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2003

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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, 2003



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                          
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)



|                                         |  |           
|---------------------------------------- |  | ----------
|810 Houston Street, Fort Worth, Texas    |  | 76102     
|(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. ̈



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, 2003 (the last business day of its most recently completed second fiscal quarter), held by nonaffiliates of the Registrant on that date was approximately $3.5 billion.



Number of Shares of Common Stock outstanding as of March 8, 2004 (as
adjusted for the 5-for-4 stock split to be effected March 17, 2004) - 234,838,221



DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)



Part III of this Report is incorporated by reference from the Registrants definitive
Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 30, 2004.



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XTO ENERGY INC.

2003 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                            |  | 39  
|8.        |  | Financial Statements and Supplementary Data                                           |  | 41  
|9.        |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  | 41  
|9A.       |  | Controls and Procedures                                                               |  | 41  
|          |  |                                                                                      
|          |  | Part III                                                                              |  |     
|          |  |                                                                                      
|10.       |  | Directors and Executive Officers of the Registrant                                    |  | 42  
|11.       |  | Executive Compensation                                                                |  | 42  
|12.       |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 42  
|13.       |  | Certain Relationships and Related Transactions                                        |  | 42  
|14.       |  | Principal Accountant Fees and Services                                                |  | 42  
|          |  |                                                                                      
|          |  | Part IV                                                                               |  |     
|          |  |                                                                                      
|15.       |  | Exhibits, Financial Statement Schedules and Reports on Form 8-K                       |  | 43  





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PART I



Items 1. and 2.BUSINESS AND PROPERTIES



General



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



Our corporate internet web site is www.xtoenergy.com. We make available free of charge, on or through the investor relations
section of our web site, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as
soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.



We have grown primarily through acquisitions of proved oil and gas reserves, followed by development and exploitation activities and strategic
acquisitions of additional interests in or near such acquired properties. Growth for the next year or more is expected to be accomplished through a combination of acquisitions and development. Given expected significant property divestitures by
major energy, merchant energy, power generating and utility companies, larger strategic acquisitions could be made during 2004.



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:



| |  | the Eastern Region, located in East Texas and North Louisiana;
| | - | --------------------------------------------------------------



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



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



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



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



| |  | the Green River Basin of Wyoming;
| | - | ---------------------------------



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



| |  | the Middle Ground Shoal Field of Alaskas Cook Inlet.
| | - | -----------------------------------------------------



We use the following volume abbreviations throughout this Form 10-K. Equivalent volumes are computed with oil and natural gas liquid
quantities converted to Mcf 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
| | - | ----------------------------------



| |  | Mcf Thousand cubic feet (of natural gas)
| | - | ----------------------------------------



| |  | Mcfe Thousand cubic feet equivalent
| | - | -----------------------------------



| |  | MMBtu One million British Thermal Units, a common energy measurement
| | - | --------------------------------------------------------------------



| |  | Tcf Trillion cubic feet (of natural gas)
| | - | ----------------------------------------



| |  | Tcfe Trillion cubic feet equivalent
| | - | -----------------------------------



Our estimated proved reserves at December 31, 2003 were 3.6 Tcf of natural gas, 34.7 million Bbls of natural gas liquids and 55.4 million Bbls of oil,
based on December 31, 2003 prices of $5.71 per Mcf for gas, $23.17 per Bbl for natural gas liquids and $30.55 per Bbl for oil. Approximately 74% of December 31, 2003 proved reserves, computed on an Mcfe basis, were proved developed reserves.
Increased proved reserves during 2003 were primarily the result of acquisitions and development and exploitation activities. During 2003, our daily average production was 668,436 Mcf of gas, 6,463 Bbls of natural gas liquids and 12,943 Bbls of oil.
Fourth quarter 2003 daily average production was 738,053 Mcf of gas, 6,528 Bbls of natural gas liquids and 12,850 Bbls of oil.



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Our properties have relatively long reserve lives and highly predictable production profiles. Based on
December 31, 2003 proved reserves and projected 2004 production from properties owned as of December 31, 2003, the average reserve-to-production index of our proved reserves is 14.7 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, 2003, we owned interests in 11,364 gross (5,633.6 net) wells, and we operated wells representing 92.2% of the present value of cash flows before income
taxes (discounted at 10%) from estimated proved reserves. The high proportion of operated properties allows us to exercise more control over expenses, capital allocation and the timing of development and exploitation activities in our fields.



We have generated a substantial inventory of approximately
2,700 potential development drilling locations. Drilling plans are primarily dependent upon product prices and the availability and pricing of drilling equipment and supplies.



We employ a disciplined acquisition program refined by senior management to augment our core properties and expand our
reserve base. Our engineers and geologists use their expertise and experience gained through the management of existing core properties to target properties to be acquired with similar geological and reservoir characteristics.



