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2002

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, 2002

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)

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

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

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

None

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 be 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 checkmark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).    Yes  x    No  ¨

Aggregate market value of the Common Stock based on the closing price on the New York Stock Exchange as of June 28, 2002 (the last business day of its most recently completed second fiscal quarter), held by nonaffiliates of the Registrant on that date was approximately $2,377,000,000

Number of Shares of Common Stock outstanding as of March 19, 2003—169,424,779

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Part III of this Report is incorporated by reference from the Registrant’s definitive Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 30, 2003.

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XTO ENERGY INC.

2002 ANNUAL REPORT ON FORM 10-K

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PART I

Items 1. and 2. BUSINESS AND PROPERTIES

General

XTO Energy Inc. and its subsidiaries (“the Company” or “XTO”) 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 strategic acquisitions of additional interests in or near such acquired properties. Growth for the next year or more is expected to be primarily internally generated and will be supplemented by incremental acquisitions. Given expected significant property divestitures by major energy, merchant energy, power generating and utility companies, larger strategic acquisitions could be made during the next year.

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 well-established production histories concentrated in the following areas:

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 on an energy equivalent ratio of one barrel to six Mcf.

Our estimated proved reserves at December 31, 2002 were 56.3 million Bbls of oil, 2.9 Tcf of natural gas and 25.4 million Bbls of natural gas liquids, based on December 31, 2002 prices of $29.69 per Bbl for oil, $4.41 per Mcf for gas and $17.86 per Bbl for natural gas liquids. Approximately 72% of December 31, 2002 proved reserves, computed on an Mcfe basis, were proved developed reserves. Increased proved reserves during 2002 were primarily the result of acquisitions and development and exploitation activities, partially offset by production. During 2002, our daily average production was 13,033 Bbls of oil, 513,925 Mcf of gas and 5,068 Bbls of natural gas liquids. Fourth quarter 2002 daily average production was 13,024 Bbls of oil, 551,356 Mcf of gas and 5,856 Bbls of natural gas liquids.

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Our properties have relatively long reserve lives and highly predictable production profiles. Based on December 31, 2002 proved reserves and projected 2003 production, the average reserve-to-production index of our proved reserves is 14.6 years. In general, these 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, 2002, we owned interests in 8,467 gross (4,506.6 net) wells, and we operated wells representing 93% 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 generated a substantial inventory of approximately 2,000 potential development drilling locations. Estimated net potential reserves associated with this inventory approach 2.9 Tcfe. Approximately one-third of these potential reserves are included in December 31, 2002 proved undeveloped reserves. Drilling plans are dependent upon product prices and the availability of drilling equipment.

We employ a disciplined acquisition program refined by senior management to augment our core properties and expand our reserve base. 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 geological and reservoir characteristics.

We operate gas gathering systems in East Texas, Louisiana, Colorado, Wyoming, the Arkoma Basin of Arkansas and Oklahoma, the Hugoton Field of Kansas and Oklahoma, and Major, Woods and Woodward counties, Oklahoma. We also operate gas processing plants in the Hugoton Field and the Cotton Valley Field of Louisiana. Gas gathering and processing operations are only in areas where we have production and are considered activities which add value to our natural gas production and sales operation.

We market our gas production and the gas output of our gathering and processing systems. A large portion of 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 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. The Board of Directors has authorized the purchase of up to two million, or 33%, of the outstanding units at a cost not to exceed $28.5 million. In June 1998, XTO and Cross Timbers Royalty Trust filed a registration statement with the Securities and Exchange Commission to register the Company’s 1,360,000 units for sale in a public offering. The registration statement was filed in anticipation of improving commodity prices and related market conditions for oil and gas equities. The registration statement was amended in June 2001. Our sale of these units is dependent upon commodity prices and related market conditions for oil and gas.

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. Hugoton Royalty Trust units are listed on the New York Stock Exchange under the symbol “HGT.”

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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. Our 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 “General – 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 Properties. We seek to acquire long-lived, operated producing properties that:

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.

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 approximately 2,000 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.

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Exploration Activities. During 2003, 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 $20 million of our $400 million 2003 development budget for exploration activities.

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

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 and Steffen E. Palko, co-founders of the Company, were previously executive officers 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 producing properties that we will not operate 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. 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 sell interests in additional royalty trusts in the future.

