10-K

2005

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, 2005

OR

¨ 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, including preferred stock purchase rights	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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer  x            Accelerated filer  ¨            Non-accelerated filer   ¨

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, 2005, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $11.7 billion based on the closing price as reported on the New York Stock Exchange.

Number of Shares of Common Stock outstanding as of February 24, 2006 - 363,949,471

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 29, 2006.

XTO ENERGY INC.

2005 ANNUAL REPORT ON FORM 10-K

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	43
8.	Financial Statements and Supplementary Data	45
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	45
9A.	Controls and Procedures	45
9B.	Other Information	45
	Part III
10.	Directors and Executive Officers of the Registrant	46
11.	Executive Compensation	46
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	46
13.	Certain Relationships and Related Transactions	46
14.	Principal Accounting Fees and Services	46
	Part IV
15.	Exhibits and Financial Statement Schedules	47

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 producing oil and gas 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 have grown primarily through acquisitions of proved oil and gas reserves, followed by development and exploitation activities and acquisition of additional interests in or near such acquired properties. We expect growth in the immediate future to continue to be accomplished through a combination of acquisitions and development. During 2006, we plan to continue to review strategic 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 and competitive factors.

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 well-established production histories concentrated in the following areas:

• Eastern Region, including the East Texas Basin and northwestern Louisiana;

• North Texas Region including the Barnett Shale;

• San Juan Region;

• Permian and South Texas Region;

• Mid-Continent and Rocky Mountain Region; and

• Middle Ground Shoal Field of Alaska’s Cook Inlet.

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 equivalent

• BOE        Barrels of oil equivalent

• Mcf         Thousand cubic feet (of natural gas)

• Mcfe       Thousand cubic feet equivalent

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

• Tcf          Trillion cubic feet (of natural gas)

• Tcfe         Trillion cubic feet equivalent

Our estimated proved reserves at December 31, 2005 were 6.09 Tcf of natural gas, 47.4 million Bbls of natural gas liquids and 208.7 million Bbls of oil, based on December 31, 2005 prices of $9.26 per Mcf for gas, $36.33 per Bbl for natural gas liquids and $57.02 per Bbl for oil. On an energy equivalent basis, our proved reserves were 7.62 Tcfe at December 31, 2005, a 30% increase from proved reserves of 5.86 Tcfe at the prior year end. Increased proved reserves during 2005 were primarily the result of acquisitions and development and exploitation activities. On an Mcfe basis, 69% of proved reserves were proved developed reserves at December 31, 2005. During 2005, our average daily production was 1,033,143 Mcf of gas, 10,445 Bbls of natural gas liquids and 39,051 Bbls of oil. Fourth quarter 2005 average daily production was 1,102,260 Mcf of gas, 10,643 Bbls of natural gas liquids and 41,976 Bbls of oil.

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Our properties typically have relatively long reserve lives and predictable production profiles. Based on December 31, 2005 proved reserves and projected 2006 production from properties owned as of December 31, 2005, the average reserve-to-production index of our proved reserves is 16.3 years. The projected 2006 production is from proved developed producing reserves as of December 31, 2005. In general, our properties have extensive production histories and production enhancement opportunities. While the properties are geographically diversified, the major producing fields are concentrated within core areas, allowing for substantial economies of scale in production and cost-effective application of reservoir management techniques gained from prior operations. As of December 31, 2005, we owned interests in 18,863 gross (9,795.5 net) producing wells, and we operated wells representing 91% 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 4,500 and 5,400 identified potential drilling locations. Drilling plans are primarily dependent upon product prices, 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. The Company then uses its development and technology knowledge to increase the reserves of acquired properties.

We operate gas gathering systems in several of our core producing areas. We also operate gas processing plants in East Texas, in Texas County, Oklahoma and the Cotton Valley Field of Louisiana. 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, and the resultant natural gas liquids are marketed by unaffiliated third parties. We use fixed-price physical sales contracts and futures, forward sales contracts 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.” From 1996 to 1998, we purchased 1,360,000, or 22.7%, of the outstanding units, at a total cost of $18.7 million. In August 2003, our Board of Directors declared a dividend of 0.0044 units of the trust for each share of our common stock outstanding on September 2, 2003. As a result of this dividend, all of the 1,360,000 trust units were distributed on September 18, 2003.

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. We sold 17 million units in the trust’s initial public offering in 1999 and 1.3 million units pursuant to an employee incentive plan in 1999 and 2000. We own the remaining 54%, or 21.7 million units, which we account for as producing properties. Hugoton Royalty Trust units are listed on the New York Stock Exchange under the symbol “HGT.”

In January 2006, the Board of Directors declared a dividend of 0.0596 units of the trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will

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be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date.

We also announced in January 2006 that the Company will consider selling its interests in the underlying properties that are subject to the Cross Timbers Royalty Trust and Hugoton Royalty Trust net profits interests. Any sale is dependent upon finding a qualified buyer, receiving sufficient consideration and structuring a tax-efficient transaction.

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 and the environment, can have a significant impact on operations and profitability. Crude oil prices are determined by global supply and demand. Oil supply is significantly influenced by production 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. 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:

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

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

• 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.

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-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. The 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.

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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. We have generated an inventory of between 4,500 and 5,400 identified potential drilling locations. 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 2006, 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 $70 million of our $1.7 billion 2006 development budget for exploration activities.

Hedging Activities. To reduce production price risk, we may enter futures contracts, collars 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,

• 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, a founder, Chairman and Chief Executive Officer of the Company, 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.

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 January 2006, we announced a strategic goal for 2006 of increasing production by 10% to 12% over 2005 levels. To achieve this growth target, we plan to drill about 1,050 (865 net) development wells and perform approximately 735 (620 net) workovers and recompletions in 2006.

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We have budgeted $1.7 billion for our 2006 development program, which is expected to be funded by cash flow from operations. We plan to spend approximately $700 million in the Eastern Region, $350 million in the North Texas Region, $240 million in the Permian and South Texas Region, $200 million in the San Juan Region and $140 million in the Mid-Continent and Rocky Mountain Region and other areas and approximately $70 million for exploration and acreage leasing activities. An additional $100 million has been budgeted for the construction of pipeline, compression and processing infrastructure that is critical to the transportation and sale of production in several operating regions.

While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2006. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, issuance of public or private debt or equity, or asset sales. Strategic property acquisitions during 2006 may alter the amount currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2006 to focus on opportunities offering the highest rates of return. We also may reevaluate our budget and drilling programs in the event of 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 have continued to tighten steel supplies and cause prices to remain high. In response, we have increased our tubular inventory and have negotiated supply contracts with our vendors to support our development program. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting production growth and increasing development costs.

Although drilling rigs have recently been in short supply throughout the industry, we have secured or contracted to secure the rigs necessary to support our current drilling program.

Acquisitions

During 2001, we acquired predominantly gas-producing properties for a total cost of $238 million. In January 2001, we acquired gas properties in East Texas and Louisiana for $115 million from Herd Producing Company, Inc., and in February 2001, we acquired gas properties in East Texas for $45 million from Miller Energy, Inc. and other owners. In August 2001, we acquired primarily underdeveloped acreage in the Freestone area of East Texas for approximately $22 million. The 2001 acquisitions increased reserves by approximately 248.3 Bcf of natural gas.

During 2002, we acquired predominantly gas-producing properties for a total cost of $354 million. In May 2002, we acquired properties in the Powder River Basin of Wyoming for $101 million. These properties were immediately exchanged with Marathon Oil Company for properties with the same value in East Texas and Louisiana. In July, we purchased gas-producing properties in the San Juan Basin of New Mexico for $43 million and in December 2002, we purchased coal bed methane gas-producing properties located in the San Juan Basin of New Mexico for $154 million from J.M. Huber Corporation. The 2002 acquisitions increased reserves by approximately 330.4 Bcf of natural gas, 2.2 million Bbls of natural gas liquids and 449,000 Bbls of oil.

During 2003, we acquired predominantly gas-producing properties for a total cost of $624 million. In April 2003, we acquired natural gas and coal bed methane producing properties in the Raton Basin of Colorado, the Hugoton Field of southwestern Kansas and the San Juan Basin of New Mexico and Colorado for $381 million from Williams of Tulsa, Oklahoma. In June 2003, we acquired coal bed methane and gas-producing properties in the San Juan Basin of New Mexico and Colorado from Markwest Hydrocarbon, Inc. for $51 million. In October 2003, we announced the completion of property transactions which increased our positions in East Texas, Arkansas and the San Juan Basin of New Mexico for a total cost of $100 million. The 2003 acquisitions increased reserves by approximately 465.7 Bcf of natural gas, 4.5 million Bbls of natural gas liquids and 2.2 million Bbls of oil.

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 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 in the Powder River Basin of Wyoming from ExxonMobil Corporation for $336 million. In August,

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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 a new operating region 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. Including $218 million of debt assumed, $225 million recorded on the step-up of deferred taxes and the assumption of other liabilities, the total purchase price plus liabilities assumed was $1.26 billion. This amount was allocated to assets acquired including approximately $634 million to proved properties, $180 million to unproved properties, $175 million to acquired gas gathering contracts and related gas gathering and pipeline assets, $213 million to goodwill and $57 million to other assets. 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. All 2005 acquisitions are subject to typical post-close adjustments. 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.

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 is subject to typical post-closing adjustments.

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, 2005:

	Proved Reserves				Discounted Present Value before Income Tax of Proved Reserves
(in millions)	Gas (Mcf)	Natural Gas Liquids (Bbls)	Oil (Bbls)	Natural Gas Equivalents (Mcfe)
Eastern Region	3,167.5	9.7	10.1	3,286.3	$	12,014	46.5	%
North Texas Region	725.6	—	—	725.6		2,234	8.7	%
San Juan Region	893.7	36.2	1.7	1,121.1		3,086	12.0	%
Permian and South Texas Region	268.9	1.5	162.8	1,254.7		4,240	16.4	%
Mid-Continent and Rocky Mountain Region	1,026.4	—	18.2	1,135.6		3,931	15.2	%
Alaska Cook Inlet	—	—	15.1	90.6		288	1.1	%
Other	3.5	—	0.8	8.3		23	0.1	%
Total	6,085.6	47.4	208.7	7,622.2	$	25,816	100.0	%

Eastern Region

We began operations in East Texas and northwestern Louisiana in 1998. These properties produce from various formations at depths between 7,000 feet and 13,000 feet. Subsequent acquisitions and development activity have significantly increased reserves here since we began operations, and we now own an interest in more than 563,000 gross (395,000 net) acres. Approximately half of our total proved reserves are in this region. We have 1,850 to 2,100 identified potential drilling locations in this area. In 2005, we expanded our gathering facilities to increase treating capacity to 730,000 Mcf per day. In 2006, we plan to drill between 290 and 330 wells and perform approximately 50 workovers in the Eastern Region.

Our primary focus in the Eastern Region is in the Freestone Trend where we have an interest in 306,000 gross (234,000 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 2005. Other areas in the region include the Sabine Uplift and Cotton Valley areas of East Texas and northwestern Louisiana.

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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, we are now the second largest producer in the area. We own interests in approximately 160,000 net acres, 50% of which are in the core productive area, approximately 360 producing wells and gas gathering and pipeline assets. We have 750 to 950 identified potential drilling locations in this area and plan to drill approximately 240 wells in 2006. We also own 300,000 Mcf per day of treating capacity, which allows us to add new wells as they are completed.

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. Production is from conventional as well as coal bed methane sources. We have 700 to 900 identified potential drilling locations to develop these complex, multi-pay basins. In 2005, we entered a new tight-gas play in the Piceance Basin of Colorado through a farm-out agreement with ExxonMobil and began drilling our first well in December 2005.

Permian and South Texas Region

The Permian and South Texas Region is made up of properties in West Texas, southeastern New Mexico and South Texas. In both 2004 and 2005, we significantly expanded our holdings in the area through acquisitions and trades with ChevronTexaco, ExxonMobil, ConocoPhillips and others. Our activities on these properties have increased oil production by returning shut-in wells to production, optimizing existing well performance, 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 850 to 950 identified potential well locations in this area.

Mid-Continent and Rocky Mountain Region

Our Mid-Continent and Rocky Mountain Region includes fields in Wyoming, Kansas, Oklahoma and Arkansas. We have operations in the Anadarko Basin, Fontenelle area and the Arkoma Basin. While most of our production in the Mid-Continent region is from conventional sources, we recently began developing coal bed methane in the Powder River Basin of Wyoming. A substantial 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. We own 54.3% of the Hugoton Royalty Trust units. In January 2006, we announced we would distribute these trust units as a dividend to our stockholders in May 2006. We also announced we will consider selling our interests in the properties underlying the Hugoton Royalty Trust net profits interest.

We operate a gathering system and pipeline in Major County, Oklahoma and a gas plant in Texas County, Oklahoma, and its associated gathering system. We are currently building a gas gathering and water disposal system in the Hartzog Draw area of Wyoming to service our coal bed methane wells.

Alaska Cook Inlet and Other

We own a 100% interest in two State of Alaska offshore leases and installations in the Middle Ground Shoal Field of the Cook Inlet. The properties include 27 wells on two platforms and a 100% interest in operated production pipelines and onshore processing facilities.

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/divisions/corpfin/forms/regsx.htm#gas.

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.

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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, other than hedge derivatives) 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.”

The following are estimated quantities of proved reserves and related cash flows as of December 31, 2005, 2004 and 2003:

	December 31
(in millions)	2005		2004		2003
Proved developed:
Gas (Mcf)		4,033.1		3,252.7		2,651.3
Natural gas liquids (Bbls)		36.5		30.0		28.2
Oil (Bbls)		168.5		134.4		47.9
Mcfe		5,262.9		4,239.1		3,107.7
Proved undeveloped:
Gas (Mcf)		2,052.5		1,461.8		992.9
Natural gas liquids (Bbls)		10.9		8.5		6.5
Oil (Bbls)		40.2		18.1		7.5
Mcfe		2,359.3		1,621.2		1,077.2
Total proved:
Gas (Mcf)		6,085.6		4,714.5		3,644.2
Natural gas liquids (Bbls)		47.4		38.5		34.7
Oil (Bbls)		208.7		152.5		55.4
Mcfe		7,622.2		5,860.3		4,184.9
Estimated future net cash flows:
Before income tax	$	50,897	$	23,605	$	16,700
After income tax	$	34,074	$	16,239	$	11,558
Present value of estimated future net cash flows, discounted at 10%:
Before income tax (a)	$	25,816	$	12,237	$	8,607
After income tax	$	17,094	$	8,402	$	5,989

(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. 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 $8.72 billion at December 31, 2005, $3.84 billion at December 31, 2004 and $2.62 billion at December 31, 2003.

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, 2005, 2004 and 2003. 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.

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Estimated future net cash flows, and the related 10% discounted present value, of year-end 2005 proved reserves are significantly higher than at year-end 2004 because of increased reserves related to acquisitions and development and higher gas, natural gas liquids and oil prices used in the estimation of year-end proved reserves. Year-end 2005 average realized prices used in the estimation of proved reserves were $9.26 per Mcf for gas, $36.33 per Bbl for natural gas liquids and $57.02 per Bbl for oil. Year-end 2004 product prices were $5.69 per Mcf for gas, $28.24 per Bbl for natural gas liquids and $41.03 per Bbl for oil. See Note 15 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 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 change in product prices, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates.

During 2005, we filed estimates of oil and gas reserves as of December 31, 2004 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, 2004 in Note 15 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, 2005, all of which are located in the United States:

	Operated Wells		Nonoperated Wells		Total (a)
	Gross	Net	Gross	Net	Gross	Net
Gas	7,539	6,476.0	4,821	810.6	12,360	7,286.6
Oil	2,258	1,980.5	4,245	528.4	6,503	2,508.9
Total	9,797	8,456.5	9,066	1,339.0	18,863	9,795.5

(a) 716 gross (436.7 net) gas wells and 10 gross (9.6 net) oil wells are dual completions.

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Drilling Activity

The following table summarizes the number of wells drilled during the years indicated. As of December 31, 2005, we were in the process of drilling 462 gross (307.1 net) wells.

	Year Ended December 31
	2005		2004		2003
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Completed as-
Gas wells	791	499.8	584	372.0	390	289.5
Oil wells	255	121.4	33	23.9	42	30.0
Non-productive	19	9.6	27	12.4	7	3.0
Total	1,065	630.8	644	408.3	439	322.5
Exploratory wells:
Completed as-
Gas wells	7	4.7	3	1.4	12	10.2
Oil wells	—	—	—	—	—	—
Non-productive	2	2.0	—	—	—	—
Total	9	6.7	3	1.4	12	10.2
Total (a)	1,074	637.5	647	409.7	451	332.7

(a) Included in totals are 472 gross (96.7 net) wells in 2005, 212 gross (27.3 net) wells in 2004 and 102 gross (17.7 net) wells in 2003, drilled on nonoperated interests.

Acreage

The following table summarizes developed and undeveloped leasehold acreage in which we own a working interest as of December 31, 2005. 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
Texas	962	703	304	263
Oklahoma	559	386	18	9
Arkansas	580	312	121	113
New Mexico	435	286	33	28
Kansas	211	167	—	—
Louisiana	122	66	—	—
Colorado	107	84	—	—
Wyoming	74	57	54	51
Utah	68	58	—	—
Other	11	9	—	—
Total	3,129	2,128	530	464

(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.

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Oil and Gas Sales Prices and Production Costs

The following table shows the average sales prices per unit of production and the production expense and taxes, transportation and other expense per Mcfe for quantities produced for the indicated period:

	Year Ended December 31
	2005		2004		2003
Sales prices (a):
Gas (per Mcf)	$	7.04	$	5.04	$	4.07
Natural gas liquids (per Bbl)	$	34.10	$	26.44	$	19.99
Oil (per Bbl)	$	47.03	$	38.38	$	28.59
Production expense per Mcfe	$	0.84	$	0.66	$	0.58
Production and property taxes per Mcfe	$	0.42	$	0.30	$	0.21
Transportation and other expense per Mcfe	$	0.21	$	0.17	$	0.16

(a) The sales prices shown include the effects of hedging. The effect of hedging on gas prices was to lower realized prices by $0.34 in 2005, $0.52 in 2004 and $0.79 in 2003. The effect of hedging on oil prices was to lower realized prices by $5.25 in 2005, $1.86 in 2004 and $0.81 in 2003.

Delivery Commitments

Under a production payment sold in 1998, we have committed to deliver 16.0 Bcf (13.0 Bcf net to our interest) beginning approximately September 2006. Delivery of the committed volumes is in East Texas. See Note 8 to Consolidated Financial Statements. The Company’s production and reserves are adequate to meet this delivery commitment.

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 liquified 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.

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. We cannot predict the impact of future government regulation on any natural gas facilities.

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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.

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.

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. One of our gathering subsidiaries is designated a gas utility and is 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.

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

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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.

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 1,680 employees as of December 31, 2005. 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, 57, was a founder of the Company and has been Chairman and Chief Executive Officer since July 1, 1996. Prior thereto, Mr. Simpson served as Vice Chairman and Chief Executive Officer or held similar positions with the Company since 1986. Mr. Simpson was Vice President of Finance and Corporate Development (1979-1986) and Tax Manager (1976-1979) of Southland Royalty Company.

Keith A. Hutton, 47, has been President since May 1, 2005. Prior thereto, Mr. Hutton served as 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, 51, has been Senior Executive Vice President and Chief of Staff since May 1, 2005. Prior thereto, Mr. Vennerberg served as 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, 56, 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, 51, 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, 55, 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 oil, natural gas and natural gas liquids. We sell most of our oil, natural gas and natural gas liquids at current market prices rather than through fixed-price contracts. Historically, the markets for oil, natural gas 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:

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

• weather conditions;

• 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 oil and natural gas 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.

