensation of its executives tax deductible. The suit claims as damages those amounts paid in taxes that would have been deductible if a Section 162(m) plan were in place. While the Company did not have in place a Section 162(m) plan at the time the suit was filed, and we are unable to predict the final outcome of this case, we believe that the damage allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

In September 2008, a class action lawsuit was filed against the Company styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. We removed the case to federal court in Wichita, Kansas. The plaintiffs allege that XTO Energy has improperly taken post-production costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma, and Colorado. The plaintiffs also seek to represent all royalty owners in these three states as a class. We have answered and denied all claims. 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.

On March 31, 2005, the Division of Air Quality of the Department of Environmental Conservation of the State of Alaska issued us a Notice of Violation regarding nitrogen oxide emissions from one of our cranes that exceed the limitations of our operational permit for one of our platforms in the Cook Inlet of Alaska. In February 2006, the Division of Air Quality proposed a fine of less than $100,000. On February 1, 2008, the Division of Air Quality issued us a Notice of Violation for leaving a portable diesel engine on one of our platforms for longer than


21		XTO ENERGY		\|		2008 form 10-K

permitted, even though the engine did not operate except for one hour of maintenance time. In a meeting with the Division of Air Quality in May 2008, it suggested a total proposed fine of $233,459. We are currently negotiating with the Division of Air Quality regarding this matter.

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.

Item 4

Submission Of Matters To A Vote Of Security Holders

There were no matters submitted to a vote of security holders during the fourth quarter of 2008.


2008 form 10-K		\|		ANNUAL REPORT		22

PART II

Item 5

Market For Registrant’s Common Equity, Related Stockholder Matters And

Issuer Purchases Of Equity Securities

Our common stock is listed on the New York Stock Exchange and trades under the symbol “XTO.” The following table sets forth quarterly high and low closing prices and cash dividends declared for each quarter of 2008 and 2007, (as adjusted for the five-for-four stock split effected in December 2007):


	HIGH		LOW		CASH DIVIDEND
2008
First Quarter	$	63.13	$	48.73	$	0.120
Second Quarter		73.40		61.18		0.120
Third Quarter		69.16		43.54		0.120
Fourth Quarter		45.69		26.71		0.120

2007
First Quarter	$	44.46	$	35.48	$	0.096
Second Quarter		50.82		43.42		0.096
Third Quarter		50.37		41.98		0.096
Fourth Quarter		53.66		48.50		0.120

The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and will depend on our financial condition, earnings and cash flow from operations, the level of our capital expenditures, our future business prospects and other matters the Board of Directors deems relevant.

On February 17, 2009, the Board of Directors declared a quarterly dividend of $0.125 per common share, payable on April 15, 2009 to stockholders of record on March 31, 2009. On February 20, 2009, we had 2,393 stockholders of record.

The following summarizes purchases of our common stock during fourth 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

October

–

November

367,842

35.27

–

December

–

Total

367,842

)

35.27

–

22,208,000

(1)

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

(2)

Does not include performance or restricted share forfeitures. Includes 243,869 shares and 123,973 shares of common stock purchased during the quarter from employees in connection with the settlement of income tax withholding obligations upon vesting of restricted shares and performance shares, respectively, under the 2004 Stock Incentive Plan. These share purchases were not part of a publicly announced program to purchase common shares.


23		XTO ENERGY		\|		2008 form 10-K

Item 6

Selected Financial Data

The following table shows selected financial information for each of the years in the five-year period ended December 31, 2008. Significant producing property acquisitions in each of the years presented affect the comparability of year-to-year financial and operating data. See Items 1 and 2, Business and Properties, “Acquisitions.” All weighted average shares and per share data have been adjusted for the five-for-four stock split effected in December 2007, the four-for-three stock split effected in March 2005 and the five-for-four stock split effected in March 2004. This information should be read in conjunction with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements at Item 15(a).


(in millions except production, per share and per unit data)	2008			2007			2006			2005			2004
Consolidated Income Statement Data
Revenues:
Gas and natural gas liquids	$	5,728		$	4,214		$	3,490		$	2,787		$	1,613
Oil and condensate		1,796			1,204			1,002			670			319
Gas gathering, processing and marketing		168			100			86			56			18
Other		3			(5	)		(2	)		6			(2	)
Total Revenues	$	7,695		$	5,513		$	4,576		$	3,519		$	1,948
Net Income	$	1,912	(a)	$	1,691	(b)	$	1,860	(c)	$	1,152	(d)	$	508	(e)
Earnings per common share:
Basic	$	3.60		$	3.58		$	4.08		$	2.57		$	1.22
Diluted	$	3.56		$	3.53		$	4.02		$	2.52		$	1.21
Weighted average common shares outstanding:
Basic		531.6			471.9			456.1			448.1			416.1
Diluted		537.8			479.0			462.2			457.0			419.6
Cash dividends declared per common share	$	0.480		$	0.408		$	0.252	(f)	$	0.180		$	0.072
Consolidated Statement of Cash Flows Data
Cash provided (used) by:
Operating activities	$	5,235		$	3,639		$	2,859		$	2,094		$	1,217
Investing activities	$	(13,006	)	$	(7,345	)	$	(3,036	)	$	(2,908	)	$	(2,518	)
Financing activities	$	7,796		$	3,701		$	180		$	806		$	1,304

Consolidated Balance Sheet Data
Property and equipment, net	$	31,281		$	17,200		$	10,824		$	8,508		$	5,624
Total assets	$	38,254		$	18,922		$	12,885		$	9,857		$	6,110
Long-term debt	$	11,959		$	6,320		$	3,451		$	3,109		$	2,043
Stockholders’ equity	$	17,347		$	7,941		$	5,865		$	4,209		$	2,599

Operating Data
Average daily production:
Gas (Mcf)		1,905,443			1,457,802			1,186,330			1,033,143			834,572
Natural gas liquids (Bbls)		15,624			13,545			11,854			10,445			7,484
Oil (Bbls)		56,025			47,047			45,041			39,051			22,696
Mcfe		2,335,336			1,821,353			1,527,705			1,330,121			1,015,654
Average realized sales price:
Gas (per Mcf)	$	7.81		$	7.50		$	7.69		$	7.04		$	5.04
Natural gas liquids (per Bbl)	$	48.76		$	45.37		$	37.03		$	34.10		$	26.44
Oil (per Bbl)	$	87.59		$	70.08		$	60.96		$	47.03		$	38.38

Production expense (per Mcfe)	$	1.10		$	0.93		$	0.88		$	0.84		$	0.66
Taxes, transportation and other expense (per Mcfe)	$	0.82		$	0.67		$	0.67		$	0.63		$	0.47

Proved reserves:
Gas (Mcf)		11,802.9			9,441.1			6,944.2			6,085.6			4,714.5
Natural gas liquids (Bbls)		75.8			66.8			53.0			47.4			38.5
Oil (Bbls)		267.5			241.2			214.4			208.7			152.5
Mcfe		13,862.4			11,289.0			8,548.6			7,622.2			5,860.3

Other Data
Ratio of earnings to fixed charges(g)		6.6			9.6			15.2			11.7			8.9


2008 form 10-K		\|		ANNUAL REPORT		24

(a)

Includes pre-tax effects of a $72 million non-cash derivative fair value gain and a $128 million impairment of proved properties.

(b)

Includes pre-tax effects of a $43 million non-cash derivative fair value loss.

(c)

Includes pre-tax effects of a gain on the distribution of Hugoton Royalty Trust units of $469 million, income tax expense related to enactment of a new State of Texas margin tax of $34 million and a $39 million non-cash derivative fair value gain.

(d)

Includes pre-tax effects of a $39 million non-cash derivative fair value gain, non-cash performance award compensation of $34 million, and a gain of $10 million on the exchange of producing properties.

(e)

Includes pre-tax effects of a $6 million non-cash derivative fair value loss, stock-based incentive compensation of $89 million and special bonuses totaling $12 million related to the ChevronTexaco and ExxonMobil acquisitions. Stock-based incentive compensation includes cash compensation of $22 million related to cash-equivalent performance shares.

(f)

Excludes the May 2006 distribution of all of the Hugoton Royalty Trust units owned by the Company to its stockholders as a dividend with a market value of approximately $1.35 per common share.

(g)

For purposes of calculating this ratio, earnings are before income tax and fixed charges. Fixed charges include interest costs and the portion of rentals considered to be representative of the interest factor.


25		XTO ENERGY		\|		2008 form 10-K

Item 7

Management’s Discussion And Analysis Of Financial Condition And

Results Of Operations

The following discussion and analysis should be read in conjunction with Item 6, Selected Financial Data, and the Consolidated Financial Statements at Item 15(a). Unless otherwise indicated, throughout this discussion the term “Mcfe” refers to thousands of cubic feet of gas equivalent quantities produced for the indicated period, with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

Overview

Our business is to produce and sell natural gas, natural gas liquids and crude oil from our predominantly southwestern and central U.S. properties, most of which we operate. Because our gathering, processing and marketing functions are ancillary to and dependent upon our production of natural gas, natural gas liquids and crude oil, we have determined that our business comprises only one industry segment.

In 2008, we achieved the following record financial and operating results:

–

Average daily gas production was 1.91 Bcf, a 31% increase from 2007, average daily oil production was 56.0 MBbls, a 19% increase from 2007, and average daily natural gas liquids production was 15.6 MBbls, a 15% increase from 2007.

–

Year-end proved reserves were 13.86 Tcfe, a 23% increase from year-end 2007.

–

Cash flow from operating activities was $5.2 billion, a 44% increase from 2007.

–

Year-end stockholders’ equity was $17.3 billion, a 118% increase from year-end 2007.

We achieve production and proved reserve growth primarily through acquisitions of both producing and unproved properties, followed by low-risk development generally funded by cash flow from operating activities. Funding sources for our acquisitions include proceeds from sales of public and private equity and debt, bank or commercial paper borrowings and cash flow from operating activities. During 2008, we acquired $7.9 billion of proved properties with proved reserves of 1.5 Tcf of natural gas, 19.9 million Bbls of natural gas liquids and 57.6 million Bbls of oil, as well as $3.1 billion of unproved properties.

In a trend that began in 2004 and continued until mid-2008, commodity prices for natural gas, natural gas liquids and crude oil increased significantly. However, due to oversupply concerns, tightened credit markets and lower demand in slowing U.S and global economies, commodity prices declined sharply in the second half of 2008 (see “Significant Events, Transactions and Conditions-Product Prices”).

The higher prices in prior years and into 2008 led to increased activity in the industry, including the highest drilling rig levels in 25 years and increased demand for oil and gas properties. All of these factors led to significant cost inflation throughout the industry – such as labor, production expenses, drilling costs and acquisition prices. With the deepening of the U.S. and global recession and tightened credit markets, which has led to sharp declines in commodity prices in the latter half of 2008, recent drilling rig counts have decreased more than 30% from peak levels reached in September 2008, acquisition activity has slowed, and all industry costs have begun to decline. This has led many oil and gas exploration and production companies to reevaluate their development plans for the coming year including cuts to their development budgets. Our 2009 development budget is $2.75 billion. Additionally, $450 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities.

Like all oil and gas exploration and production companies, we face the challenge of natural production decline. An oil and gas exploration and production company depletes part of its asset base with each unit of production. Despite this natural decline, we have been able to grow our production through acquisitions and drilling, adding more reserves than we produce. We also attempt to manage our natural decline by combining the acquisition of mature properties with shallower decline rates with the drilling of new wells that have higher decline rates. This has allowed us to keep our natural decline rate lower than the industry average. Future growth will depend on our ability to continue to add reserves in excess of production.

Our goal for 2009 is to increase production by 14%. To achieve future production and reserve growth, we will continue to evaluate acquisitions that meet our criteria and to complete development projects included in our inventory of between 11,100 and 12,220 identified potential drilling locations. We cannot ensure that we will be able to find properties that meet our acquisition criteria and that we can purchase such properties on acceptable terms (see “Liquidity and Capital Resources-Capital Expenditures”).

Increased activity in the oil and gas producing industry has also had an effect on our ability to hire qualified people including not only operational employees, but also all classifications of industry-specific professionals. We continue to hire the employees we need to adequately staff


2008 form 10-K		\|		ANNUAL REPORT		26

our operations; but, the cost of hiring and the time to fill positions has increased. However, with the slowing economy and decreased industry activity, we expect it will be easier to find qualified employees. Our employee turnover continues to remain low with total turnover of 7.2% in 2008 and 9.6% in 2007.

Sales prices for our natural gas, oil and natural gas liquids production are influenced by supply and demand conditions over which we have little or no control, including weather and regional and global economic conditions. To provide predictable production growth, we may hedge a portion of our production at commodity prices management deems attractive to ensure stable cash flow margins to fund our operating commitments and development program. As of February 2009, we have hedged approximately 80% of our 2009 projected gas production at an average NYMEX price of $8.79 per Mcf and about 95% of our 2009 crude oil production at an average NYMEX price of $117.11 per Bbl. Our average realized price on hedged production will be lower than these average NYMEX prices because of location, quality and other adjustments.

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 reduce our debt to between $10.0 billion and $10.5 billion. In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which was used to reduce outstanding debt.

The combined effect of higher product prices, a 31% increase in gas production, a 19% increase in oil production and a 16% increase in natural gas liquids production resulted in a 40% increase in total revenues to $7.7 billion in 2008 from $5.5 billion in 2007. On an Mcfe produced basis, total revenues were $9.00 in 2008, a 9% increase from $8.29 in 2007.

We analyze on an Mcfe produced basis, the following expenses, most of which trend with changes in production:


	2008		2007		INCREASE (DECREASE)
Production	$	1.10	$	0.93	18%
Taxes, transportation and other		0.82		0.67	22%
Depreciation, depletion and amortization		2.37		1.78	33%
Accretion of discount in asset retirement obligation		0.04		0.03	33%
General and administrative, excluding stock compensation		0.25		0.25	–
Interest		0.56		0.38	47%
	$	5.14	$	4.04	27%

Production expense per Mcfe rose 18% primarily because of increased water disposal, 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 expense generally is based on product revenues. The 22% increase in transportation and other expense is a result of higher product prices and higher transportation costs related to increased third-party transportation partially offset by lower property taxes. The 33% increase in depreciation, depletion and amortization per Mcfe resulted from higher acquisition, development and facility costs as well as an impairment of proved properties of approximately $128 million, or $0.15 per Mcfe, and a $107 million, or $0.13 per Mcfe, increase in the impairment of unproved properties. The impairment of unproved properties is expected to increase approximately $70 million to approximately $225 million in 2009. General and administrative expense per Mcfe remained flat because increased personnel and other costs related to Company growth was offset by increased production. The 47% increase in interest expense is primarily because of an increase in weighted average borrowings to fund recent acquisitions.

Significant expenses that generally do not trend with production include:

Non-cash stock incentive compensation. Stock incentive compensation expense was $170 million in 2008 compared to $65 million in 2007. The increase is primarily related to additional grants made in 2007 and 2008.

Derivative fair value (gain) loss. This is the net realized and unrealized gain or loss on derivative financial instruments that does not qualify for hedge accounting treatment and fluctuates based on changes in the fair value of underlying commodities. The net derivative fair value gain was $85 million in 2008 compared to $11 million in 2007.

Our primary sources of liquidity are cash flow from operating activities, borrowings under either our revolving credit agreement, our commercial paper program, or our other unsecured and uncommitted lines of credit and public and private offerings of equity and debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest cost, interest rate volatility and financing risk (See “Liquidity and Capital Resources – Financing”).


27		XTO ENERGY		\|		2008 form 10-K

Significant Events, Transactions and Conditions

The following events, transactions and conditions affect the comparability of results of operations and financial condition for each of the years ended December 31, 2008, 2007 and 2006 and may impact future operations and financial condition.

Acquisitions. We acquired proved and unproved properties at a total cost of $11.0 billion in 2008, $4.0 billion in 2007 and $786 million in 2006, which were funded by a combination of proceeds from sales of common stock and senior notes, borrowings under either our bank credit facilities or commercial paper program and cash flow from operating activities. The following are significant acquisitions in each of these years:


CLOSING DATE		SELLER	AMOUNT (in millions)			ACQUISITION AREA
2008	January to June	Various	$	2,253		Eastern and San Juan Regions, Barnett, Fayetteville, Woodford and Marcellus Shales
	May	Southwestern Energy Company		520		Fayetteville Shale
	July	Linn Energy, LLC		600		Marcellus Shale
		Headington Oil Company		1,804		Bakken Shale
	September	Hunt Petroleum Corporation		4,315	(a)	Eastern Region, South Texas and Gulf Coast Region and North Sea
	October	Hollis R. Sullivan, Inc.		800		Barnett Shale
2007	July	Dominion Resources, Inc.		2,576		Rocky Mountain Region, San Juan Basin and South Texas
	October	Various		550		Barnett Shale
2006	February	Total E&P USA, Inc.		300		East Texas and Mississippi
	June	Peak Energy Resources Inc.		150	(b)	Barnett Shale

(a)

Represents a portion of the allocated purchase price of Hunt Petroleum Corporation and includes an allocation of $4.2 billion to proved properties and $160 million to unproved properties. See Note 14 to the Consolidated Financial Statements.

(b)

Represents a portion of the allocated purchase price of Peak Energy Resources, Inc. and includes an allocation of $97 million to proved properties and $53 million to unproved properties. See Note 14 to the Consolidated Financial Statements.

2008, 2007 and 2006 Development and Exploration Programs. Gas development focused on the Eastern and North Texas Regions during 2008, 2007 and 2006. Oil development was concentrated primarily in the Permian Region during all three years. Development costs totaled $3.4 billion in 2008, $2.5 billion in 2007 and $2.0 billion in 2006. Exploration activity in 2008 and 2007 was primarily drilling and geological and geophysical analysis, including seismic studies in the South Texas and Gulf Coast Region and the Woodford and Fayetteville Shales. Exploratory costs were $517 million in 2008, $257 million in 2007 and $123 million in 2006. Our development and exploration activities are generally funded by cash flow from operations.

2009 Acquisition, Development and Exploration Program. We have budgeted $2.75 billion for our 2009 development and exploration program, which we expect to fund using cash flow from operations. While we expect to focus primarily on development activities in 2009, we expect to actively review acquisition opportunities. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, public or private issuance of debt or equity, or asset sales. Our total budget for acquisitions, development and exploration will be adjusted to focus on opportunities offering the highest rates of return. Additionally, $450 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities.