We operate gas gathering systems in 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. Gas gathering and processing operations are only in areas where we have production and are considered activities which add value to our
natural gas production and sales 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 0.0059 units of the trust for each share of our common stock outstanding on September 2, 2003, after adjustment for the five-for-four stock split to be effected on March 17, 2004. This dividend,
totaling 1,360,000 trust units, was distributed on September 18, 2003, after which we no longer own any Cross Timbers Royalty Trust units.



In December 1998, we formed the Hugoton Royalty Trust by conveying an 80% net profits interest in principally gas-producing operated working interests in
the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These net profits interests were conveyed to the trust in exchange for 40 million units of beneficial interest. We sold 17 million units in
the trusts initial public offering in 1999 and 1.3 million units pursuant to an employee incentive plan in 1999 and 2000. We own the remaining 54% 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.



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Industry Operating Environment



The oil and gas industry is affected by many factors that we generally cannot control. Governmental regulations,
particularly in the areas of taxation, energy and the environment, can have a significant impact on operations and profitability. Crude oil prices are determined by global supply and demand. Oil supply is significantly influenced by production
levels of OPEC member countries, while demand is largely driven by the condition of worldwide economies, as well as weather. Our natural gas prices are generally determined by North American supply and demand. Weather has a significant impact on
demand for natural gas since it is a primary heating resource. Its increased use for electrical generation has kept natural gas demand elevated throughout the year, removing some of the seasonal swing in prices. See 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
| | - | -----------------------------------------------------------------------------------------------------------------------



| |  | 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 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 properties possess geologic and reservoir characteristics that make them well suited for production
increases through drilling and other development programs. We have generated an inventory of approximately 2,700 potential drilling locations. Additionally, we review operations and mechanical data on operated properties to determine if actions can



3



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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 2004, 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 $25 million of our $520 million 2004 development budget for exploration activities.



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



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



| |  | 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 2004, we announced a strategic goal for
2004 of increasing gas production by 16% to 18% over 2003 levels. With the announcement of additional acquisitions in February 2004, we updated our goal to increase gas production by 18% to 20% over 2003 levels. To achieve this growth target, we
plan to drill about 420 (336 net) development wells and perform approximately 350 (251 net) workovers and recompletions in 2004.



We have budgeted $1.17 billion for our 2004 development and acquisition programs, which is expected to be substantially funded by cash flow from
operations. We plan to allocate $650 million of the 2004 capital budget to acquisitions, including $243 million of acquisitions in January 2004 and $200 million expected to close in April 2004 (see Note 13 to Consolidated Financial Statements), and
$520 million to development and exploration. Of the $520 million development budget, we plan to spend $340 million in East Texas and Louisiana, a total of $100 million in the Arkoma, Raton and San Juan Basins, a total of $35 million for development
in Alaska, the Permian Basin and Hugoton Royalty Trust properties and $20 million in the Barnett Shale of North Texas. We expect to spend $25 million for exploration.



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If acquisitions are available in excess of our $650 million budget, we expect to fund a portion of our
2004 acquisitions with publicly placed equity securities. Strategic property acquisitions during 2004 may alter the amount currently budgeted for development and exploration.



The weak U.S. dollar, raw material shortages and strong demand for steel in China and Europe have tightened worldwide steel
supplies, causing prices to rise by more than 50% since November 2003. In response, we have increased our tubular inventory and are currently negotiating contracts with our vendors to support our development program. Should steel prices continue to
escalate, our development budget could rise by as much as 10%. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting our production growth.



We may reevaluate our budget and drilling programs in the
event of significant changes in oil and gas prices to focus on opportunities offering the highest rates of return and may increase our budget. Our ability to achieve our production goals will depend on the success of these planned drilling programs
or, if property acquisitions are made in place of a portion of the drilling program, the success of those acquisitions.



Acquisitions



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



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



During 2001, we acquired predominantly gas-producing properties for a total cost of $242 million. In January 2001, we acquired gas properties in East
Texas and Louisiana for $115 million from Herd Producing Company, Inc., and in February 2001, we acquired gas properties in East Texas for $45 million from Miller Energy, Inc. and other owners. In August 2001, we acquired primarily underdeveloped
acreage in the Freestone area of East Texas for approximately $22 million. The 2001 acquisitions increased reserves by approximately 248.3 Bcf of natural gas, approximately 50% of which were proved undeveloped.



During 2002, we acquired gas-producing properties for a total cost of $358.1
million. In 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.



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##### Index to Financial Statements

In January 2004, we completed acquisitions with multiple parties for $243 million. The producing
properties are located primarily in East Texas and northern Louisiana and will increase our reserves by approximately 182 Bcfe. Our internal engineers estimate that approximately 50% of these reserves are proved developed. In February 2004, we
entered definitive agreements with multiple parties for $200 million to acquire producing properties located primarily in the Barnett Shale of North Texas and in the Arkoma Basin. The acquisitions will increase our reserves by approximately 154
Bcfe, of which approximately 52% are proved developed.