Business Goals. In December 2002, we announced our strategic goals for 2003 of increasing gas production by 15% over 2002 levels and increasing all production, including oil and natural gas liquids, by approximately 12% on an Mcfe basis. To achieve these growth targets, we plan to drill about 309 (255 net) development wells and perform approximately 385 (283 net) workovers and recompletions in 2003. Approximately 85% of these planned wells are classified as proved undeveloped reserves on our current reserve report.

We have budgeted $400 million for our 2003 drilling programs, which is expected to be funded by cash flow from operations. We plan to spend about 65% of the development budget in East Texas and about 20% in aggregate in the Arkoma and San Juan Basins, and the balance evenly allocated to Alaska, Permian Basin and Hugoton Royalty Trust properties. Exploration expenditures are expected to be approximately 5% of the 2003 budget. Costs of strategic property acquisitions during 2003 may reduce the amount currently budgeted for development and exploration. We may reevaluate our budget and drilling programs in the event of significant changes in oil and gas prices to focus on opportunities offering the highest rates of return and may increase our budget. Our ability to achieve these production and proved reserves goals will depend on the success of these planned drilling programs or, if property acquisitions are made in place of a portion of the drilling program, the success of those acquisitions.

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Acquisitions

During 1998, we acquired producing properties for a total cost of $340 million. The East Texas Basin Acquisition was the largest of these acquisitions. The purchase closed in April 1998 at a price of $245 million, which was reduced to $215 million by a $30 million production payment sold to EEX Corporation. In September 1998, we acquired oil-producing properties in the Middle Ground Shoal Field of Alaska’s Cook Inlet in exchange for 5.7 million shares of our common stock along with certain price guarantees and a non-interest bearing note payable of $6 million, resulting in a total purchase price of $45 million. We also acquired primarily gas-producing properties in northwest Oklahoma and the San Juan Basin of New Mexico for an estimated purchase price of $31 million. The 1998 acquisitions increased reserves by approximately 16.3 million Bbls of oil and 311.3 Bcf of gas.

In 1999, the Company and Lehman Brothers Holdings, Inc. acquired the common stock of Spring Holding Company, a private oil and gas company, for a combination of cash and XTO Energy’s common stock totaling $85 million. The Company and Lehman each owned 50% of a limited liability company that acquired the common stock of Spring. In September 1999, we acquired Lehman’s 50% interest in Spring for $44.3 million. This acquisition included oil and gas properties located in the Arkoma Basin of Arkansas and Oklahoma with a purchase price of $235 million. After purchase accounting adjustments and other costs, the cost of the properties was $257 million. We also acquired, with Lehman as 50% owner, Arkoma Basin properties from affiliates of Ocean Energy, Inc. for $231 million. We acquired Lehman’s interest in the Ocean Energy Acquisition in March 2000 for $111 million. The 1999 acquisitions, including Lehman’s 50% interest in the Spring and Ocean Energy acquisitions, increased reserves by approximately 2.8 million Bbls of oil and 494.7 Bcf of natural gas.

During 2000, we acquired oil- and gas-producing properties for a total cost of $32 million, including $11 million paid to Lehman in March 2000 in excess of our investment in the Ocean Energy Acquisition. There were no individually significant acquisitions in 2000.

During 2001, we acquired predominantly gas-producing properties for a total cost of $242 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, approximately 50% of which were proved undeveloped.

During 2002, we acquired gas-producing properties for a total cost of $358.1 million. In March 2002, we acquired gas-producing properties for $20 million in the East Texas Freestone Trend. 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 coalbed methane gas-producing properties located in the San Juan Basin of New Mexico for $153.8 million from J.M. Huber Corporation. The 2002 acquisitions increased reserves by approximately 449,000 Bbls of oil, 330.4 Bcf of natural gas and 2.2 million Bbls of natural gas liquids. Approximately 10% of these reserves were proved undeveloped.

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Significant Properties

The following table summarizes proved reserves and discounted present value, before income tax, of proved reserves by major operating areas at December 31, 2002:

East Texas Area

We began operations in the East Texas area in 1998 with the purchase of 251 Bcfe of reserves in eight major fields. These properties are located in East Texas and northwestern Louisiana and produce primarily from the Rodessa, Travis Peak, Cotton Valley sandstone, Bossier sandstone and Cotton Valley limestone formations between 7,000 feet and 13,000 feet. Development in the East Texas area has more than doubled reserves since acquisition, and with our 2002 acquisitions, we now have an interest in more than 186,000 gross (145,000 net) acres and a current development inventory of 800 to 1,000 wells with an estimated 2.2 Tcfe of reserve potential. We own an interest in 1,221 gross (1,094.4 net) wells which we operate and 139 gross (19.7 net) wells operated by others. We also own the related gathering facilities.