As of December 31, 2008, we have an inventory of between 11,100 and 12,220 identified potential drilling locations. We plan to drill about 1,000 (800 net) development wells and perform approximately 800 (700 net) workovers and recompletions in 2009. Drilling plans are dependent upon product prices.

Product Prices. In addition to supply and demand, oil and gas prices are affected by seasonal, political and other conditions we generally cannot control or predict.

Gas. Natural gas prices are affected by weather, the U.S. economy, the level of North American production, storage levels, crude oil prices and import levels of liquefied natural gas. Natural gas competes with alternative energy sources as fuel for heating and the generation of electricity. In a trend that began in 2004 and continued until mid-2008, prices for natural gas increased significantly reaching as high as $13.00 per MMBtu in July 2008. Due to concerns of oversupply from shale gas development, declining demand due to the deepening U.S. recession, falling oil prices and increased gas in storage, recent gas prices have dropped sharply. We expect prices to remain volatile. As described under “Hedging Activities” below, we use commodity price hedging instruments to reduce our exposure to gas price fluctuations. The following are comparative average gas prices for the last three years:


	YEAR ENDED DECEMBER 31
(per Mcf)	2008		2007		2006
Average NYMEX price	$	9.03	$	6.86	$	7.23
Average realized sales price	$	7.81	$	7.50	$	7.69
Average realized sales price excluding hedging	$	8.04	$	6.26	$	6.26


2008 form 10-K		\|		ANNUAL REPORT		28

At February 20, 2009, the average NYMEX gas price for the following 12 months was $4.75 per MMBtu. As computed on an energy equivalent basis, our proved reserves were 85% natural gas at December 31, 2008. After considering hedges in place as of February 20, 2009, we estimate that a $0.10 per Mcf change in the average gas sales price would result in approximately a $14 million change in 2009 annual operating cash flow before income taxes.

Oil. Crude oil prices are generally determined by global supply and demand. In a trend that began in 2004 and continued until mid-2008, prices for oil increased significantly reaching a record high above $147 per Bbl in July 2008. However, lower demand as a result of the deepening U.S. recession and slowing global economy, the tightened credit markets and rising crude oil supplies have caused oil prices to decline sharply in the second half of 2008. We expect oil prices to remain volatile. As described under “Hedging Activities” below, we use commodity price hedging instruments to reduce our exposure to oil price fluctuations. The following are comparative average oil prices for the last three years:


	YEAR ENDED DECEMBER 31
(per Bbl)	2008		2007		2006
Average NYMEX price	$	99.75	$	72.39	$	66.22
Average realized sales price	$	87.59	$	70.08	$	60.96
Average realized sales price excluding hedging	$	93.17	$	68.68	$	60.79

At February 20, 2009, the average NYMEX oil price for the following 12 months was $44.87 per Bbl. After considering hedges in place as of February 20, 2009, we estimate that a $1.00 per barrel change in the average oil sales price would result in a minimal change in 2009 annual operating cash flow before income taxes.

Hedging Activities. We may enter futures contracts, collars and basis swap agreements, as well as fixed-price physical delivery contracts, to hedge our exposure to product price volatility. Our policy is to consider hedging a portion of our production at commodity prices management deems attractive. While there is a risk we may not be able to realize the full benefit of rising prices, management plans to continue its hedging strategy because of the benefits of predictable, stable cash flows.

In 2008, all hedging activities decreased gas revenue by $159 million, natural gas liquids revenue by $19 million and oil revenue by $114 million. In 2007, all hedging activities increased gas revenue by $658 million and oil revenue by $24 million. In 2006, all hedging activities increased gas revenue by $618 million and oil revenue by $3 million.

The following summarizes our NYMEX hedging positions under futures contracts and swap agreements as of February 2009, excluding basis adjustments.

Our average daily production was 2.17 Bcf of gas, 63.5 MBbls of oil and 15.4 MBbls of natural gas liquids in fourth quarter 2008. Prices to be realized for hedged production will be less than these NYMEX prices because of location, quality and other adjustments. See Note 8 to the Consolidated Financial Statements.


PRODUCTION PERIOD	MCF PER DAY	WEIGHTED AVERAGE NYMEX PRICE PER MCF
2009 January to December	1,745,000	$ 8.79(a)
2010 January to December	730,000	$ 8.67

(a)

Includes swap agreements for 1,173,000 Mcf per day which were early settled and reset at current market prices. The price shown is the price that will be used for cash flow hedge accounting purposes and has been reduced for transaction costs related to the early settlements. The weighted average cash settlement contract price for all contracts is $6.56 per Mcf. See “Early Settlement of Hedges” below.


PRODUCTION PERIOD	BBLS PER DAY	WEIGHTED AVERAGE NYMEX PRICE PER BBL
2009 January to December	62,500	$ 117.11(a)
2010 January to December	27,500	$ 126.65

(a)

Includes swap agreements for 53,000 Bbls per day which were early settled and reset at current market prices. The price shown is the price that will be used for cash flow hedge accounting purposes and has been reduced for transaction costs related to the early settlements. The weighted average cash settlement contract price for all contracts is $62.86 per Bbl. See “Early Settlement of Hedges” below.

Early Settlement of Hedges. In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which was used to reduce outstanding debt. Of this amount, $453 million ($287 million after-tax) was received in 2008 and the remainder was received in 2009. Under cash flow hedge accounting, the $453 million received in 2008 is included in accumulated other comprehensive income (loss) at December 31, 2008, and will be recognized in earnings during 2009 as the hedged production occurs.


29		XTO ENERGY		\|		2008 form 10-K

Derivative Fair Value (Gain) Loss. We record in our income statements realized and unrealized derivative fair value gains and losses related to derivatives that do not qualify for hedge accounting, as well as the ineffective portion of hedge derivatives. We recorded net derivative fair value gains of $85 million in 2008, $11 million in 2007 and $102 million in 2006. Of these amounts, a $1 million gain in 2008, an $11 million gain in 2007 and a $67 million gain in 2006 was due to the ineffective portion of hedge derivatives. These ineffective hedge derivative gains and losses are primarily because of fluctuating oil and gas prices and their effect on hedges of production in areas without corresponding basis or location differential swap contracts.

Derivative 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 Holding Inc., the parent company of one of our counterparties. The 2008 derivative fair value (gain) loss also includes a $78 million gain ($50 million after-tax) on certain crude oil swap agreements that did not qualify for hedge accounting. The derivative fair value (gain) loss in 2006 includes a net gain related to our Btu swap contracts of $16 million.

Unrealized derivative gains and losses associated with effective cash flow hedges are recorded in stockholders’ equity as accumulated other comprehensive income (loss). At December 31, 2008, we have an unrealized pre-tax gain of $4.1 billion in accumulated other comprehensive income (loss) related to the fair value of derivatives designated as cash flow hedges of natural gas and crude oil price risk. Based on December 31 mark-to-market prices, $3.1 billion of this fair value gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at contract settlement date.

Stock-Based Compensation. Stock compensation totaled $170 million in 2008, $65 million in 2007 and $63 million in 2006. Included in stock option expense in 2006 is $36 million related to options granted which were subject to accelerated vesting provisions upon retirement under employment agreements for certain employees. As required under SFAS No. 123R, stock option awards subject to such vesting provisions granted to retirement-eligible employees are expensed upon grant, rather than over the expected vesting period. As of December 31, 2008, stock compensation expense is expected to total $94 million in 2009, $55 million in 2010, and $26 million in 2011 related to all outstanding stock awards. These expected costs are subject to change for stock incentive awards granted after December 31, 2008.

Hugoton Royalty Trust Distribution. In January 2006, the Board of Directors declared a dividend to common stockholders, consisting of all 21.7 million Hugoton Royalty Trust units owned by us. The dividend ratio of 0.047688 trust units for each common share outstanding was set on the record date of April 26, 2006. The units were distributed on May 12, 2006, when this dividend was recorded. We recorded this dividend at $614 million, or approximately $1.35 per common share, the fair market value of the units based on the May 12, 2006 average high and low New York Stock Exchange trade price of $28.31. After considering the cost of the trust units, we recorded a gain on distribution of $469 million before income tax.

Senior Note Offerings . In March 2006, we sold $400 million of 5.65% senior notes due April 2016 and $600 million of 6.1% senior notes due April 2036.

In July 2007, we sold $300 million of 5.9% senior notes due August 1, 2012, $450 million of 6.25% senior notes due August 1, 2017 and $500 million of 6.75% senior notes due August 1, 2037. In August 2007, we sold an additional $250 million of the 5.9% senior notes, $300 million of the 6.25% senior notes and $450 million of the 6.75% senior notes that constituted a further issuance of the senior notes issued in July 2007.

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. 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. Proceeds from the senior notes were used to fund property acquisitions and reduce bank debt.

Common Stock Transactions. In June 2007, we completed a public offering of 21.6 million common shares at $48.40 per share. After underwriting discount and other offering costs of $35 million, net proceeds of $1.0 billion were used to fund a portion of the acquisition of natural gas and oil properties from Dominion Resources, Inc.

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 and to repay indebtedness under our commercial paper program.

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 and to pay down outstanding commercial paper borrowings.

Shelf Registration Statement. In June 2006, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities or common stock. The securities will be offered at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities are to be used for general corporate purposes, including the reduction of bank debt.


2008 form 10-K		\|		ANNUAL REPORT		30

In June 2006, we registered 3.2 million shares of our common stock, which were issued to the sellers in the acquisition of Peak Energy Resources. In July 2008, we registered 11.7 million shares of our common stock, which were issued to the sellers in the acquisition of properties from Headington Oil Company. In September 2008, we registered 23.5 million shares of our common stock, which were issued to the sellers in the acquisition of Hunt Petroleum Corporation.

Results of Operations

2008 Compared to 2007

For the year 2008, net income was $1.9 billion compared with net income of $1.7 billion for 2007. Earnings for 2008 include the net after-tax effects of both a $46 million non-cash derivative fair value gain and an $81 million impairment of proved properties. Earnings for 2007 include the net after-tax effects of a $28 million non-cash derivative fair value loss.

Revenues for 2008 were $7.7 billion, or 40% higher than 2007 revenues of $5.5 billion. Gas and natural gas liquids revenue increased $1.5 billion because of a 31% increase in gas production, a 16% increase in natural gas liquids production, a 4% increase in gas prices from an average of $7.50 per Mcf in 2007 to $7.81 in 2008 and a 7% increase in natural gas liquids prices from an average price of $45.37 per Bbl in 2007 to $48.76 in 2008 (see “Significant Events, Transactions and Conditions – Product Prices – Gas” above). Increased production was attributable to the 2008 acquisition and development program.

Oil revenue increased $592 million because of a 19% increase in production, primarily due to the 2008 acquisition and development program, and a 25% increase in oil prices from an average of $70.08 per Bbl in 2007 to $87.59 in 2008 (see “Significant Events, Transactions and Conditions – Product Prices – Oil” above).

Expenses for 2008 totaled $4.2 billion, or 60% higher than total 2007 expenses of $2.6 billion. Increased expenses are generally related to increased production from acquisitions and development and related Company growth. Production expense increased $327 million and per Mcfe increased from $0.93 in 2007 to $1.10 in 2008 primarily because of overall price increases as well as increased water disposal, power and fuel costs and certain one-time and discretionary items related to recent property acquisitions including increased compression, maintenance and workover costs. Taxes, transportation and other expense increased $259 million and per Mcfe increased from $0.67 in 2007 to $0.82 in 2008 primarily because of higher product prices and higher transportation costs related to higher throughput volumes. Exploration expense increased $36 million primarily because of increased seismic costs in the Gulf of Mexico and the Woodford and Fayetteville Shales.

Depreciation, depletion and amortization (DD&A) increased $838 million primarily because of increased production. On an Mcfe basis, DD&A increased 33% from $1.78 in 2007 to $2.37 in 2008 because of higher acquisition, development and facility costs as well as an impairment of proved properties of approximately $128 million, or $0.15 per Mcfe, and a $107 million, or $0.13 per Mcfe, increase in the impairment of unproved properties.

General and administrative expense increased $151 million. Of this increase, $105 million was the result of an increase in non-cash incentive award compensation primarily as a result of additional incentive award grants in 2007 and 2008. Increased general and administrative expense, excluding non-cash incentive award compensation, is primarily because of higher employee expenses related to Company growth. Excluding non-cash incentive award compensation, general and administrative expense per Mcfe was $0.25 in 2008 and 2007 as increased personnel and other costs were offset by increased production.

The derivative fair value gain for 2008 was $85 million compared to $11 million in 2007. The 2008 gain is primarily related to the gain on certain crude oil swap agreements that did not qualify for hedge accounting. The 2007 gain is primarily related to the ineffective portion of hedge derivatives. See Note 7 to Consolidated Financial Statements.

Interest expense increased $232 million, primarily because of a 97% increase in the weighted average borrowings to partially fund property acquisitions. Interest expense per Mcfe increased from $0.38 in 2007 to $0.56 in 2008.

The 2008 effective income tax rate was 36.8%, as compared to a 36.0% effective rate for 2007. The current portion of total income taxes was 13% in 2008 and 31% in 2007. The decline in the current portion of total income taxes was primarily due to increased development costs and accelerated tax depreciation as allowed by changes to the tax rules in 2008. Development costs are generally deducted for income tax purposes over a shorter term than for financial accounting purposes.

2007 Compared to 2006

For the year 2007, net income was $1.7 billion compared with net income of $1.9 billion for 2006. Earnings for 2007 include the net after-tax effects of a $28 million non-cash derivative fair value loss. Earnings for 2006 include the net after-tax effects of a $295 million gain on the distribution of Hugoton Royalty Trust units, a $24 million non-cash derivative fair value gain and $34 million of income tax expense related to enactment of a State of Texas margin tax.


31		XTO ENERGY		\|		2008 form 10-K

Revenues for 2007 were $5.5 billion, or 20% higher than 2006 revenues of $4.6 billion. Gas and natural gas liquids revenue increased $724 million, or 21%, because of a 23% increase in gas production, a 14% increase in natural gas liquids production and a 23% increase in natural gas liquids prices from an average price of $37.03 per Bbl in 2006 to $45.37 in 2007, partially offset by a 2% decrease in gas prices from an average of $7.69 per Mcf in 2006 to $7.50 in 2007 (see “Significant Events, Transactions and Conditions – Product Prices – Gas” above). Increased production was attributable to the 2007 acquisition and development program.

Oil revenue increased $202 million, or 20%, because of a 4% increase in production, primarily due to the 2007 acquisition and development program, and a 15% increase in oil prices from an average of $60.96 per Bbl in 2006 to $70.08 in 2007 (see “Significant Events, Transactions and Conditions – Product Prices – Oil” above).

Expenses for 2007 totaled $2.6 billion as compared with total 2006 expenses of $1.9 billion. Increased expenses are generally related to increased production from acquisitions and development and related Company growth. Production expense increased $124 million, or 25%, primarily because of increased overall production and higher maintenance costs. The per Mcfe production expense increase from $0.88 in 2006 to $0.93 in 2007 is primarily attributable to the increased maintenance costs. Taxes, transportation and other expense increased 19%, or $72 million, primarily because of higher product revenues. Taxes, transportation and other per Mcfe was $0.67 in both 2007 and 2006. An increase in transportation and other expense as a result of higher product prices was offset by lower production taxes and lower property taxes. The lower production taxes were primarily due to the benefit of increased gas volumes from new drill wells which were subject to reduced production tax rates. Exploration expense increased $30 million primarily because of increased seismic costs in South Texas and unsuccessful exploratory wells.

Depreciation, depletion and amortization (DD&A) increased $312 million, or 36% primarily because of increased production. On an Mcfe basis, DD&A increased 13% from $1.57 in 2006 to $1.78 in 2007 because of higher acquisition, development and facility costs.

General and administrative expense increased $42 million (22%). Of this increase, $2 million was the result of an increase in non-cash incentive award compensation. Included in 2006 non-cash incentive award compensation was $36 million related to options granted which were subject to accelerated vesting provisions upon retirement under employment agreements for certain employees. As required under SFAS No. 123R, stock option awards subject to such vesting provisions granted to retirement-eligible employees are expensed upon grant, rather than over the expected vesting period. Excluding this charge, non-cash incentive award compensation increased $38 million in 2007 primarily as a result of additional incentive award grants since last year as well as an increase in the fair value of each award granted. Increased general and administrative expense, excluding non-cash incentive award compensation, is primarily because of higher employee expenses related to Company growth. Excluding non-cash incentive award compensation, general and administrative expense per Mcfe increased 14% from $0.22 in 2006 to $0.25 in 2007.

The derivative fair value gain for 2007 was $11 million compared to $102 million in 2006. The 2007 gain is primarily related to the ineffective portion of hedge derivatives. The 2006 gain is primarily related to the ineffective portion of hedge derivatives as well as a $16 million gain on the final settlement of Btu swap contracts. See Note 7 to Consolidated Financial Statements.

Interest expense increased $70 million, or 39%, primarily because of a 43% increase in the weighted average borrowings to fund property acquisitions partially offset by higher interest income related to increased cash on hand and an increase in capitalized interest. Interest expense per Mcfe increased 19% from $0.32 in 2006 to $0.38 in 2007.

The 2007 effective income tax rate was 36.0%, as compared with a 37.2% effective rate for 2006. Excluding the effect of the $34 million income tax expense related to a State of Texas margin tax, the effective tax rate for the 2006 period was 36.0%. The current portion of total income taxes was 31% in 2007 and 52% in 2006. Excluding the effect of the gain on the distribution of Hugoton Royalty Trust units, the current portion of total income taxes was 39% in 2006. The decline in the current portion of total income taxes was primarily due to increased development costs in 2007.

Liquidity and Capital Resources

Our primary sources of liquidity are cash provided by operating activities, borrowings under either our revolving credit agreement, our other unsecured and uncommitted lines of credit or our commercial paper program, occasional proved property sales and private or public offerings of equity and debt. Other than for operations, our cash requirements are generally for the acquisition, exploration and development of oil and gas properties, and debt and dividend payments. Exploration and development expenditures and dividend payments have generally been funded by cash flow from operations. We believe that our sources of liquidity are adequate to fund our cash requirements in 2009.

