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##### Index to Financial Statements

2004

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



Form 10-K



|x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ------------------------------------------------------------------------------------



For the fiscal year ended December 31, 2004



OR



| ̈ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ----------------------------------------------------------------------------------------



For the transition period from
 to



Commission File Number: 1-10662



XTO Energy Inc.

(Exact name of
registrant as specified in its charter)



|                                                               |  |                                      |  |                                          |  |           
|-------------------------------------------------------------- |  | ------------------------------------ |  | ---------------------------------------- |  | ----------
|Delaware                                                       |  | 75-2347769                           |  | 810 Houston Street, Fort Worth, Texas    |  | 76102     
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.) |  | (Address of principal executive offices) |  | (Zip Code)



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



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



|                                                                        |  |                                          
|----------------------------------------------------------------------- |  | -----------------------------------------
|Title of Each Class                                                     |  | Name of Each Exchange on Which Registered
|Common Stock, $.01 par value, including preferred stock purchase rights |  | New York Stock Exchange                  



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

None



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



Yes x No ̈



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



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



Yes x No ̈



Aggregate
market value of the Common Stock based on the closing price on the New York Stock Exchange as of June 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



DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)



Part III of this Report is
incorporated by reference from the Registrants definitive Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 29, 2005.



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XTO ENERGY INC.

2004 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS



|          |  |                                                                                       |  |     
|--------- |  | ------------------------------------------------------------------------------------- |  | ----
|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  



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PART I



Items 1. and 2.BUSINESS AND PROPERTIES



General



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



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:



| |  |  | Eastern Region, including the East Texas Basin and northwestern Louisiana;
| | - |  | --------------------------------------------------------------------------



| |  |  | Barnett Shale of North Texas;
| | - |  | -----------------------------



| |  |  | San Juan and Raton basins of northern New Mexico and southern Colorado;
| | - |  | -----------------------------------------------------------------------



| |  |  | Arkoma Basin of Arkansas and Oklahoma;
| | - |  | --------------------------------------



| |  |  | Permian Basin of West Texas and southeastern New Mexico;
| | - |  | --------------------------------------------------------



| |  |  | Hugoton Field of Oklahoma and Kansas;
| | - |  | -------------------------------------



| |  |  | Anadarko Basin of Oklahoma;
| | - |  | ---------------------------



| |  |  | Green River and Powder River basins of Wyoming;
| | - |  | -----------------------------------------------



| |  |  | Uinta Basin of Utah;
| | - |  | --------------------



| |  |  | Middle Ground Shoal Field of Alaskas Cook Inlet; and
| | - |  | -----------------------------------------------------



| |  |  | South Texas Region.
| | - |  | -------------------



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




1



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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.



History of the Company



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



During 1991, we formed Cross Timbers Royalty Trust by
conveying a 90% net profits interest in substantially all of the royalty and overriding royalty interests that we then owned in Texas, New Mexico and Oklahoma, and a 75% net profits interest in seven nonoperated working interest properties in Texas
and Oklahoma. Cross Timbers Royalty Trust units are listed on the New York Stock Exchange under the symbol CRT. From 1996 to 1998, we purchased 1,360,000, or 22.7%, of the outstanding units, at a total cost of $18.7 million. In August
2003, our Board of Directors declared a dividend of 0.0044 units of the trust for each share of our common stock outstanding on September 2, 2003. As a result of this dividend, all of the 1,360,000 trust units were distributed on September 18, 2003.



In December 1998, we formed the Hugoton Royalty Trust by
conveying an 80% net profits interest in principally gas-producing operated working interests in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These net profits interests were conveyed
to the trust in exchange for 40 million units of beneficial interest. We sold 17 million units in the trusts initial public offering in 1999 and 1.3



2



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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.



Industry Operating Environment



The oil and gas industry is affected by many factors that we generally cannot control. Governmental regulations, particularly in the areas of taxation, energy and the environment, can have a significant impact on operations and
profitability. Crude oil prices are determined by global supply and demand. Oil supply is significantly influenced by production levels of OPEC member countries, while demand is largely driven by the condition of worldwide economies, as well as
weather. Natural gas prices are generally determined by North American supply and demand. Weather has a significant impact on demand for natural gas since it is a primary heating resource. Its increased use for electrical generation has kept natural
gas demand elevated throughout the year, removing some of the seasonal swing in prices. See Significant Events, Transactions and Conditions  Product Prices in Part II, Item 7, Managements Discussion and Analysis of Financial
Condition and Results of Operations, regarding recent price fluctuations and their effect on our results.



Business Strategy



The
primary components of our business strategy are:



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



| |  |  | increasing production and reserves through aggressive management of operations and through development, exploitation and exploration activities,
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | hedging a portion of our production to stabilize cash flow and protect the economic return on development projects and acquisitions, and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------



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



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



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



| |  |  | produce from non-conventional sources, including tight natural gas reservoirs, coal bed methane and natural gas-producing shale formations,
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | present opportunities to reduce expenses per Mcfe, and lower the rate of potential increases to expenses per Mcfe, through more efficient operations.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------



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



3



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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:



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



| |  |  | ability to help assure the economic return on strategic acquisitions,
| | - |  | ---------------------------------------------------------------------



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



| |  |  | more consistent returns on investment, and
| | - |  | ------------------------------------------



| |  |  | better utilization of our personnel.
| | - |  | ------------------------------------



Experienced Management and Technical Staff. Most senior management and technical staff have worked together for over 20 years and have substantial
experience in our core operating areas. Bob R. Simpson 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.



4



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##### 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.



Acquisitions



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



5



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##### 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.



Significant Properties



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



|                                       |  |                 |  |                                                               |  |           |  |                               |  |   |            |  |      |  
|-------------------------------------- |  | --------------- |  | ------------------------------------------------------------- |  | --------- |  | ----------------------------- |  | - | ---------- |  | ---- | -
|                                       |  | 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  | %
|                                       |  |                 |  |                                                               |  |           |  |                               |  |   |            |  |      |  

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|(a) | Includes 192,719,000 Mcf of gas and 1,647,000 Bbls of oil and discounted present value before income tax of $403,441,000 related to our ownership of approximately 54% of Hugoton
Royalty Trust units at December 31, 2004. The remainder is our retained interests in the properties underlying the trusts net profits interests.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Eastern Region



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.



Freestone Trend



The Freestone Trend area is located in the western shelf of the East Texas
Basin in Freestone, Robertson, Limestone and Leon counties. This area includes the Freestone, Bald Prairie, Bear Grass, Oaks, Teague, Farrar, Dew and Luna fields and was our most active gas development area in 2004, where 185 gross (166.1 net) gas
wells were



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##### 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 Eastern Region Fields



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.



North Texas Region



Barnett Shale



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.



San Juan Basin and Rocky Mountain Area



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.



San Juan Basin



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.



Raton Basin



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



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##### Table of Contents

##### 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.



Rocky Mountains



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.



Permian Basin and South Texas Region



Permian Basin



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



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##### 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.



South Texas Region



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.



Arkoma Basin and Mid-Continent Region



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.



Hugoton Royalty Trust



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.



Western Oklahoma



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.



Hugoton Area



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.



9



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##### 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.



Green River Basin



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.



Alaska Cook Inlet



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.



Reserves



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



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



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



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.



10



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##### Index to Financial Statements

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



|                                                                     |  |             |            |      |   |            |  |   |           
|-------------------------------------------------------------------- |  | ----------- | ---------- | ---- | - | ---------- |  | - | ----------
|                                                                     |  | 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 



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



11



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##### Table of Contents

##### 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.



Exploration and Production Data



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



Producing Wells



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



|      |  |                |  |                   |  |          |  |         |  |          |  |        
|----- |  | -------------- |  | ----------------- |  | -------- |  | ------- |  | -------- |  | -------
|      |  | 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
|      |  |                |  |                   |  |          |  |         |  |          |  |        

---

|(a) | 672.0 gross (378.5 net) gas wells and 9.0 gross (5.5 net) oil wells are dual completions.
|--- | -----------------------------------------------------------------------------------------



Drilling Activity



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



|                   |  |                        |  |       |  |       |  |       |  |       |  |      
|------------------ |  | ---------------------- |  | ----- |  | ----- |  | ----- |  | ----- |  | -----
|                   |  | 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
|                   |  |                        |  |       |  |       |  |       |  |       |  |      

---

|(a) | Included in totals are 212 gross (27.3 net) wells in 2004, 102 gross (17.66 net) wells in 2003 and 75 gross (11.2 net) wells in 2002, drilled on nonoperated interests.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Index to Financial Statements

Acreage



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.



|           |  |                       |  |                   |  |         |  |        
|---------- |  | --------------------- |  | ----------------- |  | ------- |  | -------
|           |  | 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
|           |  |                       |  |                   |  |         |  |        

---

|(a) | Developed acres are acres spaced or assignable to productive wells.
|--- | -------------------------------------------------------------------



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



Oil and Gas Sales Prices and Production Costs



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



|                                          |  |                        |       |      |   |       |  |   |      
|----------------------------------------- |  | ---------------------- | ----- | ---- | - | ----- |  | - | -----
|                                          |  | Year Ended December 31
|                                          |  | 2004                   |       | 2003 |   | 2002 
|Sales prices:                             |  |                        |       |      |   |       |  |   |      
|Gas (per Mcf)                             |  | $                      | 5.04  |      | $ | 4.07  |  | $ | 3.49 
|Natural gas liquids (per Bbl)             |  | $                      | 26.44 |      | $ | 19.99 |  | $ | 14.31
|Oil (per Bbl)                             |  | $                      | 38.38 |      | $ | 28.59 |  | $ | 24.24
|                                          |  |                        |      
|Production expense per Mcfe               |  | $                      | 0.66  |      | $ | 0.58  |  | $ | 0.57 
|Production and property taxes per Mcfe    |  | $                      | 0.30  |      | $ | 0.21  |  | $ | 0.15 
|Transportation and other expense per Mcfe |  | $                      | 0.17  |      | $ | 0.16  |  | $ | 0.10 



Delivery Commitments



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



Competition and Markets



We compete with other oil and gas companies in all
aspects of our business, including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and obtaining goods, services and labor. Some of our competitors have substantially larger financial and other resources.
Factors that affect our ability to acquire producing properties include available funds, available information about the property and our standards established for minimum



13



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##### 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.



Federal and State Regulations



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



Federal Energy Bill



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.



Federal Regulation of Natural Gas



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.



Federal Regulation of Oil



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



State Regulation



Oil and gas operations are subject to various types of regulation at the state and local levels. Such regulation includes requirements for drilling
permits, the method of developing new fields, the spacing and operations of wells and waste prevention. The production rate may be regulated and the maximum daily production allowable from oil and gas



14



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##### Table of Contents

##### 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.



Federal, State or Native American Leases



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



Environmental Regulations



Various federal, state and local laws 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.



Employees



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



Executive Officers of the Company



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



Bob R.
Simpson, 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.



15



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##### Table of Contents

##### 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.



|Item 3. | LEGAL PROCEEDINGS
|------- | -----------------



On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et
al., was filed in the U.S. District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against the Company and certain of our
subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing
its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney fees and expenses), civil penalties between $5,000 and $10,000 for
each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other companies have been consolidated in the
United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynbergs royalty valuation claims, and Grynbergs appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. The
parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other defendants in filing a motion to dismiss,
contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion 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



16



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##### Table of Contents

##### 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.



|Item 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
|------- | ---------------------------------------------------



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:



|            |  |            |  |         
|----------- |  | ---------- |  | --------
|For         |  | Against    |  | Withheld
|212,600,831 |  | 55,755,692 |  | 333,498 



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##### Index to Financial Statements



PART II



|Item 5. | MARKET FOR REGISTRANTS COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|------- | ------------------------------------------------------------------------------------------------------------



Our common stock is listed on the New York Stock Exchange and trades under
the symbol XTO. The following table sets forth quarterly high and low sales prices and cash dividends declared for each quarter of 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):



|               |  |      |        |     |   |              |  |   |        |    
|-------------- |  | ---- | ------ | --- | - | ------------ |  | - | ------ | ---
|               |  | High |        | Low |   | CashDividend | 
|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 |    



|(a) | In September 2003, we distributed as a dividend to our shareholders all of the Cross Timbers Royalty Trust units owned by the Company. This dividend was recorded at a market value
of $28.2 million, or approximately $0.09 per common share.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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:



|         |  |                                |     |  |                             |       |                                                                                 |        |                                                                               |           
|-------- |  | ------------------------------ | --- |  | --------------------------- | ----- | ------------------------------------------------------------------------------- | ------ | ----------------------------------------------------------------------------- | ----------
|Month    |  | Total Numberof SharesPurchased |     |  | Average PricePaid per Share |       | Total Number ofShares Purchasedas Part of PubliclyAnnounced Plansor Programs(b) |        | Maximum Numberof Shares that MayYet Be PurchasedUnder the Plans orPrograms(b)
|October  |  |                               |     |  | $                           |      |                                                                                 |       |                                                                               |           
|November |  | 696                            | (a) |  | $                           | 27.26 |                                                                                 |       |                                                                               |           
|December |  | 33,600                         |     |  | $                           | 24.18 |                                                                                 | 33,600 |                                                                               |           
|         |  |                                |     |  |                             |       |                                                                                 |        |                                                                               |           
|Total    |  | 34,296                         |     |  | $                           | 24.24 |                                                                                 | 33,600 |                                                                               | 19,966,400
|         |  |                                |     |  |                             |       |                                                                                 |        |                                                                               |           



|(a) | During the quarter ended December 31, 2004, the Company purchased shares of common stock as treasury shares to pay income tax withholding obligations in conjunction with vesting of
performance shares under the 1998 Stock Incentive Plan. These share purchases were not part of a publicly announced program to purchase common shares.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(b) | The Company has a repurchase program approved by the Board of Directors for the repurchase of up to 20,000,000 shares of the Companys common stock. The repurchase program was
announced on August 18, 2004.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

##### Index to Financial Statements

|Item 6. | SELECTED FINANCIAL DATA
|------- | -----------------------



The following table shows selected financial information for each of the
years in the five-year period ended December 31, 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).



|                                                              |  |      |            |     |      |   |            |      |  |   |           |     |  |      |           |     |  |   |           |    
|------------------------------------------------------------- |  | ---- | ---------- | --- | ---- | - | ---------- | ---- |  | - | --------- | --- |  | ---- | --------- | --- |  | - | --------- | ---
|(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       |    



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##### Index to Financial Statements

|(a) | Includes pre-tax effects of a derivative fair value loss of $11.9 million, stock-based incentive compensation of $89.5 million and special bonuses totaling $11.7 million related to
the ChevronTexaco and ExxonMobil acquisitions. Stock-based incentive compensation includes cash compensation of $22.3 million related to cash-equivalent performance shares.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(b) | Includes pre-tax effects of a derivative fair value loss of $10.2 million, a non-cash contingency gain of $1.7 million, non-cash incentive compensation of $53.1 million, a $9.6
million loss on extinguishment of debt, a $16.2 million non-cash gain on the distribution of Cross Timbers Royalty Trust units, and a $1.8 million after-tax gain on adoption of the new accounting standard for asset retirement obligation.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(c) | Includes pre-tax effects of a derivative fair value gain of $2.6 million, gain on settlement with Enron Corporation of $2.1 million, non-cash incentive compensation of $27 million
and an $8.5 million loss on extinguishment of debt.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(d) | Includes pre-tax effects of a derivative fair value gain of $54.4 million and non-cash incentive compensation of $9.6 million, and an after-tax charge of $44.6 million for the
cumulative effect of accounting change.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(e) | Includes pre-tax effects of a derivative fair value loss of $55.8 million, a gain of $43.2 million on significant asset sales, and non-cash incentive compensation expense of $26.1
million.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



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



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



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##### Index to Financial Statements

|Item 7. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
|------- | -------------------------------------------------------------------------------------



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



Overview



Our business is to produce and sell natural gas, natural
gas liquids and crude oil from our predominantly southwestern and central U.S. properties, most of which we operate. Because 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.



In 2004, we achieved the following record financial and operating results:



| |  |  | Average daily gas production was 835,000 Mcf, a 25% increase from 2003, average daily oil production was 22,696 Bbls, a 75% increase from 2003, and average daily natural gas liquids
production was 7,484 Bbls, a 16% increase from 2003.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Year-end proved reserves were 5.86 Tcfe, a 40% increase from year-end 2003.
| | - |  | ---------------------------------------------------------------------------



| |  |  | Net income was $507.9 million, a 76% increase from 2003, and earnings per basic common share was $1.53, a 59% increase from 2003.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------



| |  |  | Cash flow from operating activities was $1.22 billion, a 53% increase from 2003.
| | - |  | --------------------------------------------------------------------------------



| |  |  | Stockholders equity was $2.6 billion, a 77% increase from year-end 2003.
| | - |  | -------------------------------------------------------------------------



| |  |  | The debt-to-capitalization ratio improved to 44% at year-end from 46% at year-end 2003.
| | - |  | ---------------------------------------------------------------------------------------



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.



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.



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##### 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:



|                                                                         |  |      |      |      |   |                    |  |    
|------------------------------------------------------------------------ |  | ---- | ---- | ---- | - | ------------------ |  | ---
|                                                                         |  | 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%
|                                                                         |  |      |      |      |   |                    |  |    



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.



Significant expenses that generally do not trend with production include:



Stock-based incentive compensation. This is a component of general and administrative expense and primarily relates to 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



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##### 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.



Significant Events, Transactions and Conditions



The following events, transactions and conditions affect the comparability of results of operations and financial condition for each of the years ended
December 31, 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:



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##### Index to Financial Statements

|             |  |                 |  |                             |  |                  |     |  |                                                                                                            
|------------ |  | --------------- |  | --------------------------- |  | ---------------- | --- |  | -----------------------------------------------------------------------------------------------------------
|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                                                                                 



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.



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##### 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:



|                                               |  |                        |      |      |   |      |  |   |     
|---------------------------------------------- |  | ---------------------- | ---- | ---- | - | ---- |  | - | ----
|                                               |  | 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



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:



|                                               |  |                        |       |      |   |       |  |   |      
|---------------------------------------------- |  | ---------------------- | ----- | ---- | - | ----- |  | - | -----
|                                               |  | 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



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##### 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.



|                                                                                   |  |                             |      |             |        |                             |   |      
|---------------------------------------------------------------------------------- |  | --------------------------- | ---- | ----------- | ------ | --------------------------- | - | -----
|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
|                                                                                   |  |                            
|250,000                                                                            |  | $                           | 5.90 |             | 10,000 |                             | $ | 35.91
|                                                                                   |  |                             |      |             | 5,000  |                             | $ | 43.28



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



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##### 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 91⁄4% senior subordinated notes in April 2002, and redeemed the remaining $115.3 million
of the 91⁄4% notes in June 2002. In November 2002, we purchased and canceled $11.8 million of our 83⁄4% senior subordinated notes and redeemed the remaining $163.2 million of the 83⁄4% 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 71⁄2% senior notes due April 2012, and in April 2003, we sold $400 million of 61⁄4% senior notes
due April 2013. In January 2004, we sold $500 million of 4.9% senior notes due February 2014. In September 2004, we sold $350 million of 5% senior notes due in January 2015. 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 83⁄4% 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.



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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.