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, 2003:



|                          |  |                 |  |                                                              |  |            |  |                               |  |   |           |  |      |  
|------------------------- |  | --------------- |  | ------------------------------------------------------------ |  | ---------- |  | ----------------------------- |  | - | --------- |  | ---- | -
|                          |  | Proved Reserves |  | Discounted Present Value before Income Taxof Proved Reserves | 
|(in thousands)            |  | Gas (Mcf)       |  | Natural Gas Liquids(Bbls)                                    |  | Oil (Bbls) |  | Natural Gas Equivalents(Mcfe) | 
|Eastern Region            |  | 1,887,211       |  | 2,738                                                        |  | 4,692      |  | 1,931,791                     |  | $ | 4,261,658 |  | 48.3 | %
|San Juan and Raton Basins |  | 798,344         |  | 31,940                                                       |  | 1,707      |  | 1,000,226                     |  |   | 1,929,173 |  | 21.9 | %
|Arkoma Basin              |  | 495,594         |  |                                                             |  | 26         |  | 495,750                       |  |   | 1,204,674 |  | 13.7 | %
|Hugoton Royalty Trust(a)  |  | 293,171         |  |                                                             |  | 2,390      |  | 307,511                       |  |   | 623,495   |  | 7.1  | %
|Permian Basin             |  | 33,133          |  |                                                             |  | 30,508     |  | 216,181                       |  |   | 392,133   |  | 4.4  | %
|Mid-Continent             |  | 131,330         |  |                                                             |  | 176        |  | 132,386                       |  |   | 244,764   |  | 2.8  | %
|Alaska Cook Inlet         |  |                |  |                                                             |  | 15,133     |  | 90,798                        |  |   | 144,681   |  | 1.6  | %
|Other                     |  | 5,456           |  |                                                             |  | 799        |  | 10,250                        |  |   | 19,583    |  | 0.2  | %
|                          |  |                 |  |                                                              |  |            |  |                               |  |   |           |  |      |  
|Total                     |  | 3,644,239       |  | 34,678                                                       |  | 55,431     |  | 4,184,893                     |  | $ | 8,820,161 |  | 100  | %
|                          |  |                 |  |                                                              |  |            |  |                               |  |   |           |  |      |  

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|(a) | Includes 200,705,000 Mcf of gas and 1,636,000 Bbls of oil
and discounted present value before income tax of $426,845,000 related to our ownership of approximately 54% of Hugoton Royalty Trust units at December 31, 2003. 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. Development in the East Texas area has more than doubled reserves since acquisition, and we now have an interest in more than 215,000 gross (171,000 net) acres and a current development
inventory of 1,100 to 1,400 wells. We own an interest in 1,422 gross (1,294.4 net) wells that we operate and 192 gross (34.2 net) wells operated by others. Of these wells, 27 gross (25.6 net) operated wells are dual completions. We also own and
operate the related gathering facilities.



Freestone Trend



The Freestone Trend area is located in the western shelf
of the East Texas Basin in Freestone, Robertson, Limestone and Leon counties. This area includes the Freestone, Bald Prairie, Bear Grass, Oaks, Teague, Farrar, Dew and Luna fields and was our most active gas development area in 2003, where 175 gross
(155.8 net) gas wells were drilled and 18 workovers were performed. In 2003, we increased our acreage position to 155,000 gross (121,200 net) acres in this area and have a development inventory of 800 to 1,000 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. A 27-mile pipeline system, completed in January 2002,
connects the major fields and allows multiple exit points for marketing. We plan to continue our expansion efforts in this area by drilling approximately 170 wells in 2004. We will also continue to construct and operate infrastructure or contract
additional pipeline capacity to support our drilling activity.



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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 North Louisiana. With our 2003 and January 2004 acquisitions, we increased our position in these areas, which provides opportunities for field extensions and infill
drilling. In 2003, we drilled five wells and performed 15 workovers in the other Eastern Region fields. In 2004, we plan to drill 28 wells in the Carthage area and 22 wells in North Louisiana and perform 60 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 37,000 Mcf of gas per day, and 1,700 Bbls of natural gas liquids per day are extracted, primarily from
production in the surrounding operated wells.



San Juan and Raton Basins



The San Juan Basin of northwestern New Mexico and
southwestern Colorado contains the largest deposit of natural gas reserves in North America. We acquired a large portion of our interests in the San Juan Basin in December 1997 with the purchase of approximately 290 Bcfe from Amoco Corporation. In
2002, we purchased approximately 212 Bcfe from Marathon Oil Company and J. M. Huber Corporation and extended our coal bed methane operations into Colorado. During 2003, we purchased approximately 311 Bcfe of natural gas and coal bed methane reserves
from Williams of Tulsa, Oklahoma. We have now identified 580 to 780 potential drilling locations in the San Juan and Raton Basins. XTO owns an interest in 1,309 gross (1,113.2 net) wells that it operates and 2,204 gross (275.4 net) wells operated by
others. Of these wells, 198 gross (169.1 net) operated wells and 134 gross (28.3 net) nonoperated wells are dual completions. In 2003, we participated in the drilling of 94 wells and completed 130 workovers. Drilling focused on the Fruitland Coal
formation at shallow intervals of 3,000 feet or less and the Mesaverde and Dakota formations at depths of 3,000 to 7,500 feet. During 2004, we plan to drill 90 to 100 wells and perform 100 to 150 workovers and recompletions, including installation
of as many as 60 wellhead compressors and 40 pumping units.