Our cash provided by operations is affected by our hedge derivative contracts. In December 2008 and January 2009, we entered into early settlement and reset agreements with eight counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which we used to reduce outstanding debt. Of this amount, $453 million ($287 million after-tax) was received in 2008 and the remainder was received in 2009.


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Cash provided by operating activities was $5.2 billion in 2008, compared with cash provided by operating activities of $3.6 billion in 2007 and $2.9 billion in 2006. Increased cash provided by operating activities from 2007 to 2008 and from 2006 to 2007 was primarily because of increased production from acquisitions and development activity, and higher price realizations in 2008 compared to 2007. Also, as discussed above, 2008 benefited from the early settlement and reset arrangements with one of our financial counterparties. Cash provided by operating activities was increased by changes in operating assets and liabilities of $171 million in 2008 and $5 million in 2006 and was decreased by changes in operating assets and liabilities of $72 million in 2007. Changes in operating assets and liabilities are primarily the result of timing of cash receipts and disbursements. Cash provided by operating activities was also reduced by exploration expense, excluding dry hole expense, of $66 million in 2008, $31 million in 2007 and $13 million in 2006. Cash provided by operating activities is largely dependent on our production volumes as well as the prices received for oil and gas production. As of February 2009, we have hedged approximately 80% of our 2009 projected gas production and about 95% of our projected 2009 crude oil production. See “Significant Events, Transactions and Conditions—Product Prices” above.

Financial Condition

Total assets increased 102% from $18.9 billion at December 31, 2007 to $38.3 billion at December 31, 2008, primarily because of Company growth related to acquisitions and development. As of December 31, 2008, total capitalization was $29.3 billion, of which 41% was long-term debt. Capitalization at December 31, 2007 was $14.3 billion, of which 44% was long-term debt. The decrease in the debt-to-capitalization ratio from year-end 2007 to 2008 is primarily because of increased other comprehensive income related to fair value gains on our derivative contracts.

Working Capital

We generally maintain low cash and cash equivalent balances because we use available funds to reduce either bank debt or borrowings under our commercial paper program. Short-term liquidity needs are satisfied by either bank commitments under our loan agreements or our commercial paper program (see “Financing” below). Because of this, and since our principal source of operating cash flows (i.e., proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. Working capital improved from a negative position of $250 million at December 31, 2007 to a positive position of $1.3 billion at December 31, 2008. Excluding the effects of derivative fair value and deferred tax current assets and liabilities, working capital decreased $202 million from a negative position of $230 million at December 31, 2007 to a negative position of $432 million at December 31, 2008. This decrease is a result of increased accounts payable and accrued liabilities primarily related to increased production and drilling liabilities partially offset by increased accounts receivable related to increased revenues. Any cash settlement of hedge derivatives should generally be offset by increased or decreased cash flows from our sales of related production. Therefore, we believe that most of the changes in derivative fair value assets and liabilities are offset by changes in value of our oil and gas reserves. This offsetting change in value of oil and gas reserves, however, is not recorded in the financial statements.

When the monthly cash settlement amount under our hedge derivatives is calculated, if market prices are higher than the fixed contract prices, we are required to pay the contract counterparties. While this payment will ultimately be funded by higher prices received from sale of our production, production receipts 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. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

Recent events in global financial markets have resulted in distortions in the commercial paper markets. In response, in fourth quarter 2008, we 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 reduce our debt to between $10.0 billion and $10.5 billion. The expected debt reduction may include bank facilities, commercial paper or senior notes.

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 forms of security are obtained as considered necessary to limit risk of loss. Financial and commodity-based futures and 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. In September 2008, the parent company of one of our counterparties, Lehman Brothers Holdings Inc, filed for bankruptcy, and we recognized a $38 million ($24 million after-tax) loss in derivative fair value (gain) loss in the income statement. As discussed above in “Significant Events, Transactions and Conditions – Early Settlement of Hedges”, we reduced our counterparty exposure by entering into early settlement and reset arrangements with eight counterparties covering a portion of our 2009 hedge volumes in December 2008 and January 2009.


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Financing

On December 31, 2008, we had borrowings of $1.8 billion outstanding under our revolving credit agreement with commercial banks at an interest rate of 2.4%, and we had available borrowing capacity of $943 million net of our commercial paper borrowings. We use the facility for general corporate purposes and as a backup facility for our commercial paper program. 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 $660 million. The interest rate on any borrowing is generally based on LIBOR plus 0.40%. When utilization of available commitments is greater than 50%, then the interest rate on our borrowings is increased by 0.05%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing commitments, which is 0.09%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 65%. As of February 20, 2009, we had no revolver borrowings.

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 December 31, 2008, borrowings under our commercial paper program were $72 million at a weighted average interest rate of 3.0%. As of February 20, 2009, we had $102 million of commercial paper borrowings.

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 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 December 31, 2008, there were no borrowings under these lines.

Our revolving credit and term loan agreements contain no clauses that permit the lenders to accelerate payments or refuse to lend based on any unspecified material adverse change. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if we default on any principal or interest payments under the loan agreements or our swap agreements or under any other payment obligation in excess of $100 million. We were in compliance with the terms of the credit agreement as of December 31, 2008.

Our ability to access funds under our credit agreements is not directly subject to a “material adverse effect” clause, rather we have to make certain representations, some of which contain a specific “material adverse effect” provision which limits our scope to the representation made, though none are related to our current financial situation. We are in compliance with the representations and do not believe that making the representations is a material restriction on our ability to access funds under our credit agreements.

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, 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.

Our senior unsecured long-term debt is currently rated Baa2 by Moody’s and BBB by Standard & Poor’s. Our short-term debt rating for our commercial paper program is currently rated P-2 by Moody’s and A-2 by Standard & Poor’s. The outlook is stable from both rating agencies.

A decline in our credit ratings with Moody’s and Standard & Poor’s does not trigger any drawdown restrictions or acceleration of maturity under our credit agreements. However, our cost of borrowing under our credit agreements is determined by our credit ratings. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our revolving credit facility and term loans. Additionally, any downgrade to those ratings could increase our future borrowing costs and limit our access to debt capital markets.


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Our acquisition of properties from Headington Oil Company in July 2008 was partially funded through issuance to the sellers of 11.7 million shares of common stock. 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 sellers of 23.5 million shares of common stock. We registered these shares under our shelf registration statement.

Capital Expenditures

In 2008, exploration and development cash expenditures totaled $3.7 billion compared with $2.7 billion in 2007. We have budgeted $2.75 billion for the 2009 development and exploration program and an additional $450 million for the construction of pipeline infrastructure and compression and processing facilities. As we have done historically, we expect to fund the 2009 development program with 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 half of 2008. With demand decreasing due to sharply lower oil and natural gas prices and slowing global growth, we expect steel 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 2009 development program.

While we expect to focus on development activities in 2009, we plan to actively review acquisition opportunities. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, issuance of public or private debt or equity, or asset sales. Other than the requirement for us to maintain a debt-to-total capitalization ratio of not more than 65%, there are no restrictions under our revolving credit agreement that would affect our ability to use our remaining borrowing capacity.

To date, we have not incurred significant amounts to comply with environmental or safety regulations, and we do not expect to during 2009. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Dividends

The Board of Directors declared quarterly dividends of $0.06 per common share for the first three quarters of 2006, $0.072 per common share for fourth quarter 2006, $0.096 per common share for the first three quarters of 2007 and $0.12 per common share for fourth quarter 2007 and each quarter in 2008. On February 17, 2009, the Board of Directors declared a first quarter 2009 dividend of $0.125 per common share.

In January 2006, the Board of Directors declared a dividend to common stockholders, consisting of all 21.7 million Hugoton Royalty Trust units owned by us. The dividend ratio of 0.047688 trust units for each common share outstanding was set on the record date of April 26, 2006. The units were distributed on May 12, 2006, when this dividend was recorded at approximately $1.35 per common share, based on the fair market value of the units on that date.

Our ability to pay dividends is dependent upon our financial condition, earnings and cash flow from operations, the level of our capital expenditures, our future business prospects and other matters our Board deems relevant.

Off-Balance Sheet Arrangements

We do not have any investments in unconsolidated entities or persons that could materially affect the liquidity or the availability of capital resources. Under the terms of some of our operating leases for compressors, airplanes and vehicles, we have various residual value guarantees and other payment provisions upon our election to return the equipment under certain specified conditions. Guarantees related to these leases are not material. The only material off-balance sheet arrangements that we have entered into are those disclosed in the following table of contractual obligations and commitments.


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Contractual Obligations and Commitments

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


			PAYMENTS DUE BY YEAR
(in millions)	TOTAL		2009		2010		2011		2012		2013		AFTER 2013
Long-term debt	$	11,997	$	–	$	250	$	–	$	900	$	3,797	$	7,050
Operating leases		101		32		27		21		11		6		4
Drilling contracts		312		241		61		10		–		–		–
Purchase commitments		99		99		–		–		–		–		–
Transportation contracts		883		122		121		116		107		101		316
Derivative contract liabilities at December 31, 2008 fair value		35		35		–		–		–		–		–
Total	$	13,427	$	529	$	459	$	147	$	1,018	$	3,904	$	7,370

Long-Term Debt. Long-term debt amounts represent scheduled maturities of our debt obligations at December 31, 2008, excluding $38 million of net discounts on our senior notes included in the carrying value of debt. At December 31, 2008, borrowings were $72 million under our commercial paper program. Because we had the intent and ability to refinance the balance due with borrowings under our credit facility due in April 2013, the $72 million outstanding under the commercial paper program is reflected in the table above as due in 2013. Borrowings of $600 million under our term loans are due in 2013, and our senior notes, totaling $9.5 billion, are due 2010 through 2038. For further information regarding long-term debt, see Note 3 to Consolidated Financial Statements.

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

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 third 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, currently expected in second quarter 2009, 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 November 2008, we completed an agreement to enter into a twelve-year firm transportation contract, contingent upon obtaining regulatory approvals and completion of a new pipeline that connects the Fayetteville Shale to ANR Pipeline and Trunkline Pipeline in Quitman County, Mississippi. Upon the pipeline’s completion, currently expected in fourth quarter 2010, we will transport gas volumes for a transportation fee of up to $1.25 million per month plus fuel, currently expected to be 0.86% of the sales price.

In January 2009, we completed an agreement that obligates us to enter into a ten-year firm transportation contract, contingent upon completion and availability for service of the expansion project’s facilities, to transport gas volumes using a pipeline that connects Sherman, Texas to Tallulah, Louisiana. Upon completion, currently expected in second quarter 2009, we will transport gas volumes for a transportation fee of up to $1.3 million per month plus fuel, currently expected to be 0.85% 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 indicated projects.

Derivative Contracts. We have entered into futures contracts and swaps to hedge our exposure to natural gas and oil price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of December 31, 2008, the current liability related to such contracts was $35 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts may be received as much as 55 days after payment to counterparties and can result in draws on our revolving credit facility, our other unsecured and uncommitted lines of credit or our commercial paper program. See Note 7 to Consolidated Financial Statements.


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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 and June 2007 common stock offerings and our April and July 2008, July and August 2007 and March 2006 senior note offerings. We paid, for the credit of this firm, total fees of $11.8 million in 2008, $3.4 million in 2007 and $78,500 in 2006. There were no amounts payable at December 31, 2008 or 2007.

In February 2007, in recognition of the Chairman of the Board and Founder 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 in each of 2007 and 2008. Concurrently, our Chairman of the Board and Founder, made a $3.2 million pledge for the same project. He fulfilled his obligation in 2008. In return for these contributions, the Company and Chairman of the Board and Founder obtained naming rights for the building and certain facilities within the building.

In November 2007, the Board of Directors approved and we paid our Chairman of the Board and Founder $150,000 for an easement across his property in North Texas. The easement was for approximately 10,000 feet at the standard easement rate in the area of $15 per foot.

Critical Accounting Policies and Estimates

Our financial position and results of operations are significantly affected by accounting policies and estimates related to our oil and gas properties, proved reserves, asset retirement obligation and commodity prices and risk management, as summarized below.

Oil and Gas Property Accounting

Oil and gas exploration and production companies may elect to account for their property costs using either the “successful efforts” or “full cost” accounting method. Under the successful efforts method, unsuccessful exploratory well costs, as well as all exploratory geological and geophysical costs, are expensed. Under the full cost method, all exploration costs are capitalized, regardless of success. Selection of the oil and gas accounting method can have a significant impact on a company’s financial results. We use the successful efforts method of accounting and generally pursue acquisitions and development of proved reserves as opposed to exploration activities.

In accordance with Statement of Financial Accounting Standards No. 144, we evaluate possible impairment of producing properties when conditions indicate that the properties may be impaired. Such conditions include a significant decline in product prices which we believe to be other than temporary or a significant downward revision in estimated proved reserves for a field or area. An impairment provision must be recorded to adjust the net book value of the property to its estimated fair value if the net book value exceeds management’s estimate of future net cash flows from the property. The estimated fair value of the property is generally calculated as the discounted present value of future net cash flows. Our estimates of cash flows are based on the latest available proved reserve and production information and management’s estimates of future product prices and costs, based on available information such as forward strip prices and industry forecasts and analysis.

The impairment assessment process is primarily dependent upon the estimate of proved reserves. Any overstatement of estimated proved reserve quantities would result in an overstatement of estimated future net cash flows, which could result in an understated assessment of impairment. The subjectivity and risks associated with estimating proved reserves are discussed under “Oil and Gas Reserves” below. Prediction of product prices is subjective since prices are largely dependent upon supply and demand resulting from global and national conditions generally beyond our control. However, management’s assessment of product prices for purposes of impairment is consistent with that used in its business plans and investment decisions. While there is judgment involved in management’s estimate of future product prices, the potential impact on impairment has not been significant since product prices have been substantially higher than our net acquisition and development costs per Mcfe. However, with the deepening U.S. recession and the slowing global economy, current product prices have declined significantly, resulting in a change in our development drilling plans. Though projected product prices less expenses are still expected by management to be higher than our net acquisition and development costs per Mcfe for most of our properties, we recognized a $128 million impairment of proved properties in 2008. Prior to this year, our historical impairment of proved properties had been limited to an immaterial impairment in 1998. We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impracticable to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.

Oil and Gas Reserves

Our proved oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.


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Proved reserves, as defined by the Financial Accounting Standards Board and adopted by the Securities and Exchange Commission, are limited to reservoir areas that indicate economic producibility through actual production or conclusive formation tests, and generally cannot extend beyond the immediately adjoining undrilled portion. Although improved technology often can identify possible or probable reserves other than by drilling, under current SEC rules, these reserves cannot be estimated and disclosed.

Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in timing of when DD&A expense is recognized. Downward revisions of proved reserves result in an acceleration of DD&A expense, while upward revisions tend to lower the rate of DD&A expense recognition. As shown in Note 16 to the Consolidated Financial Statements, net downward revisions of proved reserves on an Mcfe basis occurred in 2008 and 2006, which will result in an increase in DD&A expense of approximately 8% in 2009 and resulted in an increase in DD&A expense of approximately 1% in 2007. Net upward revisions occurred to proved reserves on an Mcfe basis in 2007, resulting in a decrease in DD&A expense of approximately 1% in 2008. Based on proved reserves at December 31, 2008, we estimate that a 1% change in proved reserves would increase or decrease 2009 DD&A expense by approximately $30 million.

During 2008, development and exploration activities resulted in extensions, additions, discoveries and net revisions of proved reserves that were 168% of our 2008 production. Over the last five years, our proved reserve extensions, additions, discoveries and net revisions averaged 239% of our production for this period. Our proved reserve extensions, additions and discoveries in 2008 included an increase of 1.7 Tcfe in proved undeveloped reserves, or approximately 74% of our total extensions, additions and discoveries. The remaining extensions, additions and discoveries were proved developed reserves. Over the past five years, approximately 74% of our proved reserves extensions, additions and discoveries were proved undeveloped reserves. These proved undeveloped reserve extensions, additions and discoveries were generally reclassified to proved developed reserves within three years. Development of our proved undeveloped reserves is not subject to significant uncertainties such as regulatory approvals, and we believe that we have adequate resources to develop these reserves, dependent on commodity prices not declining significantly. We believe that reserve additions, comparable to these historical reserve additions, are attainable in the near term future, subject to product prices and development costs remaining at levels to ensure economic viability.

The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 16 to Consolidated Financial Statements, are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves.

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 federal, state and international laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2008, we revised our existing estimated asset retirement obligation by $52 million, or approximately 11% of the asset retirement obligation at December 31, 2007, based on a review of current plugging and abandonment costs. Over the past five years, revisions to the estimated asset retirement obligation averaged approximately 11% of the asset retirement obligation at the beginning of the year. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

Commodity Prices and Risk Management

Commodity prices significantly affect our operating results, financial condition, cash flows and ability to borrow funds. Current market oil and gas prices are affected by supply and demand as well as seasonal, political and other conditions which we generally cannot control. Oil and gas prices and markets are expected to continue their historical volatility. See “Significant Events, Transactions and Conditions – Product Prices” above.


2008 form 10-K		\|		ANNUAL REPORT		38

We attempt to reduce our price risk on a portion of our production by entering into financial instruments such as futures contracts, collars and basis swap agreements, as well as fixed-price physical delivery contracts. While these instruments secure a certain price and, therefore, a certain cash flow, there is the risk that we may not be able to realize the full benefit of rising prices. These contracts also expose us to credit risk of nonperformance by the contract counterparties, all of which are major investment grade financial institutions. We attempt to limit our credit risk by obtaining letters of credit or other appropriate forms of security. In 2008, the parent company of one of our counterparties, Lehman Brothers Holdings Inc., filed for bankruptcy, and we recognized a $38 million ($24 million after-tax) loss on the related derivative contracts with the counterparty.

While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under U.S. generally accepted accounting principles, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements. Derivatives that provide effective cash flow hedges are designated as hedges, and, to the extent the hedge is determined to be effective, we defer related unrealized fair value gains and losses in accumulated other comprehensive income (loss) until the hedged transaction occurs. See “Derivatives” under Note 1 to Consolidated Financial Statements regarding our accounting policy related to derivatives.

See also “Commodity Price Risk” under Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for the effect of price changes on derivative fair value gains and losses.

