XTO ENERGY INC - 10-K Annual Report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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. x

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Aggregate market value of the Common Stock based on the closing price on the New York Stock Exchange as of June 30, 2004 (the last business day of its most recently completed second fiscal quarter), held by nonaffiliates of the Registrant on that date was approximately $7.3 billion.

Number of Shares of Common Stock outstanding as of February 25, 2005 (as adjusted for the four-for-three stock split to be effected March 15, 2005) - 347,389,307

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, 2005.

Index to Financial Statements

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.

On February 15, 2005, our Board of Directors declared a four-for-three stock split to be effected on March 15, 2005. All common stock shares and per share amounts in this Form 10-K have been retroactively restated for the effect of this stock split.

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 strategic 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 2005, 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 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, 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

Index to Financial Statements

Our estimated proved reserves at December 31, 2004 were 4.71 Tcf of natural gas, 38.5 million Bbls of natural gas liquids and 152.5 million Bbls of oil, based on December 31, 2004 prices of $5.69 per Mcf for gas, $28.24 per Bbl for natural gas liquids and $41.03 per Bbl for oil. On an energy equivalent basis, our proved reserves were 5.86 Tcfe at December 31, 2004, a 40% increase from proved reserves of 4.18 Tcfe at the prior year end. Increased proved reserves during 2004 were primarily the result of acquisitions and development and exploitation activities. On an Mcfe basis, 72.3% of proved reserves were proved developed reserves at December 31, 2004 . During 2004, our average daily production was 834,572 Mcf of gas, 7,484 Bbls of natural gas liquids and 22,696 Bbls of oil. Fourth quarter 2004 average daily production was 915,905 Mcf of gas, 8,628 Bbls of natural gas liquids and 33,494 Bbls of oil.

Our properties have relatively long reserve lives and highly predictable production profiles. Based on December 31, 2004 proved reserves and projected 2005 production from properties owned as of December 31, 2004, the average reserve-to-production index of our proved reserves is 15.1 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, 2004, we owned interests in 18,104 gross (8,455.8 net) producing wells, and we operated wells representing 88% 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 3,100 and 3,850 potential development 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 geological and reservoir characteristics.

We operate gas gathering systems in several of our core producing areas. We also operate gas processing plants in East Texas, the Hugoton Field 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.

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

Index to Financial Statements

million units pursuant to an employee incentive plan in 1999 and 2000. We own the remaining 54% of the units, which we account for as producing properties. Hugoton Royalty Trust units are listed on the New York Stock Exchange under the symbol “HGT.”

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.

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.

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

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

Index to Financial Statements

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 3,100 and 3,850 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 2005, 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 $30 million of our $850 million 2005 development budget for exploration activities.

Hedging Activities. To reduce production price risk, 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. 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:

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 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 2005, we announced a strategic goal for 2005 of increasing production by 21% to 23% over 2004 levels. To achieve this growth target, we plan to drill about 735 (560 net) development wells and perform approximately 540 (400 net) workovers and recompletions in 2005.

We have budgeted $850 million for our 2005 development program, which is expected to be funded by cash flow from operations. We plan to spend $400 million in the Eastern Region of East Texas and northwestern Louisiana, $170 million in the Barnett Shale of North Texas, $85 million in the Raton, San Juan and Uinta basins, $85 million for programs in the Permian Basin, and $80 million in the Arkoma Basin and Mid-Continent Region. We expect to spend $30 million for exploration.

Index to Financial Statements

While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2005. 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 2005 may alter the amount currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2005 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.

The weak U.S. dollar, 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.

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 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 $153.8 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. Approximately 10% of these reserves were proved undeveloped.

During 2003, we acquired gas-producing properties for a total cost of $629.5 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. Approximately 12% of these reserves were proved undeveloped.

During 2004, we acquired producing properties for a total cost of $1.9 billion. In January 2004, we acquired producing properties in East Texas and northwestern Louisiana for $243 million from multiple parties. From February through April, we purchased $223.1 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 $72.3 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, including a contingent payable of up to $5 million dependent on earnings from one property in the following year. In August, we acquired properties from ChevronTexaco Corporation for a purchase price of $930 million, as adjusted for subsequent purchase of properties that were subject to preferential purchase rights. These properties expand our operations in our Eastern Region, the Permian Basin and Mid-Continent Region and add new coal bed methane properties in the Rocky Mountains and a new operating region in South Texas. All 2004 acquisitions are subject to typical post-close adjustments. Our 2004 acquisitions increased reserves by approximately 716.5 Bcf of natural gas, 2.9

Index to Financial Statements

million Bbls of natural gas liquids and 98.2 million Bbls of oil. Approximately 18% of these reserves were proved undeveloped.

In January 2005, we announced an agreement to purchase privately held Antero Resources Corporation, a prominent Barnett Shale producer, for cash and equity consideration valued at approximately $685 million. Consideration includes $337.5 million in cash, 13.3 million shares of our common stock and five-year warrants to purchase another 2 million shares of our common stock at $27 per share. The purchase agreement was amended in February 2005 to include Antero’s gas gathering assets and related bank debt of $175 million. The transaction is expected to close April 1, 2005. The booked acquisition cost will include customary non-cash adjustments, including a step-up adjustment for deferred income taxes. The cash consideration for the acquisition will be initially provided through cash flow from operations and existing bank credit facilities.

The following table summarizes proved reserves and discounted present value, before income tax, of proved reserves by major operating areas at December 31, 2004:

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. During 2004, we increased our position in the Eastern Region with the purchase of 102 Bcfe of proved reserves in Franklin, Freestone, Limestone and Anderson counties of Texas and Claiborne Parish of Louisiana. Development in the East Texas area has more than doubled reserves since we began operations, and we now have an interest in more than 375,000 gross (258,000 net) acres and a current development inventory of 1,450 to 1,700 wells. We own an interest in 1,935 gross (1,726.5 net) wells that we operate and 447 gross (72.1 net) wells operated by others. We also own the related gathering facilities. In 2004, we expanded our gathering system to more than 600 miles and our treating capacity to more than 700,000 Mcf per day.

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 2004, where 185 gross (166.1 net) gas wells were

Index to Financial Statements

drilled and 14 workovers were performed. In 2004, we increased our acreage position to 225,000 gross (166,500 net) acres in this area and have a development inventory of 1,100 to 1,300 wells. 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. We plan to continue our expansion efforts in this area by drilling approximately 175 wells and performing about 26 workovers in 2005. In 2002, we completed a 27-mile pipeline system that connects the major fields and allows multiple exit points for marketing. During 2004, we continued expansion of the pipeline and gathering systems with the completion of an amine plant and a sour treating facility. We plan to complete an additional sour treating facility during the first half of 2005. These improvements have increased our pipeline capacity to over 700,000 Mcf per day. We will continue to construct and operate infrastructure or contract additional pipeline capacity to support our drilling activity.

Other fields in the Eastern Region include the Opelika, Willow Springs, Whelan, Oak Hill and Carthage fields in the East Texas area and the Middlefork, Oaks/Colquitt, Cotton Valley and Logansport fields in northwestern Louisiana. With our 2004 acquisitions, we increased our position in these areas, which provides opportunities for field extensions and infill drilling. In 2004, we drilled 37 gross (27.0 net) wells and performed 22 workovers in the other Eastern Region fields. In 2005, we plan to drill ten wells in the Carthage area, 27 wells in northwestern Louisiana and 25 wells in various fields and perform 28 workovers and recompletions. As a part of our 2002 acquisition from Marathon, we acquired an interest in a Cotton Valley gas plant that we now operate. This plant processes approximately 38,000 Mcf of gas per day and extracts 1,825 Bbls of natural gas liquids per day, primarily from the surrounding operated wells.

The Barnett Shale is the largest natural gas field in Texas and covers 15 counties. Our operations in the Barnett Shale began in January 2004 with the acquisition of 118 Bcfe of reserves. We have continued to expand our acreage positions and, by year end, had leased more than 80,000 net acres and identified 250 to 300 potential drilling locations. We drilled 20 gross (18.4 net) wells in 2004, ten of which were horizontal wells. In January 2005, we announced the acquisition of Antero Resources Corporation, including 440 Bcfe of proved reserves and a gas gathering system. This acquisition will make us the second largest producer in the Barnett Shale and will increase our net acreage holdings to 148,000 acres. We plan to drill 120 to 130 Barnett Shale wells in 2005.

Our San Juan Basin and Rocky Mountain Area includes properties in the San Juan and Raton basins of New Mexico and Colorado, as well as properties in the Powder River Basin of Wyoming and the Uinta Basin of Utah. We have now identified 575 to 775 potential drilling locations to develop these complex, multi-pay basins where we own an interest in 1,892 gross (1,625.2 net) operated wells and 2,337 gross (286.4 net) wells operated by others.

The San Juan Basin of northwestern New Mexico and southwestern Colorado contains the largest deposit of natural gas reserves in North America. Our San Juan Basin drilling has 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. We own an interest in 1,194 gross (990.0 net) wells that we operate and 2,288 gross (279.8 net) wells operated by others. In 2004, we participated in the drilling of 102 gross (71.8 net) wells and completed 177 workovers. During 2005, we plan to drill up to 75 wells and perform approximately 200 workovers and recompletions, including installation of as many as 70 wellhead compressors and 130 pumping units.

In 2003, we acquired natural gas and coal bed methane properties in the Raton Basin of Colorado. The Raton Basin is characterized by shallow prolific coal bed methane production, low development cost, available gas market access points and significant development opportunities. Producing formations include the Raton Coals at depths of 500

Index to Financial Statements

to 1,800 feet and the Vermejo Coals at depths of 800 to 2,500 feet. We own an interest in 238 gross (237.9 net) wells that we operate. We drilled 38 gross (38.0 net) wells and performed ten workovers in this area in 2004 and plan to drill 20 wells and perform 30 workovers in 2005.

Hartzog Draw Unit. During 2004, we acquired a 78.6% working interest in this 35,000 acre unit in northeastern Wyoming from ExxonMobil. We have initiated a program to optimize secondary recovery operations and drill additional wells. In the Powder River Basin, coal bed methane development from the shallow Fort Union coal bed zones (Big George), delineated under 12,500 net acres, offers immediate opportunities for new production and reserves. We drilled 31 gross (10.0 net) wells in 2004. We plan to drill approximately 25 to 50 wells and perform 67 workovers in this area in 2005.

Uinta Basin. During 2004, as a part of our ChevronTexaco acquisition, we expanded our coal bed methane operations with the purchase of 67 Bcfe of proved reserves in the Buzzard Bench Field of Emery County, Utah. This property in the Ferron sand and coal play is an offset to the Drunkard’s Wash Field. We have identified 100 to 150 potential well locations in this area where we own an interest in 93 gross (70.3 net) operated wells and 5 gross (1.3 net) wells operated by others. We drilled three gross (2.5 net) wells in 2004 and plan to drill 15 wells in 2005.

During 2004, we acquired approximately 80 million BOE of proved reserves in 16 counties in the Permian Basin of West Texas and New Mexico from ChevronTexaco. Primary producing fields in the area include Yates, Goldsmith, Eunice Monument, Fullerton and Puckett. We have a development inventory of between 475 and 575 potential well locations where we plan to use our secondary recovery expertise to enhance operations and expand development opportunities. We also purchased from ExxonMobil operated interests in the Wasson, Russell, Champmon and Bruce fields and nonoperated working interests in the Flanagan and Wasson fields.

Yates Field. The Yates Field, discovered in 1926, is located in southeastern Pecos County, Texas. We own nonoperated interests in 442 gross (127.8 net) wells, and most production is from the San Andres formation. Results have been improved using carbon dioxide injection and horizontal sidetrack wells. In 2005, the operator plans to drill approximately 110 horizontal sidetrack wells.

Goldsmith Field. The Goldsmith Field, located in Ector County, Texas, is a multi-pay zone field including production from the San Andres, Upper and Lower Clearfork, Devonian and Ellenburger formations at depths ranging from 4,000 to 9,000 feet. The field consists of multiple waterflood units in the Clearfork formation and adjacent units are currently being developed on 10 to 20-acre spacing. We plan to drill 17 wells and perform 30 workovers in this area in 2005.

Russell Field. As a result of acquiring additional working interests from ExxonMobil in 2004, we now have a working interest in excess of 97% in most of our Russell Field wells. Producing formations include the Devonian and Clearfork, as well as exploration potential in the Ellenburger and Granite Wash formations. We drilled seven gross (6.8 net) wells in 2004 and began a 3-D seismic study in February 2005. We plan to drill approximately 21 wells and perform 30 workovers in this area in 2005.

University Block 9 Field. The University Block 9 Field is in Andrews County, Texas. We own interests in 81 gross (77.3 net) operated wells. Productive zones include the Wolfcamp, Pennsylvanian and Devonian. Development potential includes proper wellbore utilization, recompletions, infill drilling and waterflood improvement. We drilled four gross (4.0 net) wells in 2004 and performed four workovers. During 2005, we plan to drill up to 13 wells.

Prentice Field. The Prentice Field is in Terry and Yoakum counties, Texas, and produces from the Clearfork and Glorieta formations. This field has been separated into several waterflood units for secondary recovery operations. Development potential exists through infill drilling and waterflood improvement. We operate the Prentice Northeast Unit, where we have a 91.6% working interest in 216 wells. We also own interests in 71 gross (2.9 net) nonoperated wells. During 2004, we continued our 10-acre development program by drilling nine gross (8.2 net) vertical wells and

Index to Financial Statements

performing two workovers. We plan to continue our expansion of the potential infill area by drilling as many as ten wells in 2005.

Wasson Field. The Wasson Field is in Gaines and Yoakum counties, Texas and produces from the San Andres formation. We acquired the Mahoney lease in 2004 from ExxonMobil and became operator. This property is being carbon dioxide flooded and recent development has included fracturing and restimulation. The Cornell Unit has development potential that exists through infill drilling and waterflood improvement. We increased our working interest in this unit to 99.8% in 2004 as a result of the ExxonMobil acquisition. In 2004, we drilled three gross (2.1 net) 10-acre infill oil wells and three gross (2.1 net) gas cap wells in the Cornell Unit, and in 2005 we plan to drill 15 oil wells and two gas cap wells.