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

To reduce our exposure to fluctuations in oil and natural gas prices, we have entered into and expect in the future to enter into hedging arrangements for a portion of our oil and natural gas production. 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 contract 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 oil and natural gas prices.

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 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 $1.4 billion in 2005, $587 million in 2004 and $462 million in 2003. During 2005, we spent $1.7 billion on proved property acquisitions. Our exploration and development budget for 2006 is $1.7 billion. An additional $100 million has been budgeted for the construction of pipeline, compression and processing infrastructure in 2006.

We believe that, after debt service, we will have sufficient cash from operating activities to finance our exploration and development expenses through 2006. 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.

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 indebtedness is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have applicable 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.

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.

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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;

• integrating new technologies; and

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

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 or development 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 of 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 geological, 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.

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You 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 earlier net present value estimate, and as a result, net present value estimates using current prices and costs may be significantly less than the earlier estimate which is provided in this annual report.

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.

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

Our recent growth is due in part to acquisitions of producing 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 potential, 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 producing 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.

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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.

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;

• title problems;

• restricted access to land for drilling or laying pipeline;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions; 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 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. For example, during 2004, we experienced temporary curtailments of our natural gas production in the San Juan Basin and in East Texas due to infrastructure limitations and plant closings for maintenance reasons.

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

Extensive federal, state and local 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;

• discharge of hazardous materials;

• reclamation costs;

• remediation and clean-up costs; and

• other environmental damages.

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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 the coastal waters of Cook Inlet of Alaska 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 in United States waters. 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.

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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;

• failure of oilfield drilling and service tools;

• 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, 2005, we do not have any Securities and Exchange Commission staff comments that have been unresolved for more than 180 days.

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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 have been 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. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion occurred in March 2005, and in May 2005, the special master, who was appointed by the district judge to expedite matters and make recommendations to the district judge in the case, issued a report and recommendation to dismiss the case against some of the defendants but to retain jurisdiction of the case involving us and other defendants. We and the other defendants filed motions to modify the special master’s report, requesting the district judge to also dismiss the case as to us and other defendents. The district judge heard oral arguments on December 9, 2005, as to all motions seeking adoption, modification or reversal of the special master’s report, and we are awaiting the decision of the district court. While we are unable to predict the 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 June 2001, we were served with a lawsuit styled Price, et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against us and one of our subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims to cover all oil and gas leases (other than the federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas delivered into their pipelines, resulting in underpayments to the plaintiffs. The plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of action. The amount of damages was not specified in the complaint. In February 2002, we, along with one of our subsidiaries, were dismissed from the suit and another subsidiary of the Company was added. A hearing was held in January 2003, and the court held that a class should not be certified. The plaintiffs’ counsel has filed an amended class action petition, which reduces the proposed class to only royalty owners, reduces the claims to mismeasurement of volume only, conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court held an evidentiary hearing in April 2005 to determine whether the amended class should be certified, and we are awaiting the decision of the court. While we are unable to predict the 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 August 5, 2003, the Price plaintiffs served one of our subsidiaries with a new original class action petition styled Price, et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against natural gas pipeline owners and operators. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas royalty owners either from whom the defendants had purchased natural gas or measured natural gas since January 1, 1974 to the present. The new petition alleges the same improper analysis of gas heating content that had previously been alleged in the Price case discussed above until it was removed from the case by the filing of the amended class action petition. In all other respects, the new petition appears to be identical to the amended class action petition in that it has a proposed class of only royalty owners, alleges conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court held an evidentiary hearing in April 2005 to determine whether the amended class should be certified, and we are awaiting the decision of the court. The amount of damages was not specified in the complaint. While we are unable to predict the outcome of this case, we believe that

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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 2004, we were served with a lawsuit styled Burkett, et al. v. J.M. Huber Corp. and XTO Energy Inc. The action was filed in the District Court of La Plata County, Colorado against us and J.M. Huber Corporation. The plaintiffs alleged that the defendants deducted in their calculation of royalty payments expenses of compression, gathering, treatment, dehydration, or other costs to place the natural gas produced in a marketable condition at a marketable location. The plaintiffs sought to represent a class consisting of all lessors and their successors in interest who own or have owned mineral interests located in La Plata County, Colorado and that were leased to or operated by Huber or us, except to the extent that the lessors or their successors expressly authorized deduction of post-production expenses from royalties. We acquired the interests of Huber in producing properties in La Plata County effective October 1, 2002, and assumed the responsibility for certain liabilities of Huber prior to the effective date, which included liability for post-production deductions made by Huber. As of December 31, 2004, based on an evaluation of available information, we accrued a $3.1 million estimated liability for this claim in our consolidated financial statements. On February 17, 2005, we agreed to a settlement of $5.1 million, resulting in an additional loss of approximately $2 million that was recorded in our consolidated income statement for 2005. On June 21, 2005, the court entered a final judgment approving the settlement on a class-wide basis. The final judgment releases XTO from any royalty claims concerning post-production costs relating to the properties. No appeals from the final judgment were filed, so the litigation is concluded. We paid this settlement in August 2005.

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, which we are discussing with them.

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 2005.

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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 sales prices and cash dividends declared for each quarter of 2005 and 2004, (as adjusted for the four-for-three stock split effected in March 2005 and the five-for-four stock split effected in March 2004):

	High		Low		Cash Dividend
2005
First Quarter	$	35.183	$	23.865	$	0.0500
Second Quarter		36.500		26.000		0.0500
Third Quarter		46.310		34.150		0.0500
Fourth Quarter		47.610		38.150		0.0750
2004
First Quarter	$	19.512	$	15.348	$	0.0075
Second Quarter		22.875		18.315		0.0075
Third Quarter		24.833		19.050		0.0375
Fourth Quarter		27.660		22.350		0.0375

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.

In November 2005, the Board of Directors increased our quarterly dividend to $0.075 per common share. On February 21, 2006, the Board of Directors declared a quarterly dividend of $0.075 per common share payable on April 13, 2006 to stockholders of record on March 31, 2006. On February 23, 2006, we had 1,537 stockholders of record.

In January 2006, the Board of Directors declared a dividend of 0.0596 units of Hugoton Royalty Trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date. As of the January 26, 2006 declaration date, this dividend has a fair value of approximately $830 million, or $2.28 per common share.

The following summarizes purchases of our common stock during fourth quarter 2005:

Month	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (a)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (a)
October	—		$	—	—
November	—		$	—	—
December	62,563	(b)	$	44.50	—
Total	62,563		$	44.50	—	19,966,400

(a) The Company has a repurchase program approved by the Board of Directors in August 2004 for the repurchase of up to 20 million shares of the Company’s common stock.

(b) During the quarter ended December 31, 2005, the Company purchased shares of common stock as treasury shares to pay income tax withholding obligations in conjunction with vesting of performance shares under the 2004 Stock Incentive plan. These share purchases were not part of a publicly announced program to purchase common shares.

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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, 2005. 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 four-for-three stock split effected in March 2005, the five-for-four stock split effected in March 2004, the four-for-three stock split effected in March 2003 and the three-for-two stock split effected in June 2001. 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)	2005			2004			2003			2002			2001
Consolidated Income Statement Data
Revenues:
Gas and natural gas liquids	$	2,787		$	1,613		$	1,040		$	681		$	710
Oil and condensate		670			319			135			115			117
Gas gathering, processing and marketing		56			18			13			12			13
Other		6			(2	)		1			2			(1	)
Total Revenues	$	3,519		$	1,948		$	1,189		$	810		$	839
Net Income	$	1,152	(a)	$	508	(b)	$	288	(c)	$	186	(d)	$	249	(e)
Earnings per common share:
Basic	$	3.21		$	1.53		$	0.96	(f)	$	0.67		$	0.91	(g)
Diluted	$	3.15		$	1.51		$	0.95	(f)	$	0.66		$	0.90	(g)
Weighted average common shares outstanding		358.4			332.9			299.7			277.8			272.2
Cash dividends declared per common share	$	0.2250		$	0.0900		$	0.0240	(h)	$	0.0180		$	0.0165
Consolidated Statement of Cash Flows Data
Cash provided (used) by:
Operating activities	$	2,094		$	1,217		$	794		$	491		$	543
Investing activities	$	(2,908	)	$	(2,518	)	$	(1,135	)	$	(737	)	$	(611	)
Financing activities	$	806		$	1,304		$	333		$	254		$	68
Consolidated Balance Sheet Data
Property and equipment, net	$	8,508		$	5,624		$	3,312		$	2,371		$	1,841
Total assets	$	9,857		$	6,110		$	3,611		$	2,648		$	2,132
Long-term debt	$	3,109		$	2,043		$	1,252		$	1,118		$	856
Stockholders’ equity	$	4,209		$	2,599		$	1,466		$	908		$	821
Operating Data
Average daily production:
Gas (Mcf)		1,033,143			834,572			668,436			513,925			416,927
Natural gas liquids (Bbls)		10,445			7,484			6,463			5,068			4,385
Oil (Bbls)		39,051			22,696			12,943			13,033			13,637
Mcfe		1,330,121			1,015,654			784,877			622,532			525,062
Average sales price:
Gas (per Mcf)	$	7.04		$	5.04		$	4.07		$	3.49		$	4.51
Natural gas liquids (per Bbl)	$	34.10		$	26.44		$	19.99		$	14.31		$	15.41
Oil (per Bbl)	$	47.03		$	38.38		$	28.59		$	24.24		$	23.49
Production expense (per Mcfe)	$	0.84		$	0.66		$	0.58		$	0.57		$	0.57
Taxes, transportation and other expense (per Mcfe)	$	0.63		$	0.47		$	0.37		$	0.25		$	0.33
Proved reserves:
Gas (Mcf)		6,085.6			4,714.5			3,644.2			2,881.2			2,235.5
Natural gas liquids (Bbls)		47.4			38.5			34.7			25.4			20.3
Oil (Bbls)		208.7			152.5			55.4			56.3			54.0
Mcfe		7,622.2			5,860.3			4,184.9			3,371.9			2,681.6
Other Data
Ratio of earnings to fixed charges (i)		11.7			8.9			6.9			5.6			7.7

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(a) Includes pre-tax effects of a derivative fair value gain of $13 million, non-cash incentive compensation of $34 million, and a gain of $10 million on the exchange of producing properties.

(b) Includes pre-tax effects of a derivative fair value loss of $12 million, 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.

(c) Includes pre-tax effects of a derivative fair value loss of $10 million, a non-cash contingency gain of $2 million, non-cash incentive compensation of $53 million, a $10 million loss on extinguishment of debt, a $16 million non-cash gain on the distribution of Cross Timbers Royalty Trust units, and a $2 million after-tax gain on adoption of the new accounting standard for asset retirement obligation.

(d) Includes pre-tax effects of a derivative fair value gain of $3 million, gain on settlement with Enron Corporation of $2 million, non-cash incentive compensation of $27 million and a $9 million loss on extinguishment of debt.

(e) Includes pre-tax effects of a derivative fair value gain of $54 million, non-cash incentive compensation expense of $10 million, and an after-tax charge of $45 million for the cumulative effect of accounting change.

(f) Before cumulative effect of accounting change, earnings per share were $0.95 basic and $0.94 diluted.

(g) Before cumulative effect of accounting change, earnings per share were $1.08 basic and $1.06 diluted.

(h) Excludes the September 2003 distribution of all of the Cross Timbers Royalty Trust units owned by the Company to its stockholders as a dividend with a market value of approximately $0.09 per common share.

(i) 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.

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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 our production of natural gas, natural gas liquids and crude oil, we have determined that our business comprises only one industry segment.

In 2005, we achieved the following record financial and operating results:

• Average daily gas production was 1,033,143 Mcf, a 24% increase from 2004, average daily oil production was 39,051 Bbls, a 72% increase from 2004, and average daily natural gas liquids production was 10,445 Bbls, a 40% increase from 2004.

• Year-end proved reserves were 7.6 Tcfe, a 30% increase from year-end 2004.

• Net income was $1.15 billion, a 127% increase from 2004, and earnings per basic common share was $3.21, a 110% increase from 2004.

• Cash flow from operating activities was $2.1 billion, a 72% increase from 2004.

• Stockholders’ equity was $4.2 billion, a 62% increase from year-end 2004.

• The debt-to-capitalization ratio improved to 42.5% at year-end from 44% at year-end 2004.

We achieve production and proved reserve growth primarily through producing property acquisitions, 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 borrowings and cash flow from operating activities. Maintaining or improving our debt-to-capitalization ratio is a primary consideration in selecting our method of acquisition financing. During 2005, we acquired $1.7 billion of proved properties with proved reserves of 803 Bcf of natural gas, 3 million Bbls of natural gas liquids and 31 million Bbls of oil.

In a trend that began in 2004 and accelerated during 2005, commodity prices for natural gas, natural gas liquids and oil increased significantly (see “Significant Events, Transactions and Conditions – Product Prices”). The higher prices have led to increased activity in the industry and, consequently, rising costs. Drilling rig counts are at levels not seen since the last boom in the early 1980s and labor to run the rigs is in short supply. This was further aggravated by the damage in the Gulf of Mexico as a result of the August and September hurricanes (see “Significant Events, Transactions and Conditions – Gulf of Mexico Hurricanes”). These cost trends have put pressure not only on our operating costs but also our capital costs. With the increased activity, there is also increased demand for oil and gas properties which has resulted in higher acquisition prices.

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 oil and gas it produces. 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.

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Our goal for 2006 is to increase production by 10% to 12%. To achieve future production and reserve growth, we will continue to pursue acquisitions that meet our criteria, and to complete development projects included in our inventory of between 4,500 and 5,400 identified potential drilling locations. Our 2006 development budget is $1.7 billion. While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2006. 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.

Raw material shortages and strong global demand for steel have continued to tighten steel supplies and cause prices to remain high. In response, we have increased our tubular inventory and have negotiated supply contracts with our vendors to support our development program. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting production growth and increasing development costs.

Although drilling rigs have recently been in short supply throughout the industry, we have secured or contracted to secure the rigs necessary to support our current drilling program.

The increased activity in the oil and gas producing industry has also had an effect on our ability to hire qualified people including not only field operators and drillers, but also all classifications of industry-specific professionals. We continue to find the employees we need to adequately staff our operations; however, the cost of hiring and the time to fill positions has increased since 2004. Our employee turnover continues to remain low with total turnover of 7.1% in 2005 and 7.8% in 2004.

In the event that our operating cash flow exceeds our development, exploration and acquisition capital needs, we will consider other alternative uses for this cash including, but not limited to, debt repayment or stock repurchases. In August 2004, the Board of Directors authorized the repurchase of up to 20 million shares of our common stock from time to time in the open market or negotiated transactions. As of December 31, 2005, 33,600 shares have been repurchased under this authorization.

In January 2006, the Board of Directors declared a dividend of 0.0596 units of Hugoton Royalty Trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date. Based on the January 26, 2006 declaration date, this dividend has a fair value of approximately $830 million, or $2.28 per common share.

Sales prices for our natural gas and oil 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 2006, we have hedged approximately 50% of our first quarter 2006 projected gas production at an average NYMEX price of $12.95 per Mcf, and 20% of our last nine months 2006 projected gas production at an average NYMEX price of $11.06 per Mcf, and about 35% of our 2006 crude oil production at an average NYMEX price of $59.53 per Bbl. Our average realized price on hedged production will be lower than these average NYMEX prices because of location, quality and other adjustments.

The combined effect of higher product prices, a 23% increase in gas production and a 72% increase in oil production resulted in an 81% increase in total revenues to $3.52 billion in 2005 from $1.95 billion in 2004. On an Mcfe produced basis, total revenues were $7.25 in 2005, a 38% increase from $5.24 in 2004.

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We analyze, on an Mcfe produced basis, expenses that generally trend changes in production:

	2005		2004		Increase (Decrease)
Production	$	0.84	$	0.66	27%
Taxes, transportation and other		0.63		0.47	34%
Depreciation, depletion and amortization		1.35		1.09	24%
Accretion of discount in asset retirement obligation		0.02		0.02	—
General and administrative, excluding stock-based incentive compensation		0.25		0.20	25%
Interest		0.31		0.25	24%
	$	3.40	$	2.69	26%

Production expense per Mcfe rose 27% primarily because of the 72% increase in oil production, which is more expensive to produce than natural gas. Increased maintenance and labor costs and the higher cost of gas used for fuel also contributed to higher production expense. Taxes, transportation and other expense generally is based on product revenues, and the 34% increase in this expense per Mcfe is primarily caused by increased product prices. The 24% increase in depreciation, depletion and amortization per Mcfe resulted from higher acquisition, development and infrastructure costs. The 25% increase in general and administrative expense per Mcfe is because of increased personnel and other costs related to Company growth.

Significant expenses that generally do not trend with production include:

Stock-based incentive compensation. This is a component of general and administrative expense and primarily relates to performance shares that vest when the common stock price reaches specified target levels. Incentive compensation was $34 million in 2005, a 62% decrease from the comparable 2004 expense of $89 million. Included in 2004 incentive compensation is $22 million of cash compensation related to vesting of cash-equivalent performance shares. Otherwise, stock-based incentive compensation was non-cash. Decreased incentive compensation is because performance shares were not awarded to the executive officers named in the proxy. Including stock-based incentive compensation, general and administrative expense decreased $10 million, or 6%.

As required by SFAS No. 123 (Revised 2004), as of January 1, 2006, we will begin recognizing compensation expense in our consolidated financial statements related to the estimated fair value of all stock-based awards, including stock options, granted in 2006 and after. In addition, we will record compensation expense of $17 million in 2006 related to the estimated fair value of unvested stock awards outstanding at December 31, 2005.

Derivative fair value (gain) loss. This is the net realized and unrealized gain or loss on derivative financial instruments that do 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 $13 million in 2005 compared to a $12 million loss in 2004. In 2005, a $37 million gain primarily related to natural gas basis swap agreements not qualifying for hedge accounting was partially offset by a loss on the Btu swap contracts. The derivative loss in 2004 was primarily attributable to the ineffective portion of hedge derivatives.

Our primary sources of liquidity are cash flow from operating activities, borrowings under our revolving credit facility with commercial banks 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”).

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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, 2005, 2004 and 2003 and may impact future operations and financial condition.

Acquisitions. We acquired proved and unproved properties at a total cost of $2 billion per year in 2005 and 2004 and $629 million in 2003, which were funded by a combination of proceeds from sales of common stock and senior notes, bank borrowings and cash flow from operating activities. The following are the significant acquisitions:

Closing Date		Seller	Amount (in millions)	Acquisition Area
2005	April	Antero Resources Corporation	$814(a)	Barnett Shale of North Texas
	May	Plains Exploration & Production Company	336	East Texas and northwestern Louisiana
	July	ExxonMobil Corporation	200	Permian Basin of West Texas and New Mexico
2004	January	Multiple parties	243	East Texas and northwestern Louisiana
	February - April	Multiple parties	223	Barnett Shale of North Texas and Arkoma Basin
	April	ExxonMobil Corporation	336	Permian Basin of West Texas and Powder River Basin of Wyoming
	August	ChevronTexaco Corporation	958	Eastern Region, Permian Basin, Mid-Continent, Rocky Mountains and South Texas
2003	May	Williams of Tulsa, Oklahoma	381	Raton Basin of Colorado, Hugoton field of southwestern Kansas and San Juan Basin of New Mexico and Colorado
	June	Markwest Hydrocarbon, Inc.	51	San Juan Basin of New Mexico and Colorado
	October	Multiple parties	100	East Texas, Arkansas and San Juan Basin of New Mexico

(a) Represents a portion of the allocated purchase price of Antero Resources Corporation and includes an allocation of $634 million to proved properties and $180 million to unproved properties. See Note 13 to the Consolidated Financial Statements.