Results of Operations



2004 Compared to 2003



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.



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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.



2003 Compared to 2002



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 83⁄4% senior subordinated notes, compared with the recognition in 2002 of an $8.5 million loss on extinguishment of debt



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primarily related to the redemption of our 91⁄4% 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.



Liquidity and Capital Resources



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.



Financial Condition



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.



Working Capital



We generally maintain low cash and cash equivalent balances because we use available funds to reduce bank debt. Short-term liquidity needs are satisfied
by bank commitments under 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.



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##### 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.



Financing



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.



Capital Expenditures



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.



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.



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. There are no restrictions under our
revolving credit agreement that would affect our ability to use our remaining borrowing capacity for acquisitions of producing properties.



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



Dividends



The Board of Directors declared quarterly dividends of $0.0045 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



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##### 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.



Income Taxes



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.



Contractual Obligations and Commitments



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.



|                                                                |  |       |           |                      |   |         |  |      |        |      |   |        |  |            |        |  |   |         |  |   |          
|--------------------------------------------------------------- |  | ----- | --------- | -------------------- | - | ------- |  | ---- | ------ | ---- | - | ------ |  | ---------- | ------ |  | - | ------- |  | - | ---------
|                                                                |  |       |           | 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
|                                                                |  |       |           |                      |   |         |  |      |        |      |   |        |  |            |        |  |   |         |  |   |          



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.



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Post-Retirement Plans



We have a retiree medical plan that provides retired employees and directors with health care benefits similar to those provided employees. Employees and
directors are eligible to receive benefits when their combined age and years of qualified service total 60, with a minimum age of 45 and a minimum of five years of service. Otherwise, retirement benefits are only provided through our defined
contribution 401(k) plan. Post-retirement medical benefits are not prefunded but are paid when incurred. Our periodic benefit cost recorded for 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.



Related Party Transactions



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.



Critical Accounting Policies and Estimates



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



Oil and Gas Property Accounting



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



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



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



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##### 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.



Oil and Gas Reserves



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



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



Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas
reserves. While total DD&A expense for the life of a property is limited to the propertys total cost, proved reserve revisions result in a change in timing of when DD&A expense is recognized. Downward revisions of proved reserves
result in an acceleration of DD&A expense, while upward revisions tend to lower the rate of DD&A expense recognition. As shown in Note 15 to the Consolidated Financial Statements, net upward revisions occurred to proved reserves on an Mcfe
basis in 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.



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Asset Retirement Obligation



Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. Our asset retirement
obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties (including removal of our offshore platforms in Alaska) at the end of their productive lives, in
accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present
value as of the assets inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.



Our liability is determined using significant assumptions, including current
estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset
retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 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 and Risk Management



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



We attempt to reduce our price risk on a portion of our production by entering into financial instruments such as futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. While these
instruments secure a certain price and, therefore, a certain cash flow, there is the risk that we may not be able to realize the full benefit of rising prices. These contracts also expose us to credit risk of nonperformance by the contract
counterparties, all of which are major investment grade financial institutions. We attempt to limit our credit risk by obtaining letters of credit or other appropriate forms of security. 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.



Accounting Pronouncements



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



35



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##### Table of Contents

##### 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:



| |  |  | Companies may enter concurrent commodity buy/sale arrangements, or transactions in contemplation of other transactions, often to assure that the commodity is available at a specific
location. Pending resolution of accounting questions with the Emerging Issues Task Force, the Commission staff has requested additional disclosures for any such material arrangements, including separate disclosure on the face of the income statement
of any related proceeds and costs reported on a gross basis. These disclosures are not applicable to us since we have not entered any significant transactions of this nature.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, specifies that drilling costs for completed
exploratory wells should be expensed if the related reserves cannot be classified as proved within one year unless certain criteria are met. Rather than specifying this one-year requirement, a proposed FASB Staff Position has been issued that
provides guidance for evaluating whether sufficient progress is being made to determine whether reserves can be classified as proved. Pending approval of the FASB Staff Position, the Commission staff has requested additional disclosures be included
in registrants financial statements regarding their accounting policy for capitalization of exploratory drilling costs, as well as disclosure of capitalized exploratory drilling cost amounts included in the financial statements. As disclosed
in Note 1 to Consolidated Financial Statements, we generally pursue development of proved reserves as opposed to exploration activities, and our drill well costs are generally transferred to producing properties within one month of the well
completion date. Disclosure of changes in capitalized exploratory well costs is included in Note 15 to Consolidated Financial Statements.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Index to Financial Statements

Production Imbalances



We have gas production imbalance positions that are the result of partial interest owners selling more or less than their proportionate share of gas on
jointly owned wells. Imbalances are generally settled by disproportionate gas sales over the remaining life of the well, or by cash payment by the overproduced party to the underproduced party. We use the entitlement method of accounting for natural
gas sales. Accordingly, revenue is deferred for gas deliveries in excess of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the
time of production. The consolidated balance sheets include the following amounts related to production imbalances:



|                                                         |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|-------------------------------------------------------- |  | ----------- | ------- | - | ---- | ------ | - | ------ | - | ------- | --- |  | ------ | -
|                                                         |  | December 31 |        
|                                                         |  | 2004        |         |   | 2003 |       
|(in thousands)                                           |  | Amount      |         |   | Mcf  |        |   | Amount |   |         | Mcf | 
|Accounts receivable - current underproduction            |  | $           | 30,780  |   |      | 8,116  |   |        | $ | 23,949  |     |  | 7,135  |  
|Accounts payable - current overproduction                |  |             | (24,087 | ) |      | (6,388 | ) |        |   | (19,366 | )   |  | (5,900 | )
|                                                         |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net current gas underproduction balancing receivable     |  | $           | 6,693   |   |      | 1,728  |   |        | $ | 4,583   |     |  | 1,235  |  
|                                                         |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Other assets - noncurrent underproduction                |  | $           | 17,723  |   |      | 4,868  |   |        | $ | 19,385  |     |  | 6,148  |  
|Other long-term liabilities - noncurrent overproduction  |  |             | (33,262 | ) |      | (9,063 | ) |        |   | (29,776 | )   |  | (9,353 | )
|                                                         |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net long-term gas overproduction balancing payable       |  |             | (15,539 | ) |      | (4,195 | ) |        |   | (10,391 | )   |  | (3,205 | )
|                                                         |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Other assets - noncurrent carbon dioxide underproduction |  |             | 1,985   |   |      | 12,480 |   |        |   | 1,977   |     |  | 12,354 |  
|                                                         |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net long-term overproduction balancing payable           |  | $           | (13,554 | ) |      |        |   |        | $ | (8,414  | )   |  |        |  
|                                                         |  |             |         |   |      |        |   |        |   |         |     |  |        |  



Forward-Looking Statements



Certain information included in this annual report and
other materials filed or to be filed by us with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by us, contain projections and forward-looking statements
within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to our operations and the oil and gas industry. Such forward-looking statements may be or may
concern, among other things, capital expenditures, capital budget, cash flow, drilling activity, drilling locations, acquisition and development activities and funding thereof, production and reserve growth, pricing differentials, reserve potential,
operating costs, operating margins, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, unused borrowing capacity, estimated stock award vesting periods,
completion of pipelines and processing facilities, regulatory matters 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



37



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##### 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.



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##### Index to Financial Statements

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



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



Governmental Regulations.Extensive federal, state and local
regulation of the oil and gas industry significantly affects our operations. In particular, our oil and natural gas exploration, development and production, and our storage and transportation of liquid hydrocarbons, are subject to stringent
environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other related facilities. These regulations may become more demanding in the
future. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, reports concerning operations, and taxation.



Under these laws and regulations, we could be liable for personal injuries, property damage,
oil spills, discharge of hazardous materials, reclamation costs, remediation and clean-up costs, and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations
and subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. Any of these liabilities, penalties, suspensions, terminations or regulatory changes
could make it more expensive for us to conduct our business or cause us to limit or curtail some of our operations.



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



Our operations in the coastal waters of Cook Inlet of Alaska are subject to the federal Oil Pollution Act, which imposes a variety of requirements related to the
prevention of oil spills and liability for damages resulting from such spills in United States waters. The Oil Pollution Act imposes strict joint and several liability on responsible parties for oil removal costs and a variety of public and private
damages, including natural resource damages. Liability limits for offshore facilities require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was
caused by gross negligence or willful misconduct of the party, if the spill



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##### Index to Financial Statements

resulted from violation of a federal safety, construction or operation regulation, or if the party failed to report the spill or cooperate fully in any
resulting cleanup. The Oil Pollution Act also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.
We believe our operations are in substantial compliance with Oil Pollution Act requirements.



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



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



|Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
|-------- | ----------------------------------------------------------



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



Our Board of Directors has adopted a policy
governing the use of derivative instruments, which requires that all derivatives used by us relate to an underlying, offsetting position, anticipated transaction or firm commitment, and prohibits the use of speculative, highly complex or leveraged
derivatives. The policy also requires review and approval by the Chairman, the Executive Vice President - Administration and the Senior Vice President - Marketing of all risk management programs using derivatives and all derivative transactions.
These programs are also reviewed at least quarterly by our internal risk management committee and annually by the Board of Directors.



Hypothetical changes in interest rates and prices chosen for the following estimated sensitivity effects are considered to be reasonably possible
near-term changes generally based on consideration of past fluctuations for each risk category. It is not possible to accurately predict future changes in interest rates and product prices. Accordingly, these hypothetical changes may not necessarily
be an indicator of probable future fluctuations.



Interest Rate Risk



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



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##### Index to Financial Statements

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



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

---

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



Commodity Price Risk



We hedge a portion of our price risks associated with our crude oil and
natural gas sales. As of December 31, 2004, we had outstanding gas futures contracts, swap agreements and gas basis swap agreements. These contracts and agreements had a net fair value loss of approximately $30.8 million at December 31, 2004 and a
net fair value loss of $84.7 million at December 31, 2003. Of the December 31, 2004 fair value, a $34.8 million loss has been determined based on the exchange-trade value of NYMEX contracts, and a $4 million gain has been determined based on the
broker bid and ask quotes for basis contracts. These fair values approximate amounts confirmed by the counterparties. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $47.9 million in the fair
value of gas futures contracts and swap agreements at December 31, 2004. As of December 31, 2004, outstanding oil futures contracts and differential swaps had a net fair value loss of $22.1 million. The aggregate effect of a hypothetical 10% change
in oil prices would result in a change of approximately $20.6 million in the fair value of these oil futures and differential swaps at December 31, 2004. None of our derivative contracts have margin requirements or collateral provisions that could
require funding prior to the scheduled cash settlement date. See Note 8 to Consolidated Financial Statements.



Because most of our futures contracts and swap agreements have been designated as hedge derivatives, changes in their fair value generally are reported as
a component of accumulated other comprehensive income (loss) until the related sale of production occurs. At that time, the realized hedge derivative gain or loss is transferred to product revenues in the consolidated income statement.



We had a physical delivery contract to sell 35,500 Mcf per day from 2002
through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. Because this gas sales contract was priced based on crude oil, which is not clearly and closely associated with natural gas prices, it
was accounted for as a non-hedge derivative financial instrument. This contract (referred to as the Enron Btu swap contract) was terminated in December 2001 in conjunction with the bankruptcy filing of Enron Corporation. In November 2001, we entered
derivative contracts to effectively defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. The net fair value loss on these contracts at December
31, 2004 was $19.1 million. The effect of a hypothetical 10% change in gas prices would result in a change of approximately $5.6 million in the fair value of these contracts, while a 10% change in crude oil prices would result in a change of
approximately $3.7 million. Since the contracts are not hedge derivatives, changes in their fair value are recognized in our consolidated income statement as a derivative fair value gain or loss.



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##### Index to Financial Statements

|Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|------- | -------------------------------------------



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



|                                                                                                  |  |     
|------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                  |  | Page
|                                                                                                  | 
|Consolidated Balance Sheets                                                                       |  | 45  
|                                                                                                  | 
|Consolidated Income Statements                                                                    |  | 46  
|                                                                                                  | 
|Consolidated Statements of Cash Flows                                                             |  | 47  
|                                                                                                  | 
|Consolidated Statements of Stockholders Equity                                                   |  | 48  
|                                                                                                  | 
|Notes to Consolidated Financial Statements                                                        |  | 49  
|                                                                                                  | 
|Selected Quarterly Financial Data (Note 14 to Consolidated Financial Statements)                  |  | 75  
|                                                                                                  | 
|Information about Oil and Gas Producing Activities (Note 15 to Consolidated Financial Statements) |  | 76  
|                                                                                                  | 
|Managements Report on Internal Control over Financial Reporting                                  |  | 80  
|                                                                                                  | 
|Reports of Independent Registered Public Accounting Firm                                          |  | 81  



|Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
|------- | ------------------------------------------------------------------------------------



There have been no changes in accountants or any disagreements with accountants on any matter of accounting principles or practices or financial statement
disclosures during the two years ended December 31, 2004.



|Item 9A. | CONTROLS AND PROCEDURES
|-------- | -----------------------



a) Evaluation of Disclosure Controls and Procedures



We performed an evaluation, under the supervision and with the participation
of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the
period covered by this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to
the Company required to be included in our periodic filings with the Securities and Exchange Commission. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and
instances of fraud, if any, within our Company have been detected.



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



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



c) Changes in Internal Control over Financial Reporting



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



|Item 9B. | OTHER INFORMATION
|-------- | -----------------



None.



42



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PART III



Except for the portion of Item 10 relating to Executive Officers of the
Registrant which is included in Part I of this Report or is included below, the information called for by Items 10 through 14 is incorporated by reference to the Companys Notice of Annual Meeting and Proxy Statement to be filed with the
Securities and Exchange Commission no later than April 29, 2005.



|Item 10. | DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT
|-------- | --------------------------------------------------



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



|Item 11. | EXECUTIVE COMPENSATION
|-------- | ----------------------



|Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
|-------- | --------------------------------------------------------------



|Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
|-------- | ----------------------------------------------



|Item 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES
|-------- | --------------------------------------



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##### Index to Financial Statements



PART IV



|Item 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|-------- | ------------------------------------------



| | (a) | The following documents are filed as a part of this report:
| | --- | -----------------------------------------------------------



|   |  |                                                                                                                                                                                                                   |  |     
|-- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|   |  |                                                                                                                                                                                                                   |  | Page
|1. |  | Financial Statements:                                                                                                                                                                                             |  |     
|   |  | Consolidated Balance Sheets at December 31, 2004 and 2003                                                                                                                                                         |  | 45  
|   |  | Consolidated Income Statements for the years ended December 31, 2004, 2003 and 2002                                                                                                                               |  | 46  
|   |  | Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002                                                                                                                        |  | 47  
|   |  | Consolidated Statements of Stockholders Equity for the years ended December 31, 2004, 2003 and 2002                                                                                                              |  | 48  
|   |  | Notes to Consolidated Financial Statements                                                                                                                                                                        |  | 49  
|   |  | Managements Report on Internal Control over Financial Reporting                                                                                                                                                  |  | 80  
|   |  | Reports of Independent Registered Public Accounting Firm                                                                                                                                                          |  | 81  
|2. |  | Financial Statement Schedules:                                                                                                                                                                                    |  |     
|   |  | Schedule II - Consolidated Valuation and Qualifying Accounts                                                                                                                                                      |  | 83  
|   |  | All other financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to consolidated
financial statements. |  |     



|(b) | Exhibits
|--- | --------



See Index to Exhibits at page 85 for a description of the exhibits filed as a part of this report. Documents filed prior to June 1, 2001, were filed with the Securities and Exchange Commission under our prior name,
Cross Timbers Oil Company.



44



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##### Index to Financial Statements



XTO ENERGY INC.

Consolidated Balance Sheets



|                                                                                                        |      |             |            |      |  |   |            |  
|------------------------------------------------------------------------------------------------------- | ---- | ----------- | ---------- | ---- |  | - | ---------- | -
|(in thousands, except shares)                                                                           |      | December 31 |           
|                                                                                                        | 2004 |             |            | 2003 | 
|ASSETS                                                                                                  |      |             |            |      |  |   |            |  
|Current Assets:                                                                                         |      |             |            |      |  |   |            |  
|Cash and cash equivalents                                                                               |      | $           | 9,700      |      |  | $ | 6,995      |  
|Accounts receivable, net                                                                                |      |             | 333,134    |      |  |   | 193,666    |  
|Derivative fair value                                                                                   |      |             | 14,713     |      |  |   | 11,351     |  
|Current income tax receivable                                                                           |      |             | 9,089      |      |  |   | 4,503      |  
|Deferred income tax benefit                                                                             |      |             | 22,613     |      |  |   | 32,455     |  
|Other                                                                                                   |      |             | 47,716     |      |  |   | 12,193     |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Total Current Assets                                                                                    |      |             | 436,965    |      |  |   | 261,163    |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Property and Equipment, at cost  successful efforts method:                                            |      |             |            |      |  |   |            |  
|Producing properties                                                                                    |      |             | 6,871,245  |      |  |   | 4,253,221  |  
|Undeveloped properties                                                                                  |      |             | 61,170     |      |  |   | 12,627     |  
|Other                                                                                                   |      |             | 106,031    |      |  |   | 70,494     |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Total Property and Equipment                                                                            |      |             | 7,038,446  |      |  |   | 4,336,342  |  
|Accumulated depreciation, depletion and amortization                                                    |      |             | (1,414,068 | )    |  |   | (1,024,275 | )
|                                                                                                        |      |             |            |      |  |   |            |  
|Net Property and Equipment                                                                              |      |             | 5,624,378  |      |  |   | 3,312,067  |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Other Assets:                                                                                           |      |             |            |      |  |   |            |  
|Derivative fair value                                                                                   |      |             |           |      |  |   | 646        |  
|Other                                                                                                   |      |             | 49,029     |      |  |   | 37,258     |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Total Other Assets                                                                                      |      |             | 49,029     |      |  |   | 37,904     |  
|                                                                                                        |      |             |            |      |  |   |            |  
|TOTAL ASSETS                                                                                            |      | $           | 6,110,372  |      |  | $ | 3,611,134  |  
|                                                                                                        |      |             |            |      |  |   |            |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                    |      |             |            |      |  |   |            |  
|Current Liabilities:                                                                                    |      |             |            |      |  |   |            |  
|Accounts payable and accrued liabilities                                                                |      | $           | 415,350    |      |  | $ | 218,710    |  
|Payable to royalty trusts                                                                               |      |             | 9,823      |      |  |   | 4,848      |  
|Derivative fair value                                                                                   |      |             | 75,534     |      |  |   | 96,653     |  
|Other                                                                                                   |      |             | 259        |      |  |   | 346        |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Total Current Liabilities                                                                               |      |             | 500,966    |      |  |   | 320,557    |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Long-term Debt                                                                                          |      |             | 2,042,732  |      |  |   | 1,252,000  |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Other Long-term Liabilities:                                                                            |      |             |            |      |  |   |            |  
|Derivative fair value                                                                                   |      |             | 11,179     |      |  |   | 18,044     |  
|Deferred income taxes payable                                                                           |      |             | 756,369    |      |  |   | 426,730    |  
|Asset retirement obligation                                                                             |      |             | 159,948    |      |  |   | 93,379     |  
|Other                                                                                                   |      |             | 39,805     |      |  |   | 34,782     |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Total Other Long-term Liabilities                                                                       |      |             | 967,301    |      |  |   | 572,935    |  
|                                                                                                        |      |             |            |      |  |   |            |  
|Commitments and Contingencies (Note 6)                                                                  |      |             |            |      |  |   |            |  
|Stockholders Equity:                                                                                   |      |             |            |      |  |   |            |  
|Common stock ($.01 par value, 500,000,000 shares authorized, 348,428,489 and 312,335,137 shares issued) |      |             | 3,484      |      |  |   | 3,123      |  
|Additional paid-in capital                                                                              |      |             | 1,410,135  |      |  |   | 753,120    |  
|Treasury stock, at cost (1,250,266 and -0- shares)                                                      |      |             | (24,917    | )    |  |   |           |  
|Retained earnings                                                                                       |      |             | 1,239,553  |      |  |   | 762,640    |  
|Accumulated other comprehensive income (loss)                                                           |      |             | (28,882    | )    |  |   | (53,241    | )
|                                                                                                        |      |             |            |      |  |   |            |  
|Total Stockholders Equity                                                                              |      |             | 2,599,373  |      |  |   | 1,465,642  |  
|                                                                                                        |      |             |            |      |  |   |            |  
|TOTAL LIABILITIES AND STOCKHOLDERS EQUITY                                                              |      | $           | 6,110,372  |      |  | $ | 3,611,134  |  
|                                                                                                        |      |             |            |      |  |   |            |  



See accompanying notes
to consolidated financial statements.