We acquired 54 Bcfe of proved reserves in nine South Texas counties as a part of our 2004 ChevronTexaco acquisition. The Fashing Field, located in Atascosa County, primarily produces from the Edwards Limestone reservoir at depths ranging from approximately 10,000 to 11,000 feet. We have identified 20 to 40 potential well locations in this region and plan to drill six wells in 2005.

The Arkoma Basin extends from central Arkansas into southeastern Oklahoma and is known for low production decline rates, multiple formations and complex geology. We control 40% of Arkansas production from the Arkoma Basin and are the largest natural gas producer in the state with over 600,000 gross acres of leasehold. With the addition of our leasehold acreage in eastern Oklahoma, we have interests in approximately 800,000 gross acres in the Arkoma Basin. We own an interest in 1,261 gross (895.9 net) wells which we operate and 982 gross (169.5 net) wells operated by others. Our fault-block analysis technique has identified trapped hydrocarbons in offsetting and new reservoirs across the basin. During 2004, we drilled 98 gross (51.7 net) wells and completed 43 workovers, 17 of which were stimulation/recompletions and four of which were wellhead compressor installations. We plan to drill approximately 56 wells and perform up to 55 workovers in 2005.

A substantial portion of properties in western Oklahoma, 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.

We are one of the largest producers in the Major and Woodward counties, Oklahoma area of the Anadarko Basin. We operate 575 gross (489.6 net) wells and have an interest in 139 gross (36.6 net) wells operated by others. Development in Major County focuses on mechanical improvements, restimulations and recompletions to shallower zones and development drilling. During 2004, we participated in the drilling of 12 gross (8.6 net) wells in the northwestern portion of the county, targeting the Mississippian and Chester formations, and performed eight workovers. We plan to drill eight wells and perform ten workovers in Major County during 2005. We also drilled 12 gross (9.5 net) Chester formation wells in Woodward County. In 2005, we plan to drill up to ten wells and to perform as many as five workovers.

We operate a gathering system and pipeline in the Major County area. The system collects gas from over 400 wells through 300 miles of pipeline. Current throughput is approximately 15,000 Mcf per day, 70% of which is produced from Company-operated wells. Gas is processed at a third party plant and then transmitted to an interstate pipeline.

The Hugoton Field covers parts of Texas, Oklahoma and Kansas and is one of the largest domestic gas fields with an estimated five million productive acres. We own an interest in 373 gross (350.5 net) operated wells and 78 gross (18.9 net) wells operated by others. During 2004, we continued our restimulation program in the Chase intervals with 33 restimulations. We plan to drill as many as seven wells and perform 50 Chase restimulations during 2005.

Index to Financial Statements

Approximately 75% of our Hugoton gas production is delivered to the Tyrone Plant, an operated gas processing plant. Improvements in the Hugoton area have included the acquisition of low pressure gathering lines and installation of lateral compressors that lowered the line pressure and increased production.

The Green River Basin is located in southwestern Wyoming. We have interests in 195 gross (193.5 net) operated wells and 34 gross (4.3 net) wells operated by others in the Fontenelle Field area. Gas production is from the Frontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000 feet. Development potential for this area includes deepening and opening new producing zones in existing wells, drilling new wells and adding compression to lower line pressures. During 2004, we drilled seven gross (7.0 net) wells and performed 13 workovers. During 2005, we plan to perform seven workovers and drill up to ten wells in the Green River Basin.

We own a 100% working interest in two State of Alaska leases and offshore installations in the Middle Ground Shoal Field of the Cook Inlet. The properties include 27 wells, two platforms set in 70 feet of water about seven miles offshore, and a 50% interest in operated production pipelines and onshore processing facilities. The field has produced more than 130 million Bbls and 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 from multiple zones within the Tyonek formation. We drilled two sidetrack wells in 2004 and plan to drill one East Flank well and one West Flank well in 2005.

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.

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.”

Index to Financial Statements

The following are estimated quantities of proved reserves and related cash flows as of December 31, 2004, 2003 and 2002:

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, 2004, 2003 and 2002. 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. Year-end 2004 average realized prices used in the estimation of proved reserves 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.

In our prior reports, the estimated future net cash flows from proved reserves and related present value amounts were reported before reduction for estimated operated overhead expense. Operated overhead is a component of production expense in the consolidated income statements and is an allocation from general and administrative expense of the costs estimated to support the production function. As part of its periodic review of our filings, the staff of the Securities and Exchange Commission concluded that production expense components for proved reserve disclosures should be consistent with components of production expense recorded in the financial statements. Accordingly, we have restated estimated future net cash flows and the related present value amounts for all years presented, resulting in a reduction to these amounts of approximately 2% at December 31, 2003 and 3% at December 31, 2002.

Estimated future net cash flows, and the related 10% discounted present value, of year-end 2004 proved reserves are significantly higher than at year-end 2003 because of increased reserves related to acquisitions and development and higher oil and natural gas liquids prices used in the estimation of year-end proved reserves. Year-end 2003 product prices were $5.71 per Mcf for gas, $23.17 per Bbl for natural gas liquids and $30.55 per Bbl for oil.

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

Index to Financial Statements

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 2004, we filed estimates of oil and gas reserves as of December 31, 2003 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, 2003 in Note 15 to Consolidated Financial Statements, with the exception that Form EIA-23 includes only reserves from properties that we operate.

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.

The following table summarizes producing wells as of December 31, 2004, all of which are located in the United States:

The following table summarizes the number of wells drilled during the years indicated. As of December 31, 2004, we were in the process of drilling 284 gross (121.2 net) wells.

Index to Financial Statements

The following table summarizes developed and undeveloped leasehold acreage in which we own a working interest as of December 31, 2004. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

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:

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.

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

Index to Financial Statements

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.

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. We do 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, “Significant Events, Transactions and Conditions - Product Prices.”

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 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.

After failing to pass legislation in 2003 and 2004, Congress is currently considering a new energy bill. The potential effect of this legislation is unknown, but it may include certain tax incentives for oil and gas producers and changes in the federal regulatory framework.

The interstate transportation and certain sales for resale of natural gas, including transportation rates charged and various other matters, is 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. We cannot predict the impact of future government regulation on any natural gas facilities.

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

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.

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

Index to Financial Statements

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 we cannot predict whether any further rules will be adopted or, if adopted, the effect these rules may have on our gathering systems.

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.

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. 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. 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 our consolidated financial position or results of operations.

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 had 1,356 employees as of December 31, 2004. We consider our relations with our employees to be good.

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

Bob R. Simpson, 56, was a co-founder of the Company with Mr. Palko 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.

Steffen E. Palko, 54, was a co-founder of the Company with Mr. Simpson and has been Vice Chairman and President or held similar positions since 1986. Mr. Palko was Vice President - Reservoir Engineering (1984-1986) and Manager of Reservoir Engineering (1982-1984) of Southland Royalty Company.

Index to Financial Statements

Louis G. Baldwin, 55, 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, 46, 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, 50, 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, 54, 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.

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 has been scheduled for March 2005. 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. (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. 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 has set an evidentiary hearing in April 2005 to determine whether the amended class should be certified. 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

Index to Financial Statements

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 has set an evidentiary hearing in April 2005 to determine whether the amended class should be certified. 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 allege that the defendants have 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 seek 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 are leased to or operated by Huber or us, except to the extent that the lessors or their successors have 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 have assumed the responsibility for certain liabilities of Huber prior to the effective date, which may include 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 tentative settlement of approximately $5.1 million, resulting in an additional loss of approximately $2 million to be recorded in first quarter 2005.

In December 2004, the U.S. Environmental Protection Agency issued a Compliance Agreement and Final Order to us, which cited certain violations concerning the discharge of produced water and sanitary wastes into Alaska’s Cook Inlet from our two operated production platforms from January 2000 through June 2004. We reported these discharges to the EPA as part of our offshore discharge permit monitoring. We have agreed to pay a monetary penalty of $139,000 and have accrued this amount in our financial statements.

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.

A Special Meeting of the Shareholders of the Company was held on November 16, 2004, to vote on the proposed 2004 Stock Incentive Plan. All common shares in this Item 4 have been retroactively restated for the effect of the four-for-three stock split to be effected on March 15, 2005. A total of 268,690,021 of the Company’s shares were present at the meeting in person or by proxy, which represented 77% of our outstanding shares as of September 30, 2004, the record date for the Special Meeting.

Shareholders approved the 2004 Stock Incentive Plan, based on the following vote tabulation:

Index to Financial Statements

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 2004 and 2003 (as adjusted for the four-for-three stock split to be effected on March 15, 2005, the five-for-four stock split effected in March 2004, and the four-for-three stock split effected in March 2003):

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

On February 15, 2005, the Board of Directors declared a quarterly dividend of $0.05 per common share payable on April 15, 2005 to stockholders of record on March 31, 2004. As a result of the four-for-three stock split to be effected on March 15, 2005, this represents a 33% increase in our dividend rate. On February 23, 2005, we had 1,054 stockholders of record.

The following summarizes purchases of our common stock during fourth quarter 2004:

Index to Financial Statements

The following table shows selected financial information for each of the years in the five-year period ended December 31, 2004. 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 to be effected on March 15, 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 splits effected in June 2001 and September 2000. 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).

Index to Financial Statements

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.

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 we consider our gathering, processing and marketing as ancillary functions to our production of natural gas, natural gas liquids and crude oil, we have determined that our business comprises only one industry segment.

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, cash flow from operating activities, or a combination of these sources. Maintaining or improving our debt-to-capitalization ratio is a primary consideration in selecting our method of acquisition financing.

During 2004, we acquired $1.9 billion of producing properties with proved reserves of 716.5 Bcf of natural gas, 2.9 million Bbls of natural gas liquids and 98.2 million Bbls of oil. In January 2005, we announced an agreement to acquire Antero Resources Corporation, a prominent producer in the Barnett Shale of North Texas, for cash and equity consideration of approximately $685 million. The agreement was amended in February to include Antero’s gas gathering assets and related bank debt of $175 million.

Our goal for 2005 is to increase production by 21% to 23%. 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 3,100 and 3,850 potential development drilling locations. Our 2005 development budget is $850 million. While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2005. 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.

Index to Financial Statements

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 hedge a portion of our production at prices that ensure stable cash flow margins to fund our operating commitments and development program. As of February 25, 2005 we have hedged approximately 25% of our 2005 projected gas production at an average NYMEX price of $5.90 per Mcf and about 45% of our crude oil production at an average NYMEX price of $38.37 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 25% increase in gas production and a 75% increase in oil production resulted in a 64% increase in total revenues to $1.95 billion in 2004 from $1.19 billion in 2003. On an Mcfe produced basis, total revenues were $5.24 in 2004, a 26% increase from $4.15 in 2003.

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

Production expense rose 14% primarily because of the 75% increase in oil production, which is more expensive to produce than natural gas. Taxes, transportation and other expense generally is based on product revenues, and the 27% increase in this expense per Mcfe is primarily caused by increased product prices. The 10% increase in depreciation, depletion and amortization resulted from higher acquisition and development costs. The 5% increase in general and administrative expense is because of increased personnel and other costs related to Company growth.

Stock-based incentive compensation. This is a component of general and administrative expense and primarily relates to the vesting of performance shares when the common stock price reaches specified target levels. Incentive compensation was $89.5 million in 2004, a 69% increase from the comparable 2003 expense of $53.1 million. Included in 2004 incentive compensation is $22.3 million of cash compensation related to vesting of cash-equivalent performance shares. Otherwise, stock-based incentive compensation was non-cash. Increased incentive compensation is because of the 56% increase in the common stock price during 2004 and the resulting increased value of vested awards. After adjusting for the effect of the May 2004 and April 2003 common stock offerings, stock-based incentive compensation was approximately 3% of the increase in market capitalization during each of 2004 and 2003. Including stock-based incentive compensation, general and administrative expense increased $57.4 million, or 53%.

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. Derivative fair value losses of $11.9 million in 2004 and $10.2 million in 2003 were primarily related to the ineffective portion of hedge derivatives caused by the effect of increasing oil and gas prices on hedges in areas without basis or location differential contracts.

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. In January 2004, Standard & Poors upgraded our corporate credit rating to investment grade and all liens on producing properties and other collateral were

Index to Financial Statements

irrevocably released as security for our revolving credit agreement with commercial banks. As a result, Moody’s upgraded our existing senior notes to Ba1 from Ba2 and confirmed our Ba1 senior implied rating. In March 2004, Moody’s upgraded our issuer rating and senior implied rating to Baa3.

In February 2004, we fully repaid our revolving credit agreement and entered a new five-year revolving credit agreement with commercial banks that matures in February 2009. The agreement currently provides for a maximum commitment amount of $1 billion, and an interest rate based on the London Interbank Offered Rate plus 1%. On December 31, 2004, borrowings under the revolving credit agreement with commercial banks were $146 million at a weighted average interest rate of 3.49%, with unused borrowing capacity of $854 million. In November 2004, we borrowed $300 million under a five-year bank term loan due April 2010 with an initial interest rate of LIBOR plus 0.75%. Other terms and conditions are substantially the same as our existing revolving credit agreement.

Our consolidated financial position and results of operations are significantly affected by our critical accounting policies and estimates. We utilize the successful efforts method of oil and gas accounting that requires expensing of unsuccessful exploratory well costs, as well as exploratory geological and geophysical costs. All acquisition, development and successful exploratory well costs are generally capitalized and expensed through depreciation, depletion and amortization, which is computed on the unit-of-production method. If conditions indicate our properties may be impaired, we estimate future net cash flows from the applicable properties and compare this estimate to our total net cost of the properties. If the property cost cannot be recovered from the estimated future net cash flows, we must write down the property cost to the discounted present value of such future net cash flows. To date, our impairment of producing properties has been limited to a $2 million provision recorded in 1998. While we do not expect significant impairment provisions in the near future, any prolonged significant decline in commodity prices could require an impairment adjustment to our property cost. The amounts we record for depreciation, depletion and amortization and impairment are dependent upon our estimates of proved oil and gas reserves. Our proved reserve estimates are subject to potentially significant revisions based on subsequent drilling results and production data, changes in prices and costs, as well as other factors.

The following events, transactions and conditions affect the comparability of results of operations and financial condition for each of the years ended December 31, 2004, 2003 and 2002 and may impact future operations and financial condition.