On February 28, 2006, we acquired proved and unproved properties from Total E&P USA, Inc. for $300 million. The acquisition is subject to typical post-closing adjustments.

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2005, 2004 and 2003 Development and Exploration Programs. Gas development focused on the Eastern and North Texas Regions during 2005 and on the Eastern and Mid-Continent Regions in 2004 and 2003. Oil development was concentrated primarily in the Permian Region during all three years. Development costs totaled $1.34 billion in 2005, $570 million in 2004 and $443 million in 2003. Exploration activity in 2005 was primarily drilling and geological and geographical analysis, including seismic studies of underdeveloped properties in the North Texas Region. Exploration activity in 2004 was primarily geological and geophysical analysis, including seismic studies of undeveloped properties. Exploration activity in 2003 consisted primarily of drilling successful wells in the Eastern Region. Exploratory costs were $52 million in 2005, $17 million in 2004 and $19 million in 2003. Our development and exploration activities are generally funded by cash flow from operations.

2006 Acquisition, Development and Exploration Program. We have budgeted $1.7 billion for our 2006 development and exploration program, which we expect to fund using cash flow from operations. While an acquisition budget has not been formalized, we plan to continue to actively review additional acquisition opportunities during 2006. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, public or private issuance of debt or equity, or asset sales. The cost of 2006 property acquisitions may alter the amount currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2006 to focus on opportunities offering the highest rates of return.

As of December 31, 2005, we have an inventory of between 4,500 and 5,400 identified potential drilling locations. We plan to drill about 1,050 (865 net) development wells and perform approximately 735 (620 net) workovers and recompletions in 2006. 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, crude oil prices and import levels of liquified natural gas. Natural gas competes with alternative energy sources as fuel for heating and the generation of electricity. Since late 2002, gas prices have generally been increasing due primarily to increased demand and declining North American production. These trends accelerated in the second half of 2005 due to the effects of hurricanes on Gulf of Mexico production. During the last half of 2005 and the first two months of 2006, gas prices have ranged from a high in excess of $15.00 per MMBtu to a low of almost $7.00 per MMBtu. 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)	2005		2004		2003
Average NYMEX price	$	8.62	$	6.14	$	5.39
Average realized sales price	$	7.04	$	5.04	$	4.07
Average realized sales price excluding hedging	$	7.38	$	5.56	$	4.86

At February 24, 2006, the average NYMEX gas price for the following 12 months was $8.46 per MMBtu. As computed on an energy equivalent basis, our proved reserves were 80% natural gas at December 31, 2005. After considering hedges in place as of February 24, 2006, we estimate that a $0.10 per Mcf change in the average gas sales price would result in approximately a $27 million change in 2006 annual operating cash flow before income taxes.

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Oil. Crude oil prices are generally determined by global supply and demand. Since late 2002, oil prices have generally been rising primarily because of increasing global demand and supply shortage concerns, inadequate refining capacity, reduced production as a result of tropical storms and hurricanes in the Gulf of Mexico and political instability. Oil prices increased to record levels in August 2005, exceeding $70.00 per Bbl. 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)	2005		2004		2003
Average NYMEX price	$	56.57	$	41.38	$	31.08
Average realized sales price	$	47.03	$	38.38	$	28.59
Average realized sales price excluding hedging	$	52.28	$	40.24	$	29.40

At February 24, 2006, the average NYMEX oil price for the following 12 months was $66.33 per Bbl. After considering hedges in place as of February 24, 2006, we estimate that a $1.00 per barrel change in the average oil sales price would result in approximately a $9 million change in 2006 annual operating cash flow before income taxes.

Gulf of Mexico Hurricanes. In late August and September 2005, hurricanes in the Gulf of Mexico disrupted a significant portion of U.S. oil and gas production, leading to higher and more volatile commodity prices. The Company’s field operations and production were substantially unaffected by these hurricanes. Production expense and development costs, however, have increased throughout the industry because of storm damages and related supply shortages and higher insurance costs.

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 2005, all hedging activities decreased gas revenue by $127 million and decreased oil revenue by $75 million, while in 2004, all hedging activities decreased gas revenue by $156 million and decreased oil revenue by $15 million. In 2003, hedging activities decreased gas revenue by $193 million and decreased oil revenue by $4 million.

The following summarizes our January 2006 through December 2006 NYMEX hedging positions as of February 2006, excluding basis adjustments which are separately hedged. Our average daily production was 1,102,260 Mcf of gas and 41,976 Bbls of oil in fourth quarter 2005. 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.

	Futures Contracts and Swap Agreements For January through December 2006 Production
	Natural Gas			Crude Oil
Period Hedged	Volume per Day (Mcf )	Average NYMEX Price per Mcf		Volume per Day (Bbls)	Average NYMEX Price per Bbl
Jan. - Mar. 2006	560,000	$	12.95	15,000	$	59.53
Apr. - Dec. 2006	260,000	$	11.06	15,000	$	59.53

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 a net derivative fair value gain of $13 million in 2005, and net losses of $12 million in 2004 and $10 million in 2003. The 2005 gain includes a $1 million loss on the ineffective portion of hedge derivatives, or approximately 1% of total hedge derivative losses. The 2004 loss includes a $12 million loss on the ineffective portion of hedge derivatives, or approximately 8% of total hedge derivative losses. The 2003 loss includes a $7 million loss on the ineffective portion of hedge derivatives, or approximately 4% of total hedge derivative losses. These ineffective hedge derivative losses are primarily because of increasing oil and gas prices and their effect on hedges of production in areas without corresponding basis or location differential swap contracts.

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Derivative fair value (gain) loss includes a net loss related to our Btu swap contracts of $23 million in 2005, $1 million in 2004 and $5 million in 2003. The remaining portion of these contracts was terminated as of February 28, 2006, resulting in a net Btu swap contract gain of approximately $16 million in first quarter 2006.

Unrealized derivative gains and losses associated with effective cash flow hedges are recorded in stockholders’ equity as accumulated other comprehensive income. At December 31, 2005, we have an unrealized pre-tax gain of $106 million in accumulated other comprehensive income related to the fair value of derivatives designated as cash flow hedges of gas and crude oil price risk. This fair value gain is expected to be reclassified into earnings in 2006. The actual reclassification to earnings will be based on mark-to-market prices at contract settlement date.

Stock-based Incentive Compensation. Through 2005, incentive compensation generally resulted from vesting of performance share awards as our common stock price increased. Incentive compensation totaled $34 million in 2005, $89 million in 2004 and $53 million in 2003, which relates to increases in our stock price of 66% in 2005, 56% in 2004 and 53% in 2003. Included in 2004 incentive compensation is $22 million of cash compensation related to vesting of cash-equivalent performance shares. Otherwise, stock-based compensation was non-cash. As of December 31, 2005, outstanding performance shares comprise 154,500 shares that vest when the common stock price closes above $50 and 1,250 shares that vest when the common stock price closes above $55. Based on management’s estimated probable vesting period, $2 million of related stock incentive compensation was accrued at December 31, 2005.

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123 (Revised 2004), which requires companies to record compensation expense for all stock awards at fair value effective January 1, 2006. Accordingly, we will begin recording compensation related to stock options in first quarter 2006. See “Accounting Pronouncements” below.

Hugoton Royalty Trust Distribution. In January 2006, the Board of Directors declared a dividend of 0.0596 units of Hugoton Royalty Trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date. As of the January 26, 2006 declaration date, this dividend has a fair value of approximately $830 million or $2.28 per common share.

Based on 2005 production and proved reserves estimates as of December 31, 2005, the distribution of Hugoton Royalty Trust units will reduce our production and our proved reserves by less than 3% on an Mcfe basis.

We also announced in January 2006 that the Company will consider selling its interests in the underlying properties that are subject to the Cross Timbers Royalty Trust and Hugoton Royalty Trust net profits interests. Any sale is dependent upon finding a qualified buyer, receiving sufficient consideration and structuring a tax-efficient transaction.

Cross Timbers Royalty Trust Distribution. In August 2003, our Board of Directors declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each share of our common stock outstanding on September 2, 2003. This dividend, totaling 1,360,000 units, was distributed on September 18, 2003, after which we no longer own any Cross Timbers Royalty Trust units. We recorded this dividend at $28 million, or approximately $0.09 per common share, based on the fair market value of the units on the distribution date. After considering the cost of the units, we recorded a pre-tax gain on distribution of $16 million.

Extinguishment of Debt. In May 2003, we purchased and canceled the remaining $163 million of our 8 ³/4% notes. As a result of this transaction, we recorded a total pre-tax loss on extinguishment of debt of $10 million in 2003, which includes the effects of redemption premium paid and expensing related deferred debt costs.

Cumulative Effect of Accounting Change for Asset Retirement Obligations. As of January 1, 2003, we adopted SFAS No. 143 by recording a long-term liability for asset retirement obligations of $75 million, an increase in property cost of $61 million, a reduction of accumulated depreciation, depletion and amortization of $17 million and a cumulative effect of accounting change gain, net of tax, of $2 million.

Senior Note Offerings. In April 2003, we sold $400 million of 6 ¹/4% senior notes due April 2013. In January 2004, we sold $500 million of 4.9% senior notes due February 2014. In September 2004, we sold $350 million of 5% senior notes due in January 2015. In April 2005, we sold $400 million of 5.3% senior notes due June 2015. Proceeds from the senior notes were used to fund property acquisitions, redeem senior subordinated notes and reduce bank debt.

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Common Stock Transactions. In April 2003, we completed a public offering of 23 million shares of common stock at $11.25 per share, with net proceeds of approximately $248 million. The proceeds and net proceeds from the concurrent sale of senior notes were used to fund our producing property acquisition from Williams, to redeem our 8 ³/4% senior subordinated notes and to reduce bank debt. In May 2004, we completed a public offering of 32 million shares of common stock at $18.92 per share. Net proceeds of $580 million were used to reduce bank borrowings that funded our producing property acquisitions from ExxonMobil Corporation and our deposit on the ChevronTexaco acquisition.

Shelf Registration Statement. In February 2005, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities, preferred stock, common stock, or warrants to purchase debt or stock. The total face amount of securities that can be offered is $2.5 billion, 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. In April 2005, we sold $400 million of 5.3% senior notes under this registration statement.

Results of Operations

2005 Compared to 2004

For the year 2005, net income was $1.15 billion compared with net income of $508 million for 2004. Earnings for 2005 include the net after-tax effects of non-cash incentive compensation of $22 million, an $8 million derivative fair value gain, and a gain of $6 million on the exchange of producing properties. Earnings for 2004 include the net after-tax effects of stock-based incentive compensation of $55 million, special bonuses totaling $12 million related to acquisitions announced in second quarter 2004, and a $7 million derivative fair value loss.

Revenues for 2005 were $3.52 billion, or 81% higher than 2004 revenues of $1.95 billion. Gas and natural gas liquids revenue increased $1.17 billion, or 73%, because of a 23% increase in gas production and a 40% increase in gas prices from an average of $5.04 per Mcf in 2004 to $7.04 in 2005, as well as a 29% increase in natural gas liquids prices from an average price of $26.44 per Bbl in 2004 to $34.10 in 2005 and a 39% increase in natural gas liquids production (see “Significant Events, Transactions and Conditions – Product Prices – Gas” above). Increased production was attributable to the 2005 acquisition and development program.

Oil revenue increased $351 million, or 110%, because of a 72% increase in production, primarily due to acquisitions, and a 23% increase in oil prices from an average of $38.38 per Bbl in 2004 to $47.03 in 2005 (see “Significant Events, Transactions and Conditions – Product Prices – Oil” above). Gas gathering, processing and marketing revenues increased $38 million primarily because of new gathering assets included in the Antero Resources acquisition and increased volumes, margins and prices. In 2005, other revenues included a $10 million gain on exchange of producing properties, partially offset by a $3 million loss on sale of property and equipment and an additional loss of $2 million related to a lawsuit settlement. See Notes 6 and 13 to Consolidated Financial Statements.

Expenses for 2005 totaled $1.56 billion as compared with total 2004 expenses of $1.03 billion. Increased expenses are generally related to increased production from acquisitions and development and related Company growth. Production expense increased $160 million, or 65%, primarily because of increased overall production, higher labor, fuel, workover and maintenance costs and the 72% increase in oil production, which is more expensive per Mcfe to produce than natural gas. The per Mcfe production expense increase from $0.66 in 2004 to $0.84 in 2005 is primarily attributable to the increase in oil production, and also because of increased maintenance and labor costs and the higher cost of gas used for fuel. Taxes, transportation and other expense, which is generally based on product revenue, increased 76%, or $132 million, primarily because of a corresponding increase in revenues. Taxes, transportation and other per Mcfe increased 34% from $0.47 in 2004 to $0.63 in 2005 primarily due to higher product prices. Exploration expense increased $13 million primarily because of increased seismic expense and unsuccessful exploratory wells.

Depreciation, depletion and amortization (DD&A) increased $248 million, or 61%, primarily because of increased production. On an Mcfe basis, DD&A increased from $1.09 in 2004 to $1.35 in 2005 because of higher acquisition, development and infrastructure costs.

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General and administrative expense decreased $10 million, or 6%. Excluding a $55 million decrease in incentive compensation related to performance share grants to employees and the $12 million in special bonuses related to acquisitions announced in second quarter 2004, general and administrative expense increased $57 million, or 89%. Increased general and administrative expense is primarily because of additional employees and higher employee expenses related to Company growth. Excluding stock-based incentive compensation, general and administrative expense per Mcfe increased 25% from $0.20 in 2004 to $0.25 in 2005.

The derivative fair value gain for 2005 was $13 million compared to the 2004 derivative fair value loss of $12 million. The 2005 gain is primarily because of a $37 million gain related to natural gas basis swap agreements not qualifying for hedge accounting, partially offset by losses on Btu swap contracts. The derivative loss in 2004 was primarily attributable to the ineffective portion of hedge derivatives, as well as the effect of higher gas prices on the fair value of Btu swap contracts. See Note 7 to Consolidated Financial Statements.

Interest expense increased $60 million, or 63%, primarily because of a 69% increase in the weighted average borrowings to partially fund property acquisitions. Interest expense per Mcfe increased 24% from $0.25 in 2004 to $0.31 in 2005. The 2005 effective income tax rate was 36.3%, as compared with a 38.5% effective rate for 2004. The higher rate in 2004 is because of higher state income taxes. Because of increased profit in 2005 and greater utilization of net operating loss carryforwards in 2004, the current portion of total income tax expense has increased from 14% in 2004 to 34% in 2005.

2004 Compared to 2003

For the year 2004, net income was $508 million compared with net income of $288 million for 2003. Earnings for 2004 include the net after-tax effects of stock-based incentive compensation of $55 million, special bonuses totaling $12 million related to acquisitions announced in second quarter 2004, and a $7 million derivative fair value loss. Earnings for 2003 include the net after-tax effects of non-cash incentive compensation of $35 million, loss on extinguishment of debt of $6 million, a $7 million derivative fair value loss, a non-cash contingency gain of $1 million, a non-cash gain of $11 million resulting from the distribution of Cross Timbers Royalty Trust units as a dividend to common stockholders and a $2 million gain on the cumulative effect of the accounting change for adoption of SFAS No. 143 for asset retirement obligations.

Revenues for 2004 were $1.95 billion, or 64% higher than 2003 revenues of $1.19 billion. Gas and natural gas liquids revenue increased $573 million, or 55%, because of a 25% increase in gas production and a 24% increase in gas prices from an average of $4.07 per Mcf in 2003 to $5.04 in 2004, as well as a 32% increase in natural gas liquids prices from an average price of $19.99 per Bbl in 2003 to $26.44 in 2004 and a 16% increase in natural gas liquids production (see “Significant Events, Transactions and Conditions – Product Prices – Gas” above). Increased production was attributable to the 2004 acquisition and development program.

Oil revenue increased $184 million, or 136%, primarily because of a 75% increase in production, primarily due to acquisitions, and a 34% increase in oil prices from an average of $28.59 per Bbl in 2003 to $38.38 in 2004 (see “Significant Events, Transactions and Conditions – Product Prices – Oil” above). Gas gathering, processing and marketing revenues increased $5 million primarily because of higher natural gas liquids prices and margins.

Expenses for 2004 totaled $1.03 billion as compared with total 2003 expenses of $687 million. Most expenses increased in 2004 because of increased production from acquisitions and development and related Company growth. Production expense increased $81 million, or 49%, primarily because of increased production and maintenance. The production expense per Mcfe increase from $0.58 in 2003 to $0.66 in 2004 is primarily attributable to the 75% increase in oil production, which is more expensive to produce than natural gas. Taxes, transportation and other expense, which is generally based on product revenue, increased 67%, or $70 million, primarily because of significantly higher oil and gas prices and increased production. Taxes, transportation and other per Mcfe increased 27% from $0.37 in 2003 to $0.47 in 2004 primarily due to higher product prices. Exploration expense increased $9 million primarily because of 2004 seismic studies conducted in the Barnett Shale and East Texas.

Depreciation, depletion and amortization (DD&A) increased $123 million, or 43%, primarily because of increased production and higher acquisition costs. On an Mcfe basis, DD&A increased from $0.99 in 2003 to $1.09 in 2004 because of higher acquisition and development costs.

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General and administrative expense increased $57 million, or 53%, primarily because of an increase of $36 million in stock-based incentive compensation from $53 million to $89 million, of which $67 million is non-cash. General and administrative expense for the year also includes a total of $12 million in special bonuses related to the ChevronTexaco and ExxonMobil acquisitions announced in second quarter 2004 and other increased expenses from Company growth. Excluding stock-based incentive compensation, general and administrative expense per Mcfe increased 5% from $0.19 in 2003 to $0.20 in 2004.

The derivative fair value loss for 2004 was $12 million compared to the 2003 derivative fair value loss of $10 million. This loss is primarily related to the ineffective portion of hedge derivatives as well as the effect of higher gas prices on the fair value of Btu swap contracts. See Note 7 to Consolidated Financial Statements.

Interest expense increased $29 million, or 45%, primarily because of a 46% increase in the weighted average borrowings to partially fund property acquisitions. Interest expense per Mcfe increased 14% from $0.22 in 2003 to $0.25 in 2004.

Liquidity and Capital Resources

Our primary sources of liquidity are cash flow from operating activities, borrowings against the revolving credit facility, 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 2006.

Cash provided by operating activities was $2.09 billion in 2005, compared with cash provided by operating activities of $1.22 billion in 2004 and $794 million in 2003. Increased cash provided by operating activities from 2004 to 2005 and from 2003 to 2004 was primarily because of higher prices and increased production from acquisitions and development activity. Cash provided by operating activities was decreased by changes in operating assets and liabilities of $158 million in 2005 and $58 million in 2004 and was increased by changes in operating assets and liabilities of $4 million in 2003. 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 of $24 million in 2005, $11 million in 2004 and $2 million in 2003. Cash provided by operating activities is largely dependent upon the prices received for oil and gas production. As of February 2006, we have hedged approximately 50% of our first quarter 2006 projected gas production, 20% of our last nine months of projected 2006 gas production and about 35% of our projected 2006 crude oil production. See “Significant Events, Transactions and Conditions - Product Prices” above.

Financial Condition

Total assets increased 61% from $6.11 billion at December 31, 2004 to $9.86 billion at December 31, 2005, primarily because of Company growth related to acquisitions and development. As of December 31, 2005, total capitalization was $7.32 billion, of which 42.5% was long-term debt. Capitalization at December 31, 2004 was $4.64 billion, of which 44% was long-term debt. The decrease in the debt-to-capitalization ratio from year-end 2004 to 2005 is primarily because of our 2005 earnings.

