Form 10-K for the Period Ended December 31, 2004

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.

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

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, ou


	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