Mesaverde and Dakota Formations



Eighty-acre
spacing was approved for the Mesaverde and Dakota formations in January 2002, which now allows wells to be drilled with multiple zone targets. We have identified more than 200 potential well locations that will allow deeper drilling through the
Dakota to the Burro Canyon and Morrison sandstones. In 2003, we drilled 22 Dakota and eight Mesaverde wells. Twenty-eight drill wells are planned for 2004.



Fruitland Coal Formation



XTO has centered its Fruitland Coal development efforts on trend extensions. Our coal bed methane play is focused on the northwestern portion of the Basin
surrounding the city of Farmington, New Mexico and in the southwestern portion of Colorado. We began drilling Fruitland Coal wells on 160-acre spacing in 2003. We drilled 38 wells in 2003 and plan to drill an additional 25 wells in 2004.



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 expansive development opportunities. Producing formations include the Raton Coals
at depths of 500 to 1,800 feet with coal seams one to twelve feet thick and the Vermejo Coals at depths of 800 to 2,500 feet with coal seams one to twelve feet thick. We drilled 18 wells in this area in 2003 and plan to drill 35 wells in 2004.



Arkoma Basin Area



During 1999, we acquired 480 Bcfe of reserves and a gas gathering system in
the Arkoma Basin of Arkansas and Oklahoma. The Arkoma Basin, discovered in the 1920s, extends from central Arkansas into southeastern Oklahoma and is known for shallow production decline rates, multiple formations and complex geology. XTO controls
40% of Arkansas production from the Arkoma Basin and is the largest natural gas producer in Arkansas with over 500,000 gross acres of leasehold. We own an interest in 973 gross (700.7 net) wells which we operate and 716 gross (130.2 net) wells
operated by others. Of these wells, 129 gross (91.2 net) operated wells and 83 gross (15.8 net) nonoperated wells are dual



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##### Index to Financial Statements

completions. Our fault-block analysis technique has identified trapped hydrocarbons in offsetting and new reservoirs across the basin. During 2003, we
drilled 79 wells and completed 140 workovers, 55 of which were stimulation/recompletions and 21 of which were wellhead compressor installations. Our properties can be separated into three distinct areas which are the Arkansas Fairway trend, the
Arkansas Overthrust trend and the Oklahoma Cromwell/Atoka trend.



Arkansas Fairway Trend



The Arkansas Fairway
trend comprises multiple sandstones at depths ranging from 2,500 to 7,500 feet in the Atoka and Morrow intervals. In 2003, the Orr and Hale sandstones were targets for our drilling focused in the Aetna and Cecil fields. Thirty-two wells were drilled
and 129 workovers were performed in 2003. In 2004, we plan to drill 30 wells.



Arkansas Overthrust Trend



The Arkansas Overthrust trend area, located south of the Arkansas Fairway trend, typically has multiple thrust faults that created isolated reservoirs. Production is found at varying depths, ranging from 3,500 to 7,500 feet, in the
Chismville, Booneville and Gragg fields. This extremely complex geology requires an ongoing process to develop the best exploitation opportunities. The use of electric imaging logs has enhanced the process of identifying new well locations. In 2003,
80-acre well spacing was approved in the Booneville and Chismville fields and 160-acre well spacing was approved in the Gragg Field. This down-spacing added 100 to 150 potential well locations for both operated and non-operated wells. We drilled 29
wells and completed 11 workovers in this area in 2003. We plan to drill 11 wells in 2004.



Oklahoma Cromwell/Atoka Trend



The Oklahoma Cromwell/Atoka trend of southeastern Oklahoma was originally developed in the 1970s targeting the Cromwell sandstones, with the Atoka and Wapanuka limestones as secondary objectives. Development activities were concentrated in
the Ashland and South Pine Hollow fields where 18 wells were drilled and four workovers were performed in 2003. In 2004, we plan to drill five wells in this area.



Hugoton Royalty Trust Areas



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



Mid-Continent Area



XTO is one of the largest producers in the Major and Woodward counties, Oklahoma area of the Anadarko Basin. We operate 576 gross (490.7 net) wells and
have an interest in 138 gross (36.8 net) wells operated by others. Oil and gas were first discovered in the Major County area in 1945. The fields in the Major and Woodward counties area are characterized by oil and gas production from a variety of
structural and stratigraphic traps. Productive zones range from 6,500 to 9,400 feet and include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations.