Working Capital

We generally maintain low cash and cash equivalent balances because we use available funds to reduce bank debt. Short-term liquidity needs are satisfied by bank commitments under our loan agreements (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 $64 million at December 31, 2004 to working capital of $59 million at December 31, 2005. Excluding the effects of derivative fair value and deferred tax current assets and liabilities, working capital increased $19 million from a negative position of $25 million at December 31, 2004 to a negative position of $6 million at December 31, 2005. This increase is because of increased accounts receivable related to increased revenues partially offset by increased accounts payable and accrued liabilities primarily related to increased production and drilling liabilities. 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

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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 our revolving credit agreement. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated integrated energy companies. 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 counterparties that provide for offsetting payables against receivables from separate derivative contracts. Letters of credit or other appropriate forms of security are obtained as considered necessary to limit risk of loss.

Financing

In April 2005, we entered into an amended and restated five-year senior revolving credit agreement with commercial banks with an initial commitment amount of $1.5 billion, which may be increased by us, subject to certain approvals, to a maximum of $2 billion. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 60%. We use the facility for general corporate purposes and as a backup facility for possible future issuance of commercial paper. The maturity date on the facility is April 1, 2010, with annual options to request successive one-year extensions. On December 31, 2005, borrowings under the revolving credit agreement were $813 million, with unused borrowing capacity of $687 million. The weighted average interest rate of 5.2% at December 31, 2005 is based on the one-month London Interbank Offered Rate plus 0.75%.

Also in April 2005, we entered into an amendment to our $300 million term loan credit agreement. The amendment conforms the term loan covenants to the covenants contained in our revolving credit agreement.

In April 2005, we sold $400 million of 5.3% senior notes at 99.683% of par to yield 5.338% to maturity. The notes mature in June 2015 and interest is payable each June 30 and December 30. Net proceeds of approximately $395 million were used to reduce borrowings under our bank revolving credit facility.

Our outstanding debt is currently rated by both Standard & Poor’s and Moody’s. The current ratings from both agencies are investment grade.

In February 2005, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities, preferred stock, common stock or warrants to purchase debt or stock. The total face amount of securities that can be offered is $2.5 billion, 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. The April 2005 senior notes were sold under this registration statement.

Capital Expenditures

In 2005, exploration and development cash expenditures totaled $1.33 billion compared with $534 million in 2004. We have budgeted $1.7 billion for the 2006 development and exploration program and an additional $100 million for the construction of pipeline infrastructure and compression and processing facilities. As we have done historically, we expect to fund the 2006 development program with cash flow from operations. We have the flexibility to adjust our actual development expenditures in response to changes in product prices, industry conditions and the effects of our acquisition and development programs.

Raw material shortages and strong global demand for steel have continued to tighten steel supplies and cause prices to remain high. In response, we have increased our tubular inventory and have negotiated supply contracts with our vendors to support our development program. While we expect to acquire adequate supplies to complete our

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development program, a further tightening of steel supplies could restrain the program, limiting production growth and increasing development costs.

Although drilling rigs have recently been in short supply throughout the industry, we have secured or contracted to secure the rigs necessary to support our current drilling program.

While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2006. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, 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 60%, there are no restrictions under our revolving credit agreement that would affect our ability to use our remaining borrowing capacity for acquisitions of producing properties.

To date, we have not spent significant amounts to comply with environmental or safety regulations, and we do not expect to do so during 2006. 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 $0.006 per common share each quarter of 2003, $0.0075 per common share for first and second quarter 2004 and $0.0375 per common share for the remainder of 2004, and $0.05 per common share for the first three quarters of 2005. In November 2005, the Board increased the dividend rate 50% by declaring a fourth quarter 2005 dividend of $0.075 per common share.

In January 2006, the Board declared a dividend of 0.0596 units of Hugoton Royalty Trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date.

In August 2003, the Board declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each share of our common stock outstanding on September 2, 2003. The market value at the date of distribution was approximately $0.09 per common share.

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.

Income Taxes

As of December 31, 2005, we had estimated tax loss carryforwards of $67 million as a result of our acquisitions. We expect to use these carryforwards in 2006 and 2007. We have not recorded any valuation allowance because we believe we have tax planning strategies available to realize our tax loss carryforwards. We have estimated that all of our alternative minimum tax credit carryforwards were fully utilized as of December 31, 2005.

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 were 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, 2005. 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		2006		2007		2008		2009		2010		After 2010
Long-term debt	$	3,113	$	—	$	—	$	—	$	—	$	1,113	$	2,000
Operating leases		134		27		26		22		18		14		27
Drilling contracts		259		193		53		7		6		—		—
Transportation contracts		243		41		38		36		35		28		65
Derivative contract liabilities at December 31, 2005 fair value		90		90		—		—		—		—		—
Total	$	3,839	$	351	$	117	$	65	$	59	$	1,155	$	2,092

Long-Term Debt. At December 31, 2005, borrowings were $813 million under our senior bank revolving credit facility due in April 2010, as reflected in the table above. Borrowings of $300 million under our term bank facility are due in April 2010, and our senior notes, totaling $2 billion at December 31, 2005, are due in 2012 through 2015. 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. 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 July 2005, we entered into a ten-year firm transportation contract that commences upon completion of a new 264-mile pipeline spanning from North Texas to East Texas. Upon the pipeline’s completion, currently expected in 2007, we will transport gas volumes for a minimum transportation fee ranging from $2 million per month in the first year, up to approximately $4 million per month beginning in the fourth year.

In October 2005, we entered into a ten-year firm transportation agreement that commences upon completion of a new 168-mile pipeline spanning from East Texas to northeast Louisiana. Upon the pipeline’s completion, currently expected as early as the winter of 2006-2007, we will transport daily gas volumes for a minimum monthly transportation fee of $3 million plus fuel ranging from 0.8% to 1.6% depending on receipt point and other conditions.

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

Derivative Contracts. We have entered into futures contracts and swaps to hedge our exposure to oil and natural gas price fluctuations. As of December 31, 2005, the fixed prices specified by these contracts generally exceeded market prices, resulting in a net derivative fair value current asset of $103 million and long-term asset of $1 million. 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, 2005, the current liability related to such contracts was $90 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. See Note 8 to Consolidated Financial Statements.

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Post-Retirement Plans

We have a retiree medical plan that provides retired employees and directors with health care benefits similar to those provided employees. Employees and directors are eligible to receive benefits when their combined age and years of qualified service total 60, with a minimum age of 45 and a minimum of five years of service. Otherwise, retirement benefits are only provided through our defined contribution 401(k) plan. Post-retirement medical benefits are not prefunded but are paid when incurred. Our periodic benefit cost recorded for 2005 was $1 million and is expected to be approximately $1 million in 2006. Future benefit costs will be affected by fluctuations in interest rates and health care cost trends. We do not currently anticipate that retiree medical plan costs will be significant in relation to the Company’s future financial position, results of operations or cash flows.

Related Party Transactions

A firm, partially owned by one of our directors, has performed property acquisition advisory services for the Company. In February 2005, this firm was acquired by another company which continues to perform property acquisition advisory services for us, and also performed co-manager services on our April 2005 senior note offering (see “Liquidity and Capital Resources– Financing,” above). In January 2006, we announced that the Company is considering the sale of its interests in the underlying properties that are subject to the Cross Timbers Royalty Trust and Hugoton Royalty Trust net profits interests. We have engaged this director-affiliated firm to act as a broker in this potential sale. We paid this firm total fees of $5 million in 2005 and $9 million in 2004, and there were no amounts payable at December 31, 2005 or 2004. No fees were paid to this firm in 2003.

A portion of the producing properties obtained in the ChevronTexaco acquisition were considered nonstrategic and marked for disposition at the time of purchase. In August 2004, we exchanged $38 million of these properties for 19,000 net contiguous acres in our new core operating area, the Barnett Shale of North Texas, and $25 million in other consideration. This exchange was with companies either wholly or majority owned by the adult children and a brother of Bob R. Simpson, Chairman and Chief Executive Officer of the Company. In connection with this exchange, we granted these companies an option to purchase other properties included in the ChevronTexaco acquisition. On March 1, 2005, these companies purchased the properties for an adjusted purchase price of $11 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.

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. 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. 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 the estimated 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.

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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 is not currently significant since current and projected product prices are substantially higher than our net acquisition and development costs per Mcfe. Because of this, our historical impairment of producing properties has been limited to a $2 million provision in 1998, and we do not currently expect significant future impairment unless product prices were to decline and remain at levels substantially below current levels. 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.

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, 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 15 to the Consolidated Financial Statements, net upward revisions occurred to proved reserves on an Mcfe basis in 2003 and 2005, resulting in a decrease of DD&A expense of approximately 1%, or $2 million, in 2003 and 2%, or $10 million, in 2005. Net downward revisions of proved reserves on an Mcfe basis occurred in 2004, resulting in an increase in DD&A expense of approximately 2%, or $7 million. Based on proved reserves at December 31, 2005, we estimate that a 1% change in proved reserves would increase or decrease 2006 DD&A expense by approximately $7 million.

During 2005, development and exploration activities resulted in extensions, additions, discoveries and net revisions of proved reserves that were 274% of our 2005 production. Over the last five years, our proved reserve extensions, additions, discoveries and net revisions averaged 230% of our production for this period. Our proved reserve extensions, additions and discoveries in 2005 included an increase of 954 Bcfe in proved undeveloped reserves, or approximately 78% of our total extensions, additions and discoveries, which are expected to be developed within three years. Over the past five years, approximately 79% of our proved reserves extensions, additions and discoveries were proved undeveloped reserves which 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.

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The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 15 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

Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties (including removal of our offshore platforms in Alaska) 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 retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to producing 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 2005, we increased our estimated asset retirement obligation by $16 million, or approximately 10% of the asset retirement obligation at December 31, 2004, based on a review of current plugging and abandonment costs. 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.

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.

While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under 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.

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Accounting Pronouncements

In December 2004, the FASB issued 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. This pronouncement replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. We are adopting SFAS No. 123R as of January 1, 2006 and, for stock awards on and after the date, we will be using either a lattice model or a Monte Carlo simulation model to value these stock awards. We have previously recorded stock compensation pursuant to the intrinsic value method under APB Opinion No. 25, whereby no compensation was recognized for most stock option awards. We expect that stock option grants will continue to be a significant part of employee compensation, and, therefore, SFAS No. 123R will have a significant impact on our financial statements. We do not expect SFAS No. 123R to significantly change recorded compensation expense related to grants of performance and unrestricted shares. For the pro forma effect of recording compensation for all stock awards at fair value, utilizing the Black-Scholes method, see Note 1 to Consolidated Financial Statements. We are using 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 will be recognized as compensation expense in periods subsequent to December 31, 2005, based on the same valuation method used in our pro forma disclosure. As of December 31, 2005, we had 2.8 million stock options outstanding that had not yet vested, with a remaining estimated fair value of $30 million. Based on this estimated fair value, we currently anticipate stock option compensation expense for service periods after December 31, 2005 will be $11 million in both 2006 and 2007, and $8 million in 2008 related in these stock options.

In February 2006, the FASB issued FASB Staff Position 123(R)-4, Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event. FSP 123(R)-4 addresses the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. Since we do not currently issue stock awards that allow for cash settlement, the adoption of FSP 123(R)-4 is not expected to have a significant effect on our reported financial position.

In March 2005, the staff of the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107, Share-Based Payment. SAB No. 107 provides implementation guidance for SFAS No. 123R and specifies the interaction between SFAS No. 123R and certain SEC rules and regulations.

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. Under the provisions of FIN No. 47, the term conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity while the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation is required to be recognized when incurred—generally upon acquisition, construction, or development and/or through the normal operation of the asset. We have adopted FIN No. 47 as of December 31, 2005. Adoption of this pronouncement did not have a significant effect on our 2005 consolidated financial statements, and we do not expect this pronouncement to have a significant effect on our future reported financial position or earnings.

In July 2005, the Financial Accounting Standards Board issued SFAS No. 154, Accounting for Changes and Error Corrections - - A Replacement of APB Opinion No. 20 and FASB Statement No. 3. Under the provisions of SFAS No. 154, a voluntary change in accounting principle requires retrospective application to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. A change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets must be accounted for as a change in accounting estimate effected by a change in accounting principle. The guidance contained in Opinion No. 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate was not changed. We are implementing this new standard as of January 1, 2006. This standard is not expected to have a significant effect on our reported financial position or earnings.

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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. As of December 31, 2005, we had a net gas imbalance payable of $7 million of which $6 million is included as a net current receivable and $13 million is included as a net long-term payable on the consolidated balance sheets. As of December 31, 2004, we had a net gas imbalance payable of $7 million of which $7 million is included as a net current receivable and $14 million is included as a net long-term payable on the consolidated balance sheets.

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, capital budget, cash flow, drilling activity, drilling locations, acquisition and development activities and funding thereof, production and reserve growth, pricing differentials, reserve potential, operating costs, operating margins, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, 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.

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 option agreements 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 and crude oil 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 Senior Executive Vice President and Chief of Staff. 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.

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Interest Rate Risk

We are exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At December 31, 2005, our variable rate debt had a carrying value of $1.11 billion, which approximated its fair value, and our fixed rate debt had a carrying value of $2 billion and an approximate fair value of $2.04 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
December 31, 2005
Long-term debt	$	(3,109	)	$	(3,154	)	$	131
December 31, 2004
Long-term debt	$	(2,043	)	$	(2,134	)	$	115

(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 hedge a portion of our price risks associated with our crude oil and natural gas sales. As of December 31, 2005, we had outstanding gas futures contracts, swap agreements and gas basis swap agreements. These contracts and agreements had a net fair value gain of approximately $144 million at December 31, 2005 and a net fair value loss of $31 million at December 31, 2004. Of the December 31, 2005 fair value, a $90 million gain has been determined based on the exchange-trade value of NYMEX contracts, and a $54 million gain has been determined based on the broker bid and ask quotes for basis contracts. These fair values approximate amounts confirmed by the counterparties. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $103 million in the fair value of gas futures contracts and swap agreements at December 31, 2005. Outstanding oil futures contracts and differential swaps had a net fair value loss of $17 million as of December 31, 2005 and a net fair value loss of $22 million at December 31, 2004. The aggregate effect of a hypothetical 10% change in oil prices would result in a change of approximately $31 million in the fair value of these oil futures and differential swaps at December 31, 2005. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. See Note 8 to Consolidated Financial Statements.

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.

We had a physical delivery contract to sell 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. Because this gas sales contract was priced based on crude oil, which is not clearly and closely associated with natural gas prices, it was accounted for as a non-hedge derivative financial instrument. This contract (referred to as the Enron Btu swap contract) was terminated in December 2001 in conjunction with the bankruptcy filing of Enron Corporation. In November 2001, we entered derivative contracts to effectively defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. The net fair value loss on these contracts was $23 million at December 31, 2005 and $19 million at December 31, 2004. As of February 28, 2006, we terminated the remaining portion of these contracts, resulting in total expected payments to the counterparty of approximately $7 million in first quarter 2006. Since the contracts are not hedge derivatives, changes in their fair value are recognized in our consolidated income statement as a derivative fair value gain or loss.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     

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

	Page
Consolidated Balance Sheets	48
Consolidated Income Statements	49
Consolidated Statements of Cash Flows	50
Consolidated Statements of Stockholders’ Equity	51
Notes to Consolidated Financial Statements	52
Selected Quarterly Financial Data (Note 14 to Consolidated Financial Statements)	79
Information about Oil and Gas Producing Activities (Note 15 to Consolidated Financial Statements)	80
Management’s Report on Internal Control over Financial Reporting	84
Reports of Independent Registered Public Accounting Firm	85

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, 2005.

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 the design and operation 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. 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, 2005 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. OTHER INFORMATION

None.

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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 29, 2006.

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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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, 2005 and 2004	48
		Consolidated Income Statements for the years ended December 31, 2005, 2004 and 2003	49
		Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	50
		Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003	51
		Notes to Consolidated Financial Statements	52
		Management’s Report on Internal Control over Financial Reporting	84
		Reports of Independent Registered Public Accounting Firm	85
	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 88 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.

47

XTO ENERGY INC.

Consolidated Balance Sheets

	December 31
(in millions, except shares)	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	2		$	10
Accounts receivable, net		644			333
Derivative fair value		193			15
Current income tax receivable		35			9
Deferred income tax benefit		—			22
Other		69			48
Total Current Assets		943			437
Property and Equipment, at cost – successful efforts method:
Proved properties		9,979			6,871
Unproved properties		283			61
Other		278			106
Total Property and Equipment		10,540			7,038
Accumulated depreciation, depletion and amortization		(2,032	)		(1,414	)
Net Property and Equipment		8,508			5,624
Derivative fair value		1			—
Acquired gas gathering contracts, net of amortization		132			—
Goodwill		213			—
Other		60			49
Total Other Assets		406			49
TOTAL ASSETS	$	9,857		$	6,110
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	739		$	415
Payable to royalty trusts		13			10
Derivative fair value		90			76
Deferred income tax payable		38			—
Other		4			—
Total Current Liabilities		884			501
Long-term Debt		3,109			2,043
Other Long-term Liabilities:
Derivative fair value		—			11
Deferred income taxes payable		1,390			756
Asset retirement obligation		219			160
Other		46			40
Total Other Long-term Liabilities		1,655			967
Commitments and Contingencies (Note 6)
Stockholders’ Equity:
Common stock ($0.01 par value, 500,000,000 shares authorized, 365,220,597 and 348,428,489 shares issued)		4			3
Additional paid-in capital		1,865			1,410
Treasury stock, at cost (1,655,413 and 1,250,266 shares)		(39	)		(25	)
Retained earnings		2,311			1,240
Accumulated other comprehensive income (loss)		68			(29	)
Total Stockholders’ Equity		4,209			2,599
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	9,857		$	6,110

See accompanying notes to consolidated financial statements.

48

XTO ENERGY INC.

Consolidated Income Statements

	Year Ended December 31
(in millions, except per share data)	2005			2004			2003
REVENUES
Gas and natural gas liquids	$	2,787		$	1,613		$	1,040
Oil and condensate		670			319			135
Gas gathering, processing and marketing		56			18			13
Other		6			(2	)		1
Total Revenues		3,519			1,948			1,189
EXPENSES
Production		406			246			165
Taxes, transportation and other		306			174			104
Exploration		24			11			2
Depreciation, depletion and amortization		655			407			284
Accretion of discount in asset retirement obligation		12			8			5
Gas gathering and processing		11			6			9
General and administrative		155			165			108
Derivative fair value (gain) loss		(13	)		12			10
Total Expenses		1,556			1,029			687
OPERATING INCOME		1,963			919			502
OTHER (INCOME) EXPENSE
Gain on distribution of royalty trust units		—			—			(16	)
Loss on extinguishment of debt		—			—			10
Interest expense, net		153			93			64
Total Other Expense		153			93			58
INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		1,810			826			444
INCOME TAX EXPENSE		658			318			158
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		1,152			508			286
Cumulative effect of accounting change, net of tax		—			—			2
NET INCOME	$	1,152		$	508		$	288
EARNINGS PER COMMON SHARE
Basic:
Net income before cumulative effect of accounting change	$	3.21		$	1.53		$	0.95
Cumulative effect of accounting change, net of tax		—			—			0.01
Net income	$	3.21		$	1.53		$	0.96
Diluted:
Net income before cumulative effect of accounting change	$	3.15		$	1.51		$	0.94
Cumulative effect of accounting change, net of tax		—			—			0.01
Net income	$	3.15		$	1.51		$	0.95
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		358.4			332.9			299.7

See accompanying notes to consolidated financial statements.

49

XTO ENERGY INC.