Goodwill

Goodwill is not amortized to earnings but is tested, at least annually, for impairment at the reporting unit level. We conduct the goodwill impairment test effective October 1 of each year. Other events and changes in circumstances may also require goodwill to be tested for impairment between annual measurement dates. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. If the estimated fair value is greater than the carrying amount of the reporting unit, then no impairment loss is required. With the deepening of the U.S. and global recessions, which led to sharp declines in oil and gas prices over the last half of 2008, we updated our impairment test as of December 31, 2008. This test indicated no impairment.

Although we cannot predict if or when goodwill may become impaired in the future, impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the associated reporting unit. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.

Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates.

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 did not 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 will result in a decrease to earnings when acquisitions occur.


39		XTO ENERGY		\|		2008 form 10-K

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 is not expected to have a significant effect on our reported financial position or earnings.

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

Production Imbalances

We have gas production imbalance positions that are the result of partial interest owners selling more or less than their proportionate share of gas on jointly owned wells. Imbalances are generally settled by disproportionate gas sales over the remaining life of the well, or by cash payment by the overproduced party to the underproduced party. We use the entitlement method of accounting for natural gas sales. Accordingly, revenue is deferred for gas deliveries in excess of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. Our net gas imbalance at December 31, 2008 was reported in the balance sheet as a $2 million net long-term receivable. At December 31, 2007, our net gas imbalance was reported in the balance sheet as a $1 million net current receivable.

Forward-Looking Statements

Certain information included in this annual report and other materials filed or to be filed by us with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by us, 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 our operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures in total or by region, capital budget and funding thereof, cash flow, drilling activity, drilling locations, the number of wells to be drilled, worked over or recompleted in total or by region, acquisition and development activities and funding thereof, production and reserve growth, pricing differentials, reserve potential, operating costs, operating margins, production and exploration activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, unused borrowing capacity, estimated stock award vesting periods, completion of pipelines and processing facilities, regulatory matters, competition and value of non-cash dividends. 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. Therefore, actual results may differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are discussed in Item 1A, Risk Factors.


2008 form 10-K		\|		ANNUAL REPORT		40

Item 7A

Quantitative And Qualitative Disclosures About Market Risk

We only enter derivative financial instruments in conjunction with our hedging activities. These instruments principally include commodity futures, collars, swaps and interest rate swap agreements. These financial and commodity-based derivative contracts are used to limit the risks of fluctuations in interest rates and natural gas, crude oil and natural gas liquids prices. Gains and losses on these derivatives are generally offset by losses and gains on the respective hedged exposures.

Our Board of Directors has adopted a policy governing the use of derivative instruments, which requires that all derivatives used by us relate to an underlying, offsetting position, anticipated transaction or firm commitment, and prohibits the use of speculative, highly complex or leveraged derivatives. Risk management programs using derivatives must be authorized by the Chairman of the Board and the President. These programs are also reviewed quarterly by our internal risk management committee and annually by the Board of Directors.

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. It is not possible to accurately predict future changes in interest rates and product prices. Accordingly, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Interest Rate Risk

We are exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At December 31, 2008, our variable rate debt had a carrying value of $2.5 billion, which approximated its fair value, and our fixed rate debt had a carrying value of $9.5 billion and an approximate fair value of $8.9 billion. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest cost, interest rate volatility and financing risk. This is accomplished through a mix of bank debt with short-term variable rates and fixed rate senior and subordinated debt, as well as the occasional use of interest rate swaps.

The following table shows the carrying amount and fair value of long-term debt and the hypothetical change in fair value that would result from a 100-basis point change in interest rates. Unless otherwise noted, the hypothetical change in fair value could be a gain or a loss depending on whether interest rates increase or decrease.


(in millions)	CARRYING AMOUNT	FAIR VALUE(a)	HYPOTHETICAL CHANGE IN FAIR VALUE
Long-term debt as of December 31, 2008	$ (11,959)	$ (11,421)	$ 644
Long-term debt as of December 31, 2007	$ (6,320)	$ (6,438)	$ 422

(a)

Fair value is based upon current market quotes and is the estimated amount required to purchase our long-term debt on the open market. This estimated value does not include any redemption premium.

Commodity Price Risk

We have hedged a portion of our price risks associated with our natural gas and crude oil sales. As of December 31, 2008, our outstanding futures contracts and swap agreements had a net fair value gain of $3.7 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 December 31, 2008. The hypothetical change in fair value could be a gain or a loss depending on whether prices increase or decrease.


(in millions)	FAIR VALUE		HYPOTHETICAL CHANGE IN FAIR VALUE
Natural gas futures and sell basis swap agreements	$	1,903	$ 520
Natural gas purchase basis swap agreements	$	–	$ 1
Crude oil futures	$	1,820	$ 185

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.


41		XTO ENERGY		\|		2008 form 10-K

Item 8

Financial Statements And Supplementary Data

The following financial statements and supplementary information are included under Item 15(a):


		PAGE
Consolidated Balance Sheets		46
Consolidated Income Statements		47
Consolidated Statements of Cash Flows		48
Consolidated Statements of Stockholders’ Equity		49
Notes to Consolidated Financial Statements		50
Selected Quarterly Financial Data
(Note 15 to Consolidated Financial Statements)		73
Information about Oil and Gas Producing Activities
(Note 16 to Consolidated Financial Statements)		73
Management’s Report on Internal Control over Financial Reporting		77
Reports of Independent Registered Public Accounting Firm		78

Item 9

Changes In And Disagreements With Accountants On Accounting And

Financial Disclosure

There have been no changes in accountants or any disagreements with accountants on any matter of accounting principles or practices or financial statement disclosures during the two years ended December 31, 2008.

Item 9A

Controls And Procedures

a) Evaluation of Disclosure 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 in timely alerting them to material information relating to the Company required to be included in our periodic filings with the Securities and Exchange Commission and that our disclosure controls and procedures are effective to ensure that information required to be disclosed in Exchange Act reports is recorded, processed, summarized and reported within the specific time periods. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected.

b) Management’s Report on Internal Control over Financial Reporting

Our management’s report on internal control over financial reporting is set forth in Item 8 of this Annual Report on Form 10-K and is incorporated by reference herein.

c) Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting during the quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B

Other Information

None.


2008 form 10-K		\|		ANNUAL REPORT		42

PART III

Except for the portion of Item 10 relating to Executive Officers of the Registrant which is included in Part I of this Report or is included below, the information called for by Items 10 through 14 is incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement to be filed with the Securities and Exchange Commission no later than April 30, 2009.

Item 10

Directors, Executive Officers And Corporate Governance

We have a Code of Business Conduct and Ethics that applies to all directors, officers and employees, including the chief executive officer and senior financial officers. We also have a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. You can find our Code of Business Conduct and Ethics and our Code of Ethics for the Chief Executive Officer and Senior Financial Officers on our web site at http://www.xtoenergy.com. You can also obtain a free copy of these materials by contacting us at 810 Houston Street, Fort Worth, Texas 76102, Attn: Corporate Secretary. Any amendments to or waivers from these codes that apply to our executive officers will be posted on the Company’s web site or by other appropriate means in accordance with the rules of the Securities and Exchange Commission.

Item 11

Executive Compensation

Item 12

Security Ownership Of Certain Beneficial Owners And

Management And Related Stockholder Matters

Item 13

Certain Relationships And Related Transactions, And

Director Independence

Item 14

Principal Accountant Fees And Services


43		XTO ENERGY		\|		2008 form 10-K

PART IV

Item 15

Exhibits And Financial Statement Schedules

(a)

The following documents are filed as a part of this report:


		PAGE
1.	Financial Statements:
	Consolidated Balance Sheets at December 31, 2008 and 2007	46
	Consolidated Income Statements for the years ended December 31, 2008, 2007 and 2006	47
	Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	48
	Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2008, 2007 and 2006	49
	Notes to Consolidated Financial Statements	50
	Management’s Report on Internal Control over Financial Reporting	77
	Reports of Independent Registered Public Accounting Firm	78

2.	Financial Statement Schedules:
	All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to consolidated financial statements

(b)

Exhibits

See Index to Exhibits at page 80 for a description of the exhibits filed as a part of this report. Documents filed prior to June 1, 2001, were filed with the Securities and Exchange Commission under our prior name, Cross Timbers Oil Company.


2008 form 10-K		\|		ANNUAL REPORT		44

XTO ENERGY INC.

Consolidated Balance Sheets


	DECEMBER 31
(in millions, except shares)	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	25		$	–
Accounts receivable, net		1,217			852
Derivative fair value		2,735			199
Current income tax receivable		57			118
Deferred income tax benefit		–			20
Other		224			98
Total Current Assets		4,258			1,287
Property and Equipment, at cost – successful efforts method:
Proved properties		30,994			18,671
Unproved properties		3,907			1,050
Other		2,239			1,376
Total Property and Equipment		37,140			21,097
Accumulated depreciation, depletion and amortization		(5,859	)		(3,897	)
Net Property and Equipment		31,281			17,200
Other Assets:
Derivative fair value		1,023			–
Acquired gas gathering contracts, net of accumulated amortization		105			112
Goodwill		1,447			215
Other		140			108
Total Other Assets		2,715			435
TOTAL ASSETS	$	38,254		$	18,922
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,912		$	1,264
Payable to royalty trusts		13			30
Derivative fair value		35			239
Deferred income tax payable		940			–
Other		30			4
Total Current Liabilities		2,930			1,537
Long-term Debt		11,959			6,320
Other Liabilities:
Derivative fair value		–			4
Deferred income taxes payable		5,200			2,610
Asset retirement obligation		735			450
Other		83			60
Total Other Liabilities		6,018			3,124
Commitments and Contingencies (Note 6)
Stockholders’ Equity:
Common stock ($0.01 par value, 1,000,000,000 shares authorized, 585,094,847 and 490,434,003 shares issued)		6			5
Additional paid-in capital		8,315			3,172
Treasury stock, at cost (5,563,247 and 5,140,230 shares)		(147	)		(134	)
Retained earnings		6,588			4,938
Accumulated other comprehensive income (loss)		2,585			(40	)
Total Stockholders’ Equity		17,347			7,941
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	38,254		$	18,922

See accompanying notes to consolidated financial statements.


45		XTO ENERGY		\|		2008 form 10-K

XTO ENERGY INC.

Consolidated Income Statements


	YEAR ENDED DECEMBER 31
(in millions, except per share data)	2008			2007			2006
REVENUES
Gas and natural gas liquids	$	5,728		$	4,214		$	3,490
Oil and condensate		1,796			1,204			1,002
Gas gathering, processing and marketing		168			100			86
Other		3			(5	)		(2	)
Total Revenues		7,695			5,513			4,576
EXPENSES
Production		942			615			491
Taxes, transportation and other		703			444			372
Exploration		88			52			22
Depreciation, depletion and amortization		2,025			1,187			875
Accretion of discount in asset retirement obligation		31			22			16
Gas gathering and processing		101			81			41
General and administrative		382			231			189
Derivative fair value (gain) loss		(85	)		(11	)		(102	)
Total Expenses		4,187			2,621			1,904
OPERATING INCOME		3,508			2,892			2,672
OTHER (INCOME) EXPENSE
Gain on distribution of royalty trust units		–			–			(469	)
Interest expense, net		482			250			180
Total Other (Income) Expense		482			250			(289	)
INCOME BEFORE INCOME TAX		3,026			2,642			2,961
INCOME TAX EXPENSE
Current		140			292			572
Deferred		974			659			529
Total Income Tax Expense		1,114			951			1,101
NET INCOME	$	1,912		$	1,691		$	1,860
EARNINGS PER COMMON SHARE
Basic	$	3.60		$	3.58		$	4.08
Diluted	$	3.56		$	3.53		$	4.02
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic		531.6			471.9			456.1
Diluted		537.8			479.0			462.2

See accompanying notes to consolidated financial statements.


2008 form 10-K		\|		ANNUAL REPORT		46

XTO ENERGY INC.

Consolidated Statements of Cash Flows


	YEAR ENDED DECEMBER 31
(in millions)	2008			2007			2006
OPERATING ACTIVITIES
Net income	$	1,912		$	1,691		$	1,860
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		2,025			1,187			875
Accretion of discount in asset retirement obligation		31			22			16
Non-cash incentive compensation		170			65			63
Dry hole expense		22			21			9
Deferred income tax		974			659			529
Gain on distribution of royalty trust units		–			–			(469	)
Non-cash change in derivative fair value (gain) loss		(72	)		43			(39	)
Other non-cash items		2			23			10
Changes in operating assets and liabilities, net of effects of acquisitions of corporations(a)		171			(72	)		5
Cash Provided by Operating Activities		5,235			3,639			2,859
INVESTING ACTIVITIES
Proceeds from sale of property and equipment		24			1			6
Property acquisitions, including acquisitions of corporations		(8,456	)		(4,012	)		(616	)
Development costs, capitalized exploration costs and dry hole expense		(3,661	)		(2,668	)		(2,047	)
Other property and asset additions		(913	)		(666	)		(379	)
Cash Used by Investing Activities		(13,006	)		(7,345	)		(3,036	)
FINANCING ACTIVITIES
Proceeds from long-term debt		19,560			7,293			5,719
Payments on long-term debt		(14,250	)		(4,433	)		(5,377	)
Net proceeds from common stock offerings		2,612			1,009			–
Dividends		(250	)		(170	)		(109	)
Debt costs		(32	)		(18	)		(9	)
Proceeds from exercise of stock options and warrants		23			33			24
Payments upon exercise of stock options		(70	)		(57	)		(46	)
Excess tax benefit on exercise of stock options or vesting of stock awards		64			57			50
Other, including cash overdrafts and purchase of treasury stock		139			(13	)		(72	)
Cash Provided by Financing Activities		7,796			3,701			180
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		25			(5	)		3
Cash and Cash Equivalents, January 1		–			5			2
Cash and Cash Equivalents, December 31	$	25		$	–		$	5

(a) Changes in Operating Assets and Liabilities
Accounts receivable		$(151	)	$	(198	)	$	(12	)
Other current assets		(32	)		(85	)		(16	)
Other operating assets and liabilities		(7	)		(9	)		(12	)
Current liabilities		(92	)		220			45
Change in current assets from early settlement of hedges		453			–			–
	$	171		$	(72	)	$	5

See accompanying notes to consolidated financial statements.


47		XTO ENERGY		\|		2008 form 10-K

XTO ENERGY INC.

Consolidated Statements of Stockholders’ Equity


(in millions, except per share amounts)	COMMON STOCK		ADDITIONAL PAID-IN CAPITAL		TREASURY STOCK			RETAINED EARNINGS			ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	TOTAL
Balances, December 31, 2005	$	5	$	1,864	$	(39	)	$	2,311		$ 68	$	4,209
Net income		–		–		–			1,860		–		1,860
Change in hedge derivative fair value, net of applicable income tax of $473		–		–		–			–		810		810
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income (loss), net of applicable income tax of $225		–		–		–			–		(390)		(390	)
Adjustment related to initial recognition of funded status of post-retirement health plan, net of applicable income tax of $1		–		–		–			–		(2)		(2	)
Comprehensive income													2,278
Issuance/vesting of stock awards		–		10		(3	)		–		–		7
Expensing of stock options		–		53		–			–		–		53
Stock option and warrant exercises, including income tax benefits		–		28		–			–		–		28
Treasury stock purchases		–		–		(83	)		–		–		(83	)
Issuance of common stock for acquisition of corporation		–		102		–			–		–		102
Fair value of royalty trust unit distribution ($1.35 per share)		–		–		–			(614	)	–		(614	)
Common stock dividends ($0.252 per share)		–		–		–			(115	)	–		(115	)
Balances, December 31, 2006		5		2,057		(125	)		3,442		486		5,865
Net income		–		–		–			1,691		–		1,691
Change in hedge derivative fair value, net of applicable income tax of $49		–		–		–			–		(77)		(77	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income (loss), net of applicable income tax of $257		–		–		–			–		(444)		(444	)
Change in funded status of post-retirement health plan, net of applicable income tax of $3		–		–		–			–		(5)		(5	)
Comprehensive income													1,165
Issuance/vesting of stock awards, including income tax benefits		–		26		(9	)		–		–		17
Expensing of stock options		–		42		–			–		–		42
Stock option and warrant exercises, including income tax benefits		–		38		–			–		–		38
Common stock offering		–		1,009		–			–		–		1,009
Common stock dividends ($0.408 per share)		–		–		–			(195	)	–		(195	)
Balances, December 31, 2007		5		3,172		(134	)		4,938		(40)		7,941
Net income		–		–		–			1,912		–		1,912
Change in hedge derivative fair value, net of applicable income tax of $1,408		–		–		–			–		2,444		2,444
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income (loss), net of applicable income tax of $107		–		–		–			–		187		187
Change in funded status of post-retirement plans, net of applicable income tax of $3		–		–		–			–		(6)		(6	)
Comprehensive income													4,537
Issuance/vesting of stock awards, including income tax benefits		–		89		(13	)		–		–		76
Expensing of stock options				80		–			–		–		80
Stock option and warrant exercises, including income tax benefits		–		25		–			–		–		25
Issuance of common stock for acquisition of corporation or properties		–		2,338		–			–		–		2,338
Common stock offerings		1		2,611		–			–		–		2,612
Common stock dividends ($0.480 per share)		–		–		–			(262	)	–		(262	)
Balances, December 31, 2008	$	6	$	8,315	$	(147	)	$	6,588		$ 2,585	$	17,347

See accompanying notes to consolidated financial statements.


2008 form 10-K		\|		ANNUAL REPORT		48

XTO ENERGY INC.

Notes to Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

XTO Energy Inc., a Delaware corporation, was organized under the name Cross Timbers Oil Company in October 1990 to ultimately acquire the business and properties of predecessor entities that were created from 1986 through 1989. Cross Timbers Oil Company completed its initial public offering of common stock in May 1993 and changed its name to XTO Energy Inc. in June 2001.

The accompanying consolidated financial statements include the financial statements of XTO Energy Inc. and all of its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation.

We are an independent oil and gas company with production and exploration concentrated in the southwestern and central United States. We also have international operations located in the North Sea that do not have a material impact on either our financial position or earnings. Additionally, we gather, process and market gas, transport and market oil and conduct other activities directly related to our oil and gas producing activities.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

•

estimates of proved reserves and related estimates of the present value of future revenues;

•

the carrying value of oil and gas properties;

•

asset retirement obligations;

•

income taxes;

•

derivative financial instruments;

•

obligations related to employee benefits; and

•

legal and environmental risks and exposure.