Freestone Trend

The Freestone Trend area is located in the western shelf of the East Texas Basin in Freestone, Robertson, Limestone and Leon counties. This area includes the Freestone, Bald Prairie, Bear Grass, Oaks, Teague, Farrar, Dew and Luna fields and was our most active gas development area in 2002, where 130 gross (108.2 net) gas wells were drilled and ten workovers were performed. Initial development was concentrated in the Travis Peak formation, but is now focused on multi-pay development of the deeper horizons including the Cotton Valley and Bossier sandstones, and Cotton Valley limestone. A 27-mile pipeline system, completed in January 2002, connects the major fields and allows multiple exit points for marketing. Currently transporting 225,000 Mcf per day, our gathering system was increased to more than 400,000 Mcf per day. We plan to continue our expansion efforts in this area by drilling approximately 144 wells in 2003.

Other East Texas Fields

Other fields in the East Texas area include Willow Springs, Opelika, Cotton Valley, Colquitt, Tri-Cities, Whelan, North Lansing and Logansport which provide opportunities for field extensions and infill drilling. In 2002, we drilled seven wells and performed 43 workovers in these fields. In 2003, we plan to drill five wells and perform 60 workovers. As a part of our 2002 acquisition from Marathon, we acquired an interest in a Cotton Valley gas plant that we now

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operate. This plant processes approximately 2,500 Bbls of natural gas liquids per day, primarily from our own production in the surrounding wells.

Arkoma Basin Area

During 1999, we acquired 480 Bcfe of reserves and a gas gathering system in the Arkoma Basin of Arkansas and Oklahoma. The Arkoma Basin, discovered in the 1920s, extends from central Arkansas into southeastern Oklahoma and is known for shallow production decline rates, multiple formations and complex geology. XTO controls 40% of Arkansas production from the Arkoma Basin and is the largest natural gas producer in Arkansas with over 500,000 gross acres of leasehold. We own an interest in 918 gross (650.6 net) wells which we operate and 677 gross (122.4 net) wells operated by others. Of these wells, 150 gross (99.5 net) operated wells and 78 gross (15.1 net) nonoperated wells are dual completions. Our fault-block analysis technique has identified trapped hydrocarbons in offsetting and new reservoirs across the basin. During 2002, we drilled 54 wells and completed 136 workovers, 40 of which were stimulation/recompletions and 40 of which were wellhead compressor installations. Our properties can be separated into three distinct areas which are the Arkansas Fairway trend, the Arkansas Overthrust trend and the Oklahoma Cromwell/Atoka trend.

Arkansas Fairway Trend

The Arkansas Fairway trend comprises multiple sandstones at depths ranging from 2,500 to 7,500 feet in the Atoka and Morrow intervals. In 2002, the Orr and Hale sandstones were targets for our drilling in the Aetna, Silex and Cecil fields where 21 wells were drilled and 55 workovers were performed. Drilling was concentrated in the Aetna and Cecil fields where compression was also upgraded. In 2003, we plan to drill 31 wells.

Arkansas Overthrust Trend

The Arkansas Overthrust trend area, located south of the Arkansas Fairway trend, typically has multiple thrust faults that created isolated reservoirs. Production is found at varying depths, ranging from 3,500 to 7,500 feet, in the Chismville, Booneville and Gragg fields. This extremely complex geology requires an ongoing process to develop the best exploitation opportunities. The use of electric imaging logs has enhanced the process of identifying new well locations. In 2002, 160-acre well spacing was approved which added 30 to 40 potential well locations in the Booneville and Chismville fields. Reduced well spacing in the Gragg Field may occur in 2003. We drilled 19 wells in this area in 2002 and completed 74 workovers. In 2003, we plan to drill 13 wells.

Oklahoma Cromwell/Atoka Trend

The Oklahoma Cromwell/Atoka trend of southeastern Oklahoma was originally developed in the 1970s targeting the Cromwell sandstones, with the Atoka and Wapanuka limestones as secondary objectives. Development activities were concentrated in the Ashland and South Pine Hollow fields where 14 wells were drilled and 7 workovers were performed in 2002. In 2003, there will be approximately ten wells drilled in this area.