45



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##### Index to Financial Statements



XTO ENERGY INC.

Consolidated Income Statements



|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|------------------------------------------------------------------- | ---- | ---------------------- | --------- | ---- |  | - | --------- | - |  | - | ------- | -
|(in thousands, except per share data)                               |      | Year Ended December 31 |          
|                                                                    | 2004 |                        |           | 2003 |  |   | 2002      |  
|REVENUES                                                            |      |                        |           |      |  |   |           |   |  |   |         |  
|Gas and natural gas liquids                                         |      | $                      | 1,613,135 |      |  | $ | 1,040,370 |   |  | $ | 681,147 |  
|Oil and condensate                                                  |      |                        | 318,800   |      |  |   | 135,058   |   |  |   | 115,324 |  
|Gas gathering, processing and marketing                             |      |                        | 18,380    |      |  |   | 12,982    |   |  |   | 11,622  |  
|Other                                                               |      |                        | (2,714    | )    |  |   | 1,145     |   |  |   | 2,070   |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|Total Revenues                                                      |      |                        | 1,947,601 |      |  |   | 1,189,555 |   |  |   | 810,163 |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|EXPENSES                                                            |      |                        |           |      |  |   |           |   |  |   |         |  
|Production                                                          |      |                        | 245,892   |      |  |   | 164,864   |   |  |   | 129,182 |  
|Taxes, transportation and other                                     |      |                        | 174,007   |      |  |   | 104,654   |   |  |   | 57,225  |  
|Exploration                                                         |      |                        | 10,513    |      |  |   | 1,811     |   |  |   | 2,186   |  
|Depreciation, depletion and amortization                            |      |                        | 406,749   |      |  |   | 284,006   |   |  |   | 204,109 |  
|Accretion of discount in asset retirement obligation                |      |                        | 7,592     |      |  |   | 5,330     |   |  |   |        |  
|Gas gathering and processing                                        |      |                        | 6,586     |      |  |   | 9,350     |   |  |   | 9,114   |  
|General and administrative                                          |      |                        | 165,092   |      |  |   | 107,675   |   |  |   | 62,114  |  
|Derivative fair value (gain) loss                                   |      |                        | 11,889    |      |  |   | 10,201    |   |  |   | (2,599  | )
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|Total Expenses                                                      |      |                        | 1,028,320 |      |  |   | 687,891   |   |  |   | 461,331 |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|OPERATING INCOME                                                    |      |                        | 919,281   |      |  |   | 501,664   |   |  |   | 348,832 |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|OTHER INCOME (EXPENSE)                                              |      |                        |           |      |  |   |           |   |  |   |         |  
|Gain on distribution of royalty trust units                         |      |                        |          |      |  |   | 16,216    |   |  |   |        |  
|Loss on extinguishment of debt                                      |      |                        |          |      |  |   | (9,601    | ) |  |   | (8,528  | )
|Interest expense, net                                               |      |                        | (93,661   | )    |  |   | (63,769   | ) |  |   | (53,555 | )
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|Total Other Expense                                                 |      |                        | (93,661   | )    |  |   | (57,154   | ) |  |   | (62,083 | )
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE |      |                        | 825,620   |      |  |   | 444,510   |   |  |   | 286,749 |  
|INCOME TAX EXPENSE                                                  |      |                        | 317,738   |      |  |   | 158,009   |   |  |   | 100,690 |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE            |      |                        | 507,882   |      |  |   | 286,501   |   |  |   | 186,059 |  
|Cumulative effect of accounting change, net of tax                  |      |                        |          |      |  |   | 1,778     |   |  |   |        |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|NET INCOME                                                          |      | $                      | 507,882   |      |  | $ | 288,279   |   |  | $ | 186,059 |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|EARNINGS PER COMMON SHARE                                           |      |                        |           |      |  |   |           |   |  |   |         |  
|Basic:                                                              |      |                        |           |      |  |   |           |   |  |   |         |  
|Net income before cumulative effect of accounting change            |      | $                      | 1.53      |      |  | $ | 0.95      |   |  | $ | 0.67    |  
|Cumulative effect of accounting change, net of tax                  |      |                        |          |      |  |   | 0.01      |   |  |   |        |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|Net income                                                          |      | $                      | 1.53      |      |  | $ | 0.96      |   |  | $ | 0.67    |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|Diluted:                                                            |      |                        |           |      |  |   |           |   |  |   |         |  
|Net income before cumulative effect of accounting change            |      | $                      | 1.51      |      |  | $ | 0.94      |   |  | $ | 0.66    |  
|Cumulative effect of accounting change, net of tax                  |      |                        |          |      |  |   | 0.01      |   |  |   |        |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|Net income                                                          |      | $                      | 1.51      |      |  | $ | 0.95      |   |  | $ | 0.66    |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  
|WEIGHTED AVERAGE COMMON SHARES OUTSTANDING                          |      |                        | 332,907   |      |  |   | 299,665   |   |  |   | 277,834 |  
|                                                                    |      |                        |           |      |  |   |           |   |  |   |         |  



See accompanying notes
to consolidated financial statements.



46



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##### Index to Financial Statements



XTO ENERGY INC.

Consolidated Statements of Cash Flows



|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|--------------------------------------------------------------------------------- |  | ---------------------- | ---------- | - | ---- | - | ---------- | ---- |  | - | --------- | -
|                                                                                  |  | Year Ended December 31 |           
|(in thousands)                                                                    |  | 2004                   |            |   | 2003 |   |            | 2002 | 
|OPERATING ACTIVITIES                                                              |  |                        |            |   |      |   |            |      |  |   |           |  
|Net income                                                                        |  | $                      | 507,882    |   |      | $ | 288,279    |      |  | $ | 186,059   |  
|Adjustments to reconcile net income to net cash provided by operating activities: |  |                        |            |   |      |   |            |      |  |   |           |  
|Depreciation, depletion and amortization                                          |  |                        | 406,749    |   |      |   | 284,006    |      |  |   | 204,109   |  
|Accretion of discount in asset retirement obligation                              |  |                        | 7,592      |   |      |   | 5,330      |      |  |   |          |  
|Non-cash incentive compensation                                                   |  |                        | 67,184     |   |      |   | 53,123     |      |  |   | 26,990    |  
|Deferred income tax                                                               |  |                        | 272,672    |   |      |   | 157,715    |      |  |   | 100,368   |  
|Gain on distribution of royalty trust units                                       |  |                        |           |   |      |   | (16,216    | )    |  |   |          |  
|Non-cash derivative fair value loss                                               |  |                        | 6,652      |   |      |   | 10,771     |      |  |   | 6,890     |  
|Cumulative effect of accounting change, net of tax                                |  |                        |           |   |      |   | (1,778     | )    |  |   |          |  
|Loss on extinguishment of debt                                                    |  |                        |           |   |      |   | 9,601      |      |  |   | 8,528     |  
|Non-cash settlement gain with Enron Corporation, and related revenue              |  |                        |           |   |      |   |           |      |  |   | (16,142   | )
|Other non-cash items                                                              |  |                        | 6,366      |   |      |   | (386       | )    |  |   | (3,084    | )
|Changes in operating assets and liabilities (a)                                   |  |                        | (58,205    | ) |      |   | 3,736      |      |  |   | (22,876   | )
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|Cash Provided by Operating Activities                                             |  |                        | 1,216,892  |   |      |   | 794,181    |      |  |   | 490,842   |  
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|INVESTING ACTIVITIES                                                              |  |                        |            |   |      |   |            |      |  |   |           |  
|Proceeds from sale of property and equipment                                      |  |                        | 25,265     |   |      |   |           |      |  |   | 149       |  
|Property acquisitions                                                             |  |                        | (1,905,109 | ) |      |   | (653,742   | )    |  |   | (358,087  | )
|Development and capitalized exploration costs                                     |  |                        | (599,458   | ) |      |   | (459,762   | )    |  |   | (370,558  | )
|Other property and asset additions                                                |  |                        | (38,959    | ) |      |   | (21,730    | )    |  |   | (8,321    | )
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|Cash Used by Investing Activities                                                 |  |                        | (2,518,261 | ) |      |   | (1,135,234 | )    |  |   | (736,817  | )
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|FINANCING ACTIVITIES                                                              |  |                        |            |   |      |   |            |      |  |   |           |  
|Proceeds from long-term debt                                                      |  |                        | 3,883,423  |   |      |   | 1,835,000  |      |  |   | 1,156,000 |  
|Payments on long-term debt                                                        |  |                        | (3,093,000 | ) |      |   | (1,701,170 | )    |  |   | (893,830  | )
|Net proceeds from common stock offering                                           |  |                        | 580,272    |   |      |   | 247,972    |      |  |   |          |  
|Dividends                                                                         |  |                        | (19,824    | ) |      |   | (6,640     | )    |  |   | (4,984    | )
|Senior note offering and debt costs                                               |  |                        | (13,869    | ) |      |   | (7,797     | )    |  |   | (8,381    | )
|Proceeds from exercise of stock options and warrants                              |  |                        | 7,973      |   |      |   | 16,248     |      |  |   | 23,745    |  
|Payments upon exercise of stock options                                           |  |                        | (13,030    | ) |      |   | (18,183    | )    |  |   | (1,440    | )
|Subordinated note redemption costs                                                |  |                        |           |   |      |   | (7,139     | )    |  |   | (3,794    | )
|Purchases of treasury stock and other                                             |  |                        | (27,871    | ) |      |   | (25,197    | )    |  |   | (13,197   | )
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|Cash Provided by Financing Activities                                             |  |                        | 1,304,074  |   |      |   | 333,094    |      |  |   | 254,119   |  
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                  |  |                        | 2,705      |   |      |   | (7,959     | )    |  |   | 8,144     |  
|Cash and Cash Equivalents, January 1                                              |  |                        | 6,995      |   |      |   | 14,954     |      |  |   | 6,810     |  
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|Cash and Cash Equivalents, December 31                                            |  | $                      | 9,700      |   |      | $ | 6,995      |      |  | $ | 14,954    |  
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|(a)Changes in Operating Assets and Liabilities                                    |  |                        |            |   |      |   |            |      |  |   |           |  
|Accounts receivable                                                               |  | $                      | (131,817   | ) |      | $ | (49,628    | )    |  | $ | (19,088   | )
|Other current assets                                                              |  |                        | (39,791    | ) |      |   | (5,523     | )    |  |   | 2,758     |  
|Other operating assets                                                            |  |                        | 4,153      |   |      |   | 1,103      |      |  |   | 4,293     |  
|Enron Btu swap contract                                                           |  |                        |           |   |      |   |           |      |  |   | (43,272   | )
|Current liabilities                                                               |  |                        | 109,250    |   |      |   | 57,784     |      |  |   | 32,433    |  
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  
|                                                                                  |  | $                      | (58,205    | ) |      | $ | 3,736      |      |  | $ | (22,876   | )
|                                                                                  |  |                        |            |   |      |   |            |      |  |   |           |  



See accompanying notes
to consolidated financial statements.



47



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##### Index to Financial Statements



XTO ENERGY INC.

Consolidated Statements of Stockholders Equity



|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|----------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------ | ----- | - | ------------------------ | - | --------- | -------------- |  | - | ---------------- | - |  | ------------------------------------------- | --------- | - | ----- | - | -------- | - |  | - | --------- | -
|(in thousands, except per share amounts)                                                                                                              |  | Common Stock |       |   | AdditionalPaid-inCapital |   |           | Treasury Stock |  |   | RetainedEarnings |   |  | Accumulated OtherComprehensiveIncome (Loss) |           |   | Total |  
|Balances, December 31, 2001                                                                                                                           |  | $            | 2,933 |   |                          | $ | 483,481   |                |  | $ | (64,714          | ) |  | $                                           | 328,712   |   |       | $ | 70,638   |   |  | $ | 821,050   |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Net income                                                                                                                                            |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             | 186,059   |   |       |   |         |   |  |   | 186,059   |  
|Change in hedge derivative fair value, net of applicable income tax of $51,543                                                                        |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             |          |   |       |   | (95,723  | ) |  |   | (95,723   | )
|Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of
$19,647 |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             |          |   |       |   | (36,488  | ) |  |   | (36,488   | )
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Comprehensive income                                                                                                                                  |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   | 53,848    |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Issuance/vesting of performance shares                                                                                                                |  |              | 22    |   |                          |   | 25,596    |                |  |   | (10,276          | ) |  |                                             |          |   |       |   |         |   |  |   | 15,342    |  
|Stock option and warrant exercises, including income tax benefits                                                                                     |  |              | 61    |   |                          |   | 24,071    |                |  |   | (35              | ) |  |                                             |          |   |       |   |         |   |  |   | 24,097    |  
|Treasury stock purchases                                                                                                                              |  |              |      |   |                          |   |          |                |  |   | (1,536           | ) |  |                                             |          |   |       |   |         |   |  |   | (1,536    | )
|Common stock dividends ($0.018 per share)                                                                                                             |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             | (5,015    | ) |       |   |         |   |  |   | (5,015    | )
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Balances, December 31, 2002                                                                                                                           |  |              | 3,016 |   |                          |   | 533,148   |                |  |   | (76,561          | ) |  |                                             | 509,756   |   |       |   | (61,573  | ) |  |   | 907,786   |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Net income                                                                                                                                            |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             | 288,279   |   |       |   |         |   |  |   | 288,279   |  
|Change in hedge derivative fair value, net of applicable income tax of $65,850                                                                        |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             |          |   |       |   | (122,293 | ) |  |   | (122,293  | )
|Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of
$70,337 |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             |          |   |       |   | 130,625  |   |  |   | 130,625   |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Comprehensive income                                                                                                                                  |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   | 296,611   |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Issuance/vesting and forfeiture of performance shares                                                                                                 |  |              | 45    |   |                          |   | 51,080    |                |  |   | (23,124          | ) |  |                                             |          |   |       |   |         |   |  |   | 28,001    |  
|Stock option exercises, including income tax benefits                                                                                                 |  |              | 44    |   |                          |   | 22,919    |                |  |   |                 |   |  |                                             |          |   |       |   |         |   |  |   | 22,963    |  
|Treasury stock purchases                                                                                                                              |  |              |      |   |                          |   |          |                |  |   | (2,296           | ) |  |                                             |          |   |       |   |         |   |  |   | (2,296    | )
|Common stock offering                                                                                                                                 |  |              | 230   |   |                          |   | 247,742   |                |  |   |                 |   |  |                                             |          |   |       |   |         |   |  |   | 247,972   |  
|Fair value of royalty trust unit distribution                                                                                                         |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             | (28,151   | ) |       |   |         |   |  |   | (28,151   | )
|Common stock dividends ($0.024 per share)                                                                                                             |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             | (7,244    | ) |       |   |         |   |  |   | (7,244    | )
|Cancellation of treasury stock                                                                                                                        |  |              | (212  | ) |                          |   | (101,769  | )              |  |   | 101,981          |   |  |                                             |          |   |       |   |         |   |  |   |          |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Balances, December 31, 2003                                                                                                                           |  |              | 3,123 |   |                          |   | 753,120   |                |  |   |                 |   |  |                                             | 762,640   |   |       |   | (53,241  | ) |  |   | 1,465,642 |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Net income                                                                                                                                            |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             | 507,882   |   |       |   |         |   |  |   | 507,882   |  
|Change in hedge derivative fair value, net of applicable income tax of $51,063                                                                        |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             |          |   |       |   | (85,023  | ) |  |   | (85,023   | )
|Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of applicable income tax of
$63,485 |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             |          |   |       |   | 109,382  |   |  |   | 109,382   |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Comprehensive income                                                                                                                                  |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   | 532,241   |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Issuance/vesting of performance shares                                                                                                                |  |              | 25    |   |                          |   | 64,358    |                |  |   | (24,105          | ) |  |                                             |          |   |       |   |         |   |  |   | 40,278    |  
|Stock option exercises, including income tax benefits                                                                                                 |  |              | 19    |   |                          |   | 12,702    |                |  |   |                 |   |  |                                             |          |   |       |   |         |   |  |   | 12,721    |  
|Treasury stock purchases                                                                                                                              |  |              |      |   |                          |   |          |                |  |   | (812             | ) |  |                                             |          |   |       |   |         |   |  |   | (812      | )
|Common stock offering                                                                                                                                 |  |              | 317   |   |                          |   | 579,955   |                |  |   |                 |   |  |                                             |          |   |       |   |         |   |  |   | 580,272   |  
|Common stock dividends ($0.09 per share)                                                                                                              |  |              |      |   |                          |   |          |                |  |   |                 |   |  |                                             | (30,969   | ) |       |   |         |   |  |   | (30,969   | )
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  
|Balances, December 31, 2004                                                                                                                           |  | $            | 3,484 |   |                          | $ | 1,410,135 |                |  | $ | (24,917          | ) |  | $                                           | 1,239,553 |   |       | $ | (28,882  | ) |  | $ | 2,599,373 |  
|                                                                                                                                                      |  |              |       |   |                          |   |           |                |  |   |                  |   |  |                                             |           |   |       |   |          |   |  |   |           |  



See accompanying notes
to consolidated financial statements.



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XTO ENERGY INC.

Notes to Consolidated Financial Statements



1. Organization and Summary of Significant Accounting Policies



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



The
accompanying consolidated financial statements include the financial statements of XTO Energy Inc. and all of its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in the consolidation. In
preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Certain
amounts presented in prior period financial statements have been reclassified for consistency with current period presentation.



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



We are an independent oil and gas company with production and exploration concentrated in Texas, Oklahoma, Arkansas, Kansas, New Mexico, Colorado,
Wyoming, Alaska, Utah and Louisiana. We also gather, process and market gas, transport and market oil and conduct other activities directly related to our oil and gas producing activities.