Development in the Major County area focuses on mechanical improvements,
restimulations and recompletions to shallower zones and development drilling. During 2003, we participated in the drilling of four gross (3.2 net) wells in the northwestern portion of the county, targeting the Mississippian formation. We plan to
drill seven wells and perform ten workovers in Major County during 2004. We were also very active in Woodward County, Oklahoma, where 12 gross (9.8 net) wells were drilled which targeted the Chester formation. In 2004, we plan to drill up to five
wells and to perform as many as five workovers.



We operate a
gathering system and pipeline in the Major County area. The gathering system collects gas from over 400 wells through 300 miles of pipeline in the Major County area. The gathering system has current throughput of approximately 16,800 Mcf per day,
70% of which is produced from Company-operated wells. Estimated capacity of



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##### Index to Financial Statements

the gathering system is 35,000 Mcf per day. Gas is delivered to a processing plant owned and operated by a third party, and then transmitted by an operated
residue pipeline to a connection with an interstate pipeline.



Hugoton Area



The Hugoton Field, discovered in
1922, covers parts of Texas, Oklahoma and Kansas and is one of the largest gas fields in North America with an estimated five million productive acres. XTO owns an interest in 372 gross (349.5 net) wells that we operate and 78 gross (18.8 net) wells
operated by others. During 2003, we continued our restimulation program in the Chase intervals by completing 37 restimulations. We plan to perform 35 Chase restimulations during 2004.



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



Green
River Basin



The Green River Basin is located in
southwestern Wyoming. We have interests in 188 gross (186.5 net) wells that we operate and 34 gross (4.2 net) wells operated by others in the Fontenelle Field area. Gas production began in the Fontenelle area in the early 1970s and the producing
reservoirs are the Cretaceous-aged Frontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000 feet. Development potential for the fields in this area include deepening and opening new producing zones in existing wells, drilling
new wells and adding compression to lower line pressures. During 2003, we drilled six gross (6.0 net) wells and performed 11 workovers. During 2004, we plan to perform seven workovers and drill up to seven wells in the Green River Basin.



Permian Basin Area



University Block 9. The University Block 9 Field is located in
Andrews County, Texas and was discovered in 1953. We own interests in 82 gross (76.3 net) operated wells. Productive zones are of Wolfcamp, Pennsylvanian and Devonian age and range from 8,400 to 10,000 feet. Development potential includes proper
wellbore utilization, recompletions, infill drilling and improvement of waterflood efficiency.



Development in 2003 focused on the Devonian, Grayburg and Wolfcamp formations, where XTO drilled six wells. We also discovered a new shallow Grayburg producing interval. During 2004, we plan to drill up to six wells.



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



We operate the Prentice Northeast Unit, where we have a 91.6% working
interest in 212 wells. We also own an interest in 71 gross (2.9 net) nonoperated wells. During 2003, we continued our 10-acre development drilling program by drilling 14 gross (12.8 net) vertical wells in the Prentice Field. During 2004, we plan to
continue our expansion of the potential infill area by drilling as many as ten wells.



Wasson Field. The Wasson Field, discovered in 1936, is located in Gaines and Yoakum counties, Texas and produces from the San Andres formation at depths ranging from 4,500 to 6,300 feet. The Cornell Unit was
formed in 1965 and has development potential that exists through infill drilling and improvement of waterflood efficiency. We have a 68.4% working interest in the unit. In 2003, we drilled four 10-acre infill oil wells and eight gas cap wells, and
in 2004 we plan to drill four oil wells and five gas cap wells in this area.



Alaska Cook Inlet Area



In September
1998, we acquired a 100% working interest in two State of Alaska leases and the offshore installations in the Middle Ground Shoal Field of the Cook Inlet. The properties included 27 wells, two operated



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##### Index to Financial Statements

production platforms set in 70 feet of water about seven miles offshore, and a 50% interest in certain operated production pipelines and onshore processing
facilities.



Oil was discovered in the Cook Inlet in 1966 and,
to date, more than 130 million Bbls have been produced from the Middle Ground Shoal Field. The field is separated into East and West flanks by a crestal fault. Waterflooding of the East Flank has been successful, but the West Flank has not been
fully developed or efficiently waterflooded. Production is primarily from multiple zones within the Miocene-Oligocene-aged Tyonek formation between 7,000 feet and 10,000 feet subsea. We plan to drill up to two East Flank wells in 2004.



Reserves



Definitions of terms used in the following disclosures of oil and natural gas reserves include:



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 - Also
referred to herein as standardized measure of discounted future net cash flows or standardized measure. Computational result of discounting estimated future net revenues at a rate of 10% annually.