Consolidated Statements of Cash Flows

	Year Ended December 31
(in millions)	2005			2004			2003
OPERATING ACTIVITIES
Net income	$	1,152		$	508		$	288
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		655			407			284
Accretion of discount in asset retirement obligation		12			8			5
Non-cash incentive compensation		34			67			53
Deferred income tax		436			273			158
Gain on distribution of royalty trust units		—			—			(16	)
Non-cash derivative fair value (gain) loss		(39	)		6			10
Cumulative effect of accounting change, net of tax		—			—			(2	)
Loss on extinguishment of debt		—			—			10
Gain on disposition of property		(7	)		—			—
Other non-cash items		9			6			—
Changes in operating assets and liabilities net of effects of acquisitions of corporations (a)		(158	)		(58	)		4
Cash Provided by Operating Activities		2,094			1,217			794
INVESTING ACTIVITIES
Proceeds from sale of property and equipment		17			25			—
Property acquisitions, including acquisitions of corporations		(1,407	)		(1,905	)		(654	)
Development and capitalized exploration costs		(1,304	)		(523	)		(439	)
Other property and asset additions		(214	)		(115	)		(42	)
Cash Used by Investing Activities		(2,908	)		(2,518	)		(1,135	)
FINANCING ACTIVITIES
Proceeds from long-term debt		3,825			3,884			1,835
Payments on long-term debt		(2,977	)		(3,093	)		(1,701	)
Net proceeds from common stock offering		—			580			248
Dividends		(67	)		(20	)		(7	)
Senior note offering and debt offering costs		(5	)		(14	)		(8	)
Proceeds from exercise of stock options and warrants		73			8			16
Payments upon exercise of stock options		(20	)		(13	)		(18	)
Subordinated note redemption costs		—			—			(7	)
Purchases of treasury stock and other		(23	)		(28	)		(25	)
Cash Provided by Financing Activities		806			1,304			333
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(8	)		3			(8	)
Cash and Cash Equivalents, January 1		10			7			15
Cash and Cash Equivalents, December 31	$	2		$	10		$	7
(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	(258	)	$	(132	)	$	(50	)
Other current assets		(47	)		(40	)		(5	)
Other operating assets and liabilities		(3	)		4			1
Current liabilities		150			110			58
	$	(158	)	$	(58	)	$	4

See accompanying notes to consolidated financial statements.

50

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, 2002	$	3	$	533		$	(77	)	$	510		$	(61	)	$	908
Net income		—		—			—			288			—			288
Change in hedge derivative fair value, net of applicable income tax of $66		—		—			—			—			(122	)		(122	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of $71		—		—			—			—			130			130
Comprehensive income																296
Issuance/vesting and forfeiture of performance shares		—		51			(23	)		—			—			28
Stock option exercises, including income tax benefits		—		23			—			—			—			23
Treasury stock purchases		—		—			(2	)		—			—			(2	)
Common stock offering		—		248			—			—			—			248
Fair value of royalty trust unit distribution		—		—			—			(28	)		—			(28	)
Common stock dividends ($0.024 per share)		—		—			—			(7	)					(7	)
Cancellation of treasury stock		—		(102	)		102			—			—			—
Balances, December 31, 2003		3		753			—			763			(53	)		1,466
Net income		—		—			—			508			—			508
Change in hedge derivative fair value, net of applicable income tax of $51		—		—			—			—			(85	)		(85	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of $64		—		—			—			—			109			109
Comprehensive income																532
Issuance/vesting of performance shares		—		64			(24	)		—			—			40
Stock option exercises, including income tax benefits		—		13			—			—			—			13
Treasury stock purchases		—		—			(1	)		—			—			(1	)
Common stock offering		—		580			—			—			—			580
Common stock dividends ($0.09 per share)		—		—			—			(31	)		—			(31	)
Balances, December 31, 2004		3		1,410			(25	)		1,240			(29	)		2,599
Net income		—		—			—			1,152			—			1,152
Change in hedge derivative fair value, net of applicable income tax of $27		—		—			—			—			(48	)		(48	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of $81		—		—			—			—			145			145
Comprehensive income																1,249
Issuance/vesting of performance shares		—		33			—			—			—			33
Stock option and warrant exercises, including income tax benefits		—		75			—			—			—			75
Treasury stock purchases		—		—			(14	)		—			—			(14	)
Issuance of common stock and warrants for acquisition of corporation		1		347			—			—			—			348
Common stock dividends ($0.225 per share)		—		—			—			(81	)		—			(81	)
Balances, December 31, 2005	$	4	$	1,865		$	(39	)	$	2,311		$	68		$	4,209

See accompanying notes to consolidated financial statements.

51

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. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation.

All common stock shares and per share amounts in the accompanying financial statements have been adjusted for the four-for-three stock split effected on March 15, 2005, the five-for-four stock split effected March 17, 2004 and the four-for-three stock split effected on March 18, 2003.

We are an independent oil and gas company with production and exploration concentrated in the southwestern and central United States. We also gather, process and market gas, transport and market oil and conduct other activities directly related to our oil and gas producing activities.

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 properties from other oil and gas companies. Proved properties balances include costs of $391 million at December 31, 2005 and $139 million at December 31, 2004 related to wells in process of drilling. Drill well costs are transferred to proved properties generally within one month of the well completion date. As of December 31, 2005, capitalized costs totaled approximately $13 million for exploratory wells pending determination of proved reserves. No exploratory wells have been pending determination of proved reserves for more than one year. Inventory held for future use on our producing properties totaled $53 million at December 31, 2005 and $35 million at December 31, 2004, and is included in other current assets on the consolidated balance sheet.

Depreciation, depletion and amortization 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 long-term assets 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 existing proved reserve and production information and pricing assumptions that management believes are reasonable. Impairment of individually significant unproved properties is assessed on a property-by-property basis, and impairment of other unproved properties is assessed and amortized on an aggregate basis.

52

In December 2004, the Financial Accounting Standards Board issued SFAS No. 153, Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29, which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged, and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion No. 29 previously exempted exchanges of similar productive assets from fair value accounting, subject to recording an impairment loss. We adopted the provisions of SFAS No. 153 beginning July 1, 2005, and, based on the fair value of properties exchanged, we recognized a $10 million gain on the exchange of nonmonetary assets during 2005 (Note 13).

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.

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 own 54.3% of Hugoton Royalty Trust, which is the portion we retained following our sale of units in 1999 and 2000. The cost of our interest in Hugoton Royalty Trust is included in proved properties.

We owned 22.7% of Cross Timbers Royalty Trust as a result of units we purchased on the open market from 1996 through 1998. In August 2003, our Board of Directors declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each share of our common stock outstanding in September 2003. Our Cross Timbers Royalty Trust units were distributed to our common stockholders in September 2003, after which we no longer own any Cross Timbers Royalty Trust units. We recorded this dividend at $28 million, the fair market value of the units on the date of distribution, resulting in a gain on distribution of $16 million.

Amounts due the trusts, net of amounts retained by our ownership of trust units, are deducted from our revenues, taxes, production expenses and development costs.

See note 16.

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 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.

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

53

below). Other assets are presented net of accumulated amortization of $19 million at December 31, 2005 and $13 million at December 31, 2004.

In accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, we have determined that a portion of the purchase price of the Antero Resources Corporation acquisition (Note 13) is allocable to gas gathering contracts and goodwill. Gas gathering contracts are associated with the pipeline acquired, and the value of $140 million has been 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. As of December 31, 2005, accumulated amortization of acquired gas gathering contracts was $8 million. Amortization expense is expected to be approximately $7 million to $12 million annually from 2006 through 2010, depending on Barnett Shale production.

Goodwill of $213 million represents the excess of the purchase price paid for Antero Resources over the 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 in the fourth quarter.

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, 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)
	Realized	Reported in the Consolidated Income Statements and classified based on the hedged item (e.g., gas revenue, oil revenue or interest expense)

54

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 2005, 2004 and 2003, there were no gains or losses reclassified into earnings as a result of the discontinuance of hedge accounting treatment for any of our derivitives.

Physical delivery contracts that are not expected to be net cash settled are deemed to be normal sales and therefore are not accounted for as derivatives. 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 (Note 8).

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. As of December 31, 2005, we had a net gas imbalance payable of $7 million of which $6 million is included as a net current receivable and $13 million is included as a net long-term payable on the consolidated balance sheets. As of December 31, 2004, we had a net gas imbalance payable of $7 million of which $7 million is included as a net current receivable and $14 million included as a net long-term payable on the consolidated balance sheets.

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. Gas processing and marketing revenues are recorded net of cost of gas sold of $185 million for 2005, $99 million for 2004 and $66 million for 2003. These amounts are net of intercompany eliminations.

Other Revenues

Other revenues result from and are related to our ongoing major operations. These revenues include various gains and losses, including from lawsuits and other disputes, as well as from other than 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.

55

Interest

Interest expense includes amortization of deferred debt costs and is presented net of interest income of $1 million or less in 2005, 2004 and 2003, and net of capitalized interest of $6 million in 2005, $3 million in 2004 and $2 million in 2003. Interest is capitalized as producing 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 $32 million at December 31, 2005 and $27 million at December 31, 2004.

Stock-Based Compensation

In accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, no compensation is recorded for stock options or other stock-based awards that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on the grant date. Compensation related to performance share grants with time vesting conditions is based on the fair value of the award at the grant date and recognized over the vesting period. Compensation related to performance shares with price target vesting is recognized over the estimated vesting period if management believes it is able to reasonably estimate a vesting date or, if earlier, when the price target is reached. See New Accounting Pronouncements below and Note 12.

As required to be disclosed pursuant to SFAS No. 148, Accounting for Stock-Based Compensation–Transition and Disclosure, the following is the pro forma effect of recording stock-based compensation at the estimated fair value of awards on the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation:

	Year Ended December 31
(in millions, except per share data)	2005			2004			2003
Net income as reported	$	1,152		$	508		$	288
Add stock-based compensation expense included in the income statement, net of related tax effects		22			56			34
Deduct stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects		(73	)		(77	)		(33	)
Pro forma net income	$	1,101		$	487		$	289
Earnings per common share:
Basic - as reported	$	3.21		$	1.53		$	0.96
Basic - pro forma	$	3.07		$	1.46		$	0.96
Diluted - as reported	$	3.15		$	1.51		$	0.95
Diluted - pro forma	$	3.01		$	1.45		$	0.95

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.

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. All of our assets are located in the United States, and all revenues are attributable to United States customers.

56

Our production is sold to various purchasers, based on their credit rating and location of our production. For the year ended December 31, 2005, sales to each of three purchasers were approximately 23%, 14% and 14% of total revenues. For the year ended December 31, 2004, sales to each of two purchasers were approximately 20% and 13% of total revenues. For the year ended December 31, 2003, sales to each of three purchasers were approximately 25%, 15% and 12% 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. We currently have greater concentrations of credit with several A- or better rated integrated energy companies.

New Accounting Pronouncements

In December 2004, the FASB issued 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. This pronouncement replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. We are adopting SFAS No. 123R as of January 1, 2006 and, for stock awards on and after that date, we will be using either a lattice model or a Monte Carlo simulation model to value these stock awards. We have previously recorded stock compensation pursuant to the intrinsic value method under APB Opinion No. 25, whereby no compensation was recognized for most stock option awards. We expect that stock option grants will continue to be a significant part of employee compensation, and, therefore, SFAS No. 123R will have a significant impact on our financial statements. We do not expect SFAS No. 123R to significantly change recorded compensation expense related to grants of performance and unrestricted shares. For the pro forma effect of recording compensation for all stock awards at fair value, utilizing the Black-Scholes method, see Stock-Based Compensation above. We are using 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 will be recognized as compensation expense in periods subsequent to December 31, 2005, based on the same valuation method used in our pro forma disclosure. As of December 31, 2005, we had 2.8 million stock options outstanding that had not yet vested, with a remaining estimated fair value of $30 million. Based on this estimated fair value, we currently anticipate stock option compensation expense for service periods after December 31, 2005 will be $11 million in both 2006 and 2007, and $8 million in 2008 related to these stock options.

In February 2006, the FASB issued FASB Staff Position 123(R)-4, Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event. FSP 123(R)-4 addresses the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. Since we do not currently issue stock awards that allow for cash settlement, the adoption of FSP 123(R)-4 is not expected to have a significant effect on our reported financial position.

In March 2005, the staff of the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107, Share-Based Payment. SAB No. 107 provides implementation guidance for SFAS No. 123R and specifies the interaction between SFAS No. 123R and certain SEC rules and regulations.

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. Under the provisions of FIN No. 47, the term conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity while the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation is required to be recognized when incurred—generally upon acquisition, construction, or development and/or through the normal operation of the asset. We have adopted FIN No. 47 as of December 31, 2005. Adoption of this pronouncement did not have a significant effect on our 2005 consolidated financial statements, and we do not expect this pronouncement to have a significant effect on our future reported financial position or earnings.

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In July 2005, the Financial Accounting Standards Board issued SFAS No. 154, Accounting for Changes and Error Corrections - A Replacement of APB Opinion No. 20 and FASB Statement No. 3. Under the provisions of SFAS No. 154, a voluntary change in accounting principle requires retrospective application to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. A change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets must be accounted for as a change in accounting estimate effected by a change in accounting principle. The guidance contained in Opinion No. 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate was not changed. We are implementing this new standard as of January 1, 2006. This standard is not expected to have a significant effect on our reported financial position or earnings.

2. Related Party Transactions

A firm, partially owned by one of our directors, has performed property acquisition advisory services for the Company. In February 2005, this firm was acquired by another company which continues to perform property acquisition advisory services for us, and also performed co-manager services on our April 2005 senior note offering (see Note 3). We paid this firm total fees of $5 million in 2005 and $9 million in 2004, and there were no amounts payable at December 31, 2005 or 2004. No fees were paid to this firm in 2003. The Company has engaged this firm to act as a broker in the potential sale of its property interests underlying the royalty trusts’ net profits interests (Note 16).

A portion of the producing properties obtained in the ChevronTexaco acquisition (Note 13) were considered nonstrategic and marked for disposition at the time of purchase. In August 2004, we exchanged $38 million of these properties for 19,000 net contiguous acres in our new core operating area, the Barnett Shale of North Texas, and $25 million in other consideration. This exchange was with companies either wholly or majority owned by the adult children and a brother of Bob R. Simpson, Chairman and Chief Executive Officer of the Company. In connection with this exchange, we granted these companies an option to purchase other properties included in the ChevronTexaco acquisition. In March 2005, these companies purchased the properties for an adjusted purchase price of $11 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.

3. Debt

Our long-term debt consists of the following:

	December 31
(in millions)	2005		2004
Bank debt:
Revolving credit agreement due April 2010, 5.2% at December 31, 2005	$	813	$	146
Term loan due April 2010, 5.1% at December 31, 2005		300		300
Senior notes:
7 1/2%, due April 15, 2012		350		350
6 1/4%, due April 15, 2013		400		400
4.9%, due February 1, 2014, net of discount		497		497
5%, due January 31, 2015, net of discount		350		350
5.3% due June 30, 2015, net of discount		399		—
Total long-term debt	$	3,109	$	2,043

Other than borrowings under our revolving credit agreement and term loan, no debt matures within five years. Before the April 2010 maturity, we may renegotiate the revolving credit agreement and term loan to increase the borrowing commitment and extend the maturity.

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Bank Debt

In April 2005, we entered into an amended and restated five-year senior revolving credit agreement with commercial banks with an initial commitment amount of $1.5 billion, which may be increased by us, subject to certain approvals, to a maximum of $2 billion. The maturity date on the facility is April 1, 2010, with annual options to request successive one-year extensions. Interest rates are currently based on LIBOR plus 0.75%. 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 was 0.125% at February 2006. The agreement requires us to maintain a ratio of debt-to-total capitalization of not more the 60%. We use the facility for general corporate purposes and as a backup facility for possible future issuance of commercial paper. On December 31, 2005, borrowings under the revolving credit agreement were $813 million, with unused borrowing capacity of $687 million. The weighted average interest rate on bank debt was 4.3% during 2005 and 2.6% during 2004 and 2003.

Also in April 2005, we entered into an amendment to our $300 million term loan credit agreement. The amendment conforms the term loan covenants to the covenants contained in our revolving credit agreement.

We have entered into unsecured and uncommitted lines of credit with commercial banks in the amount of $15 million in June 2005 and $100 million in February 2006.

Senior Notes

In April 2003, we sold $400 million of 6 ¹/4% senior notes due in April 2013, with interest payable each April 15 and October 15. Net proceeds of $393 million, combined with proceeds from the concurrent sale of common stock (Note 9), were used to finance our producing property acquisition from units of Williams of Tulsa, Oklahoma, to redeem our 8 ³/4% senior subordinated notes and to reduce bank debt.

In January 2004, we sold $500 million of 4.9% senior notes that were issued at 99.34% of par to yield 4.98% to maturity. The notes mature in February 2014 and interest is payable each February 1 and August 1. Net proceeds of $490 million were used to fund our January 2004 property acquisitions of $243 million (Note 13) and to reduce bank debt.

In September 2004, we sold $350 million of 5% senior notes that were issued at 99.918% of par to yield 5.011% to maturity. The notes are due in January 2015 and interest is payable each January 31 and July 31. Net proceeds of $347 million were used to reduce bank debt associated with our 2004 acquisitions.

In April 2005, we sold $400 million of 5.3% senior notes at 99.683% of par to yield 5.338% to maturity. The notes mature in June 2015 and interest is payable each June 30 and December 30. Net proceeds of approximately $395 million were used to reduce borrowings under our bank revolving credit facility.

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 0.15%.

Subordinated Debt

In October 1997, we sold $175 million of 8 ³/4% senior subordinated notes due November 2009. Under the terms of an agreement with a bank counterparty, we purchased and canceled $12 million of these notes in November 2002. In May 2003, we redeemed the remaining $163 million at a redemption price of 104.375%, or $170 million, plus accrued interest of approximately $1 million. As a result of these transactions, we recorded a loss on extinguishment of debt of $10 million in 2003.

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4. Income Tax

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

(in millions)	2005		2004		2003
Income tax expense at the federal statutory rate (35%)	$	634	$	289	$	156
State and local income taxes and other		24		29		2
Income tax expense	$	658	$	318	$	158
Components of income tax expense are as follows:
(in millions)	2005		2004		2003
Current income tax	$	222	$	45	$	—
Deferred income tax		419		185		148
Net operating loss carryforwards used		17		88		10
Income tax expense	$	658	$	318	$	158

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 $38 million and a long-term liability of $1.39 billion at December 31, 2005 and as a current asset of $22 million and a long-term liability of $756 million at December 31, 2004. Significant components of net deferred tax assets and liabilities are:

	December 31
(in millions)	2005			2004
Deferred tax assets:
Net operating loss carryforwards	$	24		$	—
Alternative minimum tax credit carryforwards		—			38
Derivative fair value loss		35			31
Other		18			11
Total deferred tax assets		77			80
Deferred tax liabilities:
Property and equipment		(1,426	)		(802	)
Derivative fair value gain		(70	)		(5	)
Other		(9	)		(7	)
Total deferred tax liabilities		(1,505	)		(814	)
Net deferred tax liabilities	$	(1,428	)	$	(734	)

As of December 31, 2005, we had estimated tax loss carryforwards of $67 million as a result of our 2005 acquisitions. We expect to use these carryforwards in 2006 and 2007. We have not recorded any valuation allowance because we believe we have tax planning strategies available to realize our tax loss carryforwards.

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5. Asset Retirement Obligation

Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations, recording a cumulative effect of accounting change gain, net of tax, of $2 million. 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 (including removal of our offshore platforms in Alaska) 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, 2005 and 2004:

(in millions)	2005			2004
Asset retirement obligation, January 1	$	160		$	93
Revisions in the estimated cash flows		16			6
Liability incurred upon acquiring and drilling wells		37			54
Liability settled upon plugging and abandoning wells		(2	)		(1	)
Accretion of discount expense		12			8
Asset retirement obligation, December 31		223			160
Less current portion		(4	)		—
Asset retirement obligation, long term	$	219		$	160

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, 2005, minimum future lease payments for all noncancelable lease agreements (including the sale and operating leaseback agreements described below) were as follows:

(in millions)
2006	$	27
2007		26
2008		22
2009		18
2010		14
Remaining		27
Total	$	134

Amounts incurred under operating leases (including renewable monthly leases) were $41 million in 2005, $35 million in 2004 and $32 million in 2003.