Property and Equipment



We follow the successful efforts method of accounting, capitalizing costs of
successful exploratory wells and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. We generally pursue acquisition and development of
proved reserves as opposed to exploration activities. A significant portion of the property costs reflected in the accompanying consolidated balance sheets are from acquisitions of producing properties from other oil and gas companies. Producing
properties balances include costs of $139.4 million at December 31, 2004 and $80.6 million at December 31, 2003 related to wells in process of drilling. Drill well costs are transferred to producing properties generally within one month of the well
completion date. See Note 15 for information regarding exploratory well costs. Inventory held for future use on our producing properties totaled $34.7 million at December 31, 2004 and $6.5 million at December 31, 2003, and is included in other
current assets on the consolidated balance sheet.



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



If conditions indicate that long-term assets may be impaired, the carrying value of property is compared to
managements future estimated pre-tax cash flow from properties generally aggregated on a field-level basis. If impairment is necessary, the asset carrying value is written down to fair value. Cash flow pricing estimates are based on existing
proved reserve and production information and pricing assumptions that management believes are reasonable. Impairment of individually significant undeveloped properties is assessed on a property-by-property basis, and impairment of other undeveloped
properties is assessed and amortized on an aggregate basis.



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Asset Retirement Obligation



Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset
Retirement Obligations. SFAS No. 143 provides that, if the fair value for asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and gas producing companies incur this
liability upon acquiring or drilling a well. Under the method prescribed by SFAS No. 143, the retirement obligation is recorded as a liability at its estimated present value at the assets inception, with an offsetting increase to producing
properties on the balance sheet. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. Prior to adoption of SFAS No. 143, we accrued for any estimated asset retirement obligation, net of
estimated salvage value, as part of our calculation of depletion, depreciation and amortization. This method resulted in recognition of the obligation over the life of the property on a unit-of-production basis, with the estimated obligation netted
in property cost as part of the accumulated depreciation, depletion and amortization balance. See Note 5.



Royalty Trusts



We created Cross Timbers Royalty Trust in February 1991 and Hugoton Royalty Trust in December 1998 by conveying defined net profits interests in certain
of our properties. Units of both trusts are traded on the New York Stock Exchange. We make monthly net profits payments to each trust based on revenues and costs from the related underlying properties. We own 54.3% of Hugoton Royalty Trust, which is
the portion we retained following our sale of units in 1999 and 2000. The cost of our interest in Hugoton Royalty Trust is included in producing properties. We owned 22.7% of Cross Timbers Royalty Trust as a result of units we purchased on the open
market from 1996 through 1998. In August 2003, our Board of Directors declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each share of our common stock outstanding on September 2, 2003. Our Cross Timbers Royalty Trust units were
distributed to our common stockholders on September 18, 2003, after which we no longer own any Cross Timbers Royalty Trust units. We recorded this dividend at $28.2 million, the fair market value of the units on the date of distribution, resulting
in a gain on distribution of $16.2 million. Amounts due the trusts, net of amounts retained by our ownership of trust units, are deducted from our revenues, taxes, production expenses and development costs.



Cash and Cash Equivalents



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



Income Taxes



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



Other Assets



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



Derivatives



We use derivatives to hedge against changes in cash flows related to product price and interest rate risks, as opposed to their use for trading purposes.
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, requires that all derivatives be recorded on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on
the difference between the derivatives fixed contract price and the



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##### Index to Financial Statements

underlying market price at the determination date. The fair value of call options and collars are generally determined under the Black-Scholes option-pricing
model. Most values are confirmed by counterparties to the derivative.



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



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



|                                                                  |          |                          |                                                                                                                      |                                                                                                         
|----------------------------------------------------------------- | -------- | ------------------------ | -------------------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------
|Derivative Type                                                   |          | Fair Value Gains/ Losses |                                                                                                                      | Financial Statement Classification                                                                      
|Non-hedge derivatives
and Hedge derivatives  ineffective portion |          | UnrealizedandRealized    |                                                                                                                      | Derivative fair value (gain)
loss in the Consolidated Income Statements                                 
|                                                                  |          |                         
|Hedge
derivatives  effective portion                             |          | Unrealized               |                                                                                                                      | Accumulated other comprehensive income (loss)
in Stockholders Equity in the Consolidated Balance Sheets
|                                                                  | Realized |                          | Hedged item as classified in the Consolidated Income Statements (e.g., gas revenue, oil revenue or interest expense)



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



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



Physical delivery contracts that are not expected to be net cash settled are deemed to be normal sales and therefore are not accounted for as derivatives.
However, physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a non-hedge derivative (Note 8).



Revenue Recognition and Gas Balancing



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



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##### Index to Financial Statements

the entitlement method of accounting for gas sales, based on our net revenue interest in production. Accordingly, revenue is deferred for gas deliveries in
excess of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. The consolidated balance sheets include the
following amounts related to production imbalances:



|                                                         |        |             |         |     |      |        |        |  |   |         |   |  |        |  
|-------------------------------------------------------- | ------ | ----------- | ------- | --- | ---- | ------ | ------ |  | - | ------- | - |  | ------ | -
|                                                         |        | December 31 |        
|(in thousands)                                           |        | 2004        |         |     | 2003 |       
|                                                         | Amount |             |         | Mcf |      |        | Amount |  |   | Mcf     |  
|Accounts receivable - current underproduction            |        | $           | 30,780  |     |      | 8,116  |        |  | $ | 23,949  |   |  | 7,135  |  
|Accounts payable - current overproduction                |        |             | (24,087 | )   |      | (6,388 | )      |  |   | (19,366 | ) |  | (5,900 | )
|                                                         |        |             |         |     |      |        |        |  |   |         |   |  |        |  
|Net current gas underproduction balancing receivable     |        | $           | 6,693   |     |      | 1,728  |        |  | $ | 4,583   |   |  | 1,235  |  
|                                                         |        |             |         |     |      |        |        |  |   |         |   |  |        |  
|Other assets - noncurrent underproduction                |        | $           | 17,723  |     |      | 4,868  |        |  | $ | 19,385  |   |  | 6,148  |  
|Other long-term liabilities - noncurrent overproduction  |        |             | (33,262 | )   |      | (9,063 | )      |  |   | (29,776 | ) |  | (9,353 | )
|                                                         |        |             |         |     |      |        |        |  |   |         |   |  |        |  
|Net long-term gas overproduction balancing payable       |        |             | (15,539 | )   |      | (4,195 | )      |  |   | (10,391 | ) |  | (3,205 | )
|                                                         |        |             |         |     |      |        |        |  |   |         |   |  |        |  
|Other assets - noncurrent carbon dioxide underproduction |        |             | 1,985   |     |      | 12,480 |        |  |   | 1,977   |   |  | 12,354 |  
|                                                         |        |             |         |     |      |        |        |  |   |         |   |  |        |  
|Net long-term overproduction balancing payable           |        | $           | (13,554 | )   |      |        |        |  | $ | (8,414  | ) |  |        |  
|                                                         |        |             |         |     |      |        |        |  |   |         |   |  |        |  



Gas Gathering,
Processing and Marketing Revenues



We market our gas, as
well as some gas produced by third parties, to brokers, local distribution companies and end-users. Gas gathering and marketing revenues are recognized in the month of delivery based on customer nominations. Gas processing and marketing revenues are
recorded net of cost of gas sold of $98.3 million for 2004, $66.3 million for 2003 and $55.6 million for 2002. These amounts are net of intercompany eliminations.



Other Revenues



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



Loss Contingencies



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



Interest



Interest expense includes amortization of deferred debt costs and is presented net of interest income of $402,000 in 2004, $553,000 in 2003 and $836,000
in 2002, and net of capitalized interest of $2.6 million in 2004, $2.2 million in 2003 and $4.3 million in 2002. Interest is capitalized as producing property cost based on the weighted average interest rate and the cost of wells in process of
drilling. Included in accounts payable and accrued liabilities is accrued interest of $26.6 million at December 31, 2004 and $11.5 million at December 31, 2003.



Stock-Based Compensation



In accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, no compensation is recorded for stock
options or other stock-based awards that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on the grant date. Compensation related to performance share grants with time vesting
conditions is based on the fair value of the award at the grant date and recognized over the vesting period. Compensation related to performance shares with price target vesting is



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recognized over the estimated vesting period if management believes it is able to reasonably estimate a vesting date or, if earlier, when the price target is
reached. See New Accounting Pronouncements below and Note 12.



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



|                                                                                                                               |      |                        |         |      |  |   |         |   |  |   |         |  
|------------------------------------------------------------------------------------------------------------------------------ | ---- | ---------------------- | ------- | ---- |  | - | ------- | - |  | - | ------- | -
|(in thousands, except per share data)                                                                                          |      | Year Ended December 31 |        
|                                                                                                                               | 2004 |                        |         | 2003 |  |   | 2002    |  
|Net income as reported                                                                                                         |      | $                      | 507,882 |      |  | $ | 288,279 |   |  | $ | 186,059 |  
|Add stock-based compensation expense included in the income statement, net of related tax effects                              |      |                        | 56,368  |      |  |   | 34,530  |   |  |   | 17,543  |  
|Deduct stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects |      |                        | (76,859 | )    |  |   | (33,498 | ) |  |   | (19,762 | )
|                                                                                                                               |      |                        |         |      |  |   |         |   |  |   |         |  
|Pro forma net income                                                                                                           |      | $                      | 487,391 |      |  | $ | 289,311 |   |  | $ | 183,840 |  
|                                                                                                                               |      |                        |         |      |  |   |         |   |  |   |         |  
|Earnings per common share:                                                                                                     |      |                        |         |      |  |   |         |   |  |   |         |  
|Basic - as reported                                                                                                            |      | $                      | 1.53    |      |  | $ | 0.96    |   |  | $ | 0.67    |  
|                                                                                                                               |      |                        |         |      |  |   |         |   |  |   |         |  
|Basic - pro forma                                                                                                              |      | $                      | 1.46    |      |  | $ | 0.96    |   |  | $ | 0.66    |  
|                                                                                                                               |      |                        |         |      |  |   |         |   |  |   |         |  
|Diluted - as reported                                                                                                          |      | $                      | 1.51    |      |  | $ | 0.95    |   |  | $ | 0.66    |  
|                                                                                                                               |      |                        |         |      |  |   |         |   |  |   |         |  
|Diluted - pro forma                                                                                                            |      | $                      | 1.45    |      |  | $ | 0.95    |   |  | $ | 0.65    |  
|                                                                                                                               |      |                        |         |      |  |   |         |   |  |   |         |  



Earnings per Common
Share



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



Segment Reporting



In accordance with SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, we evaluated how the Company is organized and managed, and have identified only one operating segment, which is the exploration and production of oil, natural gas and natural gas liquids. We
consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. All of our assets are located in the United States, and all revenues are attributable to United States customers.



Our production is sold to various purchasers, based on their credit rating
and location of our production. For the year ended December 31, 2004, sales to each of two purchasers were approximately 20% and 13% of total revenues. For the year ended December 31, 2003, sales to each of three purchasers were approximately 25%,
15% and 12% of total revenues. For the year ended December 31, 2002, sales to each of two purchasers were approximately 10% of total revenues. We believe that alternative purchasers are available, if necessary, to purchase production at prices
substantially similar to those received from these significant purchasers. We currently have greater concentrations of credit with several A- or better rated integrated energy companies.



New Accounting Pronouncements



In December 2004, the Financial Accounting Standards Board issued SFAS No. 153, Exchanges of Nonmonetary Assets, an
Amendment of APB Opinion No. 29, which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged, and any resulting gain or loss recorded. An exchange is defined
as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion 29 previously
exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. We must implement SFAS 153 for any



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



2.
Related Party Transactions



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 (Note 13) were considered nonstrategic and marked for disposition at the time of purchase. In August 2004, we exchanged $37.8 million of these properties for 19,000 net contiguous acres
in our new core operating area, the Barnett Shale of North Texas, and $25.4 million in other consideration. This exchange was with companies either wholly or majority owned by the adult children and a brother of Bob R. Simpson, Chairman and Chief
Executive Officer of the Company. In connection with this exchange, we granted these companies an option to purchase other properties included in the ChevronTexaco acquisition. On March 1, 2005, these companies purchased the properties for an
adjusted purchase price of $11.5 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.



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3. Debt



Our long-term debt consists of the following:



|                                                                         |  |             |           |      |   |          
|------------------------------------------------------------------------ |  | ----------- | --------- | ---- | - | ---------
|                                                                         |  | December 31
|(in thousands)                                                           |  | 2004        |           | 2003
|Bank debt:                                                               |  |             |           |      |   |          
|Revolving credit agreement due February 2009, 3.49% at December 31, 2004 |  | $           | 146,000   |      | $ | 502,000  
|Term loan due April 2010, 3.17% at December 31, 2004                     |  |             | 300,000   |      |   |         
|Senior notes:                                                            |  |             |           |      |   |          
|71⁄2%, due April 15, 2012                                                  |  |             | 350,000   |      |   | 350,000  
|61⁄4%, due April 15, 2013                                                  |  |             | 400,000   |      |   | 400,000  
|4.9%, due February 1, 2014, net of discount                              |  |             | 497,012   |      |   |         
|5%, due January 31, 2015, net of discount                                |  |             | 349,720   |      |   |         
|                                                                         |  |             |           |      |   |          
|Total long-term debt                                                     |  | $           | 2,042,732 |      | $ | 1,252,000
|                                                                         |  |             |           |      |   |          



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



Bank Debt



In February 2004, we fully repaid our revolving facility and entered a new
five-year revolving credit agreement with commercial banks that matures in February 2009. The agreement currently provides for a maximum commitment amount of $1 billion, and an interest rate based on London Interbank Offered Rates
(LIBOR) plus 1%. The loan agreement provides the option of borrowing at floating interest rates based on the prime rate, certificate of deposit rates, or LIBOR. Interest is paid at maturity, or quarterly if the term is for a period of 90
days or more. We also incur a commitment fee on unused borrowing commitments, which was 0.20% at February 2005. The agreement requires us to maintain a ratio of debt-to-total capitalization of not more than 60%. Borrowings under the loan agreement
may be prepaid at any time without penalty. The weighted average interest rate on bank debt was 2.6% during 2004 and 2003 and 3.2% during 2002.



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



Senior Notes



In April
2002, we sold $350 million of 71⁄2% senior notes due in April 2012, with interest payable each April 15 and October 15. Net proceeds of $341.6 million were used to finance property transactions (Note 13), to redeem our 91⁄4% senior
subordinated notes and to reduce bank debt.



In April 2003, we
sold $400 million of 61⁄4% senior notes due in April 2013, with interest payable each April 15 and October 15. Net proceeds of $393.4 million, combined with proceeds from the concurrent sale of common stock (Note 9), were used to finance our
producing property acquisition from units of Williams of Tulsa, Oklahoma (Note 13), to redeem our 83⁄4% senior subordinated notes and to reduce bank debt.



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



In September 2004, we sold $350 million of 5% notes that were issued at
99.918% of par to yield 5.011% to maturity pursuant to Rule 144A under the Securities Act of 1933, which allows unregistered transactions with qualified institutional buyers. Through March 14, 2005, noteholders can exchange these notes with notes
that were registered with



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##### Index to Financial Statements

the Securities and Exchange Commission in February 2005. The notes are due in January 2015 and interest is payable each January 31 and July 31. Net proceeds
of $347 million were used to reduce bank debt associated with our 2004 acquisitions.



The senior notes require no sinking fund. We may redeem all or a part of the senior notes at any time at a price of 100% of their principal balance plus accrued interest and a make-whole premium payment. The
make-whole premium is calculated as any excess over the principal balance of the present value of remaining principal and interest payments at the U.S. Treasury rate for a comparable maturity plus no more than 0.15%.



Subordinated Debt



In April 1997, we sold $125 million of 91⁄4% senior subordinated notes
due April 2007, and in October 1997, we sold $175 million of 83⁄4% senior subordinated notes due November 2009. Under the terms of an agreement with a bank counterparty, we purchased and canceled $9.7 million of 91⁄4% senior subordinated notes
in April 2002, and we purchased and canceled $11.8 million of 83⁄4% senior subordinated notes in November 2002. In June 2002, we redeemed the remaining $115.3 million 91⁄4% notes at a redemption price of 104.625%, or $120.6 million, plus
accrued interest of $1.8 million. In May 2003, we redeemed the remaining $163.2 million of our 83⁄4% senior subordinated notes at a redemption price of 104.375%, or $170.3 million, plus accrued interest of approximately $700,000. As a result of
these transactions, we recorded a loss on extinguishment of debt of $8.5 million in 2002 and $9.6 million in 2003.