Property and Equipment

We follow the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. We generally pursue acquisition and development of proved reserves as opposed to exploration activities. A significant portion of the property costs reflected in the accompanying consolidated balance sheets are from acquisitions of proved and unproved properties from other oil and gas companies. Proved properties balances include costs of $1.4 billion at December 31, 2008 and $813 million at December 31, 2007 related to wells in process of drilling. Successful drill well costs are transferred to proved properties generally within one month of the well completion date. Inventory held for future use on our producing properties totaled $182 million at December 31, 2008 and $60 million at December 31, 2007, and is included in other current assets on the consolidated balance sheet.

Depreciation, depletion and amortization (DD&A) of proved producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. Other property and equipment is generally depreciated using either the unit-of-production method for assets associated with specific reserves or the straight-line method over estimated useful lives which range from 3 to 40 years. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.

If conditions indicate that producing properties may be impaired, the carrying value of property is compared to management’s future estimated pre-tax cash flow from properties generally aggregated on a field-level basis. If impairment is necessary, the asset carrying value is written down to fair value. Cash flow pricing estimates are based on estimated reserves and production information and pricing assumptions that management believes are reasonable. We recognized an impairment of proved properties of $128 million in 2008.


49		XTO ENERGY		\|		2008 form 10-K

Impairment of individually significant unproved properties is assessed on a property-by-property basis using an impairment analysis similar to the proved property model discussed above. Impairment of other unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. We recognized in DD&A an impairment of unproved properties of $156 million in 2008, $49 million in 2007 and $31 million in 2006.

Asset Retirement Obligation

Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations . SFAS No. 143 provides that, if the fair value for asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by SFAS No. 143, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to proved properties on the balance sheet. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. See Note 5.

Royalty Trusts

We created Cross Timbers Royalty Trust in February 1991 and Hugoton Royalty Trust in December 1998 by conveying defined net profits interests in certain of our properties. Units of both trusts are traded on the New York Stock Exchange. We make monthly net profits payments to each trust based on revenues and costs from the related underlying properties. We owned 54.3% of Hugoton Royalty Trust, which was the portion we retained following our sale of units in 1999 and 2000. In January 2006, the Board of Directors declared a dividend to common stockholders, consisting of all 21.7 million Hugoton Royalty Trust units owned by us. The dividend ratio of 0.047688 trust units for each common share outstanding was set on the record date of April 26, 2006. The units were distributed on May 12, 2006, when this dividend was recorded. We recorded this dividend at $614 million, or approximately $1.35 per common share, the fair market value of the units based on the May 12, 2006 average high and low New York Stock Exchange trade price of $28.31. After considering the cost of the trust units, we recorded a gain on distribution of $469 million before income tax.

Amounts due the trusts are deducted from our revenues, taxes, production expenses and development costs.

Cash and Cash Equivalents

Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less.

Income Taxes

We record deferred income tax assets and liabilities to recognize timing differences between recognition of income for financial statement and income tax reporting purposes. Deferred income tax assets are calculated using enacted tax rates for each jurisdiction applicable to taxable income in the years when we anticipate these timing differences will reverse. The effect of changes in tax rates is recognized in the period of enactment.

Effective January 1, 2007, we adopted the provisions of FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 . FIN No. 48 clarifies financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense and general and administrative expense, respectively. See Note 4.

Other Assets

Other assets primarily include deferred debt costs that are amortized to interest expense over the term of the related debt (Note 3) and the long-term portion of gas balancing receivable (see Revenue Recognition and Gas Balancing below). Other assets are presented net of accumulated amortization of $31 million at December 31, 2008 and $22 million at December 31, 2007.

In accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets , we determined that a portion of the purchase price of the 2005 Antero Resources Corporation acquisition was allocable to gas gathering contracts and goodwill. Gas gathering contracts are associated with the pipeline acquired, and the value of $140 million was determined based on the estimated discounted cash flows from those contracts. The gas gathering contracts are amortized, as a component of depreciation, depletion and amortization expense, on a unit-of-production basis using the estimated proved reserves of the related Barnett Shale properties. Accumulated


2008 form 10-K		\|		ANNUAL REPORT		50

amortization of acquired gas gathering contracts was $35 million as of December 31, 2008 and $28 million as of December 31, 2007. Amortization expense is expected to be approximately $6 million to $8 million annually from 2009 through 2013, depending on Barnett Shale production.

Goodwill of $1.4 billion represents the excess of the purchase price paid for Hunt Petroleum Corporation (Note 14) and Antero Resources over their respective fair value of the assets acquired and liabilities assumed. In accordance with SFAS No. 142, goodwill is not amortized, but instead is subject to an annual assessment of impairment based on a fair value test performed as of October 1. With the deepening of the U.S. and global recessions, which led to sharp declines in oil and gas prices over the last half of 2008, we updated our impairment test as of December 31, 2008.

Derivatives

We use derivatives to hedge against changes in cash flows related to product price and interest rate risks, as opposed to their use for trading purposes. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended, requires that all derivatives be recorded on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. The fair value of call options and collars are generally determined under the Black-Scholes option-pricing model. Most values are confirmed by counterparties to the derivative.

Realized and unrealized gains and losses on derivatives that are not designated as hedges, as well as on the ineffective portion of hedge derivatives, are recorded as a derivative fair value gain or loss in the income statement. Unrealized gains and losses on effective cash flow hedge derivatives, as well as any deferred gain or loss realized upon early termination of effective hedge derivatives, are recorded as a component of accumulated other comprehensive income (loss). When the hedged transaction occurs, the realized gain or loss, as well as any deferred gain or loss, on the hedge derivative is transferred from accumulated other comprehensive income (loss) to earnings. Realized gains and losses on commodity hedge derivatives are recognized in oil and gas revenues, and realized gains and losses on interest hedge derivatives are recorded as adjustments to interest expense. Settlements of derivatives are included in cash flows from operating activities.

To summarize, we record our derivatives at fair value in our consolidated balance sheets. Gains and losses resulting from changes in fair value and upon settlement are reported as follows:


DERIVATIVE TYPE	FAIR VALUE GAINS/ LOSSES	FINANCIAL STATEMENT REPORTING
Non-hedge derivatives and Hedge derivatives – ineffective portion	Unrealized and Realized	Reported in the Consolidated Income Statements as derivative fair value (gain) loss
Hedge derivatives – effective portion	Unrealized	Reported in Stockholders’ Equity in the Consolidated Balance Sheets as accumulated other comprehensive income (loss)
Hedge derivatives – effective portion	Realized	Reported in the Consolidated Income Statemen ts and classified based on the hedged item (e.g., gas revenue, oil revenue or interest expense)

To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as oil or gas revenue or interest expense when the underlying transaction occurs. If it is determined that the designated hedge transaction is not probable to occur, any unrealized gains or losses are recognized immediately in the income statement as a derivative fair value gain or loss. During 2008, 2007 and 2006, there were no gains or losses reclassified into earnings as a result of the discontinuance of hedge accounting treatment for any of our derivatives.

Physical delivery contracts that are not expected to be net cash settled are deemed to be normal sales. However, physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a non-hedge derivative.


51		XTO ENERGY		\|		2008 form 10-K

Revenue Recognition and Gas Balancing

Oil, gas and natural gas liquids revenues are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured. At times we may sell more or less than our entitled share of gas production. When this happens, we use the entitlement method of accounting for gas sales, based on our net revenue interest in production. Accordingly, revenue is deferred for gas deliveries in excess of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. Our net gas imbalance at December 31, 2008, was reported in the balance sheet as a $2 million net long-term receivable. At December 31, 2007, our net gas imbalance was reported in the balance sheet as a $1 million net current receivable.

Gas Gathering, Processing and Marketing Revenues

We market our gas, as well as some gas produced by third parties, to brokers, local distribution companies and end-users. Gas gathering and marketing revenues are recognized in the month of delivery based on customer nominations and adjusted based on actual deliveries. Gas processing and marketing revenues are recorded net of cost of gas sold of $872 million in 2008, $517 million for 2007 and $333 million for 2006. These amounts are net of intercompany eliminations.

Other Revenues

Other revenues result from and are related to our ongoing major operations. These revenues include dividends, foreign currency transaction adjustments, and various gains and losses, including from lawsuits and other disputes, as well as from non-significant sales of property and equipment.

Loss Contingencies

We account for loss contingencies in accordance with SFAS No. 5, Accounting for Contingencies . Accordingly, when management determines that it is probable that an asset has been impaired or a liability has been incurred, we accrue our best estimate of the loss if it can be reasonably estimated. Our legal costs related to litigation are expensed as incurred. See Note 6.

Interest

Interest expense includes amortization of deferred debt costs and is presented net of interest income of $13 million in 2008, $17 million in 2007 and $3 million in 2006, and net of capitalized interest of $39 million in 2008, $30 million in 2007 and $18 million in 2006. Interest is capitalized as proved property cost based on the weighted average interest rate and the cost of wells in process of drilling. Included in accounts payable and accrued liabilities is accrued interest of $139 million at December 31, 2008 and $112 million at December 31, 2007.

Stock-Based Compensation

Effective January 1, 2006, we adopted SFAS No. 123 (Revised 2004), Share-Based Payment , which requires that compensation related to all stock-based awards, including stock options, be recognized in the financial statements based on their estimated grant-date fair value. We previously recorded stock compensation pursuant to the intrinsic value method under APB Opinion No. 25, whereby compensation was recorded related to performance share and unrestricted share awards and no compensation was recognized for most stock option awards. We used the modified prospective application method of adopting SFAS No. 123R, whereby the estimated fair value of unvested stock awards granted prior to January 1, 2006 was recognized as compensation expense in periods subsequent to December 31, 2005, based on the same valuation method used in our prior pro forma disclosures. We estimate expected forfeitures, as required by SFAS No. 123R, and we recognize compensation expense only for those awards expected to vest. Compensation expense is amortized over the estimated service period, which is the shorter of the award’s time vesting period or the derived service period as implied by any accelerated vesting provisions when the common stock price reaches specified levels. All compensation must be recognized by the time the award vests. See Note 13.

Earnings per Common Share

In accordance with SFAS No. 128, Earnings Per Share , we report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. See Note 10.


2008 form 10-K		\|		ANNUAL REPORT		52

Segment Reporting

In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information , we evaluated how the Company is organized and managed and have identified only one operating segment, which is the exploration and production of oil, natural gas and natural gas liquids. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. Substantially all of our assets are located in the United States, and substantially all revenues are attributable to United States customers. Our North Sea assets and revenues comprised less than 1% of total consolidated assets as of December 31, 2008 and less than 1% of total consolidated revenues for the year ended December 31, 2008.

Our production is sold to various purchasers, based on their credit rating and the location of our production. For the year ended December 31, 2008, sales to one purchaser were approximately 16% of total revenues. For the year ended December 31, 2007, sales to each of two purchasers were approximately 18% and 11% of total revenues. For the year ended December 31, 2006, sales to each of two purchasers were approximately 22% and 15% of total revenues. We believe that alternative purchasers are available, if necessary, to purchase production at prices substantially similar to those received from these significant purchasers.

New Accounting Pronouncements

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.


53		XTO ENERGY		\|		2008 form 10-K

2. Related Party Transactions

In February 2007, in recognition of the Chairman of the Board and Founder 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 was a conditional contribution, the first payment was included as general and administrative expense in 2007, and the second payment was included in general administrative expense when the condition was satisfied in the second quarter 2008. Concurrently, our Chairman of the Board and Founder, made a $3.2 million pledge for the same project. He fulfilled his obligation in 2008. In return for these contributions, the Company and Chairman of the Board and Founder obtained naming rights for the building and certain facilities within the building.

3. Debt

Our long-term debt consists of the following:


	DECEMBER 31
(in millions)	2008			2007
Bank debt:
Commercial paper, 3.0% at December 31, 2008 and 5.4% at December 31, 2007	$	72		$	772
Revolving credit facility due April 1, 2013, 2.4% at December 31, 2008		1,825			–
Term loan due April 1, 2013, 1.9% at December 31, 2008 and 5.7% at December 31, 2007		500			300
Term loan due February 5, 2013, 2.3% at December 31, 2008		100			–
Senior notes:
5.00%, due August 1, 2010		250			–
7.50%, due April 15, 2012		350			350
5.90%, due August 1, 2012		550			550
6.25%, due April 15, 2013		400			400
4.625%, due June 15, 2013		400			–
5.75%, due December 15, 2013		500			–
4.90%, due February 1, 2014		500			500
5.00%, due January 31, 2015		350			350
5.30%, due June 30, 2015		400			400
5.65%, due April 1, 2016		400			400
6.25%, due August 1, 2017		750			750
5.50%, due June 15, 2018		800			–
6.50%, due December 15, 2018		1,000			–
6.10%, due April 1, 2036		600			600
6.75%, due August 1, 2037		1,450			950
6.375%, due June 15, 2038		800			–
Net discount on senior notes		(38	)		(2	)
Total long-term debt	$	11,959		$	6,320


2008 form 10-K		\|		ANNUAL REPORT		54

Because we had both the intent and ability to refinance the commercial paper balance outstanding with borrowings under our revolving credit facility due in April 2013, we have classified these borrowings as long-term debt in our consolidated balance sheets. Before the stated maturities of April 2013, we may renegotiate the revolving credit agreement and term loans to increase the borrowing commitment and/or extend the maturity. Maturities of long-term debt as of December 31, 2008, excluding net discounts, are as follows:


(in millions)
2009	$	–
2010		250
2011		–
2012		900
2013		3,797
Remaining		7,050
Total	$	11,997

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 December 31, 2008, borrowings were $72 million at a weighted average interest rate of 3.0%. The weighted average interest rate on commercial paper borrowings was 3.7% during 2008. As of February 20, 2009, we had $102 million of commercial paper borrowings.

Bank Debt

On December 31, 2008, we had borrowings of $1.8 billion outstanding under our revolving credit agreement with commercial banks at an interest rate of 2.4%, and we had available borrowing capacity of $943 million net of our commercial paper borrowings. We use the facility for general corporate purposes and as a backup facility for our commercial paper program. 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 $660 million. The interest rate on any borrowing is generally based on LIBOR plus 0.40%. When utilization of available commitments is greater than 50%, then the interest rate on our borrowings is increased by 0.05%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing commitments, which is 0.09%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 65%. The weighted average interest rate on revolver borrowings was 3.3% during 2008. As of February 20, 2009, we had no revolver borrowings.

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

Senior Notes

In March 2006, we sold $400 million of 5.65% senior notes due April 1, 2016 and $600 million of 6.1% senior notes due April 1, 2036. The 5.65% senior notes were issued at 99.917% of par to yield 5.661% to maturity. The 6.1% senior notes were issued at 99.346% of par to yield 6.148% to maturity. Interest is payable on both series of notes each April 1 and October 1, beginning October 1, 2006. Net proceeds of approximately $987 million were used to reduce borrowings outstanding under our bank revolving credit facility and for other general corporate purposes.


55		XTO ENERGY		\|		2008 form 10-K

July 2007. Together, the 5.9% senior notes were issued at 100.585% of par to yield 5.761% to maturity. The 6.25% senior notes were issued at 100.419% of par to yield 6.193% to maturity. The 6.75% senior notes were issued at 100.022% of par to yield 6.748% to maturity. Interest is payable on each series of notes on February 1 and August 1 of each year, beginning February 1, 2008. Net proceeds of $2.24 billion were used to fund a portion of the acquisition of properties from Dominion Resources, Inc. (Note 14) and to pay down outstanding commercial paper borrowings.

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 14), to pay down outstanding commercial paper borrowings and for general corporate purposes.

The senior notes require no sinking fund. We may redeem all or a part of the senior notes at any time at a price of 100% of their principal balance plus accrued interest and a make-whole premium payment. The make-whole premium is calculated as any excess over the principal balance of the present value of remaining principal and interest payments at the U.S. Treasury rate for a comparable maturity plus no more than 0.375%.

If we are the subject of a change in control, we are required to offer to purchase at 101% of par our 7.50% senior notes due 2012 and our 6.25% senior notes due 2013. Our other senior notes are not subject to this provision.

4. Income Tax

The following reconciles our income tax expense to the amount calculated at the statutory federal income tax rate:


(in millions)	2008		2007		2006
Income tax expense at the federal statutory rate (35%)	$	1,059	$	925	$	1,036
State and local income taxes and other(a)		55		26		65
Income tax expense	$	1,114	$	951	$	1,101

(a)

The 2006 provision includes $34 million related to enactment of a new State of Texas margin tax.

Components of income tax expense are as follows:


(in millions)	2008		2007		2006
Current income tax(a)	$	140	$	292	$	572
Deferred income tax		974		659		505
Net operating loss carryforwards used		—		—		24
Income tax expense	$	1,114	$	951	$	1,101

(a)

The current income tax provision exceeds cash tax expense by the benefit realized upon exercise of stock options or vesting of stock awards in excess of amounts expensed in the financial statements. This benefit, which is recorded in additional paid-in capital, was $69 million in 2008, $64 million in 2007 and $50 million in 2006.


2008 form 10-K		\|		ANNUAL REPORT		56

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a current liability of $940 million and a long-term liability of $5.2 billion at December 31, 2008 and as a current asset of $20 million and a long-term liability of $2.6 billion at December 31, 2007. Significant components of net deferred tax assets and liabilities are:


	DECEMBER 31
(in millions)	2008			2007
Deferred tax assets:
Derivative fair value loss	$	13		$	91
Alternative minimum tax credit caryforwards		40			—
Stock incentive compensation		76			35
Other		45			33
Total deferred tax assets		174			159
Deferred tax liabilities:
Property and equipment		(4,897	)		(2,649	)
Derivative fair value gain		(1,376	)		(73	)
Other		(41	)		(27	)
Total deferred tax liabilities		(6,314	)		(2,749	)
Net deferred tax liabilities	$	(6,140	)	$	(2,590	)

As of December 31, 2008, we had estimated tax loss carryforwards of $30 million on our United Kingdom subsidiary acquired from Hunt Petroleum (Note14). A valuation allowance for the full amount of these carryforwards has been recorded.

At the time of adoption of FIN 48 and as of December 31, 2008, we did not have any unrecognized tax benefits. As a result, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our consolidated balance sheets.