Acquisitions. We acquired producing and undeveloped properties at a total cost of $2.0 billion in 2004, $629.5 million in 2003 and $358.1 million in 2002, 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:

Index to Financial Statements

In January 2005, we announced an agreement to purchase privately held Antero Resources Corporation, a prominent Barnett Shale producer, for cash and equity consideration valued at approximately $685 million. Consideration includes $337.5 million in cash, 13.3 million shares of our common stock and five-year warrants to purchase another 2 million shares of our common stock at $27.00 per share. The purchase agreement was amended in February 2005 to include Antero’s gas gathering assets and related bank debt of $175 million. The transaction is expected to close April 1, 2005. The booked acquisition cost will include customary non-cash adjustments, including a step-up for deferred taxes. The cash consideration for the acquisition will be initially provided through cash flow from operations and existing bank credit facilities.

2004, 2003 and 2002 Development and Exploration Programs. Gas development focused on the East Texas area and the Arkoma and San Juan basins during 2004, 2003 and 2002. Oil development was concentrated in Alaska and in the Permian Basin during all three years. Development costs totaled $572.1 million in 2004, $445.9 million in 2003 and $352.1 million in 2002. Exploration activity in 2004 was primarily geological and geophysical analysis, including seismic studies, of undeveloped properties. Exploration activity in 2003 and 2002 consisted primarily of drilling successful wells in East Texas. Exploratory costs were $15 million in 2004, $16.1 million in 2003 and $4.2 million in 2002. Our development and exploration activities are generally funded by cash flow from operations.

2005 Acquisition, Development and Exploration Program. We have budgeted $850 million for our 2005 development and exploration program, which we expect to fund by cash flow from operations. While an acquisition budget has not been formalized, we plan to continue to actively review additional acquisition opportunities during 2005. 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 2005 property acquisitions may alter the amount currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2005 to focus on opportunities offering the highest rates of return.

Index to Financial Statements

As of December 31, 2004, we have an inventory of between 3,100 and 3,850 potential drilling locations. We plan to drill about 735 (560 net) development wells and perform approximately 540 (400 net) workovers and recompletions in 2005. Drilling plans are dependent upon product prices and the availability of drilling equipment.

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 dependent upon North American supply and demand, which is affected by weather and economic conditions. Natural gas competes with alternative energy sources as a fuel for heating and the generation of electricity. The winter of 2001-2002 was one of the warmest on record, resulting in higher than average gas storage levels and lower gas prices in 2002. Prices climbed in fourth quarter 2002 as a result of low levels of drilling activity, increased industrial demand, colder weather and international instability. Colder than normal weather, record low gas storage levels and continued increasing demand caused gas prices to remain relatively high during the first five months of 2003. With diminished demand related to higher prices, natural gas prices were lower during the summer months, then rose with cooler weather in the fall and early winter. Forecasts for continued production declines, increasing natural gas demand and larger than projected storage withdrawals supported higher prices in the first six months of 2004. Mild summer weather and increased gas storage inventories led to declining gas prices in August and early September. Natural gas prices rose again in mid-September because of reduced gas production as a result of hurricanes in the Gulf of Mexico. Gas prices remained relatively high for the remainder of 2004 because of sporadic colder weather and lower gas supplies. With moderate temperatures and favorable supply, prices were lower in January 2005, but rose in February as a result of colder weather in the U.S. Northeast and Europe. Prices will continue to be affected by weather, the recovery of the domestic economy, increases in the level of North American production and import levels of liquified natural gas. In any case, management expects natural gas 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:

At February 25, 2005, the average NYMEX gas price for the following 12 months was $7.23 per MMBtu. As computed on an energy equivalent basis, our proved reserves were 80% natural gas at December 31, 2004. After considering hedges in place as of February 25, 2005, we estimate that a $0.10 per Mcf increase or decrease in the average gas sales price would result in approximately a $25 million change in 2005 annual operating cash flow before income taxes.

Oil. Crude oil prices are generally determined by global supply and demand. Oil prices declined in 2002 because of lagging demand caused by a global recession. Rising uncertainties in the Middle East led to higher prices late in 2002. During 2003, unusually low storage levels, the war in Iraq and production discipline by OPEC maintained oil prices at relatively high levels. Oil prices continued to increase in early 2004 because of increasing demand and low crude stocks. Despite increased production by OPEC members, oil prices exceeded $55 per Bbl in October because of continued instability in the Middle East and Nigeria and hurricanes in the Gulf of Mexico. With mild winter weather and an ample supply of oil stocks, prices declined in late 2004 but rebounded in January and February 2005 following global supply outages, colder weather in the U.S. Northeast and Europe and continued disruptions of Iraqi exports. 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:

Index to Financial Statements

At February 25, 2005, the average NYMEX oil price for the following 12 months was $50.62 per Bbl. After considering hedges in place as of February 25, 2005, we estimate that a $1.00 per barrel increase or decrease in the average oil sales price would result in approximately a $6 million change in 2005 annual operating cash flow before income taxes.

Hedging Activities. We 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 routinely hedge a portion of our production. 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 more predictable production growth and cash flows.

In 2004, all hedging activities decreased gas revenue by $156.1 million and decreased oil revenue by $15.5 million, while in 2003, all hedging activities decreased gas revenue by $193 million and decreased oil revenue by $3.9 million, and in 2002, hedging activities increased gas revenue by $95.4 million and decreased oil revenue by $1.3 million.

The following summarizes our January 2005 through December 2005 NYMEX hedging positions at February 25, 2005, excluding basis adjustments which are separately hedged. Our average daily production was 915,905 Mcf of gas and 33,494 Bbls of oil in fourth quarter 2004. 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.

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 an $11.9 million loss is 2004, a $10.2 million loss in 2003 and a $2.6 million gain in 2002 related to changes in fair value of these non-hedge derivatives. The 2004 loss includes a $12.5 million loss on the ineffective portion of hedge derivatives, or approximately 8% of total hedge derivative losses, while the 2003 loss includes a $7.3 million loss on the ineffective portion of hedge derivatives, or approximately 4% of total hedge derivative losses. Netted in the 2002 derivative fair value gain is a $2.9 million loss on the ineffective portion of hedge derivatives, or approximately 2% 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.

Unrealized derivative gains and losses associated with effective cash flow hedges are recorded in stockholders’ equity as accumulated other comprehensive income (loss). At December 31, 2004, we have an unrealized pre-tax loss of $45.1 million in accumulated other comprehensive income (loss) related to the fair value of derivatives designated as cash flow hedges of gas and crude oil price risk. This fair value loss is expected to be reclassified into earnings through December 2005. The actual reclassification to earnings will be based on mark-to-market prices at contract settlement date.

Stock-based Incentive Compensation. Incentive compensation generally results from vesting of performance share awards as our common stock price increases. Incentive compensation totaled $89.5 million in 2004, $53.1 million in 2003 and $27 million in 2002, which relates to increases in our stock price of 56% in 2004, 53% in 2003 and 41% in 2002. Included in 2004 incentive compensation is $22.3 million cash compensation related to vesting of cash-equivalent performance shares. Otherwise, stock-based compensation was non-cash. After adjusting for the effects of the May 2004 and April 2003 common stock offerings, stock-based incentive compensation was approximately 3% of the increase in market capitalization during each of 2004, 2003 and 2002. As of December 31, 2004, outstanding performance shares comprise 397,500 shares that vest when the common stock price reaches $28.13, 2,533 shares that vest when the common stock price reaches $28.50, and 397,500 shares that vest when the common stock price reaches $31.88. Based on

Index to Financial Statements

management’s estimated probable vesting period, $2.8 million of related stock incentive compensation was accrued at December 31, 2004. All performance shares vested in February 2005 when these target stock prices were attained, resulting in the remaining related non-cash compensation of $21.1 million to be recorded in first quarter 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 July 1, 2005. Accordingly, we will begin recording compensation related to stock options in third quarter 2005. See “Accounting Pronouncements” below.

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 $28.2 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 gain on distribution of $16.2 million.

Extinguishment of Debt. We purchased and canceled $9.7 million of our 9¼% senior subordinated notes in April 2002, and redeemed the remaining $115.3 million of the 9¼% notes in June 2002. In November 2002, we purchased and canceled $11.8 million of our 8¾% senior subordinated notes and redeemed the remaining $163.2 million of the 8¾% notes in May 2003. As a result of these transactions, we recorded a total pre-tax loss on extinguishment of debt of $9.6 million in 2003 and $8.5 million in 2002, which includes the effects of redemption premium paid and expensing related deferred debt costs.

Enron Corporation Bankruptcy and Settlement. In December 2001, after Enron Corporation filed for bankruptcy, we had recorded a $21.4 million receivable from Enron and a $43.3 million Btu swap contract payable to Enron. In December 2002, we paid Enron Corporation $6 million in settlement of all claims, resulting in recognition of $14.1 million in gas revenue and a $2.1 million gain.

Cumulative Effect of Accounting Change for Asset Retirement Obligation. On January 1, 2003, we adopted SFAS No. 143 by recording a long-term liability for asset retirement obligation of $75.3 million, an increase in property cost of $60.7 million, a reduction of accumulated depreciation, depletion and amortization of $17.3 million and a cumulative effect of accounting change gain, net of tax, of $1.8 million.

Impairment Provision. We evaluate possible impairment of producing properties when conditions warrant. This evaluation is based on an assessment of recoverability of net property costs from estimated future net cash flows from those properties. Estimated future net cash flows are based on management’s best estimate of projected oil and gas reserves and prices. We have not recorded impairment of producing properties since a $2 million provision was recorded in 1998. If oil and gas prices significantly decline, we may be required to record impairment provisions for producing properties in the future, which could be material.

Investment Grade Ratings. In January 2004, Standard & Poors upgraded our corporate credit rating to investment grade and all liens on producing properties and other collateral were irrevocably released as security for our revolving credit agreement with commercial banks. As a result, Moody’s upgraded our existing senior notes to Ba1 from Ba2 and confirmed our Ba1 senior implied rating. In March 2004, Moody’s upgraded our issuer rating and senior implied rating to Baa3.

Senior Note Offering. In April 2002, we sold $350 million of 7½% senior notes due April 2012, and in April 2003, we sold $400 million of 6¼% 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. Proceeds from the senior notes were used to fund property acquisitions, redeem senior subordinated notes and reduce bank debt.

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 8¾% senior subordinated notes and to reduce bank debt. In May 2004, we completed a public offering of 31.7 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.

Index to Financial Statements

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.

For the year 2004, net income was $507.9 million compared with net income of $288.3 million for 2003. Earnings for 2004 include the net after-tax effects of stock-based incentive compensation of $55.5 million, special bonuses totaling $11.7 million related to acquisitions announced in second quarter 2004, and a $7.4 million derivative fair value loss. Earnings for 2003 include the net after-tax effects of non-cash incentive compensation of $34.5 million, loss on extinguishment of debt of $6.2 million, a $6.6 million derivative fair value loss, a non-cash contingency gain of $1.1 million, a non-cash gain of $10.5 million resulting from the distribution of Cross Timbers Royalty Trust units as a dividend to common stockholders and a $1.8 million gain on the cumulative effect of the accounting change for adoption of SFAS No. 143 for asset retirement obligation.

Revenues for 2004 were $1.95 billion, or 64% higher than 2003 revenues of $1.19 billion. Gas and natural gas liquids revenue increased $572.8 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 $183.7 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 $5.4 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 $687.9 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 66%, or $69.4 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 $8.7 million primarily because of 2004 seismic studies conducted in the Barnett Shale and East Texas.

Depreciation, depletion and amortization (DD&A) increased $122.7 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.

General and administrative expense increased $57.4 million, or 53%, primarily because of an increase of $36.4 million in stock-based incentive compensation from $53.1 million to $89.5 million, of which $67.2 million is non-cash. General and administrative expense for the year also includes a total of $11.7 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 $11.9 million compared to the 2003 derivative fair value loss of $10.2 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.

Index to Financial Statements

Interest expense increased $29.9 million, or 47%, 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.

For the year 2003, net income was $288.3 million compared with net income of $186.1 million for 2002. Earnings for 2003 include the net after-tax effects of non-cash incentive compensation of $34.5 million, loss on extinguishment of debt of $6.2 million, a $6.6 million derivative fair value loss, a non-cash contingency gain of $1.1 million, a non-cash gain of $10.5 million resulting from the distribution of Cross Timbers Royalty Trust units as a dividend to common stockholders and a $1.8 million gain on the cumulative effect of the accounting change for adoption of SFAS No. 143 for asset retirement obligation. Earnings for 2002 include a $17.5 million after-tax charge for non-cash incentive compensation, a $5.5 million after-tax charge for extinguishment of debt, a $1.3 million after-tax gain on a settlement with Enron Corporation and a $1.7 million after-tax derivative fair value gain.

Revenues for 2003 were $1.19 billion, or 47% higher than 2002 revenues of $810.2 million. Gas and natural gas liquids revenue increased $359.2 million, or 53%, because of a 30% increase in gas production and a 17% increase in gas prices from an average of $3.49 per Mcf in 2002 to $4.07 in 2003, as well as a 40% increase in natural gas liquids prices from an average price of $14.31 per Bbl in 2002 to $19.99 in 2003 and a 28% increase in natural gas liquids production (see “Significant Events, Transactions and Conditions – Product Prices – Gas” above). Increased production was attributable to the 2003 acquisition and development program.

Oil revenue increased $19.7 million, or 17%, primarily because of an 18% increase in oil prices from an average of $24.24 per Bbl in 2002 to $28.59 in 2003 (see “Significant Events, Transactions and Conditions – Product Prices – Oil” above). A 1% decrease in production was the result of natural decline, partially offset by development. Gas gathering, processing and marketing revenues increased $1.4 million primarily because of higher natural gas liquids prices and margins. Other revenues of $2.1 million in 2002 represent the gain on a settlement with Enron Corporation.