4. Income Tax



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



|                                                       |  |      |         |      |   |         |  |   |         |  
|------------------------------------------------------ |  | ---- | ------- | ---- | - | ------- |  | - | ------- | -
|(in thousands)                                         |  | 2004 |         | 2003 |   | 2002    | 
|Income tax expense at the federal statutory rate (35%) |  | $    | 288,967 |      | $ | 155,579 |  | $ | 100,362 |  
|State and local income taxes and other                 |  |      | 28,771  |      |   | 2,430   |  |   | 328     |  
|                                                       |  |      |         |      |   |         |  |   |         |  
|Income tax expense                                     |  | $    | 317,738 |      | $ | 158,009 |  | $ | 100,690 |  
|                                                       |  |      |         |      |   |         |  |   |         |  
|                                                       |  |      |        
|Components of income tax expense are as follows:       |  |      |         |      |   |         |  |   |         |  
|                                                       |  |      |        
|(in thousands)                                         |  | 2004 |         | 2003 |   | 2002    | 
|Current income tax                                     |  | $    | 45,066  |      | $ | 294     |  | $ | 322     |  
|Deferred income tax                                    |  |      | 184,927 |      |   | 148,304 |  |   | 121,396 |  
|Net operating loss carryforwards (added) used          |  |      | 87,745  |      |   | 9,411   |  |   | (21,028 | )
|                                                       |  |      |         |      |   |         |  |   |         |  
|Income tax expense                                     |  | $    | 317,738 |      | $ | 158,009 |  | $ | 100,690 |  
|                                                       |  |      |         |      |   |         |  |   |         |  



Deferred tax assets
and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a current asset of $22.6 million and a
long-term liability of $756.4 million at December 31, 2004 and as a current asset of $32.5 million and a long-term liability of $426.7 million at December 31, 2003. Significant components of net deferred tax assets and liabilities are:



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|                                             |  |             |          |   |      |   |          |  
|-------------------------------------------- |  | ----------- | -------- | - | ---- | - | -------- | -
|                                             |  | December 31 |         
|(in thousands)                               |  | 2004        |          |   | 2003 |  
|Deferred tax assets:                         |  |             |          |   |      |   |          |  
|Net operating loss carryforwards             |  | $           |         |   |      | $ | 84,001   |  
|Alternative minimum tax credit carryforwards |  |             | 37,762   |   |      |   | 429      |  
|Derivative fair value loss                   |  |             | 31,217   |   |      |   | 40,144   |  
|Other                                        |  |             | 11,427   |   |      |   | 6,304    |  
|                                             |  |             |          |   |      |   |          |  
|Total deferred tax assets                    |  |             | 80,406   |   |      |   | 130,878  |  
|                                             |  |             |          |   |      |   |          |  
|Deferred tax liabilities:                    |  |             |          |   |      |   |          |  
|Property and equipment                       |  |             | 801,610  |   |      |   | 509,877  |  
|Derivative fair value gain                   |  |             | 5,297    |   |      |   | 4,199    |  
|Other                                        |  |             | 7,255    |   |      |   | 11,077   |  
|                                             |  |             |          |   |      |   |          |  
|Total deferred tax liabilities               |  |             | 814,162  |   |      |   | 525,153  |  
|                                             |  |             |          |   |      |   |          |  
|Net deferred tax liabilities                 |  | $           | (733,756 | ) |      | $ | (394,275 | )
|                                             |  |             |          |   |      |   |          |  



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



5. Asset Retirement Obligation



Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset
Retirement Obligations, recording a cumulative effect of accounting change gain, net of tax, of $1.8 million. Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and
remediate our producing properties (including removal of our offshore platforms in Alaska) at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value
of estimated cash flows related to the liability. The following is a summary of the asset retirement obligation activity for the years ended December 31, 2004 and 2003:



|                                                     |  |      |         |   |      |   |        |  
|---------------------------------------------------- |  | ---- | ------- | - | ---- | - | ------ | -
|(in thousands)                                       |  | 2004 |         |   | 2003 |  
|Asset retirement obligation, January 1               |  | $    | 93,379  |   |      | $ | 75,256 |  
|Revisions in the estimated cash flows                |  |      | 5,978   |   |      |   |       |  
|Liability incurred upon acquiring and drilling wells |  |      | 53,886  |   |      |   | 13,879 |  
|Liability settled upon plugging and abandoning wells |  |      | (887    | ) |      |   | (1,086 | )
|Accretion of discount expense                        |  |      | 7,592   |   |      |   | 5,330  |  
|                                                     |  |      |         |   |      |   |        |  
|Asset retirement obligation, December 31             |  | $    | 159,948 |   |      | $ | 93,379 |  
|                                                     |  |      |         |   |      |   |        |  



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



6. Commitments and Contingencies



Leases



We lease compressors, offices, vehicles, aircraft and
certain other equipment in our primary locations under noncancelable operating leases. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2004, minimum future lease
payments for all noncancelable lease agreements (including the sale and operating leaseback agreements described below) were as follows:



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|               |  |   |        
|-------------- |  | - | -------
|(in thousands) |  |  
|2005           |  | $ | 30,200 
|2006           |  |   | 23,882 
|2007           |  |   | 22,806 
|2008           |  |   | 18,605 
|2009           |  |   | 15,964 
|Remaining      |  |   | 39,666 
|               |  |   |        
|Total          |  | $ | 151,123
|               |  |   |        



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



In March 1996, we sold our Tyrone gas processing plant and related gathering system for $28 million and entered an agreement to lease the facility from
the buyers for an initial term of eight years at annual rentals of $4 million with fixed renewal options for an additional 13 years at a total cost of $7.8 million. This transaction was recorded as a sale and operating leaseback, with no gain or
loss on the sale. In March 2004, we extended the lease until March 2006.



In November 1996, we sold a gathering system in Major County, Oklahoma for $8 million and entered an agreement to lease the facility from the buyers for an initial term of eight years, with fixed renewal options for
an additional ten years. This transaction was recorded as a sale and operating leaseback, with a deferred gain of $3.4 million on the sale. The deferred gain is amortized over the lease term based on pro rata rentals and is recorded in other
long-term liabilities in the accompanying consolidated balance sheets. The deferred gain balance at December 31, 2004 was $600,000. In November 2004, we extended the lease until November 2006.



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



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 our firm transportation contracts, therefore avoiding payment for deficiencies. As of December 31, 2004, maximum
commitments under our transportation contracts were as follows:



|               |  |   |        
|-------------- |  | - | -------
|(in thousands) |  |  
|2005           |  | $ | 21,935 
|2006           |  |   | 22,463 
|2007           |  |   | 19,741 
|2008           |  |   | 18,804 
|2009           |  |   | 18,030 
|Remaining      |  |   | 36,368 
|               |  |   |        
|               |  | $ | 137,341
|               |  |   |        



Guarantees



Under the terms of some of our operating leases for
compressors, airplanes and vehicles, we have various residual value guarantees and other payment provisions upon our election to return the equipment under certain specified conditions. As of December 31, 2004, we estimate the total contingent
payable under these guarantees does not exceed $5 million. Guarantees related to leases entered during 2004 and 2003 were not material.



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Employment Agreements



Two executive officers have year-to-year employment agreements with us. The agreements are automatically renewed each
year-end unless terminated by either party upon thirty days notice prior to each December 31. Under these agreements, the officers receive a minimum annual salary of $625,000 and $450,000, respectively, and are entitled to participate in any
incentive compensation programs administered by the Board of Directors. The agreements also provide that, in the event the officer terminates his employment for good reason, as defined in the agreement, we terminate the employee without cause or a
change in control of the Company occurs, the officer is entitled to a lump-sum payment of three times the officers most recent annual compensation, including any special bonuses or other compensation required to be designated as a bonus under
the rules and regulations of the Securities and Exchange Commission. In addition, the officer is entitled to receive a payment sufficient to make the officer whole for any excise tax on excess parachute payments imposed by the Internal Revenue Code.



Commodity Commitments



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



Drilling
Contracts



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



Litigation



On October 17, 1997, an action, styled United States of America ex rel.
Grynberg v. Cross Timbers Oil Company, et al., was filed in the U.S. District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against
the Company and certain of our subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of
natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney fees and expenses), civil
penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other
companies have been consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynbergs royalty valuation claims, and Grynbergs appeal of this decision was dismissed for lack of
appellate jurisdiction in May 2003. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other
defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion 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



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was not specified in the complaint. In February 2002, we, along with one of our subsidiaries, were dismissed from the suit and another subsidiary of the
Company was added. A hearing was held in January 2003, and the court held that a class should not be certified. The plaintiffs counsel has filed an amended class action petition, which reduces the proposed class to only royalty owners, reduces
the claims to mismeasurement of volume only, conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court has set an evidentiary hearing in April 2005 to determine whether the amended
class should be certified. While we are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot
currently be reasonably estimated, and no provision has been accrued in our financial statements.



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. We have
filed our response and intend to file a response for Huber. As of December 31, 2004, based on an evaluation of available information, we accrued a $3.1 million estimated liability for this claim in our consolidated financial statements. On February
17, 2005, we agreed to a tentative settlement of approximately $5.1 million, resulting in an additional loss of approximately $2 million to be recorded in first quarter 2005.



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.



Other



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



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



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



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



7. Financial Instruments



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



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



Btu Swap Contracts



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



Prior to termination of the Enron Btu swap contract, we entered Btu swap contracts with another counterparty to effectively defer until August 2005
through July 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. Changes in fair value of these contracts are recorded as a derivative (gain) loss in the income
statement. In March 2002, we terminated some of these contracts with maturities of May through December 2002 and received $6.6 million from the counterparty. Because these Btu swap contracts are non-hedge derivatives, most of the $6.6 million gain
related to their termination had previously been recorded in 2001 derivative fair value gain.



Commodity Price Hedging Instruments



We periodically enter into futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on crude oil and natural gas sales. When actual commodity prices exceed the fixed price
provided by these contracts, we pay this excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We have hedged a portion of our exposure to
variability in future cash flows from crude oil and natural gas sales through December 2005. See Note 8.



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##### Index to Financial Statements

Derivative Fair Value (Gain) Loss



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



|                                                                                   |  |      |        |   |      |   |        |      |  |   |        |  
|---------------------------------------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|(in thousands)                                                                     |  | 2004 |        |   | 2003 |   |        | 2002 | 
|Change in fair value of Btu swap contracts                                         |  | $    | 1,086  |   |      | $ | 5,115  |      |  | $ | 1,046  |  
|Change in fair value of other derivatives that do not qualify for hedge accounting |  |      | (1,685 | ) |      |   | (2,187 | )    |  |   | (6,505 | )
|Ineffective portion of derivatives qualifying for hedge accounting                 |  |      | 12,488 |   |      |   | 7,273  |      |  |   | 2,860  |  
|                                                                                   |  |      |        |   |      |   |        |      |  |   |        |  
|Derivative fair value (gain) loss                                                  |  | $    | 11,889 |   |      | $ | 10,201 |      |  | $ | (2,599 | )
|                                                                                   |  |      |        |   |      |   |        |      |  |   |        |  



Fair Value of
Financial Instruments



Because of their short-term
maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at December 31, 2004 and 2003. The following are estimated fair values and carrying values of our other financial
instruments at each of these dates:



|                                           |  |                   |            |   |                   |   |            |                |  |   |            |   |  |   |            |  
|------------------------------------------ |  | ----------------- | ---------- | - | ----------------- | - | ---------- | -------------- |  | - | ---------- | - |  | - | ---------- | -
|                                           |  | Asset (Liability) |           
|                                           |  | December 31, 2004 |            |   | December 31, 2003 |  
|(in thousands)                             |  | CarryingAmount    |            |   | Fair Value        |   |            | CarryingAmount |  |   | Fair Value |  
|Derivative Assets:                         |  |                   |            |   |                   |   |            |                |  |   |            |   |  |   |            |  
|Fixed-price natural gas futures and swaps  |  | $                 | 10,962     |   |                   | $ | 10,962     |                |  | $ | 11,997     |   |  | $ | 11,997     |  
|Fixed-price crude futures and differential |  |                   | 3,751      |   |                   |   | 3,751      |                |  |   |           |   |  |   |           |  
|Derivative Liabilities:                    |  |                   |            |   |                   |   |            |                |  |   |            |   |  |   |            |  
|Fixed-price natural gas futures and swaps  |  |                   | (41,754    | ) |                   |   | (41,754    | )              |  |   | (96,702    | ) |  |   | (96,702    | )
|Fixed-price crude futures and differential |  |                   | (25,879    | ) |                   |   | (25,879    | )              |  |   |           |   |  |   |           |  
|Btu swap contracts                         |  |                   | (19,080    | ) |                   |   | (19,080    | )              |  |   | (17,995    | ) |  |   | (17,995    | )
|                                           |  |                   |            |   |                   |   |            |                |  |   |            |   |  |   |            |  
|Net derivative asset (liability)           |  | $                 | (72,000    | ) |                   | $ | (72,000    | )              |  | $ | (102,700   | ) |  | $ | (102,700   | )
|                                           |  |                   |            |   |                   |   |            |                |  |   |            |   |  |   |            |  
|Long-term debt                             |  | $                 | (2,042,732 | ) |                   | $ | (2,133,818 | )              |  | $ | (1,252,000 | ) |  | $ | (1,275,285 | )
|                                           |  |                   |            |   |                   |   |            |                |  |   |            |   |  |   |            |  



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



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



Concentrations of Credit Risk



Although our cash equivalents, accounts receivable and derivative assets are exposed to the risk of credit loss, we do not
believe such risk to be significant. Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of our receivables are from a diverse group of companies including major energy companies, pipeline
companies, local distribution companies and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated integrated energy companies. Financial and commodity-based swap contracts expose us to
the credit risk of nonperformance by the counterparty to the contracts. This exposure



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##### Index to Financial Statements

is diversified among major investment grade financial institutions, and we have master netting agreements with counterparties that provide for offsetting
payables against receivables from separate derivative contracts. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. Our allowance for collectibility of all accounts receivable was $3.9 million
at December 31, 2004 and $6.3 million at December 31, 2003. Our bad debt provision was $232,000 in 2004, $1.3 million in 2003 and $980,000 in 2002. We also recorded a $2.2 million reduction in the allowance for collectibility in 2004.



8. Commodity Sales Commitments



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



In addition to selling gas under fixed price physical delivery contracts, we enter futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on natural gas and crude oil
sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the
counterparty. We have hedged a portion of our exposure to variability in future cash flows from natural gas and crude oil sales through December 2005.



Natural Gas



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



|                         |  |                 |  |                                        |      |             |        |                          |   |             |  |                          |  |   |     
|------------------------ |  | --------------- |  | -------------------------------------- | ---- | ----------- | ------ | ------------------------ | - | ----------- |  | ------------------------ |  | - | ----
|                         |  | Base Production |  | Production Related to2004 Acquisitions |      | Total      
|Production
Period        |  | Mcf per Day     |  | AverageNYMEX Priceper Mcf              |      | Mcf per Day |        | AverageNYMEXPriceper Mcf |   | Mcf per Day |  | AverageNYMEXPriceper Mcf
|2005 January to December |  | 200,000         |  | $                                      | 5.79 |             | 50,000 |                          | $ | 6.34        |  | 250,000                  |  | $ | 5.90



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##### Index to Financial Statements

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



|                     |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|-------------------- |  | ----------------- | ------ | - | ------------------ | - | ------- | ------- |  | - | ------------- | - |  | ----- | ------ | - |  | -------
|                     |  | Delivery Location
|Production
Period    |  | Arkoma            |        |   | HoustonShipChannel |   |         | Rockies |  |   | San JuanBasin |   |  | Total
|2005                 |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|January              |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|Mcf per day          |  |                   | 10,000 |   |                    |   | 210,000 |         |  |   | 30,000        |   |  |       | 70,000 |   |  | 320,000
|Basis per Mcf (a)    |  | $                 | (0.06  | ) |                    | $ | (0.21   | )       |  | $ | (0.77         | ) |  | $     | (0.67  | ) |  |        
|                     |  |                   |        |   |                   
|February to March    |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|Mcf per day          |  |                   | 10,000 |   |                    |   | 210,000 |         |  |   | 10,000        |   |  |       | 70,000 |   |  | 300,000
|Basis per Mcf (a)    |  | $                 | (0.06  | ) |                    | $ | (0.21   | )       |  | $ | (0.71         | ) |  | $     | (0.67  | ) |  |        
|                     |  |                   |        |   |                   
|April to June        |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|Mcf per day          |  |                   |       |   |                    |   | 270,000 |         |  |   | 5,000         |   |  |       | 30,000 |   |  | 305,000
|Basis per Mcf (a)    |  |                   |       |   |                    | $ | (0.14   | )       |  | $ | (0.75         | ) |  | $     | (0.68  | ) |  |        
|                     |  |                   |        |   |                   
|July to August       |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|Mcf per day          |  |                   |       |   |                    |   | 270,000 |         |  |   | 5,000         |   |  |       | 30,000 |   |  | 305,000
|Basis per Mcf (a)    |  |                   |       |   |                    | $ | (0.12   | )       |  | $ | (0.75         | ) |  | $     | (0.68  | ) |  |        
|                     |  |                   |        |   |                   
|September            |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|Mcf per day          |  |                   |       |   |                    |   | 250,000 |         |  |   | 5,000         |   |  |       | 30,000 |   |  | 285,000
|Basis per Mcf (a)    |  |                   |       |   |                    | $ | (0.12   | )       |  | $ | (0.75         | ) |  | $     | (0.68  | ) |  |        
|                     |  |                   |        |   |                   
|October              |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|Mcf per day          |  |                   |       |   |                    |   | 270,000 |         |  |   | 5,000         |   |  |       | 30,000 |   |  | 305,000
|Basis per Mcf (a)    |  |                   |       |   |                    | $ | (0.14   | )       |  | $ | (0.75         | ) |  | $     | (0.68  | ) |  |        
|                     |  |                   |        |   |                   
|November to December |  |                   |        |   |                    |   |         |         |  |   |               |   |  |       |        |   |  |        
|Mcf per day          |  |                   |       |   |                    |   | 220,000 |         |  |   | 10,000        |   |  |       | 40,000 |   |  | 270,000
|Basis per Mcf (a)    |  |                   |       |   |                    | $ | (0.17   | )       |  | $ | (0.76         | ) |  | $     | (0.68  | ) |  |        

---

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



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



The settlement of futures contracts and basis swap agreements related to January 2005 gas production reduced gas revenue by
approximately $1.1 million, or $0.04 per Mcf.



Crude Oil



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



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



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



Physical Delivery Contracts



From August 1995 through July 1998 we received an additional $0.30 to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, we agreed to sell
34,344 Mcf per day at the index price in 2001 and 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. See Note 7 regarding accounting for this contract, also
referred to as the Enron Btu swap contract, which was terminated as a result of the Enron bankruptcy, and regarding a related derivative commitment with another counterparty.



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



In 1998, we sold a production payment, payable from future production from certain properties acquired in an acquisition, to EEX Corporation for $30
million. Under the terms of the production payment conveyance and related delivery agreement, we committed to deliver to EEX a total of approximately 34.3 Bcf (27.8 Bcf net to our interest) of gas during the 10-year period beginning January 1, 2002,
with scheduled deliveries by year, subject to certain variables. EEX will reimburse us for all royalty and production and property tax payments related to such deliveries. EEX will also pay us an operating fee of $0.257 per Mcf for deliveries, which
fee will be escalated annually at a rate of 5.5%. In 2001 and 2002, we repurchased 18.3 Bcf (14.8 Bcf net) of gas under the production payment for $20.7 million. We expect to begin delivery of the remaining 16.0 Bcf (13.0 Bcf net) of gas in 2006.



9. Equity



Stock Splits



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



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##### Index to Financial Statements

Common Stock



The following reflects our common stock activity:



|                                                      |  |               |  |                    |   |  |         |  |       |  |         |   |  |       
|----------------------------------------------------- |  | ------------- |  | ------------------ | - |  | ------- |  | ----- |  | ------- | - |  | ------
|                                                      |  | Shares Issued |  | Shares in Treasury
|(in thousands)                                        |  | 2004          |  | 2003               |   |  | 2002    |  | 2004  |  | 2003    |   |  | 2002  
|Balance, January 1                                    |  | 312,335       |  | 301,633            |   |  | 293,308 |  |      |  | 19,462  |   |  | 18,258
|Issuance/vesting and forfeiture of performance shares |  | 2,448         |  | 4,444              |   |  | 2,224   |  | 1,216 |  | 1,585   |   |  | 1,045 
|Stock option and warrant exercises                    |  | 1,937         |  | 4,456              |   |  | 6,101   |  |      |  |        |   |  | 4     
|Treasury stock purchases                              |  |              |  |                   |   |  |        |  | 34    |  | 151     |   |  | 155   
|Common stock offering                                 |  | 31,708        |  | 23,000             |   |  |        |  |      |  |        |   |  |      
|Cancellation of treasury shares                       |  |              |  | (21,198            | ) |  |        |  |      |  | (21,198 | ) |  |      
|                                                      |  |               |  |                    |   |  |         |  |       |  |         |   |  |       
|Balance, December 31                                  |  | 348,428       |  | 312,335            |   |  | 301,633 |  | 1,250 |  |        |   |  | 19,462
|                                                      |  |               |  |                    |   |  |         |  |       |  |         |   |  |       



In May 2004, we
completed a public offering of 31.7 million shares of common stock at $18.92 per share. After underwriting discount and other offering costs of $19.7 million, net proceeds of $580.3 million were used to reduce bank borrowings that funded our
producing property acquisitions from ExxonMobil Corporation and our deposit on the ChevronTexaco acquisition (Note 13).



In April 2003, we completed a public offering of 23 million shares of common stock at $11.25 per share. After underwriting discount and other offering
costs of $10.8 million, net proceeds from the offering of $248 million and net proceeds from the concurrent sale of senior notes (Note 3) were used to fund our producing property acquisition from units of Williams of Tulsa, Oklahoma (Note 13), to
redeem our 83⁄4% senior subordinated notes and to reduce bank debt.