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The following are estimated quantities of proved reserves and related cash flows as of December 31, 2003,
2002 and 2001:



|                                                                     |  |             |            |      |   |            |  |   |          
|-------------------------------------------------------------------- |  | ----------- | ---------- | ---- | - | ---------- |  | - | ---------
|                                                                     |  | December 31
|(in thousands)                                                       |  | 2003        |            | 2002 |   | 2001      
|Proved developed:                                                    |  |             |            |      |   |            |  |   |          
|Gas (Mcf)                                                            |  |             | 2,651,259  |      |   | 2,042,661  |  |   | 1,452,222
|Natural gas liquids (Bbls)                                           |  |             | 28,187     |      |   | 19,367     |  |   | 14,774   
|Oil (Bbls)                                                           |  |             | 47,882     |      |   | 47,178     |  |   | 41,231   
|Mcfe                                                                 |  |             | 3,107,673  |      |   | 2,441,931  |  |   | 1,788,252
|Proved undeveloped:                                                  |  |             |            |      |   |            |  |   |          
|Gas (Mcf)                                                            |  |             | 992,980    |      |   | 838,520    |  |   | 783,256  
|Natural gas liquids (Bbls)                                           |  |             | 6,491      |      |   | 6,066      |  |   | 5,525    
|Oil (Bbls)                                                           |  |             | 7,549      |      |   | 9,171      |  |   | 12,818   
|Mcfe                                                                 |  |             | 1,077,220  |      |   | 929,942    |  |   | 893,314  
|Total proved:                                                        |  |             |            |      |   |            |  |   |          
|Gas (Mcf)                                                            |  |             | 3,644,239  |      |   | 2,881,181  |  |   | 2,235,478
|Natural gas liquids (Bbls)                                           |  |             | 34,678     |      |   | 25,433     |  |   | 20,299   
|Oil (Bbls)                                                           |  |             | 55,431     |      |   | 56,349     |  |   | 54,049   
|Mcfe                                                                 |  |             | 4,184,893  |      |   | 3,371,873  |  |   | 2,681,566
|Estimated future net cash flows:                                     |  |             |            |      |   |            |  |   |          
|Before income tax                                                    |  | $           | 17,130,056 |      | $ | 10,528,450 |  | $ | 3,756,602
|After income tax                                                     |  | $           | 11,837,447 |      | $ | 7,384,215  |  | $ | 2,876,728
|Present value of estimated future net cash flows, discounted at 10%: |  |             |            |      |   |            |  |   |          
|Before income tax                                                    |  | $           | 8,820,161  |      | $ | 5,461,298  |  | $ | 1,947,441
|After income tax                                                     |  | $           | 6,128,239  |      | $ | 3,873,585  |  | $ | 1,522,049



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, 2003, 2002 and 2001. 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. Year-end 2003 average realized prices used in the
estimation of proved reserves were $5.71 per Mcf for gas, $23.17 per Bbl for natural gas liquids and $30.55 per Bbl for oil. See Note 16 to Consolidated Financial Statements for additional information regarding estimated proved reserves.



Estimated future net cash flows, and the related 10% discounted present
value, of year-end 2003 proved reserves are significantly higher than at year-end 2002 because of increased reserves related to acquisitions and development and higher product prices used in the estimation of year-end proved reserves. Year-end 2002
product prices were $4.41 per Mcf for gas, $17.86 per Bbl for natural gas liquids and $29.69 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 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 2003, we filed estimates of oil and gas reserves as of December 31, 2002 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, 2002 in Note 16 to Consolidated Financial Statements, with the exception that Form EIA-23 includes only reserves from properties that we operate.



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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, 2003, all
of which are located in the United States:



|      |  |                |  |                  |  |           |  |       |  |        |  |        
|----- |  | -------------- |  | ---------------- |  | --------- |  | ----- |  | ------ |  | -------
|      |  | Operated Wells |  | NonoperatedWells |  | Total (a)
|      |  | Gross          |  | Net              |  | Gross     |  | Net   |  | Gross  |  | Net    
|Gas   |  | 5,165          |  | 4,424.0          |  | 3,451     |  | 519.4 |  | 8,616  |  | 4,943.4
|Oil   |  | 611            |  | 538.1            |  | 2,137     |  | 152.1 |  | 2,748  |  | 690.2  
|      |  |                |  |                  |  |           |  |       |  |        |  |        
|Total |  | 5,776          |  | 4,962.1          |  | 5,588     |  | 671.5 |  | 11,364 |  | 5,633.6
|      |  |                |  |                  |  |           |  |       |  |        |  |        

---

|(a) | 570.0 gross (329.0 net) gas wells and 1.0 gross (1.0 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, 2003, we were in the process of drilling 122 gross (61.0 net) wells.