In 2007, the Internal Revenue Service completed its examination of our federal income tax returns for 2003 and 2004. Additional federal tax resulting from this examination was fully accrued in our December 31, 2006 consolidated financial statements as current income tax payable. Under the terms of the final settlement with the IRS, we incurred immaterial interest expense and no penalties. Subsequent amendment of our state tax returns for these years did not have a significant effect on our results of operations or financial position. Tax years 2003 and 2004 remain subject to examination by state jurisdictions, and subsequent years are open to both federal and state examination.

5. Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of asset retirement obligation activity for the years ended December 31, 2008 and 2007:


(in millions)	2008			2007
Asset retirement obligation, January 1	$	453		$	307
Revisions in the estimated cash flows		52			39
Liability incurred upon acquiring and drilling wells		235			87
Liability settled upon plugging and abandoning wells		(12	)		(2	)
Accretion of discount expense		31			22
Asset retirement obligation, December 31		759			453
Less current portion		(24	)		(3	)
Asset retirement obligation, long term	$	735		$	450


57		XTO ENERGY		\|		2008 form 10-K

6. Commitments and Contingencies

Leases

We lease compressors, offices, vehicles, aircraft and certain other equipment in our primary locations under noncancelable operating leases. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2008, minimum future lease payments for all noncancelable lease agreements were as follows:


(in millions)
2009	$	32
2010		27
2011		21
2012		11
2013		6
Remaining		4
Total	$	101

Amounts incurred under operating leases (including renewable monthly leases) were $86 million in 2008, $57 million in 2007 and $55 million in 2006.

Purchase Commitments

As of December 31, 2008, we have contracts with various providers to purchase compressors. These future commitments will result in expected payments of $99 million in 2009.

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 December 31, 2008, maximum commitments under our transportation contracts were as follows:


(in millions)
2009	$	122
2010		121
2011		116
2012		107
2013		101
Remaining		316
Total	$	883

In December 2006, we entered into a ten-year firm transportation contract that commences upon completion of a new 502-mile pipeline spanning from southeast Oklahoma to east Alabama. Upon the pipeline’s completion, currently expected in third quarter 2009, we will transport gas volumes for a minimum transportation fee of $2 million per month plus fuel not to exceed 1.2% of the sales price, depending on receipt point and other conditions.


2008 form 10-K		\|		ANNUAL REPORT		58

Employment Agreements

On November 18, 2008, the Compensation Committee of the Board of Directors approved a new employment agreement with Mr. Simpson reflecting his role as Chairman of the Board and Founder. The committee also approved new agreements with Messrs. Hutton and Vennerberg to reflect their new positions with the Company. Each of the new agreements is effective December 1, 2008 and continues for a one-year term ending November 30, 2009, which automatically continues year to year thereafter unless terminated by either party upon thirty days’ written notice prior to each November 30. Mr. Simpson is to receive an annual base salary of $3,600,000. After the payment of a semi-annual bonus on December 1, 2008, he is no longer eligible to participate in the Company’s cash bonus program. On the first business day of January during the term of his agreement, he will be entitled to receive grants of 110,000 shares of common stock with no vesting criteria and 40,000 performance shares that will have vesting criteria set by the Compensation Committee at the time of grant. The new employment agreements with Messrs. Hutton and Vennerberg provide for minimum base salaries of $1,400,000 and $900,000, respectively, and for minimum cash bonuses each year equal to their base salaries. The Compensation Committee has authority to pay base salaries and bonuses in excess of the minimum base salaries and bonuses provided for in the agreements, subject to an annual cap on total cash compensation in the form of salary and bonuses to Messrs. Hutton and Vennerberg of $12,500,000 and $7,500,000, respectively. The agreements also provide that, in the event (i) the officer terminates his employment for good reason, as defined in the agreement, (ii) we terminate the employee without cause, (iii) the officer dies or becomes disabled, or (iv) a change in control of the Company occurs, the officer is entitled to a lump-sum payment of three times the officer’s most recent annual compensation, including bonuses. In addition, Messrs. Hutton and Vennerberg are entitled to receive a payment sufficient to make the officer whole for any excise tax on excess parachute payments imposed by the Internal Revenue Code. The Chairman of the Board and Founder’s employment agreement provides that the total aggregate payments to be made under the employment agreement and any other agreement providing payments upon a change in control be reduced to the maximum amount that can be paid without the imposition of the excise tax.

Upon retirement, each of these officers will enter into an eighteen-month consulting agreement under which the officer will receive a monthly payment based on his annual salary at the time of retirement, plus $10,000 a month for expenses. The officer will also become fully vested in any outstanding share-based awards unless otherwise provided in the award agreement.

Commodity Commitments

We have entered into futures contracts and swap agreements that effectively fix natural gas and crude oil prices. See Note 8.

Drilling Contracts

As of December 31, 2008, we have contracts with various drilling contractors to use 80 drilling rigs with terms of up to three years and minimum future commitments of $241 million in 2009, $61 million in 2010 and $10 million in 2011. Early termination of these contracts at December 31, 2008 would have required us to pay maximum penalties of $157 million. We do not expect to pay any early termination penalties related to these contracts.

Litigation


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

Other

To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Most of our undeveloped acreage is subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

7. Financial Instruments

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


2008 form 10-K		\|		ANNUAL REPORT		60

Btu Swap Contracts

Btu swap contracts outstanding at December 31, 2005 had a net fair value loss of $23 million. As of February 28, 2006, we terminated the remaining portion of these contracts, resulting in total payments to the counterparty of $7 million in first quarter 2006.

Commodity Price Hedging Instruments

We periodically enter into futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on natural gas, crude oil and natural gas liquids sales. When actual commodity prices exceed the fixed price provided by these contracts, we pay this excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. See Note 8.

Derivative Fair Value (Gain) Loss

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


(in millions)	2008		2007		2006
Change in fair value of Btu swap contracts	$	—	$	—	$	(16	)
Change in fair value of other derivatives that do not qualify for hedge accounting		(84)		—		(19	)
Ineffective portion of derivatives qualifying for hedge accounting		(1)		(11)		(67	)
Derivative fair value (gain) loss	$	(85)	$	(11)	$	(102	)

The derivative 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 gain in 2008 also includes a $78 million gain on certain crude oil swap agreements that did not qualify for hedge accounting. The remaining 2008 gain and the 2006 gain related to derivatives that do not qualify for hedge accounting are primarily related to natural gas basis swap agreements. Except to the extent basis swap agreements are utilized in conjunction with NYMEX future contracts, they cannot qualify for hedge accounting.

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


(in millions)	2008		2007		2006
Net cash received from counterparties	$	(13)	$	(54)	$	(63	)
Non-cash change in derivative fair value		(72)		43		(39	)
Derivative fair value (gain) loss	$	(85)	$	(11)	$	(102	)

Fair Value of Financial Instruments

Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at December 31, 2008 and 2007. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:


	ASSET (LIABILITY)
	DECEMBER 31, 2008 DECEMBER 31, 2007
(in millions)	CARRYING AMOUNT		FAIR VALUE		CARRYING AMOUNT		FAIR VALUE
Net derivative asset (liability)	$	3,723	$	3,723	$	(44)	$	(44	)
Long-term debt	$	(11,959)	$	(11,421)	$	(6,320)	$	(6,438	)

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


61		XTO ENERGY		\|		2008 form 10-K

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 5 for a rollforward of the asset retirement obligation.

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


	FAIR VALUE MEASUREMENTS
	DECEMBER 31, 2008 DECEMBER 31, 2007
(in millions)	SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)			SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)			SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)			SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Derivative Assets:
Fixed-price natural gas futures and basis swaps	$	1,926		$	–		$	198		$	–
Fixed-price crude oil futures and differential swaps		1,832			–			1			–
Derivative Liabilities:
Fixed-price natural gas futures and basis swaps		(23	)		–			(13	)		–
Fixed-price crude oil futures and differential swaps		(12	)		–			(208	)		–
Fixed-price natural gas liquids futures		–			–			(22	)		–
Net derivative asset (liability)	$	3,723		$	–		$	(44	)	$	–
Asset retirement obligation	$	–		$	(759	)	$	–		$	(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 in derivative fair value (gain) loss in the income statement. Our allowance for collectibility of all accounts receivable was $13 million at December 31, 2008 and $7 million at December 31, 2007.


2008 form 10-K		\|		ANNUAL REPORT		62

8. Commodity Sales Commitments

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

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

Natural Gas

We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 7 regarding accounting for commodity hedges.


PRODUCTION PERIOD	MCF PER DAY	WEIGHTED AVERAGE NYMEX PRICE PER MCF
2009 January to December	1,745,000	$ 8.79(a)
2010 January to December	730,000	$ 8.67

(a)

The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered sell basis swap agreements that effectively fix the basis adjustment as shown below. Not all of our sell basis swap agreements are designated as hedges for hedge accounting purposes. The table below does not include our physical delivery contracts tied to indices at various delivery points.


PRODUCTION PERIOD	MCF PER DAY	WEIGHTED AVERAGE SELL BASIS PER MCF(a)
2009 January	972,500	$ 0.62
February to March	932,500	$ 0.62
April to June	890,000	$ 0.52
July to August	870,000	$ 0.52
September to October	840,000	$ 0.53
November to December	280,000	$ 0.78
2010 January to March	250,000	$ 0.62
April to October	170,000	$ 0.37
November to December	120,000	$ 0.28
2011 January to October	60,000	$ 0.28
November to December	30,000	$ 0.28

(a)

Reductions to NYMEX gas prices for delivery location.

Net losses on futures and sell basis swap hedge contracts decreased gas revenues by $159 million in 2008. Net gains on these contracts increased gas revenue by $658 million in 2007 and $618 million in 2006. As of December 31, 2008, an unrealized pre-tax derivative fair value gain of approximately $2.1 billion, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss) (Note 11). Based on December 31 mark-to-market prices, $1.7 billion of this gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.


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Crude Oil

We have entered into crude oil futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. Not all of our 2009 crude oil swap agreements are designated as hedges for hedge accounting purposes. See Note 7 regarding accounting for commodity hedges.


PRODUCTION PERIOD	BBLS PER DAY	WEIGHTED AVERAGE NYMEX PRICE PER BBL
2009 January to December	62,500	$ 117.11(a)
2010 January to December	27,500	$ 126.65

(a)

Net losses on futures and differential swap hedge contracts decreased oil revenue by $114 million in 2008. Net gains on these contracts increased oil revenue by $24 million in 2007 and $3 million in 2006. As of December 31, 2008, an unrealized pre-tax derivative fair value gain of approximately $2.0 billion, related to cash flow hedges of oil price risk, was recorded in accumulated other comprehensive income (loss) (Note 11). Based on December 31 mark-to-market prices, $1.4 billion of this gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

Early Settlement of Hedges

In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight financial counterparties covering our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which was used to reduce outstanding debt. Of this amount, $453 million ($287 million after-tax) was received in 2008 and the remainder was received in 2009.

Natural Gas Liquids

Net losses on futures contracts decreased natural gas liquids revenue by $19 million in 2008.

Transportation Contracts

In connection with our commitments under our transportation contracts (Note 6), we have entered purchase basis swap agreements related to potential purchase of gas volumes to be transported. Purchase basis swap agreements are not designated as hedges for hedge accounting purposes.


PERIOD		MCF PER DAY	WEIGHTED AVERAGE PURCHASE BASIS PER MCF(a)
2009	January	135,000	$ 0.87
	February	90,000	$ 1.00
	March to April	70,000	$ 1.16
	May to October	50,000	$ 1.23

(a)

Reductions to NYMEX gas prices for purchase location.

9. Equity

Stock Splits

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.


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Common Stock

The following reflects our common stock activity:


	SHARES ISSUED SHARES IN TREASURY
(in thousands)	2008	2007	2006	2008	2007	2006
Balance, January 1	490,434	464,342	456,526	5,140	4,900	2,069
Issuance/vesting and forfeiture of performance, restricted and unrestricted shares	3,778	1,413	1,521	423	240	81
Stock option and warrant exercises	2,741	3,117	3,101	–	–	–
Treasury stock purchases	–	–	–	–	–	2,750
Common stock offerings	52,900	21,562	–	–	–	–
Issuance for acquisition of corporations or properties	35,242	–	3,194	–	–	–
Balance, December 31	585,095	490,434	464,342	5,563	5,140	4,900

Our acquisition of properties from Headington Oil Company in July 2008 was partially funded through issuance to the sellers of 11.7 million shares of our common stock (Note 14). We registered these shares under our shelf registration statement (see below).

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 14) 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 sellers of 23.5 million shares of our common stock (Note 14). We registered these shares under our shelf registration statement (see below).

In June 2007, we completed a public offering of 21.6 million common shares at $48.40 per share. After underwriting discount and other offering costs of $35 million, net proceeds of $1.0 billion were used to fund a portion of the acquisition of natural gas and oil properties from Dominion Resources, Inc. (Note 14).

Our acquisition of Peak Energy Resources, Inc. in June 2006 was partially funded through issuance to the sellers of 3.2 million shares of common stock (Note 14). We registered these shares under our shelf registration statement in June 2006.

Treasury Stock

In August 2004, our Board of Directors authorized the repurchase of up to 25 million shares of our common stock which may be purchased from time to time in open market or negotiated transactions. In June 2006, we repurchased 2.8 million shares of our common stock on the open market at $30.24 per share, or a total of $83 million. As of December 31, 2008, we have repurchased 2.8 million shares.

Shelf Registration Statement

In June 2006, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities or common stock. The securities will be offered at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including reduction of bank debt.

Common Stock Warrants

Our purchase of Antero Resources Corporation in 2005 was partially funded by issuance of warrants to purchase 2.6 million shares of common stock at $20.78 per share. The warrants expire on April 1, 2010.

Common Stock Dividends

The Board of Directors declared quarterly dividends of $0.06 per common share for the first three quarters of 2006, $0.072 per common share for fourth quarter 2006, $0.096 per common share for the first three quarters of 2007 and $0.12 per common share for fourth quarter 2007 and for each quarter in 2008. On February 17, 2009, the Board of Directors declared a first quarter 2009 dividend of $0.125 per common share.


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In January 2006, the Board of Directors declared a dividend to common stockholders, consisting of all 21.7 million Hugoton Royalty Trust units owned by us. The dividend ratio of 0.047688 trust units for each common share outstanding was set on the record date of April 26, 2006. The units were distributed on May 12, 2006, when this dividend was recorded. We recorded this dividend at $614 million, or approximately $1.35 per common share, the fair market value of the units based on the May 12, 2006 average high and low New York Stock Exchange trade price of $28.31.

See Note 13.

10. Earnings Per Share

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


(in millions, except per share data)	EARNINGS		SHARES	EARNINGS PER SHARE
2008
Basic	$	1,912	531.6	$	3.60
Effect of dilutive securities:
Stock options		—	4.6
Warrants		—	1.6
Diluted	$	1,912	537.8	$	3.56
2007
Basic	$	1,691	471.9	$	3.58
Effect of dilutive securities:
Stock options		—	5.7
Warrants		—	1.4
Diluted	$	1,691	479.0	$	3.53
2006
Basic	$	1,860	456.1	$	4.08
Effect of dilutive securities:
Stock options		—	5.1
Warrants		—	1.0
Diluted	$	1,860	462.2	$	4.02

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 8.0 million with a weighted average exercise price of $51.01 were excluded.

11. Accumulated Other Comprehensive Income (Loss)

Our comprehensive income (loss) information is included in the consolidated statements of stockholders’ equity. The following are components of accumulated other comprehensive income (loss) as of December 31, 2008, 2007 and 2006, and changes during those years:


	FAIR VALUE OF DERIVATIVE INSTRUMENTS			POST- RETIREMENT LIABILITIES			TOTAL
Balances, December 31, 2005	$	68		$	–		$	68
2006 Activity		668			(3	)		665
Deferred taxes		(248	)		1			(247	)
Balances, December 31, 2006		488			(2	)		486
2007 Activity		(827	)		(8	)		(835	)
Deferred taxes		306			3			309
Balances, December 31, 2007		(33	)		(7	)		(40	)
2008 Activity		4,146			(9	)		4,137
Deferred taxes		(1,515	)		3			(1,512	)
Balances, December 31, 2008	$	2,598		$	(13	)	$	2,585


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12. Supplemental Cash Flow Information

The consolidated statements of cash flows exclude the following non-cash transactions:

–

Non-cash component of the July 2008 Headington Oil Company acquisition purchase price, including issuance to the sellers of 11.7 million shares of common stock (Note14)

–

Non-cash components of the September 2008 Hunt Petroleum acquisition purchase price, including issuance to the sellers of 23.5 million shares of common stock and assumption of debt and other liabilities (Note 14)

–

Distribution of 21.7 million Hugoton Royalty Trust units as a dividend to common stockholders in May 2006 (Note 9)

–

Non-cash components of the June 2006 Peak Energy Resources acquisition purchase price, including issuance to the sellers of 3.2 million shares of common stock and assumption of other liabilities (Note 14)

–

The following restricted share activity (Note 13):

–

Grants of 2.5 million shares in 2008, 1.4 million shares in 2007 and 1.3 million shares in 2006

–

Vesting of 865,000 shares in 2008 and 427,000 shares in 2007

–

Forfeitures of 51,000 shares in 2008 and 48,000 shares in 2007

–

Grants and immediate vesting of unrestricted common shares to nonemployee directors totaling 25,000 shares in each of 2008, 2007 and 2006 (Note 13)

–

The following performance share activity (Note 13):

–

Grants of 1.2 million shares in 2008 and 187,000 shares in 2006

–

Vesting of 363,000 shares in 2008, 166,000 shares in 2007 and 201,000 shares in 2006

–

Forfeitures of 15,000 shares in 2007

Interest payments totaled $499 million (including $39 million of capitalized interest) in 2008, $231 million (including $30 million of capitalized interest) in 2007 and $172 million (including $18 million of capitalized interest) in 2006. Net income tax payments were $45 million in 2008, $284 million in 2007 and $556 million in 2006.

13. Employee Benefit Plans

401(k) Plan

We sponsor a 401(k) benefit plan that allows employees to contribute and defer a portion of their wages. We match employee contributions up to 14% of wages, subject to annual dollar maximums established by the federal government and plan limitations. Employee contributions vest immediately while our matching contributions vest 100% upon completion of three years of service. All employees over 18 years of age may participate. Company contributions under the plan were $20 million in 2008, $14 million in 2007 and $11 million in 2006.