In March 1996, we sold our Tyrone gas processing plant and related gathering system for $28 million and entered an agreement to lease the facility from the buyers for an initial term of eight years at annual rentals of $4 million with fixed renewal options for an additional 13 years at a total cost of $8 million. This transaction was recorded as a sale and operating leaseback, with no gain or loss on the sale. In September 2005, we extended the lease until March 2007.

In November 1996, we sold a gathering system in Major County, Oklahoma for $8 million and entered an agreement to lease the facility from the buyers for an initial term of eight years, with fixed renewal options for an additional ten years. This transaction was recorded as a sale and operating leaseback, with a deferred gain of $3 million on the sale. The deferred gain is amortized over the lease term based on pro rata rentals and is recorded in other long-term liabilities in the accompanying consolidated balance sheets. The deferred gain balance at December 31, 2005 was less than $1 million. In November 2004, we extended the lease until November 2006.

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Under each of the above sale and leaseback transactions, we do not have the right or option to purchase, nor does the lessor have the obligation to sell, the facility at any time. However, if the lessor decides to sell the facility at the end of the initial term or any renewal period, the lessor must first offer to sell it to us at its fair market value. Additionally, we have the right of first refusal of any third party offers to buy the facility after the initial term.

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, 2005, maximum commitments under our transportation contracts were as follows:

(in millions)
2006	$	41
2007		38
2008		36
2009		35
2010		28
Remaining		65
	$	243

In July 2005, we entered into a ten-year firm transportation contract that commences upon completion of a new 264-mile pipeline spanning from North Texas to East Texas. Upon the pipeline’s completion, currently expected in 2007, we will transport gas volumes for a minimum transportation fee ranging from $2 million per month in the first year, up to approximately $4 million per month beginning in the fourth year.

In October 2005, we entered into a ten-year firm transportation agreement that commences upon completion of a new 168-mile pipeline spanning from East Texas to northeast Louisiana. Upon the pipeline’s completion, currently expected as early as the winter of 2006-2007, we will transport daily gas volumes of approximately 600 million cubic feet and will pay a minimum monthly transportation fee of $3 million plus fuel ranging from 0.8% to 1.6% depending on receipt point and other conditions.

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

Guarantees

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. As of December 31, 2005, we estimate the total contingent payable under these guarantees does not exceed $5 million.

Employment Agreements

Our Chairman and Chief Executive Officer has a year-to-year employment agreement with us. The agreement is automatically renewed each year-end unless terminated by either party upon thirty days notice prior to each December 31. Under this agreement, the officer receives a minimum annual salary of $625,000, and is entitled to participate in any incentive compensation programs administered by the Board of Directors. The agreement also provides that, in the event the officer terminates his employment for good reason, as defined in the agreement, we terminate the employee without cause or 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 any special bonuses or other compensation required to be designated as a bonus under the rules and regulations of the Securities and Exchange

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Commission. In addition, the officer is 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.

Commodity Commitments

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

Drilling Contracts

As of December 31, 2005, we have contracts with various drilling contractors to use 71 drilling rigs in 2006 with terms of up to three years and minimum future commitments of $193 million in 2006, $53 million in 2007, $7 million in 2008 and $6 million in 2009. Early termination of these contracts at December 31, 2005 would have required us to pay maximum penalties of $103 million. We do not expect to pay any early termination penalties related to these contracts.

Litigation

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U.S. District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against the Company and certain of our subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other companies have been 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. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion occurred in March 2005, and in May 2005, the special master, who was appointed by the district judge to expedite matters and make recommendations to the district judge in the case, issued a report and recommendation to dismiss the case against some of the defendants but to retain jurisdiction of the case involving us and other defendants. We and the other defendants filed motions to modify the special master’s report, requesting the district judge to also dismiss the case as to us and other defendents. The district judge heard oral arguments on December 9, 2005, as to all motions seeking adoption, modification or reversal of the special masters report, and we are awaiting the decision of the district court. While we are unable to predict the 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 June 2001, we were served with a lawsuit styled Price, et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against us and one of our subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims to cover all oil and gas leases (other than the federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas delivered into their pipelines, resulting in underpayments to the plaintiffs. The plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of action. The amount of damages was not specified in the complaint. In February 2002, we, along with one of our subsidiaries, were dismissed from the

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suit and another subsidiary of the Company was added. A hearing was held in January 2003, and the court held that a class should not be certified. The plaintiffs’ counsel has filed an amended class action petition, which reduces the proposed class to only royalty owners, reduces the claims to mismeasurement of volume only, conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court held an evidentiary hearing in April 2005 to determine whether the amended class should be certified, and we are awaiting the decision of the court. While we are unable to predict the 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 August 5, 2003, the Price plaintiffs served one of our subsidiaries with a new original class action petition styled Price, et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against natural gas pipeline owners and operators. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas royalty owners either from whom the defendants had purchased natural gas or measured natural gas since January 1, 1974 to the present. The new petition alleges the same improper analysis of gas heating content that had previously been alleged in the Price case discussed above until it was removed from the case by the filing of the amended class action petition. In all other respects, the new petition appears to be identical to the amended class action petition in that it has a proposed class of only royalty owners, alleges conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court held an evidentiary hearing in April 2005 to determine whether the amended class should be certified, and we are awaiting the decision of the court. The amount of damages was not specified in the complaint. While we are unable to predict the 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 2004, we were served with a lawsuit styled Burkett, et al. v. J.M. Huber Corp. and XTO Energy Inc. The action was filed in the District Court of La Plata County, Colorado against us and J.M. Huber Corporation. The plaintiffs alleged that the defendants deducted in their calculation of royalty payments expenses of compression, gathering, treatment, dehydration, or other costs to place the natural gas produced in a marketable condition at a marketable location. The plaintiffs sought to represent a class consisting of all lessors and their successors in interest who own or have owned mineral interests located in La Plata County, Colorado and that were leased to or operated by Huber or us, except to the extent that the lessors or their successors expressly authorized deduction of post-production expenses from royalties. We acquired the interests of Huber in producing properties in La Plata County effective October 1, 2002, and assumed the responsibility for certain liabilities of Huber prior to the effective date, which included liability for post-production deductions made by Huber. As of December 31, 2004, based on an evaluation of available information, we accrued a $3.1 million estimated liability for this claim in our consolidated financial statements. On February 17, 2005, we agreed to a settlement of $5.1 million, resulting in an additional loss of approximately $2 million that was recorded in our 2005 consolidated income statement. On June 21, 2005, the court entered a final judgment approving the settlement on a class-wide basis. The final judgment releases XTO from any royalty claims concerning post-production costs relating to the properties. No appeals from the final judgment were filed, so the litigation is concluded. We paid this settlement in August 2005.

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, which we are discussing with them.

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.

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Other

On April 3, 2005, the Board of Directors accepted the retirement of Steffen E. Palko from the Board effective April 1, 2005, and as President effective May 1, 2005, and we entered a consulting and noncompetition agreement with him. Under the terms of this agreement, Mr. Palko is entitled to a $4 million bonus related to his performance as an employee and $2 million related to a noncompetition period of 18 months. Mr. Palko was paid $3 million on May 1 and the remaining $3 million is payable on November 1, 2006. The $4 million bonus was expensed ratably from January through April 2005 and the $2 million related to the noncompetition period is being expensed ratably from May 2005 through October 2006. We also pay Mr. Palko $65,000 per month for his consulting services, office space and other expenses for 18 months, subject to termination by either party upon thirty days’ notice.

In May 2005, in recognition of the Chairman and Chief Executive Officer of the Company, in support of local education and to benefit our ongoing oil and gas business endeavors in this area, the Board of Directors approved a pledge to contribute $3.1 million to a school in Fort Worth. Of this amount, $3 million is to be used for capital improvements. The remaining $100,000 is to be used for a scholarship fund for economically disadvantaged students. This pledge is to be paid annually in four equal installments of $775,000, the first of which was paid in June 2005. As of December 31, 2005, the total contribution has been expensed as general and administrative expense, and the remaining $2.3 million pledge payable is included in accounts payable and accrued liabilities.

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.

To secure tubular goods required to support our drilling program, we have entered a contract with a tubular goods supplier who commits to deliver, at market prices, our next quarter’s tubular products ordered by us at least 30 days prior to the beginning of the quarter. There is no minimum order requirement, and our order is subject to modification by the supplier. The contract is cancelable by either party with at least 60 days notice prior to the beginning of the next calendar quarter.

Through December 2005, we have acquired approximately 160,000 undeveloped net acres in the Barnett Shale of North Texas. Many of these net acres are generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding two 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.

In addition to drilling four wells to earn our 50% working interest in the 69,500 acres granted under our Piceance Basin farm-in agreement with ExxonMobil Corporation (Note 13), we are required to continue to drill wells periodically to retain the undeveloped leasehold until the entire acreage position has been drilled.

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 to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the financial statements.

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

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portion 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. Btu swap contracts do not qualify for hedge accounting.

Btu Swap Contracts

In 1995, we entered a contract to sell gas based on crude oil pricing, also referred to as the Enron Btu swap contract. This contract was terminated as a result of the Enron bankruptcy in December 2001. Because the contract pricing was not clearly and closely associated with natural gas prices, it was considered a non-hedge derivative financial instrument, with changes in fair value recorded as a derivative (gain) loss in the income statement.

Prior to termination of the Enron Btu swap contract, we entered Btu swap contracts with another counterparty to effectively defer until August 2005 through July 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. Changes in fair value of these contracts are recorded as a derivative (gain) loss in the income statement. In March 2002, we terminated some of these contracts with maturities of May through December 2002 and received $7 million from the counterparty.

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 expected payments to the counterparty of approximately $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 crude oil and natural gas 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. We have hedged a portion of our exposure to variability in future cash flows from natural gas and crude oil sales through December 2006. 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)	2005			2004			2003
Change in fair value of Btu swap contracts	$	23		$	1		$	5
Change in fair value of other derivatives that do not qualify for hedge accounting		(37	)		(1	)		(2	)
Ineffective portion of derivatives qualifying for hedge accounting		1			12			7
Derivative fair value (gain) loss	$	(13	)	$	12		$	10

The gains in 2005 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.

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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, 2005 and 2004. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:

	Asset (Liability)
	December 31, 2005						December 31, 2004
(in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Derivative Assets:
Fixed-price natural gas futures and swaps	$	194		$	194		$	11		$	11
Fixed-price crude oil futures and differential swaps		—			—			4			4
Derivative Liabilities:
Fixed-price natural gas futures and swaps		(50	)		(50	)		(42	)		(42	)
Fixed-price crude oil futures and differential swaps		(17	)		(17	)		(26	)		(26	)
Btu swap contracts		(23	)		(23	)		(19	)		(19	)
Net derivative asset (liability)	$	104		$	104		$	(72	)	$	(72	)
Long-term debt	$	(3,109	)	$	(3,154	)	$	(2,043	)	$	(2,134	)

The fair value of futures, swap and differential agreements is estimated based on the exchange-trade value of NYMEX, basis and differential contracts and market commodity prices for the applicable future periods. The fair value of bank borrowings approximates their carrying value because of short-term interest rate maturities. The fair value of senior notes is based on current market quotes.

Changes in fair value of derivative assets and liabilities are the result of changes in oil and gas prices. Futures and swaps are generally designated as hedges of commodity price risks, and accordingly, changes in their values are predominantly recorded in accumulated other comprehensive income (loss) until the hedged transaction occurs.

Concentrations of Credit Risk

Although our cash equivalents, accounts receivable and derivative assets are exposed to the risk of credit loss, we do not believe such risk to be significant. 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 and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated integrated energy companies. 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 counterparties that provide for offsetting payables against receivables from separate derivative contracts. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. Our allowance for collectibility of all accounts receivable was $4 million at December 31, 2005 and 2004.

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.

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In addition to selling gas under fixed price physical delivery contracts, we enter futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on natural gas and crude oil sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We have hedged a portion of our exposure to variability in future cash flows from natural gas and crude oil sales through December 2006.

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.

	Futures Contracts and Swap Agreements
Production Period	Mcf per Day	Average NYMEX Price per Mcf
2006    January to March             April to December	560,000 260,000	$ $	12.95 11.06	(a) (a)

(a) Includes a swap agreement for 10,000 Mcf per day acquired in the Antero Resources acquisition (Note 13) at the April 1, 2005 mark-to-market price of $7.78 per Mcf, which is the price used for cash flow hedge accounting purposes. The cash settlement contract price is $4.93 per Mcf.

We acquired the following put and call options in the Antero Resources acquisition (Note 13). These contracts are not designated as cash flow hedges. Changes in the fair market value of these options are recorded as a derivative fair value (gain) loss in our consolidated income statement.

	Put Options			Call Options
Period	Average Mcf per day	Average Price per Mcf		Average Mcf per day	Average Price per Mcf
2006 January to December	6,019	$	3.21	2,216	$	4.71
	2,603	$	4.14	—		—

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The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered basis swap agreements that effectively fix the basis adjustment for the following delivery locations and periods:

	Gas Delivery Location
Production Period	Arkoma			East Texas			Mid-Continent			Rockies			San Juan Basin			West Texas			Total
2006
January to February
Mcf per day		25,000			275,000			40,000			20,000			50,000			5,000		415,000
Basis per Mcf (a)	$	(1.82	)	$	(0.61	)	$	(1.77	)	$	(2.04	)	$	(1.96	)	$	(0.27	)
March
Mcf per day		25,000			385,000			40,000			20,000			50,000			5,000		525,000
Basis per Mcf (a)	$	(1.82	)	$	(0.55	)	$	(1.77	)	$	(2.04	)	$	(1.96	)	$	(0.27	)
April to June
Mcf per day		—			325,000			—			—			—			5,000		330,000
Basis per Mcf (a)		—		$	(0.59	)		—			—			—		$	(0.27	)
July to October
Mcf per day		—			295,000			—			—			—			5,000		300,000
Basis per Mcf (a)		—		$	(0.61	)		—			—			—		$	(0.27	)
November to December
Mcf per day		—			260,000			—			—			—			5,000		265,000
Basis per Mcf (a)		—		$	(0.61	)		—			—			—		$	(0.27	)
2007
January to March
Mcf per day		—			20,000			—			—			—			—		20,000
Basis per Mcf (a)		—		$	(0.64	)		—			—			—			—

(a) Reductions to NYMEX gas prices for delivery location.

Net losses on futures and basis swap hedge contracts decreased gas revenue by $127 million in 2005, $156 million in 2004 and $193 million in 2003. As of December 31, 2005, an unrealized pre-tax derivative fair value gain of $119 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). This fair value gain is expected to be reclassified into earnings in 2006. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date. The settlement of futures contracts and basis swap agreements related to January 2006 gas production increased gas revenue by approximately $38 million, or $1.11 per Mcf.

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. See Note 7 regarding accounting for commodity hedges.

	Futures Contracts and Swap Agreements
Production Period	Bbls per Day	Average NYMEX Price per Bbl
2006    January to December	15,000	$	59.53

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For 5,000 Bbls per day of sour crude oil production, we have entered a crude sweet and sour differential swap of $5.00 per Bbl.

Net losses on futures and differential swap hedge contracts decreased oil revenue by $75 million in 2005, $15 million in 2004 and $4 million in 2003. As of December 31, 2005, an unrealized pre-tax derivative fair value loss of $13 million related to cash flow hedges of oil price risk was recorded in accumulated other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2006. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

The settlement of futures contracts, swap agreements and differential swap contracts related to January 2006 production reduced oil revenue by approximately $2 million, or $1.76 per Bbl.

Physical Delivery Contracts

In 1998, we sold a production payment, payable from future production from certain properties acquired in an acquisition, to EEX Corporation for $30 million. The acquisition was recorded net of the sale of the production payment. Under the terms of the production payment conveyance and related delivery agreement, we committed to deliver to EEX a total of approximately 34.3 Bcf (27.8 Bcf net to our interest) of gas during the 10-year period beginning January 1, 2002, with scheduled deliveries by year, subject to certain variables. EEX will reimburse us for all royalty and production and property tax payments related to such deliveries. EEX will also pay us an operating fee of $0.257 per Mcf for deliveries, which fee will be escalated annually at a rate of 5.5%. In 2001 and 2002, we repurchased 18.3 Bcf (14.8 Bcf net) of gas under the production payment for $21 million. We expect to begin delivery of the remaining 16.0 Bcf (13.0 Bcf net) of gas in 2006.

9. Equity

Stock Splits

We effected a four-for-three stock split on March 18, 2003, a five-for-four stock split on March 17, 2004 and a four-for-three stock split on March 15, 2005. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits.

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Common Stock

The following reflects our common stock activity:

	Shares Issued				Shares in Treasury
(in thousands)	2005	2004	2003		2005	2004	2003
Balance, January 1	348,428	312,335	301,633		1,250	—	19,462
Issuance/vesting and forfeiture of performance and unrestricted shares	433	2,448	4,444		405	1,216	1,585
Stock option and warrant exercises	3,027	1,937	4,456		—	—	—
Treasury stock purchases	—	—	—		—	34	151
Common stock offering	—	31,708	23,000		—	—	—
Issuance for acquisition of corporation	13,333	—	—		—	—	—
Cancellation of treasury stock	—	—	(21,198	)	—	—	(21,198	)
Balance, December 31	365,221	348,428	312,335		1,655	1,250	—

Our acquisition of Antero Resources Corporation in April 2005 was partially funded through issuance to the seller of 13.3 million shares of common stock (Note 13). We filed a shelf registration with the Securities and Exchange Commission for the resale of the common stock including shares to be issued upon exercise of warrants. See Common Stock Warrants below.

In May 2004, we completed a public offering of 31.7 million shares of common stock at $18.92 per share. After underwriting discount and other offering costs of $20 million, net proceeds of $580 million were used to reduce bank borrowings that funded our producing property acquisitions from ExxonMobil Corporation and our deposit on the ChevronTexaco acquisition (Note 13).

In April 2003, we completed a public offering of 23 million shares of common stock at $11.25 per share. After underwriting discount and other offering costs of $11 million, net proceeds from the offering of $248 million and net proceeds from the concurrent sale of senior notes (Note 3) were used to fund producing property acquisitions, to redeem our 8 ³/4% senior subordinated notes and to reduce bank debt.

Treasury Stock

In August 2004, our Board of Directors authorized the repurchase of up to 20 million shares of our common stock which may be purchased from time to time in open market or negotiated transactions. This authorization effectively replaced the share repurchase authorization remaining from May 2000. As of December 31, 2005, we have repurchased 33,600 shares.

Stockholder Rights Plan

In August 1998, the Board of Directors adopted a stockholder rights plan that is designed to assure that all stockholders receive fair and equal treatment in the event of any proposed takeover of the Company. Under this plan, one preferred share purchase right is attached to each outstanding share of common stock. Each right entitles stockholders to buy one one-thousandth of a share of newly created Series A Junior Participating Preferred Stock at an exercise price of $80, subject to adjustment in the event a person acquires or makes a tender or exchange offer for 15% or more of the outstanding common stock. In such event, each right entitles the holder (other than the person acquiring 15% or more of the outstanding common stock) to purchase shares of common stock with a market value of twice the right’s exercise price. At any time prior to such event, the Board of Directors may redeem the rights at one cent per right. The rights can be transferred only with common stock and expire in August 2008.

Shelf Registration Statement

In February 2005, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities, preferred stock, common stock, or warrants to purchase debt or stock. The total face amount of securities that can be offered is $2.5 billion, at prices and on terms to be

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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. In April 2005, we sold $400 million of 5.3% senior notes under this registration statement (Note 3).