Hugoton Royalty Trust Areas

A substantial portion of properties in the Mid-Continent area, the Hugoton area and the Green River Basin of the Rocky Mountains are subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust as of December 1998. We sold 45.7% of our Hugoton Royalty Trust units in 1999 and 2000.

Mid-Continent Area

XTO is one of the largest producers in the Major and Woodward counties, Oklahoma area of the Anadarko Basin. We operate 570 gross (493.9 net) wells and have an interest in 142 gross (37.5 net) wells operated by others. Oil and gas were first discovered in the Major County area in 1945. The fields in the Major and Woodward counties area are characterized by oil and gas production from a variety of structural and stratigraphic traps. Productive zones range from 6,500 to 9,400 feet and include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations.

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Development in the Major County area focuses on mechanical improvements, restimulations and recompletions to shallower zones and development drilling. During 2002, we participated in the drilling of eight gross (5.5 net) wells in the northwestern portion of the county, targeting the Mississippian formation. We have budgeted six drill wells and 11 workovers in Major County for 2003. We were also very active in Woodward County, Oklahoma, where 10 gross (9.0 net) wells were drilled which targeted the Chester formation. In 2003, we plan to drill up to 12 wells and to perform as many as five workovers.

We operate a gathering system and pipeline in the Major County area. The gathering system collects gas from over 400 wells through 300 miles of pipeline in the Major County area. The gathering system has current throughput of approximately 19,500 Mcf per day, 70% of which is produced from Company-operated wells. Estimated capacity of the gathering system is 40,000 Mcf per day. Gas is delivered to a processing plant owned and operated by a third party, and then transmitted by a Company-operated residue pipeline to a connection with an interstate pipeline.

Hugoton Area

The Hugoton Field, discovered in 1922, covers parts of Texas, Oklahoma and Kansas and is the largest gas field in North America with an estimated five million productive acres. XTO owns an interest in 376 gross (353.0 net) wells that we operate and 80 gross (18.8 net) wells operated by others. During 2002, development of the Hugoton area included four successful recompletions to the Towanda formation. We also continued our restimulation program in the Chase intervals by completing 33 restimulations in 2002. We plan to perform 35 Chase restimulations during 2003.

Approximately 75% of our Hugoton gas production is delivered to the Tyrone Plant, a gas processing plant we operate. During 1998, we completed the acquisition of approximately 70 miles of low pressure gathering lines, increasing production by 3,500 Mcf per day. During 1999 and 2000, we installed additional lateral compressors that lowered the line pressure and increased production in various areas of the Hugoton Field.

Green River Basin

The Green River Basin is located in southwestern Wyoming. We have interests in 185 gross (183.5 net) wells that we operate and 36 gross (4.2 net) wells operated by others in the Fontenelle Field area. Gas production began in the Fontenelle area in the early 1970s and the producing reservoirs are the Cretaceous-aged Frontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000 feet. Development potential for the fields in this area include deepening and opening new producing zones in existing wells, drilling new wells and adding compression to lower line pressures. Development activities in the Fontenelle Field were delayed for most of 2002 by pipeline limitations and price volatility. During 2003, we plan to perform five workovers and may drill up to five wells in the Green River Basin.

San Juan Basin Area

The San Juan Basin of northwestern New Mexico and southwestern Colorado contains the second largest deposit of natural gas reserves in North America. We acquired a large portion of our interests in the San Juan Basin in December 1997 with the purchase of approximately 290 Bcfe from Amoco Corporation. In 2002, we purchased approximately 212 Bcfe from Marathon Oil Company and J. M. Huber Corporation and extended our coalbed methane operations into Colorado. We have now identified more than 400 potential drilling locations with approximately 350 Bcfe reserve potential. XTO owns an interest in 879 gross (716.3 net) wells that it operates and 830 gross (201.5 net) wells operated by others. Of these wells, 142 gross (124.8 net) operated wells and 129 gross (27.6 net) nonoperated wells are dual completions. In 2002, we participated in the drilling of 47 wells and completed 240 workovers. Drilling focused on the Fruitland Coal formation at shallow intervals of 3,000 feet or less and the Mesaverde and Dakota formations at depths of 3,000 to 7,500 feet. During 2003, we plan to drill 60 to 70 wells and perform 150 to 200 workovers and recompletions, including installation of as many as 40 wellhead compressors and 25 pumping units.