Stock Incentive 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. Prior to approval of the 2004 Plan, grants of stock awards were made pursuant to the 1998 Stock Incentive Plan. No further grants will be made under the 1998 Plan. Stock award grants are subject to certain limitations as specified in the Plan. The maximum term of stock awards is ten years under the 1998 Plan and seven years under the 2004 Plan. As a result of the May 12, 2006 distribution of the Hugoton Royalty Trust units (Note 9), appropriate antidilution adjustments were made to stock awards outstanding on that date.


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The table below summarizes stock incentive compensation expense included in the consolidated financial statements and related amounts for each year:


	YEAR ENDED DECEMBER 31
(in millions)	2008		2007		2006
Non-cash stock option compensation expense	$	80	$	42	$	53
Non-cash performance share and unrestricted share compensation expense		47		4		8
Non-cash restricted share compensation expense		43		19		2
Related tax benefit recorded in income statement		62		24		23
Intrinsic value of stock option exercises		202		170		136
Income tax benefit on exercise of stock options or vesting of stock awards(a)		69		64		50
Grant date fair value of stock options vested		70		35		24

(a)

Recorded as additional paid-in-capital

Included in stock option compensation expense in 2006 is $36 million related to options granted during May 2006, which were subject to accelerated vesting provisions upon retirement under employment agreements. Under SFAS No. 123R, stock option awards subject to such vesting provisions granted to retirement-eligible employees are expensed upon grant rather than over the expected vesting period (Note 6).

Stock Options

Stock options granted under the 2004 Plan generally vest and become exercisable ratably over a three-year period, and may include a provision for accelerated vesting when the common stock price reaches specified levels as determined by the Compensation Committee of the Board of Directors. Some stock options granted in 2008, 2007 and 2006 vest only when the common stock reaches specified levels. There was a total of 20.3 million options outstanding under the 2004 and 1998 Plans at December 31, 2008, including 14.5 million that were exercisable at that date. The table below shows the terms under which the remaining options vest.


UNVESTED STOCK OPTIONS (in thousands)		VESTING
3,999		Ratably over 3 years
60		$ 40
480		$ 45
421		$ 50
2		$ 55
794		$ 90

The following summarizes option activity and balances for the year ended December 31, 2008:


	WEIGHTED- AVERAGE EXERCISE PRICE		STOCK OPTIONS (in thousands)		WEIGHTED- AVERAGE REMAINING TERM (in years)	AGGREGATE INTRINSIC VALUE (in millions)
Balance at January 1, 2008	$	29.94	23,000
Grants		55.88	2,735
Exercises		19.96	(5,406	)
Forfeitures		42.48	(39	)
Balance at December 31, 2008	$	36.08	20,290		4.59	$	109
Exercisable at December 31, 2008	$	31.21	14,534		4.12	$	105

As a result of options exercised in 2008, outstanding common stock increased by 2.7 million shares and stockholders’ equity increased by $24 million.

Performance Shares

Performance shares granted under the 2004 Plan are subject to restrictions determined by the Compensation Committee of the Board of Directors and are subject to forfeiture if performance criteria are not met. Otherwise, holders of performance shares generally have all the voting, dividend and other rights of other common stockholders. To date, the performance criteria for all awards has been the achievement of specified increases in the common stock price above the market price at the grant date. We granted 1,216,000 performance shares in 2008 and 187,000 performance shares in 2006. There was a total of 853,000 performance shares outstanding at December 31, 2008. The table below shows the number of shares and vesting prices of these performance shares.


2008 form 10-K		\|		ANNUAL REPORT		68


PERFORMANCE SHARES (in thousands)		VESTING PRICE
363		$ 42
245		$ 77
245		$ 85

Restricted Shares

We granted 2,537,000 restricted shares in 2008, 1,388,000 restricted shares in 2007 and 1,309,000 restricted shares in 2006 to key employees other than executive officers. These shares vest over three years, with one-third vesting at each grant anniversary date. Holders of restricted shares generally have all the voting, dividend and other rights of other common stockholders.

Nonemployee Director Awards

Nonemployee directors are each eligible to receive discretionary stock awards under the 2004 Plan covering up to 25,000 shares annually, as approved by the Corporate Governance and Nominating Committee and the Board of Directors. Subsequent to the November 2008 grant, nonemployee directors will no longer be eligible to receive stock options under the 2004 plan and will be limited to annual unrestricted grants not to exceed 6,000 shares per director subject to a cap in value of $300,000 as defined in the agreement.

Nonemployee directors received 4,166 shares each totaling approximately 25,000 unrestricted shares in 2008, 2007 and 2006 under the 2004 Plan. In November 2006, nonemployee directors received 20,000 stock options each totaling 120,000 stock options, 50% of which vested in 2007 when the stock closed above the target price of $42 and 50% which vested in 2007 when the common stock price closed above the target price of $46. In November 2007, nonemployee directors received 20,000 stock options each totaling 120,000 stock options, 50% of which vested when the common stock price closed above the target price of $56 in 2008 and 50% of which vested in 2008 when the common stock price closed above the target price of $60. In November 2008, nonemployee directors received 20,000 stock options each totaling 120,000 stock options, 50% of which vest when the common stock price closes at or above the target price of $40 and 50% of which vest when the common stock price closes at or above the target price of $45.

Nonvested Stock Awards

The following summarizes the status of the nonvested stock options, performance shares and restricted shares as of December 31, 2008 and changes for the year then ended:


	STOCK OPTIONS				PERFORMANCE SHARES				RESTRICTED SHARES
(in thousands, except per share amounts)	WEIGHTED- AVERAGE GRANT DATE FAIR VALUE		NUMBER OF SHARES		WEIGHTED- AVERAGE GRANT DATE FAIR VALUE		NUMBER OF SHARES		WEIGHTED- AVERAGE GRANT DATE FAIR VALUE		NUMBER OF SHARES
Nonvested at
January 1, 2008	$	12.95	8,498		$	–	–		$	45.58	2,222
Vested		12.79	(5,438	)		27.58	(363	)		44.43	(865	)
Grants		17.10	2,735			40.06	1,216			36.51	2,537
Forfeitures		14.50	(39	)		–	–			43.75	(51	)
Nonvested at
December 31, 2008	$	15.06	5,756		$	45.37	853		$	39.87	3,843

As of December 31, 2008, the remaining unrecognized compensation expense related to nonvested stock options was $36 million. Total deferred compensation at December 31, 2008 related to performance shares was $3 million and related to restricted shares was $136 million. For these nonvested stock awards at December 31, 2008, we estimate that stock incentive compensation for service periods after December 31, 2008 will be $94 million in 2009, $55 million in 2010 and $26 million in 2011. The weighted-average remaining vesting period is 0.7 years for stock options, 0.1 years for performance shares, and 2.4 years for restricted shares.

Estimated Fair Value of Grants

We use a trinomial lattice model to value stock option grants that time vest and a Monte Carlo simulation model to value performance shares and stock options that vest, or include a provision for accelerated vesting, when the common stock price reaches specified levels.

During 2008, 2007 and 2006, we used both a trinomial lattice model and a Monte Carlo simulation model to determine the fair value of options granted, and we used a Monte Carlo simulation model to determine the fair value of performance shares granted. For restricted stock grants, the fair value is equal to the closing price of our common stock on the grant date.


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The trinomial lattice model requires inputs for risk-free interest rate, dividend yield, volatility, contract term, average vesting period, post-vest turnover rate and suboptimal exercise factor. Both expected life and fair value are outputs of this model. The Monte Carlo simulation model requires inputs for risk-free interest rate, dividend yield, volatility, contract term, target vesting price, post-vest turnover rate and suboptimal exercise factor. The suboptimal exercise factor does not affect the valuation of the performance shares since ownership is transferred at vesting. Expected life, derived vesting period and fair value are outputs of this model.

The risk-free interest rate is based on the constant maturity nominal rates of U.S. Treasury securities with remaining lives throughout the contract term on the day of the grant. The dividend yield is the expected common stock annual dividend yield over the expected life of the option or performance share, expressed as a percentage of the stock price on the date of grant. The volatility factors are based on a combination of both the historical volatilities of our stock and the implied volatility of traded options on our common stock. Contract term is seven years. For options subject to time vesting, the average vesting period is two years, based on each grant vesting ratably over a three-year period. For options subject to vesting when the common stock reaches a specified price, the target vesting price is specified by the award. The post-vesting turnover rate is 1.13% and the suboptimal exercise factor is 1.78, and are both based on actual historical exercise activity. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by certain employees who receive stock option grants, and subsequent events are not indicative of the reasonableness of the original fair value estimates.

We record stock incentive compensation only for awards expected to vest. During 2008, we estimated annual forfeitures using a rate of 1% for stock options, 2% for restricted shares and 0% for performance shares.

During the year ended December 31, 2008, we granted 2.7 million options with an estimated total grant-date fair value of $47 million and a weighted-average fair value of $17.10 per option. During 2007, we granted 4.3 million options with an estimated total grant-date fair value of $65 million and a weighted-average fair value of $15.29 per option. During the year ended December 31, 2006, we granted 6.8 million options with an estimated total grant-date fair value of $74 million and a weighted-average fair value of $10.89 per option. Fair values were determined using the following assumptions:


	2008	2007	2006
Weighted-average expected term (years)	4.4	4.6	4.4
Range of risk-free interest rates	1.7% - 3.5%	3.4% - 5.0%	4.3% - 5.2%
Weighted-average risk-free interest rates	2.7%	3.8%	4.9%
Dividend yield	1.0%	0.8%	0.7%
Range of volatility	32% - 53%	26% - 33%	29% - 35%
Weighted-average volatility	40%	32%	32%

14. 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 9) and proceeds from the April 2008 issuance of senior notes (Note 3) 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.

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 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 sellers valued at $742 million (Note 9). 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 sellers valued at $1.6 billion (Note 9). 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 (Note 3).


2008 form 10-K		\|		ANNUAL REPORT		70

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

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


(in millions)
Consideration issued to Hunt owners:
23.5 million shares of common stock (at fair value of $67.95 per share)	$	1,597
Cash paid		2,589
Total purchase price		4,186
Fair value of liabilities assumed:
Current liabilities		353
Long-term debt		337
Asset retirement obligation		155
Other long-term liabilities		3
Deferred income taxes		1,064
Total purchase price plus liabilities assumed	$	6,098
Fair value of assets acquired:
Cash and cash equivalents	$	198
Other current assets		283
Proved properties		4,155
Unproved properties		160
Other property and equipment		70
Goodwill (non-deductible for income taxes)		1,232
Total fair value of assets acquired	$	6,098

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 9), 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 (Note 9), the issuance of $1.25 billion of senior notes in July 2007 (Note 3) 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 (Note 3). 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.

On February 28, 2006, we acquired proved and unproved properties in East Texas and Mississippi from Total E&P USA, Inc. for $300 million. The acquisition was funded by bank borrowings.

On June 30, 2006, we acquired Peak Energy Resources, Inc., which operated gas-producing properties and owned unproved properties in the Barnett Shale in the Fort Worth Basin. The total purchase price was $108 million, which was primarily funded by issuance of 3.2 million shares of common stock valued at $102 million (Note 9), $5 million cash for additional leasehold interests and $1 million cash for other transaction costs. After recording estimated deferred taxes of $36 million and other liabilities, the purchase price allocated to proved properties was $97 million and unproved properties was $53 million.


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Acquisitions were recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for 2008, 2007 and 2006, as if the Hunt acquisition was made at the beginning of 2008 and 2007 and the 2007 Dominion acquisition was made at the beginning of 2007 and 2006. These pro forma results are not necessarily indicative of future results.


	PRO FORMA (UNAUDITED) YEAR ENDED DECEMBER 31
(in millions, except per share data)	2008		2007		2006
Revenues	$	8,450	$	6,648	$	5,212
Net income	$	2,090	$	1,811	$	1,959
Earnings per common share:
Basic	$	3.82	$	3.59	$	4.10
Diluted	$	3.78	$	3.54	$	4.05
Weighted average shares outstanding:
Basic		547.3		504.7		477.6
Diluted		553.5		511.7		483.8

15. Quarterly Financial Data (Unaudited)

The following are summarized quarterly financial data for the years ended December 31, 2008 and 2007:


	QUARTER
(in millions, except per share data)	1st		2nd		3rd		4th
2008
Revenues	$	1,673	$	1,936	$	2,125	$	1,961
Gross profit(a)	$	913	$	1,095	$	1,052	$	830
Net income	$	465	$	575	$	521	$	351	(c)
Earnings per common share:(b)
Basic	$	0.94	$	1.13	$	0.95	$	0.61
Diluted	$	0.92	$	1.11	$	0.94	$	0.61
Average shares outstanding:
Basic		496.3		508.6		546.6		574.4
Diluted		503.8		517.2		552.2		576.6
2007
Revenues	$	1,169	$	1,329	$	1,421	$	1,594
Gross profit(a)	$	703	$	777	$	755	$	888
Net income	$	383	$	432	$	412	$	464
Earnings per common share:(b)
Basic	$	0.83	$	0.93	$	0.86	$	0.96
Diluted	$	0.82	$	0.91	$	0.84	$	0.95
Average shares outstanding:
Basic		458.4		464.9		481.1		482.8
Diluted		465.2		473.1		489.2		490.5

(a)

Operating income before general and administrative expense.

(b)

Because quarterly earnings per share is based on the weighted average shares outstanding during the quarter, the sum of quarterly earnings per share may not equal earnings per share for the year.

(c)

Included in fourth quarter net income is an after-tax impairment of proved properties of $81 million (Note 1).

16. Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited)

Substantially all of our operations are directly related to oil and gas producing activities located in the United States. Our international oil and gas producing activities, located in the North Sea, comprise less than 1% of our 2008 revenues, costs incurred, reserves and standardized measure.


2008 form 10-K		\|		ANNUAL REPORT		72

Costs Incurred Related to Oil and Gas Producing Activities

The following table summarizes costs incurred whether such costs are capitalized or expensed for financial reporting purposes:


(in millions)	2008		2007		2006
Acquisitions:
Proved properties	$	7,935	$	3,197	$	561
Unproved properties – acquisitions of proved properties(a)		1,020		260		83
Unproved properties – other		2,094		571		142
Development(b)		3,355		2,529		2,022
Exploration		517		257		123
Asset retirement obligation accrued upon:
Acquisition		202		58		7
Development(c)		85		68		64
Total Costs Incurred	$	15,208	$	6,940	$	3,002

(a)

Represents a portion of the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties (Note 14).

(b)

Includes capitalized interest of $39 million in 2008, $30 million in 2007 and $18 million in 2006.

(c)

Includes revisions of $52 million in 2008, $39 million in 2007 and $36 million in 2006.

Proved Reserves

Our proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. Proved reserves exclude volumes deliverable to others under production payments or retained interests.

Standardized Measure

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Year-end prices are not adjusted for the effect of hedge derivatives. Discounted future net cash flows are calculated using a 10% rate. Estimated future income taxes are calculated by applying year-end statutory rates to future pre-tax net cash flows, less the tax basis of related assets and applicable tax credits.

Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. As required by SFAS No. 143, such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values as of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired (Note 5).


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The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.

PROVED RESERVES


(in millions)	GAS (MCF)		NATURAL GAS LIQUIDS (BBLS)	OIL (BBLS)		NATURAL GAS EQUIVALENTS (MCFE)
December 31, 2005	6,085.6		47.4	208.7		7,622.2
Revisions	(94.9	)	1.8	0.1		(83.2	)
Extensions, additions and discoveries	1,416.8		4.0	20.3		1,562.6
Production	(433.0	)	(4.4)	(16.4	)	(557.6	)
Purchases in place	157.9		4.2	3.3		202.9
Sales in place(a)	(188.2	)	—	(1.6	)	(198.3	)
December 31, 2006	6,944.2		53.0	214.4		8,548.6
Revisions	(46.3	)	10.2	15.5		108.2
Extensions, additions and discoveries	1,797.5		5.8	18.4		1,942.5
Production	(532.1	)	(4.9)	(17.2	)	(664.8	)
Purchases in place	1,278.8		2.7	11.3		1,362.7
Sales in place	(1.0	)	—	(1.2	)	(8.2	)
December 31, 2007	9,441.1		66.8	241.2		11,289.0
Revisions	(665.5	)	(9.4)	(20.9	)	(847.3	)
Extensions, additions and discoveries	2,195.7		4.2	10.4		2,283.3
Production	(697.4	)	(5.7)	(20.5	)	(854.7	)
Purchases in place	1,529.0		19.9	57.6		1,994.1
Sales in place	—		—	(0.3	)	(2.0	)
December 31, 2008	11,802.9		75.8	267.5		13,862.4

(a)

Includes effect of distribution of Hugoton Royalty Trust units (Note 9).

The additions to our proved reserves from extensions, additions and discoveries in the last three years are due to the success of our development drilling program. See a summary of our drilling activity over the last three years in Part I, Items 1 and 2, Business and Properties – Exploration and Production Data – Drilling Activity.

PROVED DEVELOPED RESERVES


(in millions)	GAS (MCF)	NATURAL GAS LIQUIDS (BBLS)	OIL (BBLS)	NATURAL GAS EQUIVALENTS (MCFE)
December 31, 2005	4,033.1	36.5	168.5	5,262.9
December 31, 2006	4,481.6	40.1	167.3	5,725.9
December 31, 2007	6,031.5	52.9	184.8	7,457.7
December 31, 2008	7,290.3	52.5	205.0	8,835.4

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS RELATING TO PROVED RESERVES


(in millions)	DECEMBER 31
(in millions)	2008			2007			2006
Future cash inflows	$	65,608		$	86,080		$	51,477
Future costs:
Production		(22,239	)		(22,066	)		(14,958	)
Development		(9,159	)		(6,065	)		(4,260	)
Future income tax		(7,902	)		(18,423	)		(10,251	)
Future net cash flows		26,308			39,526			22,008
10% annual discount		(13,515	)		(19,988	)		(11,180	)
Standardized measure	$	12,793		$	19,538		$	10,828

	DECEMBER 31
(in millions)	2008			2007			2006
Standardized measure, as determined above	$	12,793		$	19,538		$	10,828
Change in future net revenue – hedged production		4,583			153			1,126
Change in future income tax – hedged production		(1,675	)		(56	)		(412	)
10% annual discount – hedged production		(199	)		(4	)		(35	)
Standardized measure, including hedge instruments(a)	$	15,502		$	19,631		$	11,507


2008 form 10-K		\|		ANNUAL REPORT		74

(a)

The standardized measure, including hedge instruments, includes the changes in standardized measure resulting from our contractual arrangements related to our hedge instruments that are being accounted for as cash flow hedges under SFAS No. 133. The cash flows from these hedges will be reported in revenues in future periods (future cash inflows) as the related production occurs. The hedge prices were applied to the reserves disclosed above, with no change in volumetric measurements related to the increased prices from our contractual arrangements.