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



Treasury Stock



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



In August 2004, our Board of Directors authorized the repurchase of up to 20
million shares of our common stock which may be purchased from time to time in open market or negotiated transactions. This authorization effectively replaced the share repurchase authorization remaining from May 2000. As of December 31, 2004, we
have repurchased 33,600 shares at a cost of $812,000.



Stockholder Rights Plan



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



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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.



Common Stock Warrants



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



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



Common Stock Dividends



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



In
August 2003, our Board of Directors declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each share of common stock outstanding on September 2, 2003. This dividend, totaling 1,360,000 trust units, was distributed on September 18,
2003, and was recorded at the fair value of the units on that date of $28.2 million.



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



See Note 12.



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10. Earnings Per Share



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



|                                      |  |          |         |        |         |                   |   |     
|------------------------------------- |  | -------- | ------- | ------ | ------- | ----------------- | - | ----
|(in thousands, except per share data) |  | Earnings |         | Shares |         | Earningsper Share
|2004                                  |  |          |         |        |         |                   |   |     
|Basic                                 |  | $        | 507,882 |        | 332,907 |                   | $ | 1.53
|                                      |  |          |         |        |         |                   |   |     
|Effect of dilutive securities:        |  |          |         |        |         |                   |   |     
|Stock options                         |  |          |        |        | 2,774   |                   |   |     
|                                      |  |          |         |        |         |                   |   |     
|Diluted                               |  | $        | 507,882 |        | 335,681 |                   | $ | 1.51
|                                      |  |          |         |        |         |                   |   |     
|2003                                  |  |          |         |        |         |                   |   |     
|Basic                                 |  | $        | 288,279 |        | 299,665 |                   | $ | 0.96
|                                      |  |          |         |        |         |                   |   |     
|Effect of dilutive securities:        |  |          |         |        |         |                   |   |     
|Stock options                         |  |          |        |        | 4,087   |                   |   |     
|                                      |  |          |         |        |         |                   |   |     
|Diluted                               |  | $        | 288,279 |        | 303,752 |                   | $ | 0.95
|                                      |  |          |         |        |         |                   |   |     
|2002                                  |  |          |         |        |         |                   |   |     
|Basic                                 |  | $        | 186,059 |        | 277,834 |                   | $ | 0.67
|                                      |  |          |         |        |         |                   |   |     
|Effect of dilutive securities:        |  |          |         |        |         |                   |   |     
|Stock options                         |  |          |        |        | 1,378   |                   |   |     
|Warrants                              |  |          |        |        | 1,874   |                   |   |     
|                                      |  |          |         |        |         |                   |   |     
|Diluted                               |  | $        | 186,059 |        | 281,086 |                   | $ | 0.66
|                                      |  |          |         |        |         |                   |   |     



11. Supplemental Cash Flow
Information



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



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



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



| |  |  | The following performance share activity (Note 12):
| | - |  | ---------------------------------------------------



| |  |  | Grants of 2.6 million shares in 2004, 4.4 million shares in 2003 and 2.4 million shares in 2002
| | - |  | -----------------------------------------------------------------------------------------------



| |  |  | Vesting of 3.2 million shares in 2004, 3.5 million in 2003 and 2.8 million shares in 2002
| | - |  | -----------------------------------------------------------------------------------------



| |  |  | Forfeiture of 20,000 shares in 2003
| | - |  | -----------------------------------



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



Because we do not recognize compensation related to stock options granted,
the tax benefit realized upon exercise of stock options is recorded as an increase in additional paid-in capital. This tax benefit has increased our net operating loss carryforwards (Note 4) and is reflected in our consolidated statements of cash
flows when these carryforwards were utilized, primarily in 2004. This tax benefit from exercise of stock options was $17.9 million in 2004, $22.7 million in 2003 and $1.8 million in 2002.



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##### Index to Financial Statements

12. Employee Benefit Plans



401(k) Plan



We sponsor a 401(k) benefit plan that allows employees to contribute and defer a portion of their wages. We match employee contributions of up to 10% of
wages, subject to annual dollar maximums established by the federal government. Employee contributions vest immediately while our matching contributions vest 100% upon completion of three years of service. All employees over 21 years of age may
participate. Company contributions under the plan were $6.8 million in 2004, $5.2 million in 2003 and $4.5 million in 2002.



Post-Retirement Health Plan



Effective January 1, 2001, we adopted a medical plan for employees who retire at age 55 or over, as well as directors age 55 or over, with a minimum of
five years service. During 2003, our retiree medical plan was amended to provide benefits to employees and directors when their combined age and qualified years of service total 60, with a minimum age of 45 and a minimum of five years of service.
Benefits under the plan are the same as for active employees, and continue until the retired employee or director or the employees or directors dependents are eligible for Medicare or another similar federal health insurance program.
Post-retirement medical benefits are not prefunded but are paid when incurred. The status of our post-retirement health plan for 2004, 2003 and 2002 is as follows:



|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|----------------------------------------------------------------------------------------- |  | ----------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                                                          |  | December 31 |       
|(in thousands)                                                                            |  | 2004        |        |   | 2003 |   |        | 2002 | 
|Change in benefit obligation:                                                             |  |             |        |   |      |   |        |      |  |   |        |  
|Benefit obligation at January 1                                                           |  | $           | 3,122  |   |      | $ | 3,096  |      |  | $ | 1,078  |  
|Service cost                                                                              |  |             | 456    |   |      |   | 729    |      |  |   | 477    |  
|Interest cost                                                                             |  |             | 201    |   |      |   | 275    |      |  |   | 185    |  
|Plan amendments                                                                           |  |             |       |   |      |   | 2,380  |      |  |   | 490    |  
|Actuarial (gain) loss                                                                     |  |             | 256    |   |      |   | (3,273 | )    |  |   | 904    |  
|Benefit payments                                                                          |  |             | (100   | ) |      |   | (85    | )    |  |   | (38    | )
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Benefit obligation at December 31                                                         |  | $           | 3,935  |   |      | $ | 3,122  |      |  | $ | 3,096  |  
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Amounts recognized in the consolidated balance sheet:                                     |  |             |        |   |      |   |        |      |  |   |        |  
|Funded status                                                                             |  | $           | (3,935 | ) |      | $ | (3,122 | )    |  | $ | (3,096 | )
|Unrecognized net actuarial (gain) loss                                                    |  |             | (2,704 | ) |      |   | (3,391 | )    |  |   | 698    |  
|Unrecognized prior service cost                                                           |  |             | 2,332  |   |      |   | 2,738  |      |  |   | 424    |  
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Accrued benefit liability, as recognized in the consolidated balance sheet at December 31 |  | $           | (4,307 | ) |      | $ | (3,775 | )    |  | $ | (1,974 | )
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Components of net periodic benefit cost:                                                  |  |             |        |   |      |   |        |      |  |   |        |  
|Service cost                                                                              |  | $           | 456    |   |      | $ | 729    |      |  | $ | 477    |  
|Interest cost                                                                             |  |             | 201    |   |      |   | 275    |      |  |   | 185    |  
|Amortization of prior service cost                                                        |  |             | 406    |   |      |   | 66     |      |  |   | 66     |  
|Recognized net actuarial (gain) loss                                                      |  |             | (431   | ) |      |   | 731    |      |  |   | 159    |  
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Net periodic benefit cost                                                                 |  | $           | 632    |   |      | $ | 1,801  |      |  | $ | 887    |  
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  



Unrecognized net
actuarial gain and prior service costs are amortized to expense over the lesser of the estimated average remaining service life of plan participants or seven years. Including such amortization, the 2005 accrued benefit cost is expected to be
approximately $1 million.



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##### Index to Financial Statements

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



|                                                                              |  |      |  |      |  |     
|----------------------------------------------------------------------------- |  | ---- |  | ---- |  | ----
|                                                                              |  | 2004 |  | 2003 |  | 2002
|Weighted average discount rate                                                |  | 6%   |  | 6.5% |  | 6.5%
|Health care cost trend rate assumed for the following year                    |  | 9%   |  | 9%   |  | 9%  
|Rate to which the cost trend rate is assumed to decline (ultimate trend rate) |  | 6%   |  | 6%   |  | 6%  
|Year that the rate reaches the ultimate trend rate                            |  | 2010 |  | 2009 |  | 2008



Assumed health care
cost trends have a significant effect on the amounts reported for health care plans. A one percentage point change in assumed health care cost trend rates would have the following estimated effects as of December 31, 2004:



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



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



|               |  |   |      
|-------------- |  | - | -----
|(in thousands) |  |  
|2005           |  | $ | 155  
|2006           |  |   | 181  
|2007           |  |   | 191  
|2008           |  |   | 231  
|2009           |  |   | 267  
|2010 - 2014    |  |   | 2,326
|               |  |   |      
|Total          |  | $ | 3,351
|               |  |   |      



Stock Incentive
Plans



In November 2004, stockholders approved the 2004
Stock Incentive Plan under which 24 million shares of common stock are available for grants of stock awards. Prior to approval of the 2004 Plan, grants of stock awards were made pursuant to the 1998 Stock Incentive Plan. No further grants will be
made under the 1998 Plan. Stock award grants are subject to the provision that awards outstanding at any given time under all incentive plans may not exceed six percent of common stock outstanding at the time such grants are made. The maximum term
of stock awards is ten years under the 1998 Plan and seven years under the 2004 plan. Stock options granted under the 2004 Plan generally vest and become exercisable ratably over a three-year period, with provision for accelerated vesting when the
common stock price reaches specified levels as determined by the Compensation Committee of the Board of Directors. There were 19.3 million options outstanding under both plans at December 31, 2004, including 4.1 million that were exercisable at that
date. The remaining 15.2 million options vested when the common stock price reached specified levels in February 2005.



Nonemployee directors are each eligible to receive discretionary stock awards under the 2004 Plan covering up to 20,000 shares annually, as approved by
the Corporate Governance and Nominating Committee and the Board of Directors. In November 2004, nonemployee directors were granted a total of 88,000 stock options which were outstanding at December 31, 2004 and vested when the common stock price
reached specified levels in February 2005. Under the 1998 Plan, nonemployee directors previously received automatic annual grants of unrestricted common shares that totaled 18,000 shares in each of 2004, 2003 and 2002. In February 2005, nonemployee
directors received a total of 18,000 unrestricted shares under the 2004 Plan.



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Performance Shares



Performance shares granted under the 2004 and 1998 Plans are subject to restrictions determined by the Compensation
Committee of the Board of Directors and are subject to forfeiture if performance criteria are not met. Otherwise, holders of performance shares generally have all the voting, dividend and other rights of other common stockholders. To date, the
performance criteria for all awards has been the achievement of specified increases in the common stock price above the market price at the grant date. The following summarizes performance share activity for each year:



|                                                               |  |             |        |      |   |        |  |   |       
|-------------------------------------------------------------- |  | ----------- | ------ | ---- | - | ------ |  | - | ------
|                                                               |  | December 31
|(in thousands, except per share data)                          |  | 2004        |        | 2003 |   | 2002  
|Shares granted to key employees                                |  |             | 2,576  |      |   | 4,431  |  |   | 2,353 
|Shares vested when common stock price reached specified levels |  |             | 3,240  |      |   | 3,470  |  |   | 2,754 
|Shares forfeited                                               |  |             |       |      |   | 20     |  |   |      
|Weighted average fair value of shares when granted             |  | $           | 20.94  |      | $ | 14.71  |  | $ | 9.73  
|                                                               |  |             |       
|Treasury stock purchases related to vested shares              |  | $           | 24,105 |      | $ | 22,741 |  | $ | 10,276
|Non-cash performance share compensation                        |  | $           | 67,184 |      | $ | 50,826 |  | $ | 26,990



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



|                                        |  |              
|--------------------------------------- |  | -------------
|Shares Outstanding at December 31, 2004 |  | Vesting Price
|397,500                                 |  | $28.13       
|2,533                                   |  | $28.50       
|397,500                                 |  | $31.88       
|                                        |  |              
|797,533                                 |  |              
|                                        |  |              



Management assesses
whether the vesting period of stock-based awards can be reasonably estimated. When management is able to reasonably estimate a probable vesting period, compensation is recognized ratably over the estimated vesting period or at actual vesting, if
earlier. Performance shares outstanding at December 31, 2004 were granted to key employees other than executive officers in September and November 2004. As of December 31, 2004, management estimated a reasonably probable vesting period of one year
for performance share awards that vest at $28.13 and $28.50, resulting in related compensation of $2.8 million recorded in 2004. As of February 2005, all performance shares outstanding at December 31, 2004 vested, resulting in remaining compensation
of $21.1 million to be recorded in first quarter 2005.



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



In September 2004, the Compensation Committee of the Board of Directors announced that it intended to restructure the Companys equity incentive program to discontinue the use of performance shares for executive
officers and to provide that all future grants to the officers would be in the form of options or other stock appreciation shares. As a result, in October 2004, the Compensation Committee of the Board of Directors amended the change in control
performance share grant agreements to delete the provisions regarding the grant of performance shares for every $0.75 increment in the price of the common stock and to provide that, immediately prior to a change in control, executive officers will
receive a lump-sum cash payment equal to the value of 1,667,000 shares of common stock on the date of the change in control. A provision, providing that certain officers will also receive a total grant of 517,000 performance shares immediately prior
to a change in control without regard to the price of our common stock, has been revised to



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##### Index to Financial Statements

provide that such payment will be in cash and not in shares of common stock. All amounts to be granted under these agreements will be adjusted for any future
stock splits or other extraordinary transactions. If the executive officers are subject to the 20% parachute excise tax, the Company will pay the executive officer an additional amount to gross up the payment so that the executive
officer will receive the full amount due under the terms of the amended change in control grant agreement after payment of the excise tax.



Option Activity and Balances



The following summarizes option activity and balances from 2002 through 2004:



|                           |  |                              |       |               |             |  
|-------------------------- |  | ---------------------------- | ----- | ------------- | ----------- | -
|                           |  | WeightedAverageExercisePrice |       | Stock Options |            
|2002                       |  |                              |       |               |             |  
|Beginning of year          |  | $                            | 8.07  |               | 15,413,893  |  
|Grants                     |  |                              | 10.24 |               | 1,104,677   |  
|Exercises                  |  |                              | 6.52  |               | (1,591,438  | )
|Forfeitures                |  |                              | 7.90  |               | (73,063     | )
|                           |  |                              |       |               |             |  
|End of year                |  |                              | 8.40  |               | 14,854,069  |  
|                           |  |                              |       |               |             |  
|Exercisable at end of year |  |                              | 8.33  |               | 14,339,138  |  
|                           |  |                              |       |               |             |  
|2003                       |  |                              |       |               |             |  
|Beginning of year          |  | $                            | 8.40  |               | 14,854,069  |  
|Grants                     |  |                              | 15.06 |               | 3,530,208   |  
|Exercises                  |  |                              | 8.46  |               | (10,430,123 | )
|Forfeitures                |  |                              | 13.88 |               | (55,000     | )
|                           |  |                              |       |               |             |  
|End of year                |  |                              | 11.15 |               | 7,899,154   |  
|                           |  |                              |       |               |             |  
|Exercisable at end of year |  |                              | 9.22  |               | 5,310,993   |  
|                           |  |                              |       |               |             |  
|2004                       |  |                              |       |               |             |  
|Beginning of year          |  | $                            | 11.15 |               | 7,899,154   |  
|Grants                     |  |                              | 24.86 |               | 16,229,845  |  
|Exercises                  |  |                              | 13.17 |               | (4,794,177  | )
|Forfeitures                |  |                              | 15.14 |               | (15,000     | )
|                           |  |                              |       |               |             |  
|End of year                |  |                              | 22.16 |               | 19,319,822  |  
|                           |  |                              |       |               |             |  
|Exercisable at end of year |  |                              | 11.99 |               | 4,092,488   |  
|                           |  |                              |       |               |             |  



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



|                         |  |                     |  |                              |  |                              |       |        |           |                              |   |      
|------------------------ |  | ------------------- |  | ---------------------------- |  | ---------------------------- | ----- | ------ | --------- | ---------------------------- | - | -----
|                         |  | Options Outstanding |  | Options Exercisable         
|Range of Exercise Prices |  | Number              |  | WeightedAverageRemainingTerm |  | WeightedAverageExercisePrice |       | Number |           | WeightedAverageExercisePrice
|$  5.23 - $  7.85        |  | 1,948,925           |  | 6.1 years                    |  | $                            | 7.15  |        | 1,948,925 |                              | $ | 7.15 
|$  7.86 - $10.46         |  | 1,099,233           |  | 7.0 years                    |  | $                            | 9.43  |        | 1,099,233 |                              | $ | 9.43 
|$10.47 - $13.08          |  | 19,329              |  | 8.5 years                    |  | $                            | 11.67 |        | 19,329    |                              | $ | 11.67
|$13.09 - $15.70          |  | 55,667              |  | 8.9 years                    |  | $                            | 15.14 |        | 55,667    |                              | $ | 15.14
|$15.71 - $20.93          |  | 20,000              |  | 9.4 years                    |  | $                            | 19.22 |        | 20,000    |                              | $ | 19.22
|$20.94 - $26.16          |  | 16,176,668          |  | 7.2 years                    |  | $                            | 24.88 |        | 949,334   |                              | $ | 24.58
|                         |  |                     |  |                              |  |                              |       |        |           |                              |   |      
|                         |  | 19,319,822          |  | 7.1 years                    |  | $                            | 22.16 |        | 4,092,488 |                              | $ | 11.99
|                         |  |                     |  |                              |  |                              |       |        |           |                              |   |      



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##### Index to Financial Statements

Estimated Fair Value of Grants



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



|                                |  |         |   |  |         |   |  |         |  
|------------------------------- |  | ------- | - |  | ------- | - |  | ------- | -
|                                |  | 2004    |   |  | 2003    |   |  | 2002    |  
|Risk-free interest rates        |  | 3.5     | % |  | 3.1     | % |  | 3.1     | %
|Dividend yield                  |  | 0.6     | % |  | 0.2     | % |  | 0.2     | %
|Weighted average expected lives |  | 3 years |   |  | 4 years |   |  | 4 years |  
|Volatility                      |  | 26      | % |  | 42      | % |  | 50      | %



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



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



|                                      |  |      |         |      |   |         |  |   |        
|------------------------------------- |  | ---- | ------- | ---- | - | ------- |  | - | -------
|(in thousands, except per share data) |  | 2004 |         | 2003 |   | 2002   
|Earnings available to common stock:   |  |      |         |      |   |         |  |   |        
|As reported                           |  | $    | 507,882 |      | $ | 288,279 |  | $ | 186,059
|Pro forma                             |  | $    | 487,391 |      | $ | 289,311 |  | $ | 183,840
|Earnings per common share:            |  |      |         |      |   |         |  |   |        
|Basic         As reported             |  | $    | 1.53    |      | $ | 0.96    |  | $ | 0.67   
|Pro forma                             |  | $    | 1.46    |      | $ | 0.96    |  | $ | 0.66   
|Diluted     As reported               |  | $    | 1.51    |      | $ | 0.95    |  | $ | 0.66   
|Pro forma                             |  | $    | 1.45    |      | $ | 0.95    |  | $ | 0.65   



13. Acquisitions



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



From February through April 2004, we purchased $223.1 million of properties located primarily in the Barnett Shale of North Texas and in the Arkoma Basin.
These acquisitions are subject to typical post-closing adjustments. Funding was provided by bank debt and cash flow from operations.