Fruitland Coal and Pictured Cliffs Formations

XTO has centered its Fruitland Coal development efforts on trend extensions. Our coalbed methane play is focused on the northwestern portion of the Basin surrounding the city of Farmington, New Mexico and in the southwestern portion of Colorado. We drilled one Fruitland Coal well in 2002 and

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plan to drill an additional 29 wells in 2003. A request to reduce current spacing of coalbed methane wells from 320 acres to 160 acres was approved by regulatory authorities in October 2002, adding more than 80 potential well locations.

Mesaverde and Dakota Formations

Eighty-acre spacing was approved in January 2002, which now allows wells to be drilled with multiple zone targets. We have identified more than 200 potential well locations that will allow deeper drilling through the Dakota to the Burro Canyon and Morrison sandstones. The reduced spacing will generate significant future development opportunities, and additional test wells are planned for 2003. In 2002, we drilled 28 Dakota and 18 Mesaverde wells. Thirty-one drill wells are planned for 2003.

Permian Basin Area

University Block 9. The University Block 9 Field is located in Andrews County, Texas and was discovered in 1953. We own interests in 79 gross (73.3 net) operated wells. Productive zones are of Wolfcamp, Pennsylvanian and Devonian age and range from 8,400 to 10,000 feet. Development potential includes proper wellbore utilization, recompletions, infill drilling and improvement of waterflood efficiency.

Development in 2002 focused on the Devonian, Grayburg & Wolfcamp formations. This field was one of our most active oil development areas during 2002 where XTO drilled seven wells, including four horizontal sidetrack wells. We also discovered a new shallow Grayburg producing interval. During 2003, we plan to drill up to 11 wells.

Prentice Field. The Prentice Field is located in Terry and Yoakum counties, Texas. Discovered in 1950, the Prentice Field produces from carbonate reservoirs in the Clear Fork and Glorieta formations at depths ranging from 6,800 to 7,700 feet. The Prentice Field has been separated into several waterflood units for secondary recovery operations. The Prentice Northeast Unit was formed in 1964 with waterflood operations commencing a year later. Development potential exists through infill drilling and improvement of waterflood efficiency. Tertiary recovery potential also exists through carbon dioxide flooding.

We operate the Prentice Northeast Unit, where we have a 91.6% working interest in 204 wells. We also own an interest in 81 gross (2.0 net) nonoperated wells. During 2002, we continued our 10-acre development drilling program by drilling eight gross (7.4 net) vertical wells in the Prentice Field. During 2003, we plan to continue our expansion of the potential infill area by drilling as many as eight wells.

Wasson Field. The Wasson Field, discovered in 1936, is located in Gaines and Yoakum counties, Texas and produces from the San Andres formation at depths ranging from 4,500 to 6,300 feet. The Cornell Unit was formed in 1965 and has development potential that exists through infill drilling and improvement of waterflood efficiency. We have a 68.4% working interest in the unit. In 2002, we drilled three 10-acre infill oil wells and one gas cap well, and in 2003 we plan to drill three oil wells and three gas cap wells in this area.

Alaska Cook Inlet Area

In September 1998, we acquired a 100% working interest in two State of Alaska leases and the offshore installations in the Middle Ground Shoal Field of the Cook Inlet. The properties included 27 wells, two operated production platforms set in 70 feet of water about seven miles offshore, and a 50% interest in certain operated production pipelines and onshore processing facilities.

Oil was discovered in the Cook Inlet in 1966 and, to date, more than 120 million Bbls have been produced. The field is separated into East and West flanks by a crestal fault. Waterflooding of the East Flank has been successful, but the West Flank has not been fully developed or efficiently waterflooded. Production is primarily from multiple zones within the Miocene-Oligocene-aged Tyonek formation between 7,000 feet and 10,000 feet subsea.

In 2002, we completed an East Flank simulation study. One East Flank and three West Flank wells were drilled in 2002. Three additional East Flank wells are planned for 2003.

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Reserves

The following are definitions of terms used in the following disclosures of oil and natural gas reserves:

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

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

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

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

Present value of estimated future net cash flows—Also referred to herein as “standardized measure of discounted future net cash flows” or “standardized measure.” Computational result of discounting estimated future net revenues at a rate of 10% annually.