|                   |  |                        |  |       |  |       |  |       |  |       |  |      
|------------------ |  | ---------------------- |  | ----- |  | ----- |  | ----- |  | ----- |  | -----
|                   |  | Year Ended December 31
|                   |  | 2003                   |  | 2002  |  | 2001 
|                   |  | Gross                  |  | Net   |  | Gross |  | Net   |  | Gross |  | Net  
|Development wells: |  |                        |  |       |  |       |  |       |  |       |  |      
|Completed as-      |  |                        |  |       |  |       |  |       |  |       |  |      
|Gas wells          |  | 390                    |  | 289.5 |  | 303   |  | 227.2 |  | 282   |  | 200.3
|Oil wells          |  | 42                     |  | 30.0  |  | 27    |  | 15.5  |  | 85    |  | 33.0 
|Non-productive     |  | 7                      |  | 3.0   |  | 13    |  | 5.9   |  | 15    |  | 5.9  
|                   |  |                        |  |       |  |       |  |       |  |       |  |      
|Total              |  | 439                    |  | 322.5 |  | 343   |  | 248.6 |  | 382   |  | 239.2
|                   |  |                        |  |       |  |       |  |       |  |       |  |      
|Exploratory wells: |  |                        |  |       |  |       |  |       |  |       |  |      
|Completed as-      |  |                        |  |       |  |       |  |       |  |       |  |      
|Gas wells          |  | 12                     |  | 10.2  |  |      |  |      |  | 4     |  | 2.3  
|Oil wells          |  |                       |  |      |  |      |  |      |  | 1     |  | 0.5  
|Non-productive     |  |                       |  |      |  | 3     |  | 1.5   |  | 2     |  | 1.8  
|                   |  |                        |  |       |  |       |  |       |  |       |  |      
|Total              |  | 12                     |  | 10.2  |  | 3     |  | 1.5   |  | 7     |  | 4.6  
|                   |  |                        |  |       |  |       |  |       |  |       |  |      
|Total (a)          |  | 451                    |  | 332.7 |  | 346   |  | 250.1 |  | 389   |  | 243.8
|                   |  |                        |  |       |  |       |  |       |  |       |  |      

---

|(a) | Included in totals are 102 gross (17.66 net) wells in 2003,
75 gross (11.2 net) wells in 2002 and 125 gross (16.5 net) wells in 2001 drilled on nonoperated interests.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Acreage



The following table summarizes developed and undeveloped leasehold acreage in which we own a working interest as of December 31, 2003. 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   
|Arkansas   |  | 525,470                |  | 232,290           |  | 28,240  |  | 20,547
|Oklahoma   |  | 471,275                |  | 329,506           |  | 16,766  |  | 7,979 
|Texas      |  | 354,901                |  | 227,980           |  | 69,532  |  | 53,071
|New Mexico |  | 313,540                |  | 194,061           |  | 19,715  |  | 17,446
|Kansas     |  | 211,253                |  | 167,245           |  |        |  |      
|Colorado   |  | 107,900                |  | 83,875            |  |        |  |      
|Louisiana  |  | 55,733                 |  | 28,034            |  |        |  |      
|Wyoming    |  | 45,007                 |  | 30,241            |  | 572     |  | 315   
|Other      |  | 10,038                 |  | 9,173             |  |        |  |      
|           |  |                        |  |                   |  |         |  |       
|Total      |  | 2,095,117              |  | 1,302,405         |  | 134,825 |  | 99,358
|           |  |                        |  |                   |  |         |  |       

---

|(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
|                                                 |  | 2003                   |       | 2002 |   | 2001 
|Sales prices:                                    |  |                        |       |      |   |       |  |   |      
|Gas (per Mcf)                                    |  | $                      | 4.07  |      | $ | 3.49  |  | $ | 4.51 
|Natural gas liquids (per Bbl)                    |  | $                      | 19.99 |      | $ | 14.31 |  | $ | 15.41
|Oil (per Bbl)                                    |  | $                      | 28.59 |      | $ | 24.24 |  | $ | 23.49
|Production expense per Mcfe                      |  | $                      | 0.58  |      | $ | 0.57  |  | $ | 0.57 
|Taxes, transportation and other expense per Mcfe |  | $                      | 0.37  |      | $ | 0.25  |  | $ | 0.33 



Delivery Commitments



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



The Companys production and reserves are adequate to meet the above delivery commitments.



Competition and Markets



We face competition from other oil and gas companies in all aspects of our business, including acquisition of producing
properties and oil and gas leases, marketing of oil and gas, and obtaining goods, services and labor. Many of our competitors have substantially larger financial and other resources. Factors that affect XTOs ability to acquire producing
properties include available funds, available information about the property and our standards established



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##### Index to Financial Statements

for minimum projected return on investment. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore,
competition for natural gas delivery is presented by other pipelines and gathering systems. Competition is also presented by alternative fuel sources, including heating oil, imported liquified natural gas and other fossil fuels. Because of the
long-lived, high margin nature of our oil and gas reserves and managements experience and expertise in exploiting these reserves, management believes that it effectively competes in the market.



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



Decreases in oil and gas prices have had and could
have in the future an adverse effect on our acquisition and development programs, proved reserves, revenues, profitability, cash flow and dividends. See Part II, Item 7, Managements Discussion and Analysis of Financial Condition and Results of
Operations, 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, Congress is currently considering a new energy bill. The potential effect of this
legislation is unknown, but it is expected to include certain tax incentives for oil and gas producers.