Expenses for 2003 totaled $687.9 million as compared with total 2002 expenses of $461.3 million. Most expenses increased in 2003 because of increased production from acquisitions and development and related Company growth. Production expense increased $35.7 million, or 28%, because of higher production related to acquisitions and development. Production expense per Mcfe increased slightly from $0.57 in 2002 to $0.58 in 2003 because of increased fuel costs. Taxes, transportation and other increased 83%, or $47.4 million, primarily because of significantly higher oil and gas prices, increased production, higher transportation fuel prices and higher property taxes related to drilling and acquisitions. Taxes, transportation and other per Mcfe increased 48% from $0.25 in 2002 to $0.37 in 2003 primarily due to higher product prices.

DD&A increased $79.9 million, or 39%, primarily because of increased production and higher acquisition costs. On an Mcfe basis, DD&A increased from $0.90 in 2002 to $0.99 in 2003 because of higher acquisition and development costs.

General and administrative expense increased $45.6 million, or 73%, because of an increase of $26.1 million in stock-based incentive compensation and increased expenses from Company growth. Excluding this non-cash incentive compensation, general and administrative expense per Mcfe increased 27% from $0.15 in 2002 to $0.19 in 2003.

The derivative fair value loss for 2003 was $10.2 million compared to 2002 derivative fair value gain of $2.6 million. The 2003 loss is primarily related to the effect of higher gas prices on the fair value of Btu swap contracts and the ineffective portion of hedge derivatives. The 2002 gain is primarily the result of declining gas prices on derivatives that do not qualify for hedge accounting. See Note 7 to Consolidated Financial Statements.

Interest expense increased $10.2 million, or 19%, primarily because of a 24% increase in the weighted average borrowings to partially fund property acquisitions, offset by a 6% decrease in the weighted average interest rate. Interest expense per Mcfe decreased 8% from $0.24 in 2002 to $0.22 in 2003 because higher production offset increased borrowings.

During 2003, we recognized a $9.6 million loss on extinguishment of debt related to the redemption of our 8¾% senior subordinated notes, compared with the recognition in 2002 of an $8.5 million loss on extinguishment of debt

Index to Financial Statements

primarily related to the redemption of our 9¼% senior subordinated notes. See Note 3 to Consolidated Financial Statements. During 2003, we also recognized a $16.2 million gain on the distribution of Cross Timbers Royalty Trust units as a dividend to common stockholders.

Our primary sources of liquidity are cash flow from operating activities, borrowings against the revolving credit facility, occasional producing property sales (including sales of royalty trust units) 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 2005.

Cash provided by operating activities was $1.22 billion in 2004, compared with cash provided by operating activities of $794.2 million in 2003 and $490.8 million in 2002. Increased cash provided by operating activities from 2003 to 2004 and from 2002 to 2003 was primarily because of increased prices and production from acquisitions and development activity. Cash provided by operating activities was decreased by changes in operating assets and liabilities of $58.2 million in 2004 and $22.9 million in 2002 and was increased by changes in operating assets and liabilities of $3.7 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 $10.5 million in 2004, $1.8 million in 2003 and $2.2 million in 2002. Cash provided by operating activities is largely dependent upon the prices received for oil and gas production. As of February 2005, we have hedged approximately 25% of our projected 2005 gas production and about 45% of our projected 2005 crude oil production. See “Significant Events, Transactions and Conditions - Product Prices” above.

We do not have any investments in unconsolidated entities or persons that could materially affect the liquidity or the availability of capital resources.

Total assets increased 69% from $3.6 billion at December 31, 2003 to $6.1 billion at December 31, 2004, primarily because of Company growth related to acquisitions and development. As of December 31, 2004 total capitalization was $4.6 billion, of which 44% was long-term debt. Capitalization at December 31, 2003 was $2.7 billion, of which 46% was long-term debt. The decrease in the debt-to-capitalization ratio from year-end 2003 to 2004 is primarily because of our earnings for the year.

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 the loan agreement (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 decreased from a negative position of $59.4 million at December 31, 2003 to negative working capital of $64 million at December 31, 2004. Excluding the effects of current derivative and deferred tax assets and liabilities, working capital decreased $19.2 million. This decrease is because of increased accounts payable and accrued liabilities primarily related to increased production and drilling liabilities, partially offset by increased accounts receivable related to increased revenues. Any cash settlement of hedge derivatives should generally be offset by increased or decreased cash flows from our sales of related production. Therefore, we believe that most of the changes in derivative fair value assets and liabilities are offset by changes in value of our oil and gas reserves. This offsetting change in value of oil and gas reserves, however, is not recorded in the financial statements.

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

Index to Financial Statements

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.

In February 2004, we entered a five-year revolving credit agreement with commercial banks that matures in February 2009. The agreement currently provides for a maximum commitment amount of $1 billion, and an interest rate based on the London Interbank Offered Rate (“LIBOR”) plus 1%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 60%. On December 31, 2004, borrowings under the revolving credit agreement with commercial banks were $146 million at a weighted average interest rate of 3.49%, and with unused borrowing capacity of $854 million.

In November 2004, we entered a new $300 million five-year term loan due April 2010 with an initial interest rate of LIBOR plus 0.75%. Other terms and conditions are substantially the same as our existing revolving credit agreement. As of December 31, 2004, borrowings under the term loan were $300 million.

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 2004, exploration and development cash expenditures totaled $610 million compared with $461.6 million in 2003. We have budgeted $850 million for the 2005 development and exploration program. As we have done historically, we expect to fund the 2005 development program with cash flow from operations. Since there are no material long-term commitments associated with this budget, 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.

To date, we have not spent significant amounts to comply with environmental or safety regulations, and we do not expect to do so during 2005. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

The Board of Directors declared quarterly dividends of $0.0045 per common share each quarter of 2002, $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. In February 2005, the Board increased the dividend rate 33% by declaring

Index to Financial Statements

a first quarter 2005 dividend of $0.05 per common share after the four-for-three stock split is effected on March 15, 2005. In August 2003, the Board also 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 of Directors deems relevant.

We have estimated that all our net operating loss carryforwards will be fully utilized as of December 31, 2004. Although our alternative minimum tax credit carryforwards of $37.8 million have no expiration date, we expect to utilize these carryforwards in 2005.

The following summarizes our significant obligations and commitments to make future contractual payments as of December 31, 2004. 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.

Long-Term Debt. At December 31, 2004, borrowings were $146 million under our senior bank revolving credit facility due in February 2009, 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 $1.6 billion at December 31, 2004, 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 or pay for any deficiencies at a specified reservation fee rate. As calculated on a monthly basis, our failure to deliver these minimum volumes to the pipeline requires us to pay the pipeline for any deficiency. 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.

Purchase Obligations. We have agreed to acquire an airplane for $17.1 million, either through purchase or lease, and have made an initial payment of $6.8 million in 2004. We currently expect to take delivery of the airplane in the first half of 2005. This obligation is reflected as a purchase in the table above, net of the amount paid in 2004.

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, 2004, market prices generally exceeded the fixed prices specified by these contracts, resulting in a derivative fair value current liability of $75.5 million and long-term liability of $11.2 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. 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.

Index to Financial Statements

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 2004 was $632,000 and is expected to be approximately $1 million in 2005. 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.

A firm, partially owned by one of our directors, has performed property acquisition advisory services for the Company. We paid this firm total fees of $8.8 million in 2004 and $2.4 million in 2002, and there were no amounts payable at December 31, 2004 or 2003. No fees were paid to this firm in 2003. This same director-related company represented the seller of properties for acquisitions totaling approximately $186 million that we closed in January 2004. In February 2005, this firm was acquired by another company with which we expect to continue to have a relationship.

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 $37.8 million of these properties for 19,000 net contiguous acres in our new core operating area, the Barnett Shale of North Texas, and $25.4 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 $11.5 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.

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 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.

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

Index to Financial Statements

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.

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 2002 and 2003, resulting in a decrease of DD&A expense of approximately 4%, or $8 million, in 2002 and 1%, or $2 million, in 2003. 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, 2004, we estimate that a 1% change in proved reserves would increase or decrease 2005 DD&A expense by approximately $4 million.

During 2004, development and exploration activities resulted in extensions, additions, discoveries and net revisions of proved reserves that were 195% of our 2004 production. Over the last five years, our proved reserve extensions, additions, discoveries and net revisions averaged 220% of our production for this period. Our proved reserve extensions, additions and discoveries in 2004 included an increase of 637.6 Bcfe in proved undeveloped reserves, or approximately 80% of our total extensions, additions and discoveries, which are expected to be developed within three years. Over the past four years, approximately 80% 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.

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.

Index to Financial Statements

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 2004, we increased our estimated asset retirement obligation by $6 million, or approximately 6% of the asset retirement obligation at December 31, 2003, 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 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. We also have sold call options as part of our hedging program. Call options, however, do not provide a hedge against declining prices, and there is the risk that the call sales proceeds will be less than the benefit a higher sales price would have provided.

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 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.

Index to Financial Statements

future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. We must implement SFAS 153 for any nonmonetary asset exchanges occurring on or after January 1, 2006. This change in accounting is currently not expected to have a significant effect on our reported financial position or earnings.

In December 2004, the FASB issued Staff Position FAS 109-1 that concluded that the special tax deduction allowed under the American Jobs Creation Act of 2004 should be accounted for as a “special deduction” instead of a tax rate reduction as provided by SFAS 109. Accordingly, any tax relief the Company receives under the new tax law will be recorded as a reduction of current tax when realized, rather than an immediate reduction to its accrued deferred income tax liability.

Also 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, and will be effective beginning July 1, 2005. We have previously recorded stock compensation pursuant to the intrinsic value method under APB 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. For the pro forma effect of recording compensation for all stock awards at fair value, utilizing the Black-Scholes method, see Stock-Based Compensation in Note 1 to Consolidated Financial Statements. We are currently considering alternative valuation methods to determine stock award fair value for grants after June 30, 2005. We plan to use the modified prospective application method of adopting SFAS No. 123R, whereby the estimated fair value of unvested stock awards granted prior to July 1, 2005 will be recognized as compensation expense in periods subsequent to June 30, 2005, based on the estimated service period. The fair value of awards granted prior to July 1, 2005 will be the same value as determined under the Black–Scholes method for our pro forma disclosure. As of February 22, 2005, all stock options outstanding at that date vested when the common stock price closed above the target price level of $31.88, resulting in no compensation expense to be recognized after June 30, 2005 related to these awards.

In February 2005, the staff of the Securities and Exchange Commission sent a letter to oil and gas registrants regarding situations that require additional financial statement disclosures, pending final resolution of accounting treatment. The following are items related to registrants using the successful efforts method of accounting:

Index to Financial Statements

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. The consolidated balance sheets include the following amounts related to production imbalances:

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 and competition. 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 below.

Oil and Gas Price Fluctuations. Our results of operations depend upon the prices we receive for our oil and gas. Historically, the markets for oil and gas have been volatile and are likely to remain volatile in the future. We routinely hedge a portion of our production to reduce the effects of price volatility (see “Hedging Arrangements” below). Otherwise, the prices we receive depend upon factors beyond our control, including political instability in oil-producing regions, weather conditions, ability of OPEC to agree upon and maintain oil prices and production levels, consumer demand, worldwide economic conditions and the price and availability of alternative fuels. Moreover, government regulations, such as regulation of 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 gas. To the extent we have not hedged our production, any decline in oil and gas prices adversely affects our financial

Index to Financial Statements

condition. If the oil and gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations, make planned capital expenditures or reach production growth targets.

Debt Level. We have substantial debt and may incur more. If we are unsuccessful in increasing production from existing reserves or developing new reserves, we may lack the funds to pay principal and interest on our debt obligations. Our indebtedness also affects our ability to finance future operations and capital needs and may preclude pursuit of other business opportunities.

Capital Requirements. We make, and will continue to make, substantial capital expenditures for the acquisition, development, production, exploration and abandonment of our oil and gas reserves. We intend to finance our capital expenditures primarily through cash flow from operations, bank borrowings and public or private offerings of equity and debt. Lower oil and gas prices, however, may reduce cash flow available to pay down bank borrowings or other debt.

Competitive Industry. The oil and gas industry is highly competitive. We compete with major oil companies, independent oil and gas businesses, and individual producers and operators. In addition, there is competition from alternative energy sources, such as heating oil, imported liquified natural gas and other fossil fuels. Some of our competitors have financial, technological and other resources substantially greater than ours. These companies may be able to pay more for development prospects and productive oil and 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. We also compete with these companies for technical, managerial and other professional personnel. Our ability to develop and exploit our oil and gas properties and to acquire additional properties in the future will depend upon our ability to hire and retain qualified personnel, conduct operations, implement advanced technologies, evaluate and select suitable properties, and consummate transactions in this highly competitive environment.

Reserve Replacement. Our success depends upon finding, acquiring and developing oil and gas reserves that are economically recoverable. Unless we are able to successfully explore for, develop or acquire proved reserves, our proved reserves will decline through depletion and our financial assets and annual revenues will decline unless prices substantially increase. We cannot assure the success of our exploration, development and acquisition activities.

Hedging Arrangements. To reduce our exposure to fluctuations in the prices of oil and gas, we currently and may in the future enter into hedging arrangements for a portion of our oil and 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 agreements and actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and gas.

Reserve Estimates. Estimating our proved reserves involves many uncertainties, including factors beyond our control. Petroleum engineers consider many factors and make assumptions in estimating oil and gas reserves and future net cash flows. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures relating to our reserves will vary from any estimates, and these variations may be material.

Acquiring Producing Properties. We constantly evaluate opportunities to acquire oil and gas properties and frequently engage in bidding and negotiation for these acquisitions. If successful in this process, we may alter or increase our capitalization through the issuance of additional debt or equity securities, the sale of production payments or other measures. Any change in capitalization affects our risk profile. Acquisitions may also alter the nature of our business. This could occur when the character of acquired properties is substantially different from our existing properties in terms of operating or geologic characteristics.

Drilling Activities. Our drilling activities subject us to many risks, including the risk that we will not find commercially productive reservoirs. Drilling for oil and gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements and shortages or delays in the delivery of equipment and services can delay our drilling operations or result in their cancellation. Shortages of equipment, including pipe, can lead to a delay or suspension of drilling and can significantly increase the cost of drilling. The cost of drilling, completing and operating wells is often uncertain, and we cannot assure that new wells will be productive or that we will recover all or any portion of our investment.

Index to Financial Statements

Marketability of Production. The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could harm our business. We deliver some of our oil and gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future or access may be limited for extended periods due to maintenance or other curtailment.