The following are estimated quantities of proved reserves and related cash flows as of December 31, 2002, 2001 and 2000:

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, 2002, 2001 and 2000. As prescribed by the Securities and Exchange Commission, such proved reserves were estimated using

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oil and gas prices and production and development costs as of December 31 of each such year, without escalation. Year-end 2002 average realized prices used in the estimation of proved reserves were $29.69 per Bbl for oil, $4.41 per Mcf for gas and $17.86 per Bbl for natural gas liquids. See Note 15 to Consolidated Financial Statements for additional information regarding estimated proved reserves.

Estimated future net cash flows, and the related 10% discounted present value, of year-end 2002 proved reserves are significantly higher than at year-end 2001 because of significantly lower product prices used in the estimation of year-end 2001 proved reserves. Year-end 2001 prices were $17.39 per Bbl for oil, $2.36 per Mcf for gas and $8.70 per Bbl for natural gas liquids.

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 2002, we filed estimates of oil and gas reserves as of December 31, 2001 with the U.S. Department of Energy on Form EIA-23. These estimates are consistent with the reserve data reported for the year ended December 31, 2001 in Note 15 to Consolidated Financial Statements, with the exception that Form EIA-23 includes only reserves from properties operated by the Company.

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, 2002, all of which are located in the United States:

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Drilling Activity

The following table summarizes the number of wells drilled during the years indicated. As of December 31, 2002, we were in the process of drilling 54 gross (42.3 net) wells.

Acreage

The following table summarizes developed and undeveloped leasehold acreage in which we own a working interest as of December 31, 2002. Excluded from this summary is acreage related to royalty, overriding royalty and other similar interests.

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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 quantities produced for the indicated period:

Delivery Commitments

Under a production payment, we have committed to deliver 16 Bcf (13.0 Bcf net to XTO’s interest) beginning approximately September 2006. Delivery of the committed volumes is in East Texas. See Note 8 to Consolidated Financial Statements.

As partial consideration for an acquisition, we agreed to sell gas volumes of 35,000 Mcf per day in 2003 at specified discounts from index prices. Delivery of 20,000 Mcf per day of these volumes is from the San Juan Basin, with the remainder from the East Texas Basin.

As part of an acquisition, we assumed a commitment to sell 6,800 Mcf of gas per day in Arkansas through April 2003 at prices which are adjusted by the monthly index price. The prices ranged from $0.46 to $0.72 per Mcf in 2002.

The Company’s production and reserves are adequate to meet the above sales commitments.

Competition and Markets

We face competition from 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. Many of our competitors have substantially larger financial and other resources. Factors that affect XTO’s 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 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.

Our ability to market oil and gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the proximity of our gas production to pipelines, the available capacity in such pipelines, the demand for oil and gas, and the effects of weather and state and federal regulation. We cannot assure that we will always be able to market all of our production at favorable prices. The Company does not currently believe that the loss of any of our oil or gas purchasers would have a material adverse effect on our operations.

Decreases in oil and gas prices have had and could have in the future an adverse effect on our acquisition and development programs, proved reserves, revenues, profitability, cash flow and dividends. See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “General—Product Prices.”

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Federal and State Regulations

There have been, and continue to be, 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 this regulatory burden is often difficult and costly and may carry substantial penalties for noncompliance. The following are some specific 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 sale for resale of natural gas is subject to federal regulation, including transportation rates charged and various other matters, by the Federal Energy Regulatory Commission (“FERC”). 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. We cannot predict the impact of future government regulation on any natural gas facilities.

Although FERC’s regulations should generally facilitate the transportation of gas produced from our properties and the direct access to end-user markets, the future impact of these regulations on marketing XTO’s production or on its gas transportation business cannot be predicted. The Company, however, does not believe that it 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 operations 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. 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 XTO cannot predict whether any further rules will be adopted or, if adopted, the effect these rules may have on its 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.

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Environmental Regulations

Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. Management believes that we are in substantial compliance with applicable environmental laws and regulations. To date, we have not expended any material amounts to comply with such regulations, and management does not currently anticipate that future compliance will have a materially adverse effect on the consolidated financial position or results of operations of XTO.

Employees

We had 867 employees as of December 31, 2002. None of the employees are represented by a union. 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, 54, was a co-founder of XTO with Mr. Palko and has been Chairman and Chief Executive Officer of the Company 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.