In two separate transactions during April 2004, we acquired predominantly oil-producing properties in the Permian Basin of West Texas and in the Powder
River Basin of Wyoming from ExxonMobil Corporation for a total adjusted purchase price of $336 million, including a contingent payable of up to $5 million dependent on earnings from one property in the following year. The acquisitions were funded
with bank borrowings that were repaid with proceeds from the sale of common stock in May 2004 (Note 9) and are subject to typical post-closing adjustments.



In May 2004, we entered an agreement with ChevronTexaco Corporation to acquire properties for a stated purchase price of $1.1 billion. The acquisition
closed on August 16, 2004. After adjustments for net revenues from the January 1, 2004 effective date, preferential purchase right elections exercised in November and December 2004, and other typical closing adjustments, the adjusted purchase price
was approximately $930 million. Post-closing adjustments for final net revenues, volume balancing and income tax effects will be made within twelve months. The acquisition was funded through existing bank credit facilities and the sale of common
stock in May 2004. These properties expand our operations in the Permian Basin and our Eastern and Mid-Continent regions, and add new coal bed methane properties in the Rocky Mountains and a new operating region in South Texas.



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##### Index to Financial Statements

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



In May 2003, we acquired from Williams of Tulsa, Oklahoma natural gas and
coal bed methane producing properties in the Raton Basin of Colorado, the Hugoton Field of southwestern Kansas and the San Juan Basin of New Mexico and Colorado. The adjusted purchase price was $381 million, which was financed with proceeds from our
sale of senior notes (Note 3) and common stock (Note 9).



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



In October 2003, we announced the completion of property transactions which increased our positions in East Texas, Arkansas and the San Juan Basin of New Mexico for a total cost of $100 million. The purchases were funded with existing
credit facilities and are subject to typical post-closing adjustments.



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



|                                                         |  |                        |           |      |   |          
|-------------------------------------------------------- |  | ---------------------- | --------- | ---- | - | ---------
|                                                         |  | Pro Forma (Unaudited) 
|(in thousands, except per share data)                    |  | Year Ended December 31
|                                                         |  | 2004                   |           | 2003
|Revenues                                                 |  | $                      | 2,186,961 |      | $ | 1,645,307
|                                                         |  |                        |           |      |   |          
|Net income before cumulative effect of accounting change |  | $                      | 574,233   |      | $ | 381,985  
|                                                         |  |                        |           |      |   |          
|Net income                                               |  | $                      | 574,233   |      | $ | 383,763  
|                                                         |  |                        |           |      |   |          
|Earnings per common share:                               |  |                        |           |      |   |          
|Basic                                                    |  | $                      | 1.68      |      | $ | 1.19     
|                                                         |  |                        |           |      |   |          
|Diluted                                                  |  | $                      | 1.66      |      | $ | 1.17     
|                                                         |  |                        |           |      |   |          
|Weighted average shares outstanding                      |  |                        | 342,211   |      |   | 322,990  
|                                                         |  |                        |           |      |   |          



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



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##### Index to Financial Statements

14. Quarterly Financial Data(Unaudited)



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



|                                                         |  |         |         |     |   |         |  |     |         |  |   |        
|-------------------------------------------------------- |  | ------- | ------- | --- | - | ------- |  | --- | ------- |  | - | -------
|(in thousands, except per share data)                    |  | Quarter
|                                                         |  | 1st     |         | 2nd |   | 3rd     |  | 4th
|2004                                                     |  |         |         |     |   |         |  |    
|Revenues                                                 |  | $       | 394,764 |     | $ | 444,749 |  | $   | 507,430 |  | $ | 600,658
|Gross profit (a)                                         |  | $       | 215,777 |     | $ | 254,986 |  | $   | 284,446 |  | $ | 329,164
|Net income                                               |  | $       | 94,136  |     | $ | 99,089  |  | $   | 140,782 |  | $ | 173,875
|Earnings per common share (b)                            |  |         |         |     |   |         |  |     |         |  |   |        
|Basic                                                    |  | $       | 0.30    |     | $ | 0.30    |  | $   | 0.41    |  | $ | 0.50   
|Diluted                                                  |  | $       | 0.30    |     | $ | 0.30    |  | $   | 0.40    |  | $ | 0.50   
|Average shares outstanding                               |  |         | 312,727 |     |   | 326,087 |  |     | 345,281 |  |   | 347,118
|2003                                                     |  |         |         |     |   |         |  |    
|Revenues                                                 |  | $       | 253,484 |     | $ | 282,159 |  | $   | 322,058 |  | $ | 331,854
|Gross profit (a)                                         |  | $       | 125,532 |     | $ | 140,274 |  | $   | 172,789 |  | $ | 170,744
|Income before cumulative effect of accounting change     |  | $       | 64,452  |     | $ | 57,335  |  | $   | 102,806 |  | $ | 61,908 
|Cumulative effect of accounting change, net of tax       |  |         | 1,778   |     |   |        |  |     |        |  |   |       
|                                                         |  |         |         |     |   |         |  |     |         |  |   |        
|Net income                                               |  | $       | 66,230  |     | $ | 57,335  |  | $   | 102,806 |  | $ | 61,908 
|                                                         |  |         |         |     |   |         |  |     |         |  |   |        
|Earnings per common share (b)                            |  |         |         |     |   |         |  |     |         |  |   |        
|Basic:                                                   |  |         |         |     |   |         |  |     |         |  |   |        
|Net income before cumulative effect of accounting change |  | $       | 0.22    |     | $ | 0.19    |  | $   | 0.34    |  | $ | 0.20   
|Cumulative effect of accounting change, net of tax       |  |         | 0.01    |     |   |        |  |     |        |  |   |       
|                                                         |  |         |         |     |   |         |  |     |         |  |   |        
|Net income                                               |  | $       | 0.23    |     | $ | 0.19    |  | $   | 0.34    |  | $ | 0.20   
|                                                         |  |         |         |     |   |         |  |     |         |  |   |        
|Diluted:                                                 |  |         |         |     |   |         |  |     |         |  |   |        
|Net income before cumulative effect of accounting change |  | $       | 0.22    |     | $ | 0.19    |  | $   | 0.33    |  | $ | 0.20   
|Cumulative effect of accounting change, net of tax       |  |         | 0.01    |     |   |        |  |     |        |  |   |       
|                                                         |  |         |         |     |   |         |  |     |         |  |   |        
|Net income                                               |  | $       | 0.23    |     | $ | 0.19    |  | $   | 0.33    |  | $ | 0.20   
|                                                         |  |         |         |     |   |         |  |     |         |  |   |        
|Average shares outstanding                               |  |         | 282,263 |     |   | 300,275 |  |     | 306,320 |  |   | 309,431

---

|(a) | Operating income before general and administrative expense.
|--- | -----------------------------------------------------------



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



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



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



Costs Incurred Related to Oil and Gas Producing Activities



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



|                                                                               |  |      |           |     |      |   |           |      |  |   |        
|------------------------------------------------------------------------------ |  | ---- | --------- | --- | ---- | - | --------- | ---- |  | - | -------
|(in thousands)                                                                 |  | 2004 |           |     | 2003 |   |           | 2002
|Acquisitions:                                                                  |  |      |           |     |      |   |           |      |  |   |        
|Producing properties                                                           |  | $    | 1,948,995 | (a) |      | $ | 623,775   |      |  | $ | 354,110
|Undeveloped properties                                                         |  |      | 49,973    |     |      |   | 5,678     |      |  |   | 3,977  
|Development (b) (c)                                                            |  |      | 572,073   |     |      |   | 445,914   |      |  |   | 352,115
|Exploration:                                                                   |  |      |           |     |      |   |           |      |  |   |        
|Successful exploratory drilling costs                                          |  |      | 4,516     |     |      |   | 14,327    |      |  |   | 1,968  
|Geological and geophysical studies                                             |  |      | 8,098     |     |      |   | 639       |      |  |   | 792    
|Dry hole expense                                                               |  |      |          |     |      |   | 26        |      |  |   | 242    
|Rental expense and other                                                       |  |      | 2,415     |     |      |   | 1,146     |      |  |   | 1,152  
|Asset retirement obligation accrual recorded upon acquiring and drilling wells |  |      | 59,864    | (d) |      |   | 13,879    | (e)  |  |   |       
|                                                                               |  |      |           |     |      |   |           |      |  |   |        
|Total Costs Incurred                                                           |  | $    | 2,645,934 |     |      | $ | 1,105,384 |      |  | $ | 714,356
|                                                                               |  |      |           |     |      |   |           |      |  |   |        

---

|(a) | Includes a deferred income tax step-up adjustment of $72.3 million.
|--- | -------------------------------------------------------------------



|(b) | Includes capitalized interest of $2.6 million in 2004, $2.2 million in 2003 and $4.3 million in 2002.
|--- | -----------------------------------------------------------------------------------------------------



|(c) | Amounts have been restated from previously reported amounts to separately disclose successful exploratory drilling costs.
|--- | -------------------------------------------------------------------------------------------------------------------------



|(d) | Includes revisions of $6 million in 2004.
|--- | -----------------------------------------



|(e) | Excludes $75.3 million recorded upon adoption of SFAS No. 143 on January 1, 2003.
|--- | ---------------------------------------------------------------------------------



Exploratory Well Costs



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



|                                                      |  |      |        |   |      |   |         |      |  |   |        |  
|----------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------- | ---- |  | - | ------ | -
|(in thousands)                                        |  | 2004 |        |   | 2003 |   |         | 2002 | 
|Exploratory wells in process of drilling, January 1   |  | $    | 3,390  |   |      | $ | 1,709   |      |  | $ | 816    |  
|Exploratory drilling costs incurred                   |  |      | 4,516  |   |      |   | 14,353  |      |  |   | 2,210  |  
|Successful wells transferred to producing properties  |  |      | (5,965 | ) |      |   | (12,646 | )    |  |   | (1,075 | )
|Unsuccessful well costs charged to expense            |  |      |       |   |      |   | (26     | )    |  |   | (242   | )
|                                                      |  |      |        |   |      |   |         |      |  |   |        |  
|Exploratory wells in process of drilling, December 31 |  | $    | 1,941  |   |      | $ | 3,390   |      |  | $ | 1,709  |  
|                                                      |  |      |        |   |      |   |         |      |  |   |        |  



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



Proved Reserves



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



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##### Index to Financial Statements

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



Standardized Measure



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



As of December 31, 2003, estimated well abandonment costs, net of salvage, are deducted from the standardized measure using year-end costs. Such
abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired (Note 5).



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



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



|                                      |  |           |   |  |                           |   |  |           |   |  |                              |  
|------------------------------------- |  | --------- | - |  | ------------------------- | - |  | --------- | - |  | ---------------------------- | -
|(in thousands)                        |  | Gas (Mcf) |   |  | Natural GasLiquids (Bbls) |   |  | Oil(Bbls) |   |  | Natural GasEquivalents(Mcfe) |  
|Proved Reserves                       |  |           |   |  |                           |   |  |           |   |  |                              |  
|December 31, 2001                     |  | 2,235,478 |   |  | 20,299                    |   |  | 54,049    |   |  | 2,681,566                    |  
|Revisions                             |  | 76,400    |   |  | 2,433                     |   |  | 5,465     |   |  | 123,788                      |  
|Extensions, additions and discoveries |  | 426,541   |   |  | 2,395                     |   |  | 1,144     |   |  | 447,775                      |  
|Production                            |  | (187,583  | ) |  | (1,850                    | ) |  | (4,757    | ) |  | (227,225                     | )
|Purchases in place                    |  | 330,387   |   |  | 2,156                     |   |  | 449       |   |  | 346,017                      |  
|Sales in place                        |  | (42       | ) |  |                          |   |  | (1        | ) |  | (48                          | )
|                                      |  |           |   |  |                           |   |  |           |   |  |                              |  
|December 31, 2002                     |  | 2,881,181 |   |  | 25,433                    |   |  | 56,349    |   |  | 3,371,873                    |  
|Revisions                             |  | (11,644   | ) |  | 5,487                     |   |  | 1,792     |   |  | 32,030                       |  
|Extensions, additions and discoveries |  | 559,773   |   |  | 1,610                     |   |  | 424       |   |  | 571,977                      |  
|Production                            |  | (243,979  | ) |  | (2,359                    | ) |  | (4,724    | ) |  | (286,477                     | )
|Purchases in place                    |  | 465,732   |   |  | 4,508                     |   |  | 2,204     |   |  | 506,004                      |  
|Sales in place                        |  | (6,824    | ) |  | (1                        | ) |  | (614      | ) |  | (10,514                      | )
|                                      |  |           |   |  |                           |   |  |           |   |  |                              |  
|December 31, 2003                     |  | 3,644,239 |   |  | 34,678                    |   |  | 55,431    |   |  | 4,184,893                    |  
|Revisions                             |  | (96,139   | ) |  | (146                      | ) |  | 3,001     |   |  | (79,009                      | )
|Extensions, additions and discoveries |  | 755,385   |   |  | 3,730                     |   |  | 4,176     |   |  | 802,821                      |  
|Production                            |  | (305,453  | ) |  | (2,739                    | ) |  | (8,307    | ) |  | (371,729                     | )
|Purchases in place                    |  | 716,471   |   |  | 2,933                     |   |  | 98,205    |   |  | 1,323,299                    |  
|                                      |  |           |   |  |                           |   |  |           |   |  |                              |  
|December 31, 2004                     |  | 4,714,503 |   |  | 38,456                    |   |  | 152,506   |   |  | 5,860,275                    |  
|                                      |  |           |   |  |                           |   |  |           |   |  |                              |  



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##### Index to Financial Statements

|                          |  |           |  |                           |  |           |  |                             
|------------------------- |  | --------- |  | ------------------------- |  | --------- |  | ----------------------------
|(in thousands)            |  | Gas(Mcf)  |  | Natural GasLiquids (Bbls) |  | Oil(Bbls) |  | Natural GasEquivalents(Mcfe)
|Proved Developed Reserves |  |           |  |                           |  |           |  |                             
|December 31, 2001         |  | 1,452,222 |  | 14,774                    |  | 41,231    |  | 1,788,252                   
|                          |  |           |  |                           |  |           |  |                             
|December 31, 2002         |  | 2,042,661 |  | 19,367                    |  | 47,178    |  | 2,441,931                   
|                          |  |           |  |                           |  |           |  |                             
|December 31, 2003         |  | 2,651,259 |  | 28,187                    |  | 47,882    |  | 3,107,673                   
|                          |  |           |  |                           |  |           |  |                             
|December 31, 2004         |  | 3,252,711 |  | 30,019                    |  | 134,382   |  | 4,239,117                   
|                          |  |           |  |                           |  |           |  |                             



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



|                                        |      |             |            |      |  |   |            |   |  |   |            |  
|--------------------------------------- | ---- | ----------- | ---------- | ---- |  | - | ---------- | - |  | - | ---------- | -
|(in thousands)                          |      | December 31 |           
|                                        | 2004 |             |            | 2003 |  |   | 2002       |  
|Future cash inflows                     |      | $           | 34,027,144 |      |  | $ | 23,213,223 |   |  | $ | 14,734,787 |  
|Future costs:                           |      |             |            |      |  |   |            |   |  |   |            |  
|Production                              |      |             | (8,841,912 | )    |  |   | (5,636,953 | ) |  |   | (3,881,188 | )
|Development                             |      |             | (1,580,173 | )    |  |   | (875,665   | ) |  |   | (687,723   | )
|                                        |      |             |            |      |  |   |            |   |  |   |            |  
|Future net cash flows before income tax |      |             | 23,605,059 |      |  |   | 16,700,605 |   |  |   | 10,165,876 |  
|Future income tax                       |      |             | (7,366,185 | )    |  |   | (5,142,301 | ) |  |   | (3,017,334 | )
|                                        |      |             |            |      |  |   |            |   |  |   |            |  
|Future net cash flows                   |      |             | 16,238,874 |      |  |   | 11,558,304 |   |  |   | 7,148,542  |  
|10% annual discount                     |      |             | (7,836,431 | )    |  |   | (5,568,619 | ) |  |   | (3,392,100 | )
|                                        |      |             |            |      |  |   |            |   |  |   |            |  
|Standardized measure (a)                |      | $           | 8,402,443  |      |  | $ | 5,989,685  |   |  | $ | 3,756,442  |  
|                                        |      |             |            |      |  |   |            |   |  |   |            |  

---

|(a) | Before income tax, the year-end standardized measure (or discounted present value of future net cash flows) was $12.2 billion for 2004, $8.6 billion for 2003 and $5.3 billion for
2002.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Index to Financial Statements

Changes in Standardized Measure of Discounted Future Net Cash Flows
(a)



|                                      |  |      |            |     |      |   |           |      |  |   |            |  
|------------------------------------- |  | ---- | ---------- | --- | ---- | - | --------- | ---- |  | - | ---------- | -
|(in thousands)                        |  | 2004 |            |     | 2003 |   |           | 2002 | 
|Standardized measure, January 1       |  | $    | 5,989,685  |     |      | $ | 3,756,442 |      |  | $ | 1,473,777  |  
|                                      |  |      |            |     |      |   |           |      |  |   |            |  
|Revisions:                            |  |      |            |     |      |   |           |      |  |   |            |  
|Prices and costs                      |  |      | (20,491    | )   |      |   | 1,514,335 |      |  |   | 2,551,358  |  
|Quantity estimates                    |  |      | 436,812    |     |      |   | 207,955   |      |  |   | 209,061    |  
|Accretion of discount                 |  |      | 516,752    |     |      |   | 327,181   |      |  |   | 132,097    |  
|Future development costs              |  |      | (796,658   | )   |      |   | (493,856  | )    |  |   | (344,531   | )
|Income tax                            |  |      | (978,455   | )   |      |   | (973,113  | )    |  |   | (1,159,368 | )
|Production rates and other            |  |      | (2,007     | )   |      |   | 2,372     |      |  |   | 821        |  
|                                      |  |      |            |     |      |   |           |      |  |   |            |  
|Net revisions                         |  |      | (844,047   | )   |      |   | 584,874   |      |  |   | 1,389,438  |  
|Extensions, additions and discoveries |  |      | 1,383,710  |     |      |   | 1,092,285 |      |  |   | 619,556    |  
|Production                            |  |      | (1,512,036 | )   |      |   | (905,910  | )    |  |   | (610,064   | )
|Development costs                     |  |      | 484,341    |     |      |   | 434,554   |      |  |   | 326,219    |  
|Purchases in place (b)                |  |      | 2,900,790  |     |      |   | 1,043,242 |      |  |   | 557,561    |  
|Sales in place (c)                    |  |      |           |     |      |   | (15,802   | )    |  |   | (45        | )
|                                      |  |      |            |     |      |   |           |      |  |   |            |  
|Net change                            |  |      | 2,412,758  |     |      |   | 2,233,243 |      |  |   | 2,282,665  |  
|                                      |  |      |            |     |      |   |           |      |  |   |            |  
|Standardized measure, December 31     |  | $    | 8,402,443  | (d) |      | $ | 5,989,685 | (e)  |  | $ | 3,756,442  |  
|                                      |  |      |            |     |      |   |           |      |  |   |            |  

---

|(a) | The standardized measure has been reduced by estimated operated overhead expense, resulting in a restatement from previously reported amounts of the standardized measure at December
31, 2003 and 2002, and of the changes in the standardized measure for 2003 and 2002.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



|(c) | Generally based on beginning of the year present value (at beginning of year prices and costs) less the cash flow received from such properties during the year, rather than the
estimated present value at the date of sale.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(d) | The December 31, 2004 standardized measure includes a reduction of $14.6 million ($22.9 million before income tax) for estimated property abandonment costs. The consolidated balance
sheet at December 31, 2004 includes a long-term liability of $159.9 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(e) | The December 31, 2003 standardized measure includes a reduction of $7 million ($10.8 million before income tax) for estimated property abandonment costs. The consolidated balance
sheet at December 31, 2003 includes a long-term liability of $93.4 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



79



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##### Index to Financial Statements

MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING



Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934, as amended). Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2004. In making this assessment, our management used the criteria set forth by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Our management has concluded that, based on these criteria, we have maintained in all material respects, effective internal control
over financial reporting as of December 31, 2004. Our independent registered public accounting firm, KPMG LLP, has issued an audit report on our assessment of our internal control over financial reporting, which is included herein.