Growth through Acquisitions. Our business strategy has emphasized growth through strategic 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 or not significant acquisitions are completed in particular periods.

Governmental Regulations. 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. Failure to comply with these laws and regulations also may 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 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. 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

Index to Financial Statements

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 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.

Operating Hazards and Uninsured Risks. Our operations are subject to inherent hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as fire, natural disasters, explosions, blowouts, formations with abnormal pressures, failure of oilfield drilling and service tools, uncontrollable flows of underground gas, oil and formation water, pipeline ruptures or cement failures and environmental hazards such as gas leaks and oil spills. Any of these events could cause a loss of hydrocarbons, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations, personal injury claims, loss of life, damage to our properties, or damage to the property of others. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. We believe that our insurance is adequate and customary for companies of similar size and operation, but losses could occur for uninsured risks or in amounts exceeding existing coverage. The occurrence of an event that is not fully covered by insurance could adversely affect our financial condition and results of operations.

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. The policy also requires review and approval by the Chairman, the Executive Vice President - Administration and the Senior Vice President - Marketing of all risk management programs using derivatives and all derivative transactions. These programs are also reviewed at least 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.

We are exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At December 31, 2004, our variable rate debt had a carrying value of $446 million, which approximated its fair value, and our fixed rate debt had a carrying value of $1.60 billion and an approximate fair value of $1.69 billion. We attempt to balance the benefit of lower cost variable rate debt that has inherent increased risk with more expensive fixed rate debt that has less market 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.

Index to Financial Statements

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.

We hedge a portion of our price risks associated with our crude oil and natural gas sales. As of December 31, 2004, we had outstanding gas futures contracts, swap agreements and gas basis swap agreements. These contracts and agreements had a net fair value loss of approximately $30.8 million at December 31, 2004 and a net fair value loss of $84.7 million at December 31, 2003. Of the December 31, 2004 fair value, a $34.8 million loss has been determined based on the exchange-trade value of NYMEX contracts, and a $4 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 $47.9 million in the fair value of gas futures contracts and swap agreements at December 31, 2004. As of December 31, 2004, outstanding oil futures contracts and differential swaps had a net fair value loss of $22.1 million. The aggregate effect of a hypothetical 10% change in oil prices would result in a change of approximately $20.6 million in the fair value of these oil futures and differential swaps at December 31, 2004. 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 at December 31, 2004 was $19.1 million. The effect of a hypothetical 10% change in gas prices would result in a change of approximately $5.6 million in the fair value of these contracts, while a 10% change in crude oil prices would result in a change of approximately $3.7 million. 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.

Index to Financial Statements

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

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, 2004.

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.

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.

There were no changes in our internal controls over financial reporting during the quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Index to Financial Statements

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, 2005.

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.

Index to Financial Statements

See Index to Exhibits at page 85 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.

Index to Financial Statements

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 the 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 to be 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 Texas, Oklahoma, Arkansas, Kansas, New Mexico, Colorado, Wyoming, Alaska, Utah and Louisiana. We also gather, process and market gas, transport and market oil and conduct other activities directly related to our oil and gas producing activities.

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 producing properties from other oil and gas companies. Producing properties balances include costs of $139.4 million at December 31, 2004 and $80.6 million at December 31, 2003 related to wells in process of drilling. Drill well costs are transferred to producing properties generally within one month of the well completion date. See Note 15 for information regarding exploratory well costs. Inventory held for future use on our producing properties totaled $34.7 million at December 31, 2004 and $6.5 million at December 31, 2003, and is included in other current assets on the consolidated balance sheet.

Depreciation, depletion and amortization of 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 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 undeveloped properties is assessed on a property-by-property basis, and impairment of other undeveloped properties is assessed and amortized on an aggregate basis.

Index to Financial Statements

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 producing properties on the balance sheet. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. Prior to adoption of SFAS No. 143, we accrued for any estimated asset retirement obligation, net of estimated salvage value, as part of our calculation of depletion, depreciation and amortization. This method resulted in recognition of the obligation over the life of the property on a unit-of-production basis, with the estimated obligation netted in property cost as part of the accumulated depreciation, depletion and amortization balance. See Note 5.

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 producing 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 on September 2, 2003. Our Cross Timbers Royalty Trust units were distributed to our common stockholders on September 18, 2003, after which we no longer own any Cross Timbers Royalty Trust units. We recorded this dividend at $28.2 million, the fair market value of the units on the date of distribution, resulting in a gain on distribution of $16.2 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.

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

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. See New Accounting Pronouncements below.

Other assets primarily include deferred debt costs that are amortized to interest expense over the term of the related debt (Note 3) and the long-term portion of gas balancing receivable (see Revenue Recognition and Gas Balancing below). We do not have any goodwill or significant intangible assets that are subject to potential impairment assessment. Other assets are presented net of accumulated amortization of $13.3 million at December 31, 2004 and $19. 8 million at December 31, 2003.

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

Index to Financial Statements

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 recorded as follows:

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 on the effective portion of the derivative 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 likely to occur, any unrealized gains or losses are recognized immediately in the income statement as a derivative fair value gain or loss.

In conjunction with our hedging activities, we occasionally sell natural gas call options. Because sold options do not provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. The opportunity loss, related to gas prices exceeding the fixed gas prices effectively provided by selling the call options, is recognized as a derivative fair value loss, rather than deferring the loss and recognizing it as reduced gas revenue when the hedged production occurs, as prescribed by hedge accounting.

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).

Oil, gas and natural gas liquids revenues are recognized when the products are sold and delivery to the purchaser has occurred. At times we may sell more or less than our entitled share of gas production. When this happens, we use

Index to Financial Statements

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. The consolidated balance sheets include the following amounts related to production imbalances:

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 $98.3 million for 2004, $66.3 million for 2003 and $55.6 million for 2002. These amounts are net of intercompany eliminations.

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.

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

Interest expense includes amortization of deferred debt costs and is presented net of interest income of $402,000 in 2004, $553,000 in 2003 and $836,000 in 2002, and net of capitalized interest of $2.6 million in 2004, $2.2 million in 2003 and $4.3 million in 2002. 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 $26.6 million at December 31, 2004 and $11.5 million at December 31, 2003.

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

Index to Financial Statements

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:

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.

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.

Our production is sold to various purchasers, based on their credit rating and location of our production. 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. For the year ended December 31, 2002, sales to each of two purchasers were approximately 10% 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.

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 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. We must implement SFAS 153 for any

Index to Financial Statements

nonmonetary asset exchanges occurring on or after January 1, 2006. This change in accounting is currently not expected to have a significant effect on our reported financial position or earnings.

Also 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, and will be effective beginning July 1, 2005. We have previously recorded stock compensation pursuant to the intrinsic value method under APB 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. 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 currently considering alternative valuation methods to determine stock award fair value for grants after June 30, 2005. We plan to use the modified prospective application method of adopting SFAS No. 123R, whereby the estimated fair value of unvested stock awards granted prior to July 1, 2005 will be recognized as compensation expense in periods subsequent to June 30, 2005, based on the estimated service period. The fair value of awards granted prior to July 1, 2005 will be the same value as determined under the Black–Scholes method for our pro forma disclosure under Stock-Based Compensation above. As of February 22, 2005, all stock options outstanding at that date vested when the common stock price closed above the target price level of $31.88, resulting in no compensation expense to be recognized after June 30, 2005 related to these awards.

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 $37.8 million of these properties for 19,000 net contiguous acres in our new core operating area, the Barnett Shale of North Texas, and $25.4 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 $11.5 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.

Index to Financial Statements

Other than borrowings under our revolving credit agreement, no debt matures within five years. Before the February 2009 maturity, we may renegotiate the revolving credit agreement to increase the borrowing commitment and extend the maturity.

In February 2004, we fully repaid our revolving facility and entered a new five-year revolving credit agreement with commercial banks that matures in February 2009. The agreement currently provides for a maximum commitment amount of $1 billion, and an interest rate based on London Interbank Offered Rates (“LIBOR”) plus 1%. The loan agreement provides the option of borrowing at floating interest rates based on the prime rate, certificate of deposit rates, or LIBOR. 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 0.20% at February 2005. The agreement requires us to maintain a ratio of debt-to-total capitalization of not more than 60%. Borrowings under the loan agreement may be prepaid at any time without penalty. The weighted average interest rate on bank debt was 2.6% during 2004 and 2003 and 3.2% during 2002.

In November 2004, we entered a $300 million five-year term loan due April 2010 with an initial interest rate of LIBOR plus 0.75%. Other terms and conditions are substantially the same as our revolving credit agreement.

In April 2002, we sold $350 million of 7½% senior notes due in April 2012, with interest payable each April 15 and October 15. Net proceeds of $341.6 million were used to finance property transactions (Note 13), to redeem our 9¼% senior subordinated notes and to reduce bank debt.

In April 2003, we sold $400 million of 6¼% senior notes due in April 2013, with interest payable each April 15 and October 15. Net proceeds of $393.4 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 (Note 13), to redeem our 8¾% 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 on February 1, 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% notes that were issued at 99.918% of par to yield 5.011% to maturity pursuant to Rule 144A under the Securities Act of 1933, which allows unregistered transactions with qualified institutional buyers. Through March 14, 2005, noteholders can exchange these notes with notes that were registered with

Index to Financial Statements

the Securities and Exchange Commission in February 2005. 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.

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%.

In April 1997, we sold $125 million of 9¼% senior subordinated notes due April 2007, and in October 1997, we sold $175 million of 8¾% senior subordinated notes due November 2009. Under the terms of an agreement with a bank counterparty, we purchased and canceled $9.7 million of 9¼% senior subordinated notes in April 2002, and we purchased and canceled $11.8 million of 8¾% senior subordinated notes in November 2002. In June 2002, we redeemed the remaining $115.3 million 9¼% notes at a redemption price of 104.625%, or $120.6 million, plus accrued interest of $1.8 million. In May 2003, we redeemed the remaining $163.2 million of our 8¾% senior subordinated notes at a redemption price of 104.375%, or $170.3 million, plus accrued interest of approximately $700,000. As a result of these transactions, we recorded a loss on extinguishment of debt of $8.5 million in 2002 and $9.6 million in 2003.

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

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 asset of $22.6 million and a long-term liability of $756.4 million at December 31, 2004 and as a current asset of $32.5 million and a long-term liability of $426.7 million at December 31, 2003. Significant components of net deferred tax assets and liabilities are:

Index to Financial Statements

We have estimated that all our net operating loss carryforwards will be fully utilized as of December 31, 2004. While our alternative minimum tax credit carryforwards do not have an expiration date, we expect to fully utilize them in 2005.

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 $1.8 million. 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 following is a summary of the asset retirement obligation activity for the years ended December 31, 2004 and 2003:

Based on the same assumptions used in the calculation of our asset retirement obligation at January 1, 2003, we estimate that this obligation would have been $62.2 million at January 1, 2002 if we had adopted SFAS No. 143 as of that date. The estimated pro forma effect of earlier adoption on 2002 net income and earnings per share is not material.

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, 2004, minimum future lease payments for all noncancelable lease agreements (including the sale and operating leaseback agreements described below) were as follows:

Index to Financial Statements

Amounts incurred under operating leases (including renewable monthly leases) were $34.6 million in 2004, $31.7 million in 2003 and $26.6 million in 2002.

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 $7.8 million. This transaction was recorded as a sale and operating leaseback, with no gain or loss on the sale. In March 2004, we extended the lease until March 2006.

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 $3.4 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, 2004 was $600,000. In November 2004, we extended the lease until November 2006.

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.

We have entered firm transportation contracts with various pipelines. Under these contracts we are obligated to transport minimum daily gas volumes or pay for any deficiencies at a specified reservation fee rate. As calculated on a monthly basis, our failure to deliver these minimum volumes to the pipeline requires us to pay the pipeline for any deficiency. 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, 2004, maximum commitments under our transportation contracts were as follows:

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, 2004, we estimate the total contingent payable under these guarantees does not exceed $5 million. Guarantees related to leases entered during 2004 and 2003 were not material.

Index to Financial Statements

Two executive officers have year-to-year employment agreements with us. The agreements are automatically renewed each year-end unless terminated by either party upon thirty days notice prior to each December 31. Under these agreements, the officers receive a minimum annual salary of $625,000 and $450,000, respectively, and are entitled to participate in any incentive compensation programs administered by the Board of Directors. The agreements also provide 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 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.

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

As of December 31, 2004, we have contracts to use 32 drilling rigs in 2005 with total commitments of $99.1 million. Early termination of these contracts at December 31, 2004 would have required us to pay maximum penalties of $34.7 million.

Index to Financial Statements

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 has set an evidentiary hearing in April 2005 to determine whether the amended class should be certified. 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 allege that the defendants have 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 seek 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 are leased to or operated by Huber or us, except to the extent that the lessors or their successors have 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 have assumed the responsibility for certain liabilities of Huber prior to the effective date, which may include liability for post-production deductions made by Huber. We have filed our response and intend to file a response for 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 tentative settlement of approximately $5.1 million, resulting in an additional loss of approximately $2 million to be recorded in first quarter 2005.

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.

Index to Financial Statements

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 cancellable by either party with at least 60 days notice prior to the beginning of the next calendar quarter.

Through December 2004, we have acquired more than 80,000 net acres in the Barnett Shale of North Texas (Note 13). Approximately 60,000 net acres with an estimated value of $69 million are generally subject to lease expiration if initial wells are not drilled within one year. Because we have ample resources to meet the drilling requirements, we currently do not anticipate significant impairment of these leases.

In October 2004, we agreed to acquire an airplane for $17.1 million, either through purchase or lease, and made an initial payment of $6.8 million. We expect to take delivery of the airplane in the first half of 2005.

We use financial and commodity-based 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 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.

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 $6.6 million from the counterparty. Because these Btu swap contracts are non-hedge derivatives, most of the $6.6 million gain related to their termination had previously been recorded in 2001 derivative fair value gain.

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 crude oil and natural gas sales through December 2005. See Note 8.

Index to Financial Statements

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

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, 2004 and 2003. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:

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.

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

Index to Financial Statements

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 $3.9 million at December 31, 2004 and $6.3 million at December 31, 2003. Our bad debt provision was $232,000 in 2004, $1.3 million in 2003 and $980,000 in 2002. We also recorded a $2.2 million reduction in the allowance for collectibility in 2004.