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED

FUTURE NET CASH FLOWS


(in millions)	2008			2007			2006
Standardized measure, January 1	$	19,538		$	10,828		$	17,094
Revisions:
Prices and costs		(14,047	)		7,958			(10,687	)
Quantity estimates		(1,331	)		1,868			960
Accretion of discount		1,954			970			1,511
Future development costs		(915	)		(3,082	)		(2,479	)
Income tax		5,259			(3,749	)		4,090
Production rates and other		1			–			3
Net revisions		(9,079	)		3,965			(6,602	)
Extensions, additions and discoveries		2,714			3,541			2,248
Production		(5,879	)		(4,359	)		(3,629	)
Development costs		2,942			2,299			1,917
Purchases in place(a)		2,560			3,286			396
Sales in place(b)		(3	)		(22	)		(596	)
Net change		(6,745	)		8,710			(6,266	)
Standardized measure, December 31	$	12,793	(c)	$	19,538	(d)	$	10,828	(e)

(a)

Generally based on the year-end present value (at year-end prices and costs) plus the cash flow received from such properties during the year, rather than the estimated present value at the date of acquisition.

(b)

Generally based on beginning of the year present value (at beginning of year prices and costs) less the cash flow received from such properties during the year, rather than the estimated present value at the date of sale. Included in 2006 is the effect of distribution of Hugoton Royalty Trust units (Note 9).

(c)

The December 31, 2008 standardized measure includes a reduction of $93 million ($147 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2008 includes a liability of $759 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143, as described above.

(d)

The December 31, 2007 standardized measure includes a reduction of $43 million ($68 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2007 includes a liability of $453 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143, as described above.

(e)

The December 31, 2006 standardized measure includes a reduction of $29 million ($46 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2006 includes a liability of $307 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143, as described above.

Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.

Year-end average realized gas prices used in the estimation of proved reserves and calculation of the standardized measure were $4.66 for 2008, $6.39 for 2007, $5.46 for 2006 and $9.26 for 2005. Year-end average realized natural gas liquids prices were $18.26 for 2008, $60.24 for 2007, $31.96 for 2006 and $36.33 for 2005. Year-end average realized oil prices were $38.12 for 2008, $91.19 for 2007, $55.47 for 2006 and $57.02 for 2005.


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Management’s Report On Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended). Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. Our management has concluded that, based on these criteria, we have maintained in all material respects, effective internal control over financial reporting as of December 31, 2008.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected.

February 25, 2009


2008 form 10-K		\|		ANNUAL REPORT		76

Report Of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

XTO Energy Inc.:

We have audited the accompanying consolidated balance sheets of XTO Energy Inc. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated income statements, statements of stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2008. We also have audited XTO Energy Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). XTO Energy Inc. management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of XTO Energy Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also in our opinion, XTO Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on control criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

KPMG LLP

Fort Worth, Texas

February 25, 2009


77		XTO ENERGY		\|		2008 form 10-K

Signatures

Pursuant to the requirements of Section 13 or 15(d) 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, on the 25 ^th day of February 2009.


XTO ENERGY INC.

By		/s/ KEITH A. HUTTON
		Keith A. Hutton, Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 25 ^th day of February 2009.


PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS)		DIRECTORS

/s/ BOB R. SIMPSON		/s/ WILLIAM H. ADAMS III
Bob R. Simpson, Chairman of the Board and Founder		William H. Adams III

/s/ KEITH A, HUTTON		/s/ LANE G. COLLINS
Keith A. Hutton, Chief Executive Officer		Lane G. Collins

/s/ VAUGHN O. VENNERBERG II		/s/ PHILLIP R. KEVIL
Vaughn O. Vennerberg II, President		Phillip R. Kevil

		/s/ JACK P. RANDALL
		Jack P. Randall

		/s/ SCOTT G. SHERMAN
		Scott G. Sherman

		/s/ HERBERT D. SIMONS
		Herbert D. Simons

PRINCIPAL FINANCIAL OFFICER		PRINCIPAL ACCOUNTING OFFICER

/s/ LOUIS G. BALDWIN		/s/ BENNIE G. KNIFFEN
Louis G. Baldwin, Executive Vice President and Chief Financial Officer		Bennie G. Kniffen, Senior Vice President and Controller


2008 form 10-K		\|		ANNUAL REPORT		78

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
2.1+	Agreement and Plan of Merger dated January 9, 2005 among XTO Energy Inc., XTO Barnett Inc., and Antero Resources Corporation (incorporated by reference to Exhibit 2.2 to Form 10-K for the year ended December 31, 2004)

2.2+	Amendment No. 1 to Agreement and Plan of Merger dated February 3, 2005 among XTO Energy Inc., XTO Barnett Inc., and Antero Resources Corporation (incorporated by reference to Exhibit 2.3 to Form 10-K for the year ended December 31, 2004)

2.3+	Amendment No. 2 to Agreement and Plan of Merger dated March 22, 2005 among the Company, XTO Barnett Inc., XTO Barnett LLC and Antero Resources Corporation (incorporated by reference to Exhibit 2.1 to Form 8-K filed March 28, 2005)

2.4+	Amendment No. 3 to Agreement and Plan of Merger dated March 31, 2005 among the Company, XTO Barnett Inc., XTO Barnett LLC and Antero Resources Corporation (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 5, 2005)

2.5+	Gulf Coast/Rockies/San Juan Package Purchase Agreement dated as of June 1, 2007 between Dominion Exploration & Production, Inc., Dominion Energy, Inc., Dominion Oklahoma Texas Exploration & Production, Inc., Dominion Reserves, Inc., LDNG Texas Holdings, LLC and DEPI Texas Holdings, LLC as Sellers and XTO Energy Inc. as Buyer (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 6, 2007)

2.6+	Agreement of Sale and Purchase dated May 23, 2008 between Headington Oil Company LLC, et al. and XTO Energy Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K filed July 18, 2008)

2.7+	Acquisition Agreement dated June 9, 2008 among XTO Energy Inc., HPC Acquisition Corporation, HHEC Acquisition Corporation, Hunt Petroleum Corporation, Hassie Hunt Exploration Company and Hassie Hunt Production Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed July 18, 2008)

2.8+	Purchase and Sale Agreement dated July 18, 2008 between XTO Energy Inc. and Hollis R. Sullivan Inc., et al. (incorporated by reference to Exhibit 2.1 to Form 8-K filed July 24, 2008)

3.1	Restated Certificate of Incorporation of the Company, as restated on June 21, 2006 (incorporated by reference to Exhibit 3.1 to Form 10-Q for the quarter ended June 30, 2006)

3.2	Amended and Restated Bylaws of the Company as of February 17, 2009 (incorporated by reference to Exhibit 3.1 to Form 8-K filed February 23, 2009)

4.1	Form of Indenture for Senior Debt Securities dated as of April 23, 2002 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed April 17, 2002)

4.2	First Supplemental Indenture dated as of April 23, 2002 between the Company and the Bank of New York, as Trustee for the 7 ¹ / 2 % Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 to Form 10-K for the year ended December 31, 2002)

4.3	Second Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 7 ¹ / 2 % Senior Notes due 2012 (incorporated by reference to Exhibit 4.3 to Form 10-Q for the quarter ended March 31, 2006)

4.4	Registration Rights Agreement among the Company and partners of Cross Timbers Oil Company, L.P. (incorporated by reference to Exhibit 10.9 to Registration Statement on Form S-1, File No. 33-59820)

4.5	Indenture dated as of April 23, 2003 between the Company and the Bank of New York, as Trustee for the 6 ¹ / 4 % Senior Notes due 2013 (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2003)

4.6	First Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 6 ¹ / 4 % Senior Notes due 2013 (incorporated by reference to Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2006)

4.7	Indenture for Senior Debt Securities dated as of January 22, 2004 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed January 16, 2004)

4.8	First Supplemental Indenture dated as of January 22, 2004 between the Company and the Bank of New York, as Trustee for the 4.90% Senior Notes due 2014 (incorporated by reference to Exhibit 4.3.2 to Form 8-K filed January 16, 2004)


79		XTO ENERGY		\|		2008 form 10-K


EXHIBIT NO.	DESCRIPTION	PAGE
4.9	Second Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 4.90% Senior Notes due 2014 (incorporated by reference to Exhibit 4.5 to Form 10-Q for the quarter ended March 31, 2006)

4.10	Indenture dated as of September 23, 2004 between the Company and the Bank of New York, as Trustee for the 5% Senior Notes due 2015 (incorporated by reference to Exhibit 4.1 to Form 8-K filed September 24, 2004)

4.11	First Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 5% Senior Notes due 2015 (incorporated by reference to Exhibit 4.6 to Form 10-Q for the quarter ended March 31, 2006)

4.12	Indenture for Senior Debt Securities dated as of April 13, 2005 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed April 12, 2005)

4.13	First Supplemental Indenture dated as of April 13, 2005 between the Company and the Bank of New York, as Trustee for 5.30% Senior Notes due 2015 (incorporated by reference to Exhibit 4.3.2 to Form 8-K filed April 12, 2005)

4.14	Second Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 5.30% Senior Notes due 2015 (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006)

4.15	Third Supplemental Indenture dated as of March 30, 2006 between the Company and The Bank of New York Trust Company, as Trustee, for 5.65% Senior Notes due 2016 and 6.10% Senior Notes due 2036 (incorporated by reference to Exhibit 4.2 to Form 10-Q for the quarter ended March 31, 2006)

4.16	Registration Rights Agreement dated April 1, 2005 among the Company and the security holders of Antero Resources Corporation (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 2005)

4.17	Indenture for Senior Debt Securities dated as of July 19, 2007 between the Company and the Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed July 16, 2007)

4.18	First Supplemental Indenture dated as of July 19, 2007 between the Company and the Bank of New York Trust Company, N.A., as Trustee for 5.90% Senior Notes due 2012, 6.25% Senior Notes due 2017 and 6.75% Senior Notes due 2037 (incorporated by reference to Exhibit 4.3.2 to Form 8-K filed July 16, 2007)

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

4.20	Third Supplemental Indenture dated as of August 7, 2008 between the Company and the Bank of New York Trust Company, N.A., as Trustee for 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)

10.1*	Employment Agreement between the Company and Bob R. Simpson, dated May 16, 2006 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2006)

10.2*	Amendment to Employment Agreement between the Company and Bob R. Simpson, dated December 31, 2007 (incorporated by reference to Exhibit 10.1 to Form 8-K filed January 7, 2008)

10.3*	Employment Agreement between the Company and Bob R. Simpson, dated November 18, 2008

10.4*	Employment Agreement between the Company and Keith A. Hutton, dated May 16, 2006 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2006)

10.5*	Employment Agreement between the Company and Keith A. Hutton, dated November 18, 2008

10.6*	Employment Agreement between the Company and Vaughn O. Vennerberg II, dated May 16, 2006 (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended June 30, 2006)

10.7*	Employment Agreement between the Company and Vaughn O. Vennerberg II, dated November 18, 2008

10.8*	1998 Stock Incentive Plan, as amended March 17, 2004 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2004)

10.9*	XTO Energy Inc. Amended and Restated 2004 Stock Incentive Plan (incorporated by reference to Appendix B to the Proxy Statement dated April 13, 2006 for the Annual Meeting of Stockholders held May 16, 2006)

10.10*	XTO Energy Inc. Amended and Restated 2004 Stock Incentive Plan (as amended and restated through November 21, 2006) (incorporated by reference to Exhibit 10.10 to Form 10-K for the year ended December 31, 2006)

10.11*	XTO Energy Inc. 2004 Stock Incentive Plan, as Amended and Restated as of May 20, 2008 (incorporated by reference to Appendix B to the Proxy Statement dated April 21, 2008 for the Annual Meeting of Stockholders held May 20, 2008)


2008 form 10-K		\|		ANNUAL REPORT		80


EXHIBIT NO.	DESCRIPTION	PAGE
10.12*	Form of Nonqualified Stock Option Agreement for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 8-K filed November 22, 2004)

10.13*	Form of Nonqualified Stock Option Agreement for Employees with Employment Agreements under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2006)

10.14*	Form of Stock Award Agreement for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed November 22, 2004)

10.15*	Form of Nonqualified Stock Option Agreement for Non-Employee Directors under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.4 to Form 8-K filed November 22, 2004)

10.16*	Form of Stock Award Agreement for Non-Employee Directors under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 8-K filed November 22, 2004)

10.17*	Form of Stock Grant Agreement for Non-Employee Directors under Section 11 of the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 22, 2005)

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

10.19*	Form of Stock Award Agreement (Restricted Shares) for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.30 to Form 10-K for the year ended December 31, 2006)

10.20*	Form of Stock Award Agreement for Employees with Employment Agreements under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2008)

10.21*	Form of Stock Grant Agreement to Chairman under Section 11 of the 2004 Stock Incentive Plan

10.22*	Second Form of Stock Award Agreement for Employees with Employment Agreements under the 2004 Stock Incentive Plan

10.23*	Second Form of Nonqualified Stock Option Agreement for Employees with Employment Agreements under the 2004 Stock Incentive Plan

10.24*	Second Amended and Restated Management Group Employee Severance Protection Plan, as amended August 15, 2006 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2006)

10.25*	Third Amended and Restated Management Group Employee Severance Protection Plan, as amended November 18, 2008

10.26*	Amended and Restated Outside Directors Severance Plan, as amended August 15, 2006 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2006)

10.27*	Amended and Restated Outside Directors Severance Plan, as amended November 18, 2008

10.28*	Form of Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, Keith A. Hutton, Vaughn O. Vennerberg II and Louis G. Baldwin, dated October 15, 2004 (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 21, 2004)

10.29*	Form of Amendment No. One to Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, Keith A. Hutton, Vaughn O. Vennerberg II and Louis G. Baldwin, dated November 21, 2006 (incorporated by reference to Exhibit 10.26 to Form 10-K for the year ended December 31, 2006)

10.30*	Amendment Number Two to Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, dated December 31, 2007 (incorporated by reference to Exhibit 10.2 to Form 8-K filed January 7, 2008)

10.31*	Agreement (relating to change in control) between the Company and Timothy L Petrus, dated November 21, 2006 (incorporated by reference to Exhibit 10.27 to Form 10-K for the year ended December 31, 2006)

10.32*	Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, dated November 18, 2008

10.33*	Form of Amended and Restated Agreement (relating to change in control) between the Company and Keith A. Hutton, Vaughn O. Vennerberg II, Louis G. Baldwin and Timothy L. Petrus dated November 18, 2008

10.34*	Consulting and Non-Competition Agreement dated April 1, 2005 between the Company and Steffen E. Palko (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 5, 2005)

10.35*	Form of Indemnification Agreement dated November 15, 2005 between the Company and each director, executive officer and certain other officers (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 18, 2005)

10.36*	Description of Matching Charitable Contribution Program for officers and directors (incorporated by reference to Exhibit 10.34 to Form 10-K for the year ended December 31, 2007)

10.37	Amended and Restated 5-Year Revolving Credit Agreement dated April 1, 2005 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 2005)


81		XTO ENERGY		\|		2008 form 10-K


EXHIBIT NO.	DESCRIPTION	PAGE
10.38	First Amendment to Five-Year Revolving Credit Agreement dated March 10, 2006 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2006)

10.39	Second Amendment to Five-Year Revolving Credit Agreement dated October 25, 2006 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2006)

10.40	Third Amendment to 5-Year Revolving Credit Agreement dated March 19, 2007 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.1 to Form 8-K filed March 23, 2007)

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

10.42	Commitment Increase and Accession Agreement dated July 17, 2008 between XTO Energy Inc. and certain banks named therein (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2008)

10.43	Term Loan Credit Agreement dated November 10, 2004 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.20 to Form S-4 dated December 13, 2004)

10.44	First Amendment to Term Loan Agreement dated April 1, 2005 between the Company and certain banks named therein (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended March 31, 2005)

10.45	Second Amendment to Term Loan Agreement dated March 10, 2006 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2006)

10.46	Third Amendment to Term Loan Agreement dated March 19, 2007 between the Company and certain banks named therein (incorporated by reference to Exhibit 10.2 to Form 8-K filed March 23, 2007)

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

10.48	Form of Commercial Paper Dealer Agreement dated October 27, 2006 between the Company and each of Lehman Brothers Inc., Citigroup Global Markets Inc., Goldman, Sachs & Co. and JP Morgan Securities Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 2, 2006)

10.49	Issuing and Paying Agency Agreement dated October 27, 2006 between the Company and JP Morgan Chase Bank, National Association (incorporated by reference to Exhibit 10.2 to Form 8-K filed November 2, 2006)

10.50	Firm Intrastate Gas Transportation Agreement dated July 1, 2005 between the Company, XTO Resources I, LP and Energy Transfer Fuel, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2005) (Material has been omitted from this Exhibit pursuant to an order of confidential treatment and the omitted material has been separately filed with the Securities and Exchange Commission.)

12.1	Computation of Ratio of Earnings to Fixed Charges

21.1	Subsidiaries of XTO Energy Inc.

23.1	Consent of KPMG LLP

23.2	Consent of Miller and Lents, Ltd.

31.1	Chief Executive Officer Certification required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

31.2	Chief Financial Officer Certification required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

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

+	All schedules and similar attachments have been omitted. The Company agrees to furnish supplementally a copy of the omitted schedules and similar attachments to the Securities and Exchange Commission upon request.

*	Management contract or compensatory plan

Copies of the above exhibits not contained herein are available, at the cost of reproduction, to any security holder upon written request to the Secretary, XTO Energy Inc., 810 Houston Street, Fort Worth, Texas 76102.