Common Stock Warrants

Our purchase of Antero Resources Corporation was partially funded by issuance of warrants to purchase 2 million shares of common stock at $27.00 per share (Note 13). The warrants expire in March 2010.

Common Stock Dividends

The Board of Directors declared quarterly dividends of $0.006 per common share for each quarter in 2003, $0.0075 per common share for first and second quarter 2004, $0.0375 per common share for third and fourth quarter 2004, $0.05 per common share for the first three quarters of 2005 and $0.075 per common share for fourth quarter 2005 and first quarter 2006.

In January 2006, the Board of Directors declared a dividend of 0.0596 units of Hugoton Royalty Trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will be distributed on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date. Based on the January 26, 2006 declaration date, this dividend has a fair value of approximately $830 million, or $2.28 per common share.

In August 2003, our Board of Directors declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each share of common stock outstanding in September 2003. This dividend, totaling 1,360,000 trust units, was distributed in September 2003, and was recorded at the fair value of the units on that date of $28 million or $0.09 per common share.

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.

See Note 12.

10. Earnings Per Share

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

(in millions, except per share data)	Earnings		Shares	Earnings per Share
2005
Basic	$	1,152	358.4	$	3.21
Effect of dilutive securities:
Stock options		—	6.8
Warrants		—	0.4
Diluted	$	1,152	365.6	$	3.15
2004
Basic	$	508	332.9	$	1.53
Effect of dilutive securities:
Stock options		—	2.8
Diluted	$	508	335.7	$	1.51
2003
Basic	$	288	299.7	$	0.96
Effect of dilutive securities:
Stock options		—	4.1
Diluted	$	288	303.8	$	0.95

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11. Supplemental Cash Flow Information

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

• Exchange of producing properties with ConocoPhillips in March 2005 and Occidental Petroleum in September 2005 (Note 13)

• Non-cash components of the April 2005 Antero Resources acquisition purchase price, including issuance of 13.3 million shares of common stock and warrants to purchase 2 million shares of common stock, and assumption of debt and other liabilities (Note 13)

• Exchange of nonstrategic working and royalty interests for nonproducing acres in August 2004 (Note 2)

• Distribution of 1,360,000 Cross Timbers Royalty Trust units as a dividend to common stockholders in 2003 (Note 9)

• The following performance share activity (Note 12):

• Grants of 414,000 shares in 2005, 2.6 million shares in 2004 and 4.4 million shares in 2003

• Vesting of 1.1 million shares in 2005, 3.2 million in 2004 and 3.5 million shares in 2003

• Grants and immediate vesting of 18,000 unrestricted common shares to nonemployee directors in each of 2005, 2004 and 2003

• Forfeiture of 20,000 shares in 2003

Interest payments in 2005 totaled $150 million (including $6 million of capitalized interest), $77 million in 2004 (including $3 million of capitalized interest) and $61 million in 2003 (including $2 million of capitalized interest). Net income tax payments were $248 million during 2005, $50 million during 2004 and $5 million during 2003.

Prior to January 1, 2006, we did not recognize compensation expense related to stock options granted. Because of this, the tax benefit realized upon exercise of stock options has been recorded as an increase in additional paid-in capital. This tax benefit has increased our net operating loss carryforwards (Note 4) and is reflected in our consolidated statements of cash flows when these carryforwards were utilized, primarily in 2004 and 2005. This tax benefit from exercise of stock options was $22 million in 2005, $18 million in 2004 and $23 million in 2003.

12. 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 of up to 10% of wages, subject to annual dollar maximums established by the federal government. Employee contributions vest immediately while our matching contributions vest 100% upon completion of three years of service. All employees over 21 years of age may participate. Company contributions under the plan were $9 million in 2005, $7 million in 2004 and $5 million in 2003.

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Post-Retirement Health Plan

Effective January 1, 2001, we adopted a medical plan for employees who retire at age 55 or over, as well as directors age 55 or over, with a minimum of five years service. During 2003, our retiree medical plan was amended to provide benefits to employees and directors when their combined age and qualified years of service total 60, with a minimum age of 45 and a minimum of five years of service. Benefits under the plan are the same as for active employees, and continue until the retired employee or director or dependents are eligible for Medicare or another similar federal health insurance program. Post-retirement medical benefits are not prefunded but are paid when incurred. The plan’s benefit obligation, funded status and net periodic benefit cost for 2005, 2004 and 2003 are as follows:

	December 31
(in millions)	2005			2004			2003
Benefit obligation at December 31	$	7		$	4		$	3
Funded status	$	(7	)	$	(4	)	$	(3	)
Net periodic benefit cost	$	1		$	1		$	2
Accrued benefit liability, as recognized in the consolidated balance sheet at December 31	$	(5	)	$	(4	)	$	(4	)

Unrecognized net actuarial gain and prior service costs are amortized to expense over the lesser of the estimated average remaining service life of plan participants or seven years. Including such amortization, the 2006 accrued benefit cost is expected to be approximately $1 million.

The following are assumptions used by us to determine our benefit obligation as of December 31 of each of the years presented:

	2005		2004		2003
Weighted average discount rate	6	%	6	%	6.5	%
Health care cost trend rate assumed for the following year	8.5	%	9	%	9	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	6	%	6	%	6	%
Year that the rate reaches the ultimate trend rate	2010		2010		2009

Assumed health care cost trends have a significant effect on the amounts reported for health care plans. A one percentage point change in assumed health care cost trend rates would have less than a $1 million effect on both total service and interest cost and the post-retirement benefit obligation as of December 31, 2005.

Through 2015, projected benefit payments, which reflect expected future service, are not expected to exceed $775,000 in any one year and are less than $5 million in total.

Stock Incentive Plans

In November 2004, stockholders approved the 2004 Stock Incentive Plan under which 24 million shares of common stock are available for grants of stock awards. 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 the provision that awards outstanding at any given time under all incentive plans may not exceed six percent of common stock outstanding at the time such grants are made. The maximum term of stock awards is ten years under the 1998 Plan and seven years under the 2004 Plan. 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. There were 19.5 million options outstanding under both plans at December 31, 2005, including 16.7 million that were exercisable at that date. The remaining 2.8 million options vest over three years at a rate of one-third at each grant anniversary date, with no provision for accelerated performance-based vesting.

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Nonemployee directors are each eligible to receive discretionary stock awards under the 2004 Plan covering up to 20,000 shares annually, as approved by the Corporate Governance and Nominating Committee and the Board of Directors. Nonemployee directors received automatic annual grants of unrestricted common shares that totaled 18,000 shares in each of 2004 and 2003. Nonemployee directors received a total of 20,000 unrestricted shares in February 2006 and 18,000 unrestricted shares in February 2005 under the 2004 Plan. In November 2004, nonemployee directors were granted a total of 88,000 stock options which vested in February 2005 when the common stock price reached specified levels. In November 2005, nonemployee directors received 96,000 stock options, 48,000 of which vested in 2005 when the common stock price closed above the target price of $45. The remainder will vest when the common stock price closes above a target price of $50.

Performance Shares

Performance shares granted under the 2004 and 1998 Plans 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. The following summarizes performance share activity for each year:

	December 31
(in thousands, except per share amounts)	2005		2004		2003
Shares granted to key employees		414		2,576		4,431
Shares vested when common stock price reached specified levels		1,056		3,240		3,470
Shares forfeited		—		—		20
Weighted average fair value of shares when granted	$	36.98	$	20.94	$	14.71
(in millions)
Treasury stock purchases related to vested shares	$	14	$	24	$	23
Non-cash performance share compensation	$	34	$	67	$	51

At December 31, 2005, deferred compensation of $5 million was recorded, based on the year-end common stock price less compensation expense recorded, as an offset to additional paid-in-capital for 155,750 performance shares granted in November and December 2005. Of these performance shares, 154,500 shares vest when the common stock closes above $50 and 1,250 shares vest when the common stock closes above $55.

Management assesses whether the vesting period of stock-based awards can be reasonably estimated. When management is able to reasonably estimate a probable vesting period, compensation is recognized ratably over the estimated vesting period or at actual vesting, if earlier. Performance share grants in 2005 were to key employees other than executive officers. As of December 31, 2005, management estimated a reasonably probable vesting period of approximately six months for performance share awards that vest at $50, resulting in related compensation of $2 million recorded in 2005. Management could not estimate a reasonably probable vesting period for performance shares that vest at $55.

In September 2004, the Compensation Committee of the Board of Directors announced that it intended to restructure the Company’s equity incentive program to discontinue the use of performance shares for executive officers named in the proxy and to provide that all future grants to the officers would be in the form of options or other stock appreciation shares. As a result, in October 2004, the Compensation Committee of the Board of Directors amended the change in control performance share grant agreements to delete the provisions regarding the grant of performance shares for every $0.75 increment in the price of the common stock and to provide that, immediately prior to a change in control, these officers will receive a lump-sum cash payment equal to the value of 1,667,000 shares of common stock on the date of the change in control. A provision, providing that certain of these officers will also receive a total grant of 517,000 performance shares immediately prior to a change in control without regard to the price of our common stock, has been revised to provide that such payment will be in cash and not in shares of common stock. All amounts to be granted under these agreements will be adjusted for any future stock splits or other extraordinary transactions. If the named executive officers are subject to the 20% parachute excise tax, the Company will pay the officer an additional amount to “gross

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up” the payment so that the officer will receive the full amount due under the terms of the amended change in control grant agreement after payment of the excise tax.

Option Activity and Balances

The following summarizes option activity and balances from 2003 through 2005:

	Weighted Average Exercise Price		Stock Options (in thousands)
2003
Beginning of year	$	8.40	14,854
Grants		15.06	3,530
Exercises		8.46	(10,430	)
Forfeitures		13.88	(55	)
End of year		11.15	7,899
Exercisable at end of year		9.22	5,311
2004
Beginning of year	$	11.15	7,899
Grants		24.86	16,230
Exercises		13.17	(4,794	)
Forfeitures		15.14	(15	)
End of year		22.16	19,320
Exercisable at end of year		11.99	4,092
2005
Beginning of year	$	22.16	19,320
Grants		33.83	4,173
Exercises		21.74	(3,976	)
Forfeitures		27.61	(65	)
End of year		24.74	19,452
Exercisable at end of year		22.80	16,689

The following summarizes information about outstanding options at December 31, 2005:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number (in thousands)	Weighted Average Remaining Term	Weighted Average Exercise Price		Number (in thousands)	Weighted Average Exercise Price
$   4.65  -  $   9.29	1,889	5.1 years	$	7.41	1,889	$	7.41
$   9.30  -  $ 13.94	454	6.9 years	$	10.29	454	$	10.29
$ 13.95  -  $ 18.59	22	7.9 years	$	15.14	22	$	15.14
$ 18.60  -  $ 23.23	20	8.4 years	$	19.22	20	$	19.22
$ 23.24  -  $ 27.88	12,991	6.2 years	$	24.88	12,991	$	24.88
$ 27.89  -  $ 32.53	2,153	6.4 years	$	28.17	1,212	$	28.21
$ 32.54  -  $ 37.17	109	6.4 years	$	34.92	53	$	33.83
$ 37.18  -  $ 41.82	1,723	6.9 years	$	40.61	48	$	39.90
$ 41.83  -  $ 46.47	91	6.9 years	$	45.23	—		—
	19,452	6.2 years	$	24.74	16,689	$	22.80

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Estimated Fair Value of Grants

Using the Black-Scholes option-pricing model and the following assumptions, the weighted average option fair value of current year option grants was estimated to be $10.20 in 2005, $5.34 in 2004 and $5.47 in 2003. The Black-Scholes option-pricing model does not consider the effects of forfeitability and nontransferability on the valuation of employee stock options.

	2005	2004	2003
Risk-free interest rates	4%	3.5%	3.1%
Dividend yield	0.7%	0.6%	0.2%
Weighted average expected lives	3.5 years	3 years	4 years
Volatility	35%	26%	42%

13. Acquisitions

In March 2005, we traded nonoperated producing properties owned by us in the San Juan and Permian basins and in Alaska for producing properties owned by ConocoPhillips in the East Texas Freestone Trend, the San Juan Basin and the Permian Basin Goldsmith Field. The properties exchanged by each party had an approximate value of $74 million. We accounted for this transaction as an exchange of similar productive assets used in oil and gas producing activities, under APB Opinion No. 29 and SFAS No. 19, resulting in no gain or loss recognized on the exchange. We operate the properties that we received in this exchange.

To further establish our presence in the Barnett Shale in the Fort Worth Basin, we acquired Antero Resources Corporation on April 1, 2005. Antero Resources owned operated gas-producing properties and unproved properties in the Barnett Shale. In the transaction, we paid cash of $342 million, issued 13.3 million shares of our common stock, and issued warrants that expire March 2010 to purchase an additional 2 million shares of our common stock at $27.00 per share. We also assumed $218 million of bank debt from Antero. The cash portion of the acquisition was funded with borrowings under our revolving credit facility. At closing, bank debt assumed from Antero Resources was repaid with borrowings under our revolving credit facility.

The following is the calculation of the purchase price of Antero Resources Corporation and the allocation to assets and liabilities as of April 1, 2005. The fair value of consideration issued is determined as of January 10, 2005, 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 Antero Resources stockholders:
13.3 million shares of common stock (at fair value of $24.73 per share)	$	330
Warrants to purchase 2 million shares of common stock at $27.00 per share (at fair value of $8.46 per warrant)		17
		347
Cash paid		342
Total purchase price		689
Fair value of liabilities assumed:
Current liabilities		112
Long-term debt		218
Asset retirement obligation		4
Other long-term liabilities		11
Deferred income taxes		225
Total purchase price plus liabilities assumed	$	1,259

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Fair value of assets acquired:
Cash and cash equivalents	$	2
Other current assets		55
Proved properties		634
Unproved properties		180
Other property and equipment, primarily gathering and pipeline assets		35
Acquired gas gathering contracts		140
Goodwill (none deductible for income taxes)		213
Total fair value of assets acquired	$	1,259

In May 2005, we acquired producing properties in East Texas and northwestern Louisiana from Plains Exploration & Production Company for an adjusted purchase price of $336 million. The acquisition was funded with borrowings under our revolving credit facility and is subject to typical post-closing adjustments.

In June 2005, we entered an agreement with ExxonMobil Corporation to develop acreage in the northeastern portion of the Piceance Basin in northwest Colorado. Under the terms of the agreement, we will farm-in approximately 69,500 contiguous gross acres east of ExxonMobil’s Piceance Creek Unit. We will operate and earn a 50% working interest ownership in the leasehold position by drilling four wells. The first well is currently drilling.

In July 2005, we acquired producing properties in the Permian Basin of West Texas and New Mexico from ExxonMobil Corporation for an adjusted purchase price of $200 million. The acquisition was funded with borrowings under our revolving credit facility and is subject to typical post-closing adjustments.

In September 2005, we traded nonoperated producing properties in the Permian Basin of West Texas for producing properties owned by Occidental Petroleum in the Permian Basin of New Mexico. We accounted for this transaction as an exchange of nonmonetary assets in accordance with SFAS No. 153. This exchange resulted in the recognition of a $10 million gain.

In January 2004, we acquired producing properties located primarily in East Texas and northwestern Louisiana in three separate transactions totaling $243 million after adjustments of $6 million for net revenues, preferential right elections and other items from the effective date of the transaction. The acquisitions were funded with a portion of the proceeds from the sale of 4.9% senior notes in January 2004 (Note 3).

From February through April 2004, we purchased $223 million of properties located primarily in the Barnett Shale of North Texas and in the Arkoma Basin. Funding was provided by bank debt and cash flow from operations.

In two separate transactions during April 2004, we acquired predominantly oil-producing properties in the Permian Basin of West Texas and in the Powder River Basin of Wyoming from ExxonMobil Corporation for a total adjusted purchase price of $336 million. The acquisitions were funded with bank borrowings that were repaid with proceeds from the sale of common stock in May 2004 (Note 9).

In May 2004, we entered an agreement with ChevronTexaco Corporation to acquire properties for a stated purchase price of $1.1 billion. The acquisition closed in August 2004. After adjustments for net revenues from the January 1, 2004 effective date, preferential purchase right elections exercised in November and December 2004, and other typical closing adjustments, the adjusted purchase price was approximately $958 million. The acquisition was funded through existing bank credit facilities and the sale of common stock in May 2004. These properties expanded our operations in the Permian Basin and our Eastern and Mid-Continent regions, and added new coal bed methane properties in the Rocky Mountains and a new operating region in South Texas.

Two acquisitions in 2004 were purchases of corporations that primarily owned producing and nonproducing properties. After purchase accounting adjustments, including a $72 million step-up adjustment for deferred income taxes, the cost of all proved properties acquired in 2004 was $1.9 billion.

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Acquisitions were recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for 2005 and 2004, as if the 2005 Antero Resources acquisition, and the 2004 ChevronTexaco and ExxonMobil acquisitions were made at the beginning of each period. These pro forma results are not necessarily indicative of future results.

	Pro Forma (Unaudited)
	Year Ended December 31
(in millions, except per share data)	2005		2004
Revenues	$	3,555	$	2,267
Net income	$	1,155	$	566
Earnings per common share:
Basic	$	3.19	$	1.59
Diluted	$	3.13	$	1.58
Weighted average shares outstanding:
Basic	$	361.7	$	355.5
Diluted	$	369.0	$	358.3

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 and is subject to typical post-closing adjustments.

14. Quarterly Financial Data (Unaudited)

The following are summarized quarterly financial data for the years ended December 31, 2005 and 2004:

	Quarter
(in millions, except per share data)	1st		2nd		3rd		4th
2005
Revenues	$	629	$	749	$	964	$	1,177
Gross profit (a)	$	336	$	420	$	573	$	789
Net income	$	166	$	220	$	312	$	454
Earnings per common share (b)
Basic	$	0.48	$	0.61	$	0.86	$	1.25
Diluted	$	0.47	$	0.60	$	0.85	$	1.22
Average shares outstanding		347.4		361.0		361.9		363.4
2004
Revenues	$	395	$	445	$	507	$	601
Gross profit (a)	$	216	$	255	$	284	$	329
Net income	$	94	$	99	$	141	$	174
Earnings per common share (b)
Basic	$	0.30	$	0.30	$	0.41	$	0.50
Diluted	$	0.30	$	0.30	$	0.40	$	0.50
Average shares outstanding
		312.7		326.2		345.3		347.1

(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.

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

All of our operations are directly related to oil and gas producing activities located in the United States.

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)	2005			2004			2003
Acquisitions:
Proved properties	$	1,710		$	1,949	(a)	$	624
Unproved properties - acquisition of corporation (b)		180			—			—
Unproved properties - other		92			50			5
Development (c)		1,341			570			443
Exploration		52			17			19
Asset retirement obligation accrued upon:
Acquisition		24			48			9
Development		29	(d)		12	(d)		5	(e)
Total Costs Incurred	$	3,428		$	2,646		$	1,105

(a) Includes a deferred income tax step-up adjustment of $72 million.

(b) Represents a portion of the allocated purchase price of Antero Resources Corporation (Note 13).

(c) Includes capitalized interest of $6 million in 2005, $3 million in 2004 and $2 million in 2003.

(d) Includes revisions of $16 million in 2005 and $6 million in 2004.

(e) Excludes $75 million recorded upon adoption of SFAS No. 143 on January 1, 2003.

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.

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.