Our policy is to routinely hedge a portion of our production at commodity prices management deems attractive. This policy assures cash flow needed for funding our development program and provides more predictable economic returns for our acquisitions. While there is a risk we may not be able to realize the benefit of rising prices, management plans to continue this strategy because of these benefits.

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 2005.

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.

Index to Financial Statements

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:

Net losses on futures and basis swap hedge contracts decreased gas revenue by $156.1 million in 2004 and $193 million in 2003. Net gains on futures and basis swap hedge contracts increased gas revenue by $57.4 million in 2002. Including the effect of fixed price physical delivery contracts, all hedging activities increased gas revenue by $95.4 million in 2002. There were no fixed price physical delivery contracts in 2003 or 2004. As of December 31, 2004, an unrealized pre-tax derivative fair value loss of $28.1 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2005. 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 2005 gas production reduced gas revenue by approximately $1.1 million, or $0.04 per Mcf.

In connection with our 2004 acquisitions from ExxonMobil Corporation and ChevronTexaco Corporation (Note 13), we entered oil futures contracts to sell, through December 2005, 10,000 Bbls per day at an average West Texas Intermediate NYMEX price of $35.91 per Bbl and 5,000 Bbls per day at an average West Texas Intermediate NYMEX price of $43.28 per Bbl. For 5,000 Bbls per day of production hedged at $35.91 per Bbl, we entered a crude sweet and sour differential swap of $3.05 per Bbl, to effectively fix the price for crude sour production at $32.86 per Bbl. Prices to be realized for hedged oil production are expected to be less than the NYMEX price because of location, quality and other adjustments.

Index to Financial Statements

In 2004, net losses on futures and differential swap hedge contracts decreased oil revenue by $15.5 million. Net losses on oil futures hedge contracts decreased oil revenue by $3.9 million in 2003. During 2002, net losses on oil futures hedge contracts decreased oil revenue by $1.3 million, while changes in fair value of sour oil basis swap contracts resulted in a derivative fair value gain of $300,000. As of December 31, 2004, an unrealized pre-tax derivative fair value loss of $17 million related to cash flow hedges of oil price risk was recorded in accumulated other comprehensive income (loss). This entire fair value loss is expected to be reclassified into earnings in 2005. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

The settlement of futures contracts and crude sweet and sour differential swaps related to January 2005 production reduced oil revenue by approximately $3.1 million, or $2.84 per Bbl.

From August 1995 through July 1998 we received an additional $0.30 to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, we agreed to sell 34,344 Mcf per day at the index price in 2001 and 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. See Note 7 regarding accounting for this contract, also referred to as the Enron Btu swap contract, which was terminated as a result of the Enron bankruptcy, and regarding a related derivative commitment with another counterparty.

In addition to the Enron Btu swap contract, Enron Corporation was a purchaser of natural gas under other physical delivery contracts and was counterparty to some of our hedge derivative contracts at the time of its bankruptcy in December 2001. In settlement of all obligations, we paid Enron $6 million in December 2002. As a result of this settlement, in 2002 we recognized $14.1 million in previously unrecognized gas revenue related to physical delivery contracts and a gain of $2.1 million.

In 1998, we sold a production payment, payable from future production from certain properties acquired in an acquisition, to EEX Corporation for $30 million. 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 $20.7 million. We expect to begin delivery of the remaining 16.0 Bcf (13.0 Bcf net) of gas in 2006.

We effected a four-for-three stock split on March 18, 2003 and a five-for-four stock split on March 17, 2004, and will effect 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.

Index to Financial Statements

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 $19.7 million, net proceeds of $580.3 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 $10.8 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 our producing property acquisition from units of Williams of Tulsa, Oklahoma (Note 13), to redeem our 8¾% senior subordinated notes and to reduce bank debt.

In January 2005, we announced our agreement to purchase Antero Resources Corporation, which will partially be funded by issuance of 13.3 million shares of common stock (Note 13).

In February 2004, the Board of Directors authorized the cancellation of treasury shares as of December 31, 2003. This retirement of treasury shares is reflected in the December 31, 2003 consolidated balance sheet, resulting in a reduction of treasury stock and additional paid-in-capital of $102 million, and a reduction in shares in treasury and shares issued of 21.2 million shares.

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, 2004, we have repurchased 33,600 shares at a cost of $812,000.

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.

Index to Financial Statements

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.

As partial consideration for producing properties acquired in December 1997, we issued warrants to purchase 4.8 million shares of common stock at a price of $3.02 per share for a period of five years. These warrants, valued at $5.7 million when issued and recorded as additional paid-in capital, were exercised in August 2002, resulting in an increase to common stock and additional paid-in capital of $14.3 million.

Our purchase of Antero Resources Corporation will be partially funded by issuance of five-year warrants to purchase 2 million shares of common stock at $27.00 per share (Note 13).

The Board of Directors declared quarterly dividends of $0.0045 per common share for each quarter in 2002, $0.006 per common share for each quarter in 2003, $0.0075 per common share for first and second quarter 2004 and $0.0375 per common share for third and fourth quarter 2004. In February 2005, the Board of Directors declared a first quarter 2005 dividend of $0.05 per common share after the four-for-three stock split is effected on March 15, 2005.

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 on September 2, 2003. This dividend, totaling 1,360,000 trust units, was distributed on September 18, 2003, and was recorded at the fair value of the units on that date of $28.2 million.

Index to Financial Statements

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

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

Interest payments in 2004 totaled $77 million (including $2.6 million of capitalized interest), $60.9 million in 2003 (including $2.2 million of capitalized interest) and $52.1 million in 2002 (including $4.3 million of capitalized interest). Net income tax payments were $49.7 million during 2004, $5.3 million during 2003 and $405,000 during 2002.

Because we do not recognize compensation related to stock options granted, the tax benefit realized upon exercise of stock options is 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. This tax benefit from exercise of stock options was $17.9 million in 2004, $22.7 million in 2003 and $1.8 million in 2002.

Index to Financial Statements

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 $6.8 million in 2004, $5.2 million in 2003 and $4.5 million in 2002.

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 the employee’s or director’s 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 status of our post-retirement health plan for 2004, 2003 and 2002 is as follows:

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 2005 accrued benefit cost is expected to be approximately $1 million.

Index to Financial Statements

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

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 the following estimated effects as of December 31, 2004:

The following are projected benefit payments, which reflect expected future service, for the next ten years:

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, with 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 19.3 million options outstanding under both plans at December 31, 2004, including 4.1 million that were exercisable at that date. The remaining 15.2 million options vested when the common stock price reached specified levels in February 2005.

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. In November 2004, nonemployee directors were granted a total of 88,000 stock options which were outstanding at December 31, 2004 and vested when the common stock price reached specified levels in February 2005. Under the 1998 Plan, nonemployee directors previously received automatic annual grants of unrestricted common shares that totaled 18,000 shares in each of 2004, 2003 and 2002. In February 2005, nonemployee directors received a total of 18,000 unrestricted shares under the 2004 Plan.

Index to Financial Statements

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:

At December 31, 2004, deferred compensation of $18.4 million was recorded, based on the year-end common stock price, as an offset to additional paid-in-capital for 797,533 performance shares outstanding. These performance shares vest when the common stock reaches the following prices:

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 shares outstanding at December 31, 2004 were granted to key employees other than executive officers in September and November 2004. As of December 31, 2004, management estimated a reasonably probable vesting period of one year for performance share awards that vest at $28.13 and $28.50, resulting in related compensation of $2.8 million recorded in 2004. As of February 2005, all performance shares outstanding at December 31, 2004 vested, resulting in remaining compensation of $21.1 million to be recorded in first quarter 2005.

During second quarter 2004, the Company began granting cash-equivalent, or phantom, performance shares to executive officers in lieu of performance shares. Vested cash-equivalent performance shares are payable solely in cash in an amount equal to the fair market value of the underlying common stock upon vesting. During 2004, 967,000 cash-equivalent performance shares were issued to executive officers. All cash-equivalent performance shares vested in 2004 resulting in compensation expense of $22.3 million. As of December 31, 2004, there are no cash-equivalent performance shares outstanding.

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 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, executive 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 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

Index to Financial Statements

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 executive officers are subject to the 20% parachute excise tax, the Company will pay the executive officer an additional amount to “gross up” the payment so that the executive officer will receive the full amount due under the terms of the amended change in control grant agreement after payment of the excise tax.

The following summarizes information about outstanding options at December 31, 2004:

Index to Financial Statements

Using the Black-Scholes option-pricing model and the following assumptions, the weighted average fair value of option grants was estimated to be $5.34 in 2004, $5.47 in 2003 and $4.36 in 2002. Black-Scholes and alternative option-pricing models do not consider the effects of forfeitability and nontransferability on the valuation of employee stock options.

Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair Value

The following are pro forma earnings available to common stock and earnings per common share for 2004, 2003 and 2002, as if stock-based compensation had been recorded at the estimated fair value of stock awards at the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation:

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) and are subject to typical post-closing adjustments.

From February through April 2004, we purchased $223.1 million of properties located primarily in the Barnett Shale of North Texas and in the Arkoma Basin. These acquisitions are subject to typical post-closing adjustments. 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, including a contingent payable of up to $5 million dependent on earnings from one property in the following year. The acquisitions were funded with bank borrowings that were repaid with proceeds from the sale of common stock in May 2004 (Note 9) and are subject to typical post-closing adjustments.

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 on August 16, 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 $930 million. Post-closing adjustments for final net revenues, volume balancing and income tax effects will be made within twelve months. The acquisition was funded through existing bank credit facilities and the sale of common stock in May 2004. These properties expand our operations in the Permian Basin and our Eastern and Mid-Continent regions, and add new coal bed methane properties in the Rocky Mountains and a new operating region in South Texas.

Index to Financial Statements

Two acquisitions in 2004 were purchases of corporations that primarily owned producing and nonproducing properties. After purchase accounting adjustments, including a $72.3 million step-up adjustment for deferred income taxes, the cost of all producing properties acquired in 2004 was $1.9 billion.

In May 2003, we acquired from Williams of Tulsa, Oklahoma 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. The adjusted purchase price was $381 million, which was financed with proceeds from our sale of senior notes (Note 3) and common stock (Note 9).

In June 2003, we acquired coal bed methane and natural gas producing properties in the San Juan Basin of New Mexico and Colorado from Markwest Hydrocarbon, Inc. for an adjusted purchase price of $51 million, which was funded through bank borrowings. The acquisition is subject to typical post-closing adjustments.

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 purchases were funded with existing credit facilities and are subject to typical post-closing adjustments.

Acquisitions were recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for 2003 and 2002, as if the ChevronTexaco, ExxonMobil and Williams acquisitions were made at the beginning of each period. These pro forma results are not necessarily indicative of future results.

In January 2005, we announced an agreement to purchase privately held Antero Resources Corporation, a prominent Barnett Shale producer, for cash and equity consideration valued at approximately $685 million. Consideration includes $337.5 million in cash, 13.3 million shares of our common stock and five-year warrants to purchase another 2 million shares of our common stock at $27 per share. The purchase agreement was amended in February 2005 to include Antero’s gas gathering assets and related bank debt of $175 million. The transaction is expected to close April 1, 2005. The booked acquisition cost will include customary non-cash adjustments, including a step-up adjustment for deferred income taxes. The cash consideration for the acquisition will initially be provided through cash flow from operations and existing bank credit facilities.

Index to Financial Statements

The following are summarized quarterly financial data for the years ended December 31, 2004 and 2003:

Index to Financial Statements

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.

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

The following summarizes changes in capitalized costs for exploratory wells in process of drilling:

There were no completed exploratory wells awaiting determination of proved reserves at December 31, 2004, 2003 or 2002.

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

Index to Financial Statements

development drilling and production history and from changes in economic factors. Proved reserves exclude volumes deliverable to others under production payments.

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, are deducted from the standardized measure using year-end costs. Such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired (Note 5).

In our prior reports, the estimated future net cash flows from proved reserves and related present value amounts were reported before reduction for operated overhead expense. Operated overhead is a component of production expense in the consolidated income statement, and is an allocation from general and administrative expense of the costs estimated to support the production function. As part of its periodic review of our filings, the staff of the Securities and Exchange Commission concluded that production expense components for proved reserve disclosures should be consistent with components of production expense recorded in the financial statements. Accordingly, we have restated estimated future net cash flows and the related present value amounts for all years presented, resulting in a reduction to these amounts of approximately 2% at December 31, 2003 and 3% at December 31, 2002.

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.

Index to Financial Statements

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

Index to Financial Statements

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 $5.69 for 2004, $5.71 for 2003, $4.41 for 2002 and $2.36 for 2001. Year-end average realized natural gas liquids prices were $28.24 for 2004, $23.17 for 2003, $17.86 for 2002 and $8.70 for 2001. Year-end average realized oil prices were $41.03 for 2004, $30.55 for 2003, $29.69 for 2002 and $17.39 for 2001. Proved oil and gas reserves at December 31, 2004 include 192,719,000 Mcf of gas and 1,647,000 Bbls of oil and discounted present value before income tax of $403.4 million related to our ownership of approximately 54% of Hugoton Royalty Trust units at December 31, 2004.

Index to Financial Statements

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, 2004. 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, 2004. 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.

Index to Financial Statements

We have audited the accompanying consolidated balance sheets of XTO Energy Inc. and its subsidiaries as of December 31, 2004 and 2003, 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, 2004. 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, 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, 2004, 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 March 7, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

Index to Financial Statements

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, 2004, 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, 2004, 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, 2004, 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, 2004 and 2003, 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, 2004, and our report dated March 7, 2005 expressed an unqualified opinion on those consolidated financial statements.

Index to Financial Statements

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 7^th day of March 2005.

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 7^th day of March 2005.

Index to Financial Statements

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

Index to Financial Statements

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.