Steffen E. Palko, 52, was a co-founder of XTO with Mr. Simpson and has been Vice Chairman and President or held similar positions with the Company since 1986. Mr. Palko was Vice President—Reservoir Engineering (1984-1986) and Manager of Reservoir Engineering (1982-1984) of Southland Royalty Company.

Louis G. Baldwin, 53, 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.

Keith A. Hutton, 44, has been 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, 48, has been 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).

Bennie G. Kniffen, 52, 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.

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Item 3. LEGAL PROCEEDINGS

On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross Timbers Oil Company, was filed against us in the District Court of Dewey County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which we have assumed the obligation to pay royalties. The plaintiffs allege that we reduced royalty payments by post-production deductions and entered into contracts with subsidiaries that were not arm’s-length transactions. The plaintiffs further allege that these actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions are a breach of the leases under which the royalties are paid. These deductions allegedly include production and post-production costs, marketing costs, administration costs and costs incurred by us in gathering, compressing, dehydrating, processing, treating, blending and/or transporting the gas produced. We contend that, to the extent any fees are proportionately borne by the plaintiffs, these fees are established by arm’s-length negotiations with third parties or, if charged by affiliates, are comparable to fees charged by third party gatherers or processors. We further contend that any such fees enhance the value of the gas or the products derived from the gas. The parties have signed a settlement agreement under which we will pay $2.5 million to settle the plaintiffs claims for the period January 1, 1993 through June 30, 2002. Our portion of this liability, net of amounts allocable to Hugoton Royalty Trust units we do not own, is $2.1 million, which has been accrued in our financial statements. The court has tentatively approved the settlement, subject to a fairness hearing in April 2003.

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 against us and certain of our subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The plaintiff alleges that we underpaid royalties on gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% during at least the past 10 years as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. The plaintiff also alleges that we have failed to pay the fair market value of the carbon dioxide produced. According to the U.S. Department of Justice, the plaintiff has made similar allegations in over 70 actions filed against more than 300 other companies. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each violation and attorney fees and expenses. The plaintiff also seeks an order for us to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene and asked the court to unseal the case. The court unsealed the case in May 1999. A multi-district litigation panel ordered that the lawsuits against us and other companies filed by Grynberg be transferred and consolidated to the federal district court in Wyoming. 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 February 2000, the Department of Interior notified us and several other producers that certain Native American leases located in the San Juan Basin had expired because of the failure of the leases to produce in paying quantities from February through August 1990. The Department of Interior demanded abandonment of the property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. We have reached a tentative settlement with the Department of Interior to pay $288,000 in settlement of all claims. The settlement should be finalized in second quarter 2003. Management’s estimate of the potential liability from this claim 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. (formerly Quinque case). 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. 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. 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 and one of our subsidiaries were dismissed from the

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suit and another subsidiary was added. A hearing on whether to certify the case as a class action was held in January 2003, and the decision of the court is pending. We elieve 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.

We are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Company 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

No matters were submitted for a vote of security holders during the fourth quarter of 2002.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

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 2002 and 2001 (as adjusted for the four-for-three stock split effected on March 18, 2003 and the three-for-two stock split effected on June 5, 2001):

The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Company’s Board of Directors and will depend on our financial condition, earnings and funds from operations, the level of our capital expenditures, dividend restrictions in our financing agreements, our future business prospects and other matters as the Board of Directors deems relevant. Our revolving credit agreement with banks restricts the amount of dividends to 25% of cash flow from operations, as defined, for the latest four consecutive quarterly periods. The Company’s 7½% senior notes and 8¾% senior subordinated notes also place certain restrictions on distributions to common stockholders, including dividend payments.

On February 18, 2003, the Board of Directors declared a quarterly dividend of $0.01 per share payable on April 15, 2003 to stockholders of record on March 31, 2003. Because of the four-for-three stock split effected on March 18, 2003, this represents a 33% increase in the dividend rate. On March 19, 2003, we had approximately 683 stockholders of record.

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Item 6. SELECTED FINANCIAL DATA

The following table shows selected financial information for the five years ended December 31, 2002. Significant producing property acquisitions in each of the years presented, other than 2000, 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 March 18, 2003 and the three-for-two stock splits effected in February 1998, September 2000 and 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).

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