As of December 31, 2003, 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, 2002	2,881.2		25.4		56.3		3,371.9
Revisions	(11.7	)	5.5		1.8		32.0
Extensions, additions and discoveries	559.8		1.6		0.4		572.0
Production	(244.0	)	(2.3	)	(4.7	)	(286.5	)
Purchases in place	465.7		4.5		2.2		506.0
Sales in place	(6.8	)	—		(0.6	)	(10.5	)
December 31, 2003	3,644.2		34.7		55.4		4,184.9
Revisions	(96.1	)	(0.1	)	3.0		(79.0	)
Extensions, additions and discoveries	755.4		3.7		4.2		802.8
Production	(305.5	)	(2.7	)	(8.3	)	(371.7	)
Purchases in place	716.5		2.9		98.2		1,323.3
December 31, 2004	4,714.5		38.5		152.5		5,860.3
Revisions	4.0		5.3		12.1		108.5
Extensions, additions and discoveries	986.6		4.9		34.2		1,221.2
Production	(377.1	)	(3.8	)	(14.3	)	(485.5	)
Purchases in place	803.4		2.8		31.1		1,007.1
Sales in place	(45.8	)	(0.3	)	(6.9	)	(89.4	)
December 31, 2005	6,085.6		47.4		208.7		7,622.2

Proved Developed Reserves

(in millions)	Gas (Mcf)	Natural Gas Liquids (Bbls)	Oil (Bbls)	Natural Gas Equivalents (Mcfe)
December 31, 2002	2,042.7	19.4	47.2	2,441.9
December 31, 2003	2,651.3	28.2	47.9	3,107.7
December 31, 2004	3,252.7	30.0	134.4	4,239.1
December 31, 2005	4,033.1	36.5	168.5	5,262.9

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Standardized Measure of Discounted Future

Net Cash Flows Relating to Proved Reserves

(in millions)	December 31
	2005			2004			2003
Future cash inflows	$	69,732		$	34,027		$	23,213
Future costs:
Production		(15,660	)		(8,842	)		(5,637	)
Development		(3,175	)		(1,580	)		(876	)
Future net cash flows before income tax		50,897			23,605			16,700
Future income tax		(16,823	)		(7,366	)		(5,142	)
Future net cash flows		34,074			16,239			11,558
10% annual discount		(16,980	)		(7,837	)		(5,569	)
Standardized measure (a)	$	17,094		$	8,402		$	5,989

(a) Before income tax, the year-end standardized measure (or discounted present value of future net cash flows) was $25.8 billion in 2005, $12.2 billion for 2004 and $8.6 billion for 2003.

Changes in Standardized Measure of Discounted Future Net Cash Flows

(in millions)	2005			2004			2003
Standardized measure, January 1	$	8,402		$	5,989		$	3,756
Revisions:
Prices and costs		8,506			(20	)		1,514
Quantity estimates		708			437			208
Accretion of discount		741			517			327
Future development costs		(2,167	)		(797	)		(494	)
Income tax		(4,550	)		(979	)		(973	)
Production rates and other		(2	)		(2	)		3
Net revisions		3,236			(844	)		585
Extensions, additions and discoveries		3,723			1,384			1,092
Production		(2,744	)		(1,512	)		(906	)
Development costs		1,128			484			435
Purchases in place (a)		3,527			2,901			1,043
Sales in place (b)		(178	)		—			(16	)
Net change		8,692			2,413			2,233
Standardized measure, December 31	$	17,094	(c)	$	8,402	(d)	$	5,989	(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.

(c) The December 31, 2005 standardized measure includes a reduction of $22 million ($34 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2005 includes a liability of $223 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, 2004 standardized measure includes a reduction of $15 million ($23 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2004 includes a liability of $160 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, 2003 standardized measure includes a reduction of $7 million ($11 million before income tax) for estimated property abandonment costs.

82

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 $9.26 for 2005, $5.69 for 2004, $5.71 for 2003 and $4.41 for 2002. Year-end average realized natural gas liquids prices were $36.33 for 2005, $28.24 for 2004, $23.17 for 2003 and $17.86 for 2002. Year-end average realized oil prices were $57.02 for 2005, $41.03 for 2004, $30.55 for 2003, and $29.69 for 2002. Proved oil and gas reserves at December 31, 2005 include 192 Bcf of gas and 1.6 million Bbls of oil and discounted present value before income tax of $597 million related to our ownership of approximately 54% of Hugoton Royalty Trust units at December 31, 2005. See Note 16.

16. Hugoton Royalty Trust Distribution

In January 2006, the Board of Directors declared a dividend of 0.0596 units of Hugoton Royalty Trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date. As of the January 26, 2006 declaration date, this dividend has a fair value of approximately $830 million, or $2.28 per common share.

We also announced in January 2006 that the Company will consider selling its interests in the underlying properties that are subject to the Cross Timbers Royalty Trust and Hugoton Royalty Trust net profits interests. Any sale is dependent upon finding a qualified buyer, receiving sufficient consideration and structuring a tax-efficient transaction.

Based on 2005 production and proved reserves estimates as of December 31, 2005, the distribution of Hugoton Royalty Trust units will reduce our production and proved reserves by less than 3% on Mcfe basis.

83

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, 2005. 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, 2005. Our independent registered public accounting firm, KPMG LLP, has issued an audit report on our assessment of our internal control over financial reporting, which is included herein.

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 28, 2006

84

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of XTO Energy Inc.:

We have audited the accompanying consolidated balance sheets of XTO Energy Inc. and its subsidiaries as of December 31, 2005 and 2004, and the related consolidated income statements, statements of cash flows and statements of stockholders’ equity for each of the years in the three-year period ended December 31, 2005. In connection with our audits of the consolidated financial statements, we also have audited the related financial statement schedules. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of XTO Energy Inc. and its subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003, in connection with its adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of XTO Energy Inc.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Dallas, Texas

February 28, 2006

85

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM.

To the Board of Directors and Stockholders of XTO Energy Inc.:

We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting, that XTO Energy Inc. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

XTO Energy Inc.’s management is responsible 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 management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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, management’s assessment that XTO Energy Inc. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, XTO Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of XTO Energy Inc. and its subsidiaries as of December 31, 2005 and 2004, and the related consolidated income statements, statements of cash flows and statements of stockholders’ equity for each of the years in the three-year period ended December 31, 2005, and our report dated February 28, 2006 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Dallas, Texas

February 28, 2006

86

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 2^nd day of March 2006.

XTO ENERGY INC.
By	/S/ BOB R. SIMPSON
	Bob R. Simpson, Chairman of the Board
	and 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 2^nd day of March 2006.

PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS)	DIRECTORS
/S/ BOB R. SIMPSON Bob R. Simpson, Chairman of the Board and Chief Executive Officer	/S/ WILLIAM H. ADAMS III William H. Adams III
/S/ KEITH A. HUTTON Keith A. Hutton, President	/S/ LANE G. COLLINS Lane G. Collins
/S/ VAUGHN O. VENNERBERG II Vaughn O. Vennerberg II, Senior Executive Vice President and Chief of Staff	/S/ PHILLIP R. KEVIL 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 Louis G. Baldwin, Executive Vice President and Chief Financial Officer	/S/ BENNIE G. KNIFFEN Bennie G. Kniffen, Senior Vice President and Controller

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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 +	Asset Sale Agreement dated May 14, 2004 between Chevron U.S.A. Inc. as Seller and XTO Energy Inc. as Buyer (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 19, 2004)
2.2 +	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)
2.3 +	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)
2.4 +	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)
2.5 +	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)
3.1	Restated Certificate of Incorporation of the Company, as restated on June 21, 2004 (incorporated by reference to Exhibit 3.1 to Form 10-Q for the quarter ended June 30, 2004)
3.2	Amended Bylaws of the Company (incorporated by reference to Exhibit 3.2 to Form 10-K for the year ended December 31, 2003)
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	Preferred Stock Purchase Rights Agreement dated August 25, 1998 between the Company and ChaseMellon Shareholder Services, LLC (incorporated by reference to Exhibit 4.1 to Form 8-A/A filed September 8, 1998)
4.4	Certificate of Designation of Series A Junior Participating Preferred Stock, par value $0.01 per share, dated August 25, 1998 (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2000)
4.5	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)
4.6	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)

88

Exhibit No.	Description	Page
4.7	Registration Rights Agreement dated April 23, 2003 between the Company and certain Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to Form 10-Q for the quarter ended March 31, 2003)
4.8	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)
4.9	First Supplemental Indenture dated as of January 22, 2004 between the Company and the Bank of New York for the 4.9% Senior Notes due 2014 (incorporated by reference to Exhibit 4.3.2 to Form 8-K filed January 16, 2004)
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	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)
4.12	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)
4.13	Registration Rights Agreement dated April 1, 2005 among XTO Energy Inc. and the security holders of Antero Resources Corporation (Amended Agreement) (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 2005)
10.1 *	Amended and Restated Employment Agreement between the Company and Bob R. Simpson, dated May 17, 2000 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2000)
10.2 *	Amendment to Amended and Restated Employment Agreement between the Company and Bob R. Simpson, dated August 20, 2002 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2002)
10.3 *	Amended and Restated Employment Agreement between the Company and Steffen E. Palko, dated May 17, 2000 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2000)
10.4 *	Amendment to Amended and Restated Employment Agreement between the Company and Steffen E. Palko, dated August 20, 2002 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2002)
10.5 *	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)
10.6 *	2004 Stock Incentive Plan (incorporated by reference to Appendix A to the Proxy Statement dated October 15, 2004 for the Special Meeting of Stockholders held November 16, 2004)
10.7 *	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)
10.8 *	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)

89

Exhibit No.	Description	Page
10.9 *	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)
10.10 *	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)
10.11 *	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)
10.12 *	Amended Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.14 to Form 10-K for the year ended December 31, 1999)
10.13 *	Amendment to Amended Employee Severance Protection Plan, as amended August 20, 2002 (incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2002)
10.14 *	Amended and Restated Management Group Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.13 to Form 10-K for the year ended December 31, 1999)
10.15 *	Amendment to Amended and Restated Management Group Employee Severance Protection Plan, as amended August 20, 2002 (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2002)
10.16 *	Outside Directors Severance Plan dated August 20, 2002 (incorporated by reference to Exhibit 10.6 to Form 10-Q for the quarter ended September 30, 2002)
10.17 *	Form of Agreement for Grant of Performance Shares (relating to change in control) between the Company and each of Bob R. Simpson and Steffen E. Palko dated February 20, 2001 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2001)
10.18 *	Form of Agreement for Grant of Performance Shares (relating to change in control) between the Company and each of Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II dated February 20, 2001 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2001)
10.19 *	Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Bob R. Simpson dated May 24, 2001 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2001)
10.20 *	Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Louis G. Baldwin dated May 24, 2001 (incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2001)
10.21 *	Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Keith A. Hutton dated May 24, 2001 (incorporated by reference to Exhibit 10.6 to Form 10-Q for the quarter ended September 30, 2001)
10.22 *	Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Vaughn O. Vennerberg II dated May 24, 2001 (incorporated by reference to Exhibit 10.7 to Form 10-Q for the quarter ended September 30, 2001)

90

Exhibit No.	Description	Page
10.23 *	Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Steffen E. Palko dated May 24, 2001 (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2001)
10.24 *	Form of Amended and Restated Agreement for Grant (relating to change in control) between the Company and Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated October 15, 2004 (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 21, 2004)
10.25 *	Phantom Performance Share Award Agreement between the Company and Bob R. Simpson, dated April 23, 2004 (incorporated by reference to Form 10-Q for the quarter ended June 30, 2004)
10.26 *	Phantom Performance Share Award Agreement between the Company and Bob R. Simpson, dated June 18, 2004 (incorporated by reference to Form 10-Q for the quarter ended June 30, 2004)
10.27 *	Form of Agreement for Grant of Phantom Performance Shares between the Company and each of Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated June 24, 2004 (incorporated by reference to Form 10-Q for the quarter ended June 30, 2004)
10.28 *	Form of Agreement for Grant of Phantom Performance Shares between the Company and each of Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated July 8, 2004 (incorporated by reference to Form 10-Q for the quarter ended June 30, 2004)
10.29 *	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)
10.30*	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)
10.31	Summary of Director Compensation and Benefits
10.32	5-Year Revolving Credit Agreement dated February 17, 2004 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.18 to Form 10-K for the year ended December 31, 2003)
10.33	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)
10.34	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)
10.35	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)

91

Exhibit No.	Description	Page
10.36	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 a request for 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
23.3	Consent of Miller and Lents, Ltd.
31	Rule 13a-14(a)/15d-14(a) Certifications
31.1	Chief Executive Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Chief Financial Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Section 1350 Certifications
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.

92

EX-10.31

EXHIBIT 10.31

XTO ENERGY INC.

SUMMARY OF DIRECTOR COMPENSATION AND BENEFITS

Annual Retainer

• Directors and advisory directors who are also employees of XTO Energy receive no additional compensation for service on the Board of Directors.

• Each non-employee director receives an annual retainer, paid in four quarterly installments, totaling $180,000.

• Non-employee advisory directors receive an annual retainer, paid in four quarterly installments, totaling $90,000.

• Directors are reimbursed for travel expenses incurred in conjunction with their attendance at meetings.

Equity Compensation

• Grants to non-employee directors and advisory directors are discretionary under the 2004 Stock Incentive Plan (“2004 Plan”).

• Under the 2004 Plan, grants of up to 20,000 shares, as adjusted for the March 15, 2005 four-for-three stock split, may be granted annually to non-employee directors and advisory directors.

• Grants may be in the form of stock options, stock appreciation rights, stock units, stock awards, unrestricted shares, dividend equivalents or other stock-based awards.

• Maximum grant amounts are adjusted for any stock splits.

Use of Company Aircraft, Office Space and Other Benefits

• Non-employee directors have personal use of Company aircraft for up to 14 hours per year.

• Non-employee directors and advisory directors have use of Company office space, subject to availability.

• The Company pays the expenses for each director and their spouse or guest to attend semi-annual management meetings and the Company’s annual golf tournament.

Outside Director Severance Plan

• Upon a change in control of the Company, each non-employee director and each non-employee advisory director will receive:

i. A payment equal to three times the annual cash retainer then in effect for directors and advisory directors.

ii. An amount equal to three times the number of unrestricted shares most recently granted to the director or advisory director as part of their annual compensation multiplied by the closing price of the Company’s common stock on the date of a change in control.

• A “change in control” of the Company is deemed to have occurred if: any person, or persons acting as a group, become the beneficial owners of more than 25% of the Company’s voting shares; a merger or consolidation results in the Company’s stockholders holding less than 50% of the voting shares of the surviving entity; certain specified majority changes in the composition of the Board of Directors occur; or a plan or agreement is approved to dispose of all or substantially all of the Company’s assets or outstanding Common Stock.

Retiree Medical Health Plan

• A director with any combination of age and years of service that totals 60, with a minimum age of 45 and a minimum of five consecutive years of service on the Board, is eligible to receive benefits under the plan.

• Premiums for directors will be as established from time to time by the Company. Currently, premiums for directors equal any premiums charged employees for coverage.

• Dependents of directors will pay premiums established from time to time by the Company. Currently, premiums for dependents of directors equal the premiums charged dependents of employees for coverage.

• Benefits terminate when the participant becomes eligible for a government-sponsored health insurance plan or benefits under the plan of an employer.

Long Term Care

• This insurance provides for custodial care in the form of home health care benefits, nursing home benefits and assisted living facility benefits.

• XTO provides the basic plan at no cost to the director, and their dependents pay premiums equal to premiums paid by dependents of employees.

• Upgrades are available at the same incremental additional premiums paid by employees and their dependents.

• When service on the Board terminates, a director can continue the coverage by assuming the payment of the premiums.

• Directors are eligible to participate following six months of service on the Board.

EX-12.1

EXHIBIT 12.1

XTO ENERGY INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(in millions, except ratios)	Year Ended December 31
	2005		2004		2003		2002		2001
Income before income tax and cumulative effect of accounting change	$	1,810	$	826	$	444	$	287	$	455
Interest expense		154		94		64		54		56
Interest portion of rentals		8		7		9		3		4
Earnings before provision for taxes and fixed charges	$	1,972	$	927	$	517	$	344	$	515
Interest expense	$	154	$	94	$	64	$	54	$	56
Capitalized interest		6		3		2		4		7
Interest portion of rentals		8		7		9		3		4
Total Fixed Charges	$	168	$	104	$	75	$	61	$	67
Ratio of Earnings to Fixed Charges		11.7		8.9		6.9		5.6		7.7

EX-21.1

EXHIBIT 21.1

SUBSIDIARIES OF XTO ENERGY INC.

	Jurisdiction of Incorporation
XTO Barnett LLC	Delaware
X Landmark LLC	Texas
XTO Resources I GP, LLC	Delaware
XTO Resources I LP, LLC	Delaware
XTO Resources I, LP	Texas
Barnett Gathering, LP	Texas
Cross Timbers Energy Services, Inc.	Texas
Cross Timbers Trading Company	Texas
Ringwood Gathering Company	Delaware
Timberland Gathering & Processing Company, Inc.	Texas
WTW Properties, Inc.	Texas
Trend Gathering & Treating, LP (formed in January 2006)	Texas

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

XTO Energy Inc.

Fort Worth, Texas:

We consent to the incorporation by reference in the registration statements (No. 333-122767) and (No. 333-123402) on Form S-3, and (Nos. 333-68775, 333-69977, 333-37668, 333-81849, 333-91460, 333-120540 and 333-55784) on Form S-8 of XTO Energy Inc. of our reports dated February 28, 2006, with respect to the consolidated balance sheets of XTO Energy Inc. as of December 31, 2005 and 2004, and the related consolidated income statements, statements of cash flows and statements of stockholders’ equity for each of the years in the three-year period ended December 31, 2005, and all related financial statement schedules, management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 and the effectiveness of internal control over financial reporting as of December 31, 2005, which reports appear in the December 31, 2005 annual report on Form 10-K of XTO Energy Inc. Our reports were unqualified and included an explanation paragraph that described the Company’s change in method of accounting for asset retirement obligations effective January 1, 2003, in connection with its adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as discussed in Note 1 to the consolidated financial statements.

KPMG LLP

Dallas, Texas

March 2, 2006

EX-23.3

EXHIBIT 23.3

[LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE]

March 2, 2006

XTO Energy Inc.

810 Houston Street

Fort Worth, TX 76102

Re:	XTO Energy Inc.
	2005 Annual Report on Form 10-K

Gentlemen:

The firm of Miller and Lents, Ltd., consents to the use of its name and to the use of its report dated February 20, 2006, regarding the XTO Energy Inc. Proved Reserves and Future Net Revenues as of December 31, 2005, in the 2005 Annual Report on Form 10-K.

Miller and Lents, Ltd., has no interests in XTO Energy Inc. or in any affiliated companies or subsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employee otherwise connected with XTO Energy Inc. We are not employed by XTO Energy Inc. on a contingent basis.

Yours very truly,
MILLER AND LENTS, LTD.
By	/S/ JAMES PEARSON
	James Pearson
	Chairman

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, Bob R. Simpson, Chief Executive Officer of XTO Energy Inc., certify that:

1. I have reviewed this annual report on Form 10-K of XTO Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: March 2, 2006	/S/ BOB R. SIMPSON
	Bob R. Simpson
	Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Louis G. Baldwin, Chief Financial Officer of XTO Energy Inc., certify that:

1. I have reviewed this annual report on Form 10-K of XTO Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: March 2, 2006	/S/ LOUIS G. BALDWIN
	Louis G. Baldwin
	Chief Financial Officer

EX-32.1

EXHIBIT 32.1

Certification of Chief Executive Officer and Chief Financial Officer of XTO Energy Inc.

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the Annual Report of XTO Energy Inc. (the “Company”) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Bob R. Simpson, Chief Executive Officer of the Company, and Louis G. Baldwin, Chief Financial Officer of the Company, each hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/S/ BOB R. SIMPSON

Bob R. Simpson

Chief Executive Officer

March 2, 2006

/S/ LOUIS G. BALDWIN

Louis G. Baldwin

Chief Financial Officer

March 2, 2006