	Proved Reserves				Discounted Present Value before Income Tax of Proved Reserves
*(in thousands)*	Gas (Mcf)	Natural Gas Liquids (Bbls)	Oil (Bbls)	Natural Gas Equivalents (Mcfe)
Eastern Region	2,523,826	4,791	8,117	2,601,274	$	5,442,885	44.5	%
San Juan Basin and Rocky Mountain Area	895,802	33,266	12,442	1,170,050		2,253,065	18.4	%
Permian Basin and South Texas Region	240,613	399	108,764	895,591		2,019,883	16.5	%
Arkoma Basin and Mid-Continent Region	651,624	—	5,010	681,684		1,529,162	12.5	%
Hugoton Royalty Trust (a)	281,506	—	2,405	295,936		573,865	4.7	%
North Texas Region	117,546	—	23	117,684		205,381	1.7	%
Alaska Cook Inlet	—	—	14,986	89,916		197,221	1.6	%
Other	3,586	—	759	8,140		15,587	0.1	%

Total	4,714,503	38,456	152,506	5,860,275	$	12,237,049	100	%


	December 31
*(in thousands)*	2004		2003		2002
Proved developed:
Gas (Mcf)		3,252,711		2,651,259		2,042,661
Natural gas liquids (Bbls)		30,019		28,187		19,367
Oil (Bbls)		134,382		47,882		47,178
Mcfe		4,239,117		3,107,673		2,441,931
Proved undeveloped:
Gas (Mcf)		1,461,792		992,980		838,520
Natural gas liquids (Bbls)		8,437		6,491		6,066
Oil (Bbls)		18,124		7,549		9,171
Mcfe		1,621,158		1,077,220		929,942
Total proved:
Gas (Mcf)		4,714,503		3,644,239		2,881,181
Natural gas liquids (Bbls)		38,456		34,678		25,433
Oil (Bbls)		152,506		55,431		56,349
Mcfe		5,860,275		4,184,893		3,371,873
Estimated future net cash flows:
Before income tax	$	23,605,059	$	16,700,605	$	10,165,876
After income tax	$	16,238,874	$	11,558,304	$	7,148,542
Present value of estimated future net cash flows, discounted at 10%:
Before income tax	$	12,237,044	$	8,607,001	$	5,281,077
After income tax	$	8,402,443	$	5,989,685	$	3,756,442


	Operated Wells		Nonoperated Wells		Total *(a)*
	Gross	Net	Gross	Net	Gross	Net
Gas	6,683.5	5,667.9	4,308.5	669.8	10,992.0	6,337.7
Oil	2,027.5	1,643.5	5,084.5	474.6	7,112.0	2,118.1

Total	8,711.0	7,311.4	9,393.0	1,144.4	18,104.0	8,455.8


	Year Ended December 31
	2004		2003		2002
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Completed as-
Gas wells	584	372.0	390	289.5	303	227.2
Oil wells	33	23.9	42	30.0	27	15.5
Non-productive	27	12.4	7	3.0	13	5.9

Total	644	408.3	439	322.5	343	248.6


Exploratory wells:
Completed as-
Gas wells	1	1.0	12	10.2	—	—
Oil wells	2	0.4	—	—	—	—
Non-productive	—	—	—	—	3	1.5

Total	3	1.4	12	10.2	3	1.5


Total (a)	647	409.7	451	332.7	346	250.1


	Developed Acres *(a)(b)*		Undeveloped Acres
	Gross	Net	Gross	Net
Texas	811,785	575,617	152,209	117,173
Oklahoma	546,238	381,312	16,946	8,158
Arkansas	577,937	306,590	30,507	22,299
New Mexico	450,044	284,802	33,395	27,825
Kansas	211,253	167,245	—	—
Louisiana	114,659	61,215	160	160
Colorado	107,900	83,875	—	—
Wyoming	72,442	55,506	53,963	51,246
Utah	66,939	42,546	—	—
Other	362,354	9,608	—	—

Total	3,321,551	1,968,316	287,180	226,861


Item		Page
Part I

1. and 2.	Business and Properties	1
3.	Legal Proceedings	16
4.	Submission of Matters to a Vote of Security Holders	17

Part II

5.	Market for Registrant’s Common Equity and Related Stockholder Matters	18
6.	Selected Financial Data	19
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
7A.	Quantitative and Qualitative Disclosures about Market Risk	40
8.	Financial Statements and Supplementary Data	42
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	42
9A.	Controls and Procedures	42
9B.	Other Information	42

Part III

10.	Directors and Executive Officers of the Registrant	43
11.	Executive Compensation	43
12.	Security Ownership of Certain Beneficial Owners and Management	43
13.	Certain Relationships and Related Transactions	43
14.	Principal Accountant Fees and Services	43

Part IV

15.	Exhibits and Financial Statement Schedules	44


	High		Low		Cash Dividend
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

2003
First Quarter	$	11.916	$	10.211	$	0.0060
Second Quarter		13.494		10.920		0.0060
Third Quarter		12.852		11.148		0.0060	(a)
Fourth Quarter		17.580		12.558		0.0060


Month	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs *(b)*	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs *(b)*
October	—		$	—	—
November	696	(a)	$	27.26	—
December	33,600		$	24.18	33,600

Total	34,296		$	24.24	33,600	19,966,400


*(in thousands except production, per share and per unit data)*	2004			2003			2002			2001			2000
Consolidated Income Statement Data
Revenues:
Gas and natural gas liquids	$	1,613,135		$	1,040,370		$	681,147		$	710,348		$	456,814
Oil and condensate		318,800			135,058			115,324			116,939			128,194
Gas gathering, processing and marketing		18,380			12,982			11,622			12,832			16,123
Other		(2,714	)		1,145			2,070			(1,371	)		(280	)

Total Revenues	$	1,947,601		$	1,189,555		$	810,163		$	838,748		$	600,851

Earnings available to common stock	$	507,882	(a)	$	288,279	(b)	$	186,059	(c)	$	248,816	(d)	$	115,235	(e)

Per common share:
Basic	$	1.53		$	0.96	(f)	$	0.67		$	0.91	(g)	$	0.49

Diluted	$	1.51		$	0.95	(f)	$	0.66		$	0.90	(g)	$	0.46

Weighted average common shares outstanding		332,907			299,665			277,834			272,234			237,179

Cash dividends declared per common share	$	0.0900		$	0.0240	(h)	$	0.0180		$	0.0165		$	0.0100

Consolidated Statement of Cash Flows Data
Cash provided (used) by:
Operating activities	$	1,216,892		$	794,181		$	490,842		$	542,615		$	377,421
Investing activities	$	(2,518,261	)	$	(1,135,234	)	$	(736,817	)	$	(610,923	)	$	(133,884	)
Financing activities	$	1,304,074		$	333,094		$	254,119		$	67,680		$	(241,833	)

Consolidated Balance Sheet Data
Property and equipment, net	$	5,624,378		$	3,312,067		$	2,370,965		$	1,841,387		$	1,357,374
Total assets	$	6,110,372		$	3,611,134		$	2,648,193		$	2,132,327		$	1,591,904
Long-term debt	$	2,042,732		$	1,252,000		$	1,118,170		$	856,000		$	769,000
Stockholders’ equity	$	2,599,373		$	1,465,642		$	907,786		$	821,050		$	497,367

Operating Data
Average daily production:
Gas (Mcf)		834,572			668,436			513,925			416,927			343,871
Natural gas liquids (Bbls)		7,484			6,463			5,068			4,385			4,430
Oil (Bbls)		22,696			12,943			13,033			13,637			12,941
Mcfe		1,015,654			784,877			622,532			525,062			448,098

Average sales price:
Gas (per Mcf)	$	5.04		$	4.07		$	3.49		$	4.51		$	3.38
Natural gas liquids (per Bbl)	$	26.44		$	19.99		$	14.31		$	15.41		$	19.61
Oil (per Bbl)	$	38.38		$	28.59		$	24.24		$	23.49		$	27.07

Production expense (per Mcfe)	$	0.66		$	0.58		$	0.57		$	0.57		$	0.53
Taxes, transportation and other expense (per Mcfe)	$	0.47		$	0.37		$	0.25		$	0.33		$	0.35

Proved reserves:
Gas (Mcf)		4,714,503			3,644,239			2,881,181			2,235,478			1,769,683
Natural gas liquids (Bbls)		38,456			34,678			25,433			20,299			22,012
Oil (Bbls)		152,506			55,431			56,349			54,049			58,445
Mcfe		5,860,275			4,184,893			3,371,873			2,681,566			2,252,425

Other Data
Ratio of earnings to fixed charges (i)		8.9			6.9			5.6			7.7			2.8


	2004		2003		Increase (Decrease)
Production	$	0.66	$	0.58	14%
Taxes, transportation and other		0.47		0.37	27%
Depreciation, depletion and amortization		1.09		0.99	10%
Accretion of discount in asset retirement obligation		0.02		0.02	—
General and administrative, excluding stock-based incentive compensation		0.20		0.19	5%
Interest		0.25		0.22	14%

	$	2.69	$	2.37	14%


Closing Date		Seller	Amount (in millions)		Acquisition Area
2004	January	Multiple parties	$	243	East Texas and northwestern Louisiana

	February -April	Multiple parties		223	Barnett Shale of North Texas and Arkoma Basin

	May	ExxonMobil Corporation		336	Permian Basin of West Texas and Powder River Basin of Wyoming

	August	ChevronTexaco Corporation		930	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

2002	May	Marathon Oil Company		101	East Texas and Louisiana

	July	Marathon Oil Company		43	San Juan Basin of New Mexico

	December	J.M. Huber Corporation		154	San Juan Basin of Colorado


	Year Ended December 31
*(per Mcf)*	2004		2003		2002
Average NYMEX price	$	6.14	$	5.39	$	3.22
Average realized sales price	$	5.04	$	4.07	$	3.49
Average realized sales price excluding hedging	$	5.56	$	4.86	$	2.98


	Year Ended December 31
*(per Bbl)*	2004		2003		2002
Average NYMEX price	$	41.38	$	31.08	$	26.10
Average realized sales price	$	38.38	$	28.59	$	24.24
Average realized sales price excluding hedging	$	40.24	$	29.40	$	24.52


Futures Contracts and Swap Agreements For January through December 2005 Production
Natural Gas			Crude Oil
Mcf per Day	Average NYMEX Price per Mcf		Bbl per Day	Average NYMEX Price per Bbl
Mcf per Day	Average NYMEX Price per Mcf		Bbl per Day	Average NYMEX Price per Bbl
250,000	$	5.90	10,000	$	35.91
			5,000	$	43.28


			Payments Due by Year
(in thousands)	Total		2005		2006		2007		2008		2009		After 2009
Long-term debt	$	2,046,000	$	—	$	—	$	—	$	—	$	146,000	$	1,900,000
Operating leases		151,123		30,200		23,882		22,806		18,605		15,964		39,666
Drilling contracts		99,085		99,085		—		—		—		—		—
Transportation contracts		137,341		21,935		22,463		19,741		18,804		18,030		36,368
Purchase obligations		10,300		10,300		—		—		—		—		—
Derivative contract liabilities at December 31, 2004 fair value		86,713		75,534		11,179		—		—		—		—

Total	$	2,530,562	$	237,054	$	57,524	$	42,547	$	37,409	$	179,994	$	1,976,034


*(in thousands)*	Carrying Amount			Fair Value *(a)*			Hypothetical Change in Fair Value
December 31, 2004 Long-term debt	$	(2,042,732	)	$	(2,133,818	)	$	115,205
December 31, 2003 Long-term debt	$	(1,252,000	)	$	(1,275,285	)	$	51,085


		Page

Consolidated Balance Sheets		45

Consolidated Income Statements		46

Consolidated Statements of Cash Flows		47

Consolidated Statements of Stockholders’ Equity		48

Notes to Consolidated Financial Statements		49

Selected Quarterly Financial Data (Note 14 to Consolidated Financial Statements)		75

Information about Oil and Gas Producing Activities (Note 15 to Consolidated Financial Statements)		76

Management’s Report on Internal Control over Financial Reporting		80

Reports of Independent Registered Public Accounting Firm		81


		Page
1.	Financial Statements:
	Consolidated Balance Sheets at December 31, 2004 and 2003	45
	Consolidated Income Statements for the years ended December 31, 2004, 2003 and 2002	46
	Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002	47
	Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2004, 2003 and 2002	48
	Notes to Consolidated Financial Statements	49
	Management’s Report on Internal Control over Financial Reporting	80
	Reports of Independent Registered Public Accounting Firm	81
2.	Financial Statement Schedules:
	Schedule II - Consolidated Valuation and Qualifying Accounts	83
	All other 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.