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



March 7, 2005



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##### Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Shareholders of

XTO Energy Inc.:



We have audited the accompanying consolidated balance sheets of XTO Energy Inc. and its subsidiaries as of December 31, 2004 and 2003, and
the related consolidated income statements, statements of cash flows and statements of stockholders equity for each of the years in the three-year period ended December 31, 2004. In connection with our audits of the consolidated financial
statements, we also have audited the related financial statement schedules. These consolidated financial statements and financial statement schedules are the responsibility of the Companys management. Our responsibility is to express an
opinion on these consolidated financial statements and financial statement schedules based on our audits.



We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.



In our opinion, the consolidated financial statements referred to above present fairly, in
all material respects, the financial position of XTO Energy Inc. and its subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004,
in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all
material respects, the information set forth therein.



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



We also have audited, in accordance with
the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of XTO Energy Inc.s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 7, 2005 expressed an unqualified opinion on managements assessment of, and the effective
operation of, internal control over financial reporting.



KPMG LLP



Dallas, Texas

March 7, 2005



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Shareholders of

XTO Energy Inc.:



We have audited managements assessment, included in Managements Report on Internal Control over Financial Reporting, that XTO Energy Inc. maintained effective internal control over financial reporting as
of December 31, 2004, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).XTO Energy Inc.s management is responsible for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on managements assessment and an opinion on
the effectiveness of the Companys internal control over financial reporting based on our audit.



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



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



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



In
our opinion, managements assessment that XTO Energy Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, XTO Energy Inc. maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2004, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).



We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of XTO Energy Inc. and its subsidiaries as of December 31, 2004 and 2003, and the related consolidated income statements, statements of cash flows and statements of stockholders
equity for each of the years in the three-year period ended December 31, 2004, and our report dated March 7, 2005 expressed an unqualified opinion on those consolidated financial statements.



KPMG LLP



Dallas, Texas

March 7, 2005



82



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##### Table of Contents

##### Index to Financial Statements

|                |  |            
|--------------- |  | -----------
|XTO ENERGY INC. |  | SCHEDULE II



Consolidated Valuation and
Qualifying Accounts



|                                                                       |  |                              |       |              |   |               |  |   |       |   |  |                        |        |      |  |   |      
|---------------------------------------------------------------------- |  | ---------------------------- | ----- | ------------ | - | ------------- |  | - | ----- | - |  | ---------------------- | ------ | ---- |  | - | -----
|(in thousands)                                                         |  | Balance atBeginning ofPeriod |       | Additions(a) |   | Deductions(b) |  |   | Other |   |  | Balance atEnd ofPeriod
|Year Ended December 31, 2004                                           |  |                              |       |              |   |               |  |   |       |   |  |                        |        |      |  |   |      
|Allowance for doubtful accounts - Joint interest and other receivables |  | $                            | 6,328 |              | $ | 232           |  | $ | (535  | ) |  | $                      | (2,161 | )(c) |  | $ | 3,864
|                                                                       |  |                              |       |              |   |               |  |   |       |   |  |                        |        |      |  |   |      
|Year Ended December 31, 2003                                           |  |                              |       |              |   |               |  |   |       |   |  |                        |        |      |  |   |      
|Allowance for doubtful accounts - Joint interest and other receivables |  | $                            | 5,537 |              | $ | 1,319         |  | $ | (528  | ) |  | $                      |       |      |  | $ | 6,328
|                                                                       |  |                              |       |              |   |               |  |   |       |   |  |                        |        |      |  |   |      
|Year Ended December 31, 2002                                           |  |                              |       |              |   |               |  |   |       |   |  |                        |        |      |  |   |      
|Allowance for doubtful accounts - Joint interest and other receivables |  | $                            | 4,098 |              | $ | 980           |  | $ | (65   | ) |  | $                      | 524    | (d)  |  | $ | 5,537
|                                                                       |  |                              |       |              |   |               |  |   |       |   |  |                        |        |      |  |   |      

---

|(a) | Additions relate to provisions for doubtful accounts.
|--- | -----------------------------------------------------



|(b) | Deductions relate to the write-off of accounts receivable deemed uncollectible.
|--- | -------------------------------------------------------------------------------



|(c) | Reduction based on collection experience.
|--- | -----------------------------------------



|(d) | Adjustment related to reclassified account balances.
|--- | ----------------------------------------------------



83



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##### Index to Financial Statements



SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 7thday of March 2005.



XTO ENERGY INC.By

/s/    BOB R. SIMPSONBob R. Simpson, Chairman of the Board and Chief Executive Officer




Pursuant to the requirements of
the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 7thday of March 2005.



|                                                                       |  |  |  |                                                        
|---------------------------------------------------------------------- |  |  |  | -------------------------------------------------------
|PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS)                           |  |  |  | DIRECTORS                                              
|                                                                       |  | 
|/s/    BOB R. SIMPSON                                                  |  |  |  | /s/    WILLIAM H. ADAMS
III                            
|Bob R. Simpson, Chairman of the Board and Chief Executive Officer      |  |  |  | William H. Adams III                                   
|                                                                       |  | 
|/s/    STEFFEN E. PALKO                                                |  |  |  | /s/    PHILLIP R. KEVIL                                
|Steffen E. Palko, Vice Chairman of the Board and President             |  |  |  | Phillip R. Kevil                                       
|                                                                       |  | 
|                                                                       |  |  |  | /s/    JACK P. RANDALL                                 
|                                                                       |  |  |  | Jack P. Randall                                        
|                                                                       |  | 
|                                                                       |  |  |  | /s/    SCOTT G. SHERMAN                                
|                                                                       |  |  |  | Scott G. Sherman                                       
|                                                                       |  | 
|                                                                       |  |  |  | /s/    HERBERT D. SIMONS                               
|                                                                       |  |  |  | Herbert D. Simons                                      
|                                                                       |  | 
|PRINCIPAL FINANCIAL OFFICER                                            |  |  |  | PRINCIPAL ACCOUNTING OFFICER                           
|                                                                       |  | 
|/s/    LOUIS G. BALDWIN                                                |  |  |  | /s/    BENNIE G. KNIFFEN                               
|Louis G. Baldwin, Executive Vice President and Chief Financial Officer |  |  |  | Bennie G. Kniffen, Senior Vice President and Controller



84



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##### Index to Financial Statements



INDEX TO EXHIBITS



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



|            |  |                                                                                                                                                                                                                                                            |  |     
|----------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|Exhibit No. |  | Description                                                                                                                                                                                                                                                |  | Page
|            |  |                                                                                                                                                                                                                                                           
|2.1+        |  | Asset Sale Agreement between Chevron U.S.A. Inc. as Seller and XTO Energy Inc. as Buyer, dated May 14, 2004 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 19,
2004)                                                                   |  |     
|            |  |                                                                                                                                                                                                                                                           
|2.2+        |  | Agreement and Plan of Merger by and among Antero Resources Corporation, XTO Energy Inc. and XTO Barnett Inc., dated January 9, 2005                                                                                                                        |  |     
|            |  |                                                                                                                                                                                                                                                           
|2.3+        |  | Amendment to Agreement and Plan of Merger by and among Antero Resources Corporation, XTO Energy Inc. and XTO Barnett Inc., dated February 3, 2005                                                                                                          |  |     
|            |  |                                                                                                                                                                                                                                                           
|3.1         |  | Restated Certificate of Incorporation of the Company, as restated on June 21, 2004 (incorporated by reference to Exhibit 3.1 to Form 10-Q for the quarter ended June 30, 2004)                                                                             |  |     
|            |  |                                                                                                                                                                                                                                                           
|3.2         |  | Amended Bylaws of the Company (incorporated by reference to Form 10-K for the year ended December 31, 2003)                                                                                                                                                |  |     
|            |  |                                                                                                                                                                                                                                                           
|4.1         |  | Form of Indenture for Senior Debt Securities dated as of April 23, 2002 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed
April 17, 2002)                                             |  |     
|            |  |                                                                                                                                                                                                                                                           
|4.2         |  | First Supplemental Indenture dated as of April 23, 2002, between the Company and the Bank of New York, as Trustee for the 71⁄2% Senior Notes due April 15, 2012 (incorporated by reference
to Exhibit 4.2 to Form 10-K for the year ended December 31, 2002) |  |     
|            |  |                                                                                                                                                                                                                                                           
|4.3         |  | Preferred Stock Purchase Rights Agreement between the Company and ChaseMellon Shareholder Services, LLC (incorporated by reference to Exhibit 4.1 to Form 8-A/A filed September 8,
1998)                                                                   |  |     
|            |  |                                                                                                                                                                                                                                                           
|4.4         |  | Certificate of Designation of Series A Junior Participating Preferred Stock, par value $0.01 per share, dated August 25, 1998 (incorporated by reference to Exhibit 4.1 to Form 10-Q for the
quarter ended September 30, 2000)                             |  |     
|            |  |                                                                                                                                                                                                                                                           
|4.5         |  | Registration Rights Agreement among the Company and partners of Cross Timbers Oil Company, L.P. (incorporated by reference to Exhibit 10.9 to Registration Statement on Form S-1, File No.
33-59820)                                                       |  |     
|            |  |                                                                                                                                                                                                                                                           
|4.6         |  | Indenture dated as of April 23, 2003, between the Company and the Bank of New York, as Trustee for the 61⁄4% Senior Notes due April 15, 2013 (incorporated by reference to Exhibit 4.1 to
Form 10-Q for the quarter ended March 31, 2003)                    |  |     
|            |  |                                                                                                                                                                                                                                                           
|4.7         |  | Registration Rights Agreement dated April 23, 2003, between the Company and certain Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to Form 10-Q for the quarter
ended March 31, 2003)                                          |  |     
|            |  |                                                                                                                                                                                                                                                           
|4.8         |  | Indenture for Senior Debt Securities dated as of January 22, 2004, between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed
January 16, 2004)                                                |  |     



85



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##### Index to Financial Statements

|            |  |                                                                                                                                                                                                                                        |  |     
|----------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|Exhibit No. |  | Description                                                                                                                                                                                                                            |  | Page
|            |  |                                                                                                                                                                                                                                       
|4.9         |  | First Supplemental Indenture dated as of January 22, 2004, between the Company and the Bank of New York for the 4.9% Senior Notes due February 1, 2014 (incorporated by reference to Exhibit
4.3.2 to Form 8-K filed January 16, 2004) |  |     
|            |  |                                                                                                                                                                                                                                       
|4.10        |  | Indenture dated as of September 23, 2004, between the Company and the Bank of New York, as Trustee for the 5% Senior Notes due 2015 (incorporated by reference to Exhibit 4.1 to Form 8-K filed
September 20, 2004)                    |  |     
|            |  |                                                                                                                                                                                                                                       
|10.1  *     |  | Amended and Restated Employment Agreement between the Company and Bob R. Simpson, dated May 17, 2000 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30,
2000)                                      |  |     
|            |  |                                                                                                                                                                                                                                       
|10.2  *     |  | Amendment to Amended and Restated Employment Agreement between the Company and Bob R. Simpson, dated August 20, 2002 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter
ended September 30, 2002)                 |  |     
|            |  |                                                                                                                                                                                                                                       
|10.3  *     |  | Amended and Restated Employment Agreement between the Company and Steffen E. Palko, dated May 17, 2000 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30,
2000)                                    |  |     
|            |  |                                                                                                                                                                                                                                       
|10.4  *     |  | Amendment to Amended and Restated Employment Agreement between the Company and Steffen E. Palko, dated August 20, 2002 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter
ended September 30, 2002)               |  |     
|            |  |                                                                                                                                                                                                                                       
|10.5  *     |  | 1998 Stock Incentive Plan, as amended March 17, 2004 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2004)                                                                                     |  |     
|            |  |                                                                                                                                                                                                                                       
|10.6  *     |  | 2004 Stock Incentive Plan (incorporated by reference to Appendix A to the Proxy Statement dated October 15, 2004 for the Special Meeting of Stockholders held November 16, 2004)                                                       |  |     
|            |  |                                                                                                                                                                                                                                       
|10.7  *     |  | Form of Nonqualified Stock Option Agreement for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 8-K filed November 22, 2004)                                                          |  |     
|            |  |                                                                                                                                                                                                                                       
|10.8  *     |  | Form of Stock Award Agreement for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed November 22, 2004)                                                                        |  |     
|            |  |                                                                                                                                                                                                                                       
|10.9  *     |  | Form of Nonqualified Stock Option Agreement for Non-Employee Directors under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.4 to Form 8-K filed November 22,
2004)                                             |  |     
|            |  |                                                                                                                                                                                                                                       
|10.10*      |  | Form of Stock Award Agreement for Non-Employee Directors under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 8-K filed November 22, 2004)                                                           |  |     
|            |  |                                                                                                                                                                                                                                       
|10.11*      |  | Form of Stock Grant Agreement for Non-Employee Directors under Section 11 of the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 22,
2005)                                             |  |     
|            |  |                                                                                                                                                                                                                                       
|10.12*      |  | Amended Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.14 to Form 10-K for the year ended December 31, 1999)                                                                |  |     



86



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##### Index to Financial Statements

|            |  |                                                                                                                                                                                                                                                                                                                 |  |     
|----------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|Exhibit No. |  | Description                                                                                                                                                                                                                                                                                                     |  | Page
|            |  |                                                                                                                                                                                                                                                                                                                
|10.13*      |  | Amendment to Amended Employee Severance Protection Plan, as amended August 20, 2002 (incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ended September 30,
2002)                                                                                                                           |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.14*      |  | Amended and Restated Management Group Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.13 to Form 10-K for the year ended December 31,
1999)                                                                                                           |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.15*      |  | Amendment to Amended and Restated Management Group Employee Severance Protection Plan, as amended August 20, 2002 (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended
September 30, 2002)                                                                                             |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.16*      |  | Outside Directors Severance Plan, dated August 20, 2002 (incorporated by reference to Exhibit 10.6 to Form 10-Q for the quarter ended September 30, 2002)                                                                                                                                                       |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.17*      |  | Form of Agreement for Grant of Performance Shares (relating to change in control) between the Company and each of Bob R. Simpson and Steffen E. Palko dated February 20, 2001 (incorporated by
reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2001)                                 |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.18*      |  | Form of Agreement for Grant of Performance Shares (relating to change in control) between the Company and each of Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II dated February
20, 2001 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2001)       |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.19*      |  | Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Bob R. Simpson dated May 24, 2001 (incorporated by reference to Exhibit 10.3 to
Form 10-Q for the quarter ended September 30, 2001)                                                              |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.20*      |  | Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Steffen E. Palko dated May 24, 2001 (incorporated by reference to Exhibit 10.4
to Form 10-Q for the quarter ended September 30, 2001)                                                            |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.21*      |  | Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Louis G. Baldwin dated May 24, 2001 (incorporated by reference to Exhibit 10.5
to Form 10-Q for the quarter ended September 30, 2001)                                                            |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.22*      |  | Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Keith A. Hutton dated May 24, 2001 (incorporated by reference to Exhibit 10.6 to
Form 10-Q for the quarter ended September 30, 2001)                                                             |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.23*      |  | Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Vaughn O. Vennerberg II dated May 24, 2001 (incorporated by reference to Exhibit
10.7 to Form 10-Q for the quarter ended September 30, 2001)                                                     |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.24*      |  | Form of Amended and Restated Agreement for Grant (relating to change in control) between the Company and Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O.
Vennerberg II, dated October 15, 2004 (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 21, 2004) |  |     
|            |  |                                                                                                                                                                                                                                                                                                                
|10.25*      |  | Phantom Performance Share Award Agreement between the Company and Bob R. Simpson, dated April 23, 2004 (incorporated by reference to Form 10-Q for the quarter ended June 30, 2004)                                                                                                                             |  |     



87



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##### Index to Financial Statements

|            |  |                                                                                                                                                                                                                                                                                              |  |      |  | 
|----------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ---- |  | 
|Exhibit No. |  | Description                                                                                                                                                                                                                                                                                  |  | Page
|            |  |                                                                                                                                                                                                                                                                                             
|10.26*      |  | Phantom Performance Share Award Agreement between the Company and Bob R. Simpson, dated June 18, 2004 (incorporated by referenced to Form 10-Q for the quarter ended June 30,
2004)                                                                                                          |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|10.27*      |  | Form of Agreement for Grant of Phantom Performance Shares between the Company and each of Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O.
Vennerberg II, dated June 24, 2004 (incorporated by referenced to Form 10-Q for the quarter ended June 30, 2004) |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|10.28*      |  | Form of Agreement for Grant of Phantom Performance Shares between the Company and each of Bob R. Simpson, Steffen E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O.
Vennerberg II, dated July 8, 2004 (incorporated by referenced to Form 10-Q for the quarter ended June 30, 2004)  |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|10.29       |  | Five-Year Revolving Credit Agreement dated February 17, 2004, between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.18
to Form 10-K for the year ended December 31, 2003)                                                                  |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|10.30       |  | Term Loan Credit Agreement dated November 10, 2004 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.20 to Form S-4 dated
December 13, 2004)                                                                                           |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|12.1        |  | Computation of Ratio of Earnings to Fixed Charges                                                                                                                                                                                                                                            |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|21.1        |  | Subsidiaries of XTO Energy Inc.                                                                                                                                                                                                                                                              |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|23.1        |  | Consent of KPMG LLP                                                                                                                                                                                                                                                                          |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|23.3        |  | Consent of Miller and Lents, Ltd.                                                                                                                                                                                                                                                            |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|31          |  | Rule 13a-14(a)/15d-14(a) Certifications                                                                                                                                                                                                                                                      |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|            |  | 31.1 Chief Executive Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                         |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|            |  | 31.2 Chief Financial Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                         |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|32          |  | Section 1350 Certifications                                                                                                                                                                                                                                                                  |  |     
|            |  |                                                                                                                                                                                                                                                                                             
|            |  | 32.1 Chief Executive Officer and Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                              |  |     



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



|* | Management contract or compensatory plan
|- | ----------------------------------------

---

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



88