*(in thousands, except shares)*	December 31
*(in thousands, except shares)*	2004			2003
ASSETS
Current Assets:
Cash and cash equivalents	$	9,700		$	6,995
Accounts receivable, net		333,134			193,666
Derivative fair value		14,713			11,351
Current income tax receivable		9,089			4,503
Deferred income tax benefit		22,613			32,455
Other		47,716			12,193

Total Current Assets		436,965			261,163

Property and Equipment, at cost – successful efforts method:
Producing properties		6,871,245			4,253,221
Undeveloped properties		61,170			12,627
Other		106,031			70,494

Total Property and Equipment		7,038,446			4,336,342
Accumulated depreciation, depletion and amortization		(1,414,068	)		(1,024,275	)

Net Property and Equipment		5,624,378			3,312,067

Other Assets:
Derivative fair value		—			646
Other		49,029			37,258

Total Other Assets		49,029			37,904

TOTAL ASSETS	$	6,110,372		$	3,611,134

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	415,350		$	218,710
Payable to royalty trusts		9,823			4,848
Derivative fair value		75,534			96,653
Other		259			346

Total Current Liabilities		500,966			320,557

Long-term Debt		2,042,732			1,252,000

Other Long-term Liabilities:
Derivative fair value		11,179			18,044
Deferred income taxes payable		756,369			426,730
Asset retirement obligation		159,948			93,379
Other		39,805			34,782

Total Other Long-term Liabilities		967,301			572,935

Commitments and Contingencies (Note 6)
Stockholders’ Equity:
Common stock ($.01 par value, 500,000,000 shares authorized, 348,428,489 and 312,335,137 shares issued)		3,484			3,123
Additional paid-in capital		1,410,135			753,120
Treasury stock, at cost (1,250,266 and -0- shares)		(24,917	)		—
Retained earnings		1,239,553			762,640
Accumulated other comprehensive income (loss)		(28,882	)		(53,241	)

Total Stockholders’ Equity		2,599,373			1,465,642

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	6,110,372		$	3,611,134


*(in thousands, except per share data)*	Year Ended December 31
*(in thousands, except per share data)*	2004			2003			2002
REVENUES
Gas and natural gas liquids	$	1,613,135		$	1,040,370		$	681,147
Oil and condensate		318,800			135,058			115,324
Gas gathering, processing and marketing		18,380			12,982			11,622
Other		(2,714	)		1,145			2,070

Total Revenues		1,947,601			1,189,555			810,163

EXPENSES
Production		245,892			164,864			129,182
Taxes, transportation and other		174,007			104,654			57,225
Exploration		10,513			1,811			2,186
Depreciation, depletion and amortization		406,749			284,006			204,109
Accretion of discount in asset retirement obligation		7,592			5,330			—
Gas gathering and processing		6,586			9,350			9,114
General and administrative		165,092			107,675			62,114
Derivative fair value (gain) loss		11,889			10,201			(2,599	)

Total Expenses		1,028,320			687,891			461,331

OPERATING INCOME		919,281			501,664			348,832

OTHER INCOME (EXPENSE)
Gain on distribution of royalty trust units		—			16,216			—
Loss on extinguishment of debt		—			(9,601	)		(8,528	)
Interest expense, net		(93,661	)		(63,769	)		(53,555	)

Total Other Expense		(93,661	)		(57,154	)		(62,083	)

INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		825,620			444,510			286,749
INCOME TAX EXPENSE		317,738			158,009			100,690

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		507,882			286,501			186,059
Cumulative effect of accounting change, net of tax		—			1,778			—

NET INCOME	$	507,882		$	288,279		$	186,059

EARNINGS PER COMMON SHARE
Basic:
Net income before cumulative effect of accounting change	$	1.53		$	0.95		$	0.67
Cumulative effect of accounting change, net of tax		—			0.01			—

Net income	$	1.53		$	0.96		$	0.67

Diluted:
Net income before cumulative effect of accounting change	$	1.51		$	0.94		$	0.66
Cumulative effect of accounting change, net of tax		—			0.01			—

Net income	$	1.51		$	0.95		$	0.66

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		332,907			299,665			277,834


*(in thousands, except per share amounts)*	Common Stock			Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balances, December 31, 2001	$	2,933		$	483,481		$	(64,714	)	$	328,712		$	70,638		$	821,050

Net income		—			—			—			186,059			—			186,059
Change in hedge derivative fair value, net of applicable income tax of $51,543		—			—			—			—			(95,723	)		(95,723	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of $19,647		—			—			—			—			(36,488	)		(36,488	)

Comprehensive income																	53,848

Issuance/vesting of performance shares		22			25,596			(10,276	)		—			—			15,342
Stock option and warrant exercises, including income tax benefits		61			24,071			(35	)		—			—			24,097
Treasury stock purchases		—			—			(1,536	)		—			—			(1,536	)
Common stock dividends ($0.018 per share)		—			—			—			(5,015	)		—			(5,015	)

Balances, December 31, 2002		3,016			533,148			(76,561	)		509,756			(61,573	)		907,786

Net income		—			—			—			288,279			—			288,279
Change in hedge derivative fair value, net of applicable income tax of $65,850		—			—			—			—			(122,293	)		(122,293	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of $70,337		—			—			—			—			130,625			130,625

Comprehensive income																	296,611

Issuance/vesting and forfeiture of performance shares		45			51,080			(23,124	)		—			—			28,001
Stock option exercises, including income tax benefits		44			22,919			—			—			—			22,963
Treasury stock purchases		—			—			(2,296	)		—			—			(2,296	)
Common stock offering		230			247,742			—			—			—			247,972
Fair value of royalty trust unit distribution		—			—			—			(28,151	)		—			(28,151	)
Common stock dividends ($0.024 per share)		—			—			—			(7,244	)		—			(7,244	)
Cancellation of treasury stock		(212	)		(101,769	)		101,981			—			—			—

Balances, December 31, 2003		3,123			753,120			—			762,640			(53,241	)		1,465,642

Net income		—			—			—			507,882			—			507,882
Change in hedge derivative fair value, net of applicable income tax of $51,063		—			—			—			—			(85,023	)		(85,023	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of $63,485		—			—			—			—			109,382			109,382

Comprehensive income																	532,241

Issuance/vesting of performance shares		25			64,358			(24,105	)		—			—			40,278
Stock option exercises, including income tax benefits		19			12,702			—			—			—			12,721
Treasury stock purchases		—			—			(812	)		—			—			(812	)
Common stock offering		317			579,955			—			—			—			580,272
Common stock dividends ($0.09 per share)		—			—			—			(30,969	)		—			(30,969	)

Balances, December 31, 2004	$	3,484		$	1,410,135		$	(24,917	)	$	1,239,553		$	(28,882	)	$	2,599,373


Derivative Type	Fair Value Gains/ Losses	Financial Statement Classification
Non-hedge derivatives and Hedge derivatives – ineffective portion	Unrealized and Realized	Derivative fair value (gain) loss in the Consolidated Income Statements

Hedge derivatives – effective portion	Unrealized	Accumulated other comprehensive income (loss) in Stockholders’ Equity in the Consolidated Balance Sheets
Hedge derivatives – effective portion	Realized	Hedged item as classified in the Consolidated Income Statements (e.g., gas revenue, oil revenue or interest expense)


*(in thousands)*
2005	$	30,200
2006		23,882
2007		22,806
2008		18,605
2009		15,964
Remaining		39,666

Total	$	151,123


	Asset (Liability)
	December 31, 2004						December 31, 2003
*(in thousands)*	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Derivative Assets:
Fixed-price natural gas futures and swaps	$	10,962		$	10,962		$	11,997		$	11,997
Fixed-price crude futures and differential		3,751			3,751			—			—
Derivative Liabilities:
Fixed-price natural gas futures and swaps		(41,754	)		(41,754	)		(96,702	)		(96,702	)
Fixed-price crude futures and differential		(25,879	)		(25,879	)		—			—
Btu swap contracts		(19,080	)		(19,080	)		(17,995	)		(17,995	)

Net derivative asset (liability)	$	(72,000	)	$	(72,000	)	$	(102,700	)	$	(102,700	)

Long-term debt	$	(2,042,732	)	$	(2,133,818	)	$	(1,252,000	)	$	(1,275,285	)


	Base Production			Production Related to 2004 Acquisitions			Total
Production Period	Mcf per Day	Average NYMEX Price per Mcf		Mcf per Day	Average NYMEX Price per Mcf		Mcf per Day	Average NYMEX Price per Mcf
2005 January to December	200,000	$	5.79	50,000	$	6.34	250,000	$	5.90


	Delivery Location
Production Period	Arkoma			Houston Ship Channel			Rockies			San Juan Basin			Total
2005
January
Mcf per day		10,000			210,000			30,000			70,000		320,000
Basis per Mcf (a)	$	(0.06	)	$	(0.21	)	$	(0.77	)	$	(0.67	)

February to March
Mcf per day		10,000			210,000			10,000			70,000		300,000
Basis per Mcf (a)	$	(0.06	)	$	(0.21	)	$	(0.71	)	$	(0.67	)

April to June
Mcf per day		—			270,000			5,000			30,000		305,000
Basis per Mcf (a)		—		$	(0.14	)	$	(0.75	)	$	(0.68	)

July to August
Mcf per day		—			270,000			5,000			30,000		305,000
Basis per Mcf (a)		—		$	(0.12	)	$	(0.75	)	$	(0.68	)

September
Mcf per day		—			250,000			5,000			30,000		285,000
Basis per Mcf (a)		—		$	(0.12	)	$	(0.75	)	$	(0.68	)

October
Mcf per day		—			270,000			5,000			30,000		305,000
Basis per Mcf (a)		—		$	(0.14	)	$	(0.75	)	$	(0.68	)

November to December
Mcf per day		—			220,000			10,000			40,000		270,000
Basis per Mcf (a)		—		$	(0.17	)	$	(0.76	)	$	(0.68	)


	Shares Issued				Shares in Treasury
*(in thousands)*	2004	2003		2002	2004	2003		2002
Balance, January 1	312,335	301,633		293,308	—	19,462		18,258
Issuance/vesting and forfeiture of performance shares	2,448	4,444		2,224	1,216	1,585		1,045
Stock option and warrant exercises	1,937	4,456		6,101	—	—		4
Treasury stock purchases	—	—		—	34	151		155
Common stock offering	31,708	23,000		—	—	—		—
Cancellation of treasury shares	—	(21,198	)	—	—	(21,198	)	—

Balance, December 31	348,428	312,335		301,633	1,250	—		19,462


*(in thousands, except per share data)*	Earnings		Shares	Earnings per Share
2004
Basic	$	507,882	332,907	$	1.53

Effect of dilutive securities:
Stock options		—	2,774

Diluted	$	507,882	335,681	$	1.51

2003
Basic	$	288,279	299,665	$	0.96

Effect of dilutive securities:
Stock options		—	4,087

Diluted	$	288,279	303,752	$	0.95

2002
Basic	$	186,059	277,834	$	0.67

Effect of dilutive securities:
Stock options		—	1,378
Warrants		—	1,874

Diluted	$	186,059	281,086	$	0.66


	One Percentage Point
*(in thousands)*	Increase		Decrease
Effect on total service and interest cost	$	105	$	89
Effect on the post-retirement benefit obligation	$	513	$	450


Shares Outstanding at December 31, 2004		Vesting Price
397,500		$28.13
2,533		$28.50
397,500		$31.88

797,533


	Weighted Average Exercise Price		Stock Options
2002
Beginning of year	$	8.07	15,413,893
Grants		10.24	1,104,677
Exercises		6.52	(1,591,438	)
Forfeitures		7.90	(73,063	)

End of year		8.40	14,854,069

Exercisable at end of year		8.33	14,339,138

2003
Beginning of year	$	8.40	14,854,069
Grants		15.06	3,530,208
Exercises		8.46	(10,430,123	)
Forfeitures		13.88	(55,000	)

End of year		11.15	7,899,154

Exercisable at end of year		9.22	5,310,993

2004
Beginning of year	$	11.15	7,899,154
Grants		24.86	16,229,845
Exercises		13.17	(4,794,177	)
Forfeitures		15.14	(15,000	)

End of year		22.16	19,319,822

Exercisable at end of year		11.99	4,092,488


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number	Weighted Average Remaining Term	Weighted Average Exercise Price		Number	Weighted Average Exercise Price
$ 5.23 - $ 7.85	1,948,925	6.1 years	$	7.15	1,948,925	$	7.15
$ 7.86 - $10.46	1,099,233	7.0 years	$	9.43	1,099,233	$	9.43
$10.47 - $13.08	19,329	8.5 years	$	11.67	19,329	$	11.67
$13.09 - $15.70	55,667	8.9 years	$	15.14	55,667	$	15.14
$15.71 - $20.93	20,000	9.4 years	$	19.22	20,000	$	19.22
$20.94 - $26.16	16,176,668	7.2 years	$	24.88	949,334	$	24.58

	19,319,822	7.1 years	$	22.16	4,092,488	$	11.99


	Pro Forma (Unaudited)
*(in thousands, except per share data)*	Year Ended December 31
	2004		2003
Revenues	$	2,186,961	$	1,645,307

Net income before cumulative effect of accounting change	$	574,233	$	381,985

Net income	$	574,233	$	383,763

Earnings per common share:
Basic	$	1.68	$	1.19

Diluted	$	1.66	$	1.17

Weighted average shares outstanding		342,211		322,990


*(in thousands, except per share data)*	Quarter
	1st		2nd		3rd		4th
2004
Revenues	$	394,764	$	444,749	$	507,430	$	600,658
Gross profit (a)	$	215,777	$	254,986	$	284,446	$	329,164
Net income	$	94,136	$	99,089	$	140,782	$	173,875
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		312,727		326,087		345,281		347,118
2003
Revenues	$	253,484	$	282,159	$	322,058	$	331,854
Gross profit (a)	$	125,532	$	140,274	$	172,789	$	170,744
Income before cumulative effect of accounting change	$	64,452	$	57,335	$	102,806	$	61,908
Cumulative effect of accounting change, net of tax		1,778		—		—		—

Net income	$	66,230	$	57,335	$	102,806	$	61,908

Earnings per common share (b)
Basic:
Net income before cumulative effect of accounting change	$	0.22	$	0.19	$	0.34	$	0.20
Cumulative effect of accounting change, net of tax		0.01		—		—		—

Net income	$	0.23	$	0.19	$	0.34	$	0.20

Diluted:
Net income before cumulative effect of accounting change	$	0.22	$	0.19	$	0.33	$	0.20
Cumulative effect of accounting change, net of tax		0.01		—		—		—

Net income	$	0.23	$	0.19	$	0.33	$	0.20

Average shares outstanding		282,263		300,275		306,320		309,431


*(in thousands)*	Gas (Mcf)		Natural Gas Liquids (Bbls)		Oil (Bbls)		Natural Gas Equivalents (Mcfe)
*Proved Reserves*
December 31, 2001	2,235,478		20,299		54,049		2,681,566
Revisions	76,400		2,433		5,465		123,788
Extensions, additions and discoveries	426,541		2,395		1,144		447,775
Production	(187,583	)	(1,850	)	(4,757	)	(227,225	)
Purchases in place	330,387		2,156		449		346,017
Sales in place	(42	)	—		(1	)	(48	)

December 31, 2002	2,881,181		25,433		56,349		3,371,873
Revisions	(11,644	)	5,487		1,792		32,030
Extensions, additions and discoveries	559,773		1,610		424		571,977
Production	(243,979	)	(2,359	)	(4,724	)	(286,477	)
Purchases in place	465,732		4,508		2,204		506,004
Sales in place	(6,824	)	(1	)	(614	)	(10,514	)

December 31, 2003	3,644,239		34,678		55,431		4,184,893
Revisions	(96,139	)	(146	)	3,001		(79,009	)
Extensions, additions and discoveries	755,385		3,730		4,176		802,821
Production	(305,453	)	(2,739	)	(8,307	)	(371,729	)
Purchases in place	716,471		2,933		98,205		1,323,299

December 31, 2004	4,714,503		38,456		152,506		5,860,275