Federal Regulation of Natural Gas



The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates charged and various other matters, by the Federal Energy Regulatory Commission. Federal
wellhead price controls on all domestic gas were terminated on January 1, 1993, and none of our gathering systems are currently subject to FERC regulation. We cannot predict the impact of future government regulation on any natural gas facilities.



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



Federal Regulation of Oil



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



State Regulation



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



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



Federal, State or Native American Leases



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



Environmental Regulations



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



Employees



We had 1,007
employees as of December 31, 2003. None of the employees are represented by a union. We consider our relations with our employees to be good.



Executive Officers of the Company



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



Bob R. Simpson, 55, was a co-founder of XTO with Mr. Palko and has
been Chairman and Chief Executive Officer of the Company since July 1, 1996. Prior thereto, Mr. Simpson served as Vice Chairman and Chief Executive Officer or held similar positions with the Company since 1986. Mr. Simpson was Vice President of
Finance and Corporate Development (1979-1986) and Tax Manager (1976-1979) of Southland Royalty Company.



Steffen E. Palko, 53, was a co-founder of XTO with Mr. Simpson and has been Vice Chairman and President or held similar positions with the Company
since 1986. Mr. Palko was Vice President - Reservoir Engineering (1984-1986) and Manager of Reservoir Engineering (1982-1984) of Southland Royalty Company.



Louis G. Baldwin, 54, 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, 45, 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.



15



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##### Table of Contents

##### Index to Financial Statements

Vaughn O. Vennerberg II, 49, 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, 53, 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 against us and certain of our subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The
plaintiff alleges that we underpaid royalties on gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% during at least the past 10 years as a result of mismeasuring the volume of gas and incorrectly
analyzing its heating content. The plaintiff also alleges that we have failed to pay the fair market value of the carbon dioxide produced. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty
of $5,000 to $10,000 for each violation and attorney fees and expenses. The plaintiff also seeks an order for us to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene
and asked the court to unseal the case. The court unsealed the case in May 1999. A multi-district litigation panel ordered that the lawsuits against us and other companies filed by Grynberg be transferred and consolidated to the federal district
court in Wyoming. We believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in
our financial statements.



In June 2001, we were served with a
lawsuit styled Price, et al. v. Gas Pipelines, et al.(formerly Quinque case). The action was filed in the District Court of Stevens County, Kansas, against us and one of our subsidiaries, along with over 200 natural gas transmission
companies, producers, gatherers and processors of natural gas. Plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the
defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims
to cover all oil and gas leases (other than the Federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas
delivered into their pipelines resulting in underpayments to the plaintiffs. Plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of
Kansas statutes and other common law causes of action. The amount of damages was not specified in the complaint. In February 2002, we, 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. 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 as to gas measured in Kansas, Colorado and Wyoming. We believe that the allegations of this lawsuit are without merit and intend to vigorously defend the
action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.



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. 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, which 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 as to gas measured in Kansas, Colorado and Wyoming. The amount of damages was not specified in the complaint. We believe that the allegations of this lawsuit are
without merit and intend to vigorously defend the



16



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##### Table of Contents

##### Index to Financial Statements

action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.



On April 3, 1998, a class action lawsuit, styled Booth, et
al. v. Cross Timbers Oil Company, was filed against us in the District Court of Dewey County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well
within the State of Oklahoma under which we have assumed the obligation to pay royalties. The plaintiffs alleged that we reduced royalty payments by post-production deductions and entered into contracts with subsidiaries that were not
arms-length transactions. The plaintiffs further alleged that these actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions were a breach of the leases under which the royalties are paid. In
July 2003, we paid $2.5 million to settle the plaintiffs claims for the period January 1, 1993 through June 30, 2002. Our portion of this liability, net of amounts allocable to Hugoton Royalty Trust units we do not own, was $2.1 million, which
had been accrued in our financial statements.



In February
2000, the Department of Interior notified us and several other producers that certain Native American leases located in the San Juan Basin had expired because of the failure of the leases to produce in paying quantities from February through August
1990. The Department of Interior demanded abandonment of the property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. In January 2004, the Department of
Interior withdrew its claim against us.



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



No matters were submitted for a vote of security holders during the fourth quarter of 2003.



17



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##### Table of Contents

##### Index to Financial Statements

PART II



|Item 5. | MARKET FOR REGISTRANTS COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS
|------- | ---------------------------------------------------------------------



Our common stock is listed on the New York Stock Exchange and trades under the symbol XTO. The following table sets forth quarterly high and
low sales prices and cash dividends declared for each quarter of 2003 and 2002 (as adjusted for the five-for-four stock split to be effected on March 17, 2004, and the four-for-three stock split effected on March 18, 2003):



|               |  |      |        |     |   |              |  |   |        |    
|-------------- |  | ---- | ------ | --- | - | ------------ |  | - | ------ | ---
|               |  | High |        | Low |   | CashDividend | 
|2003           |  |      |        |     |   |              |  |   |        |    
|First Quarter  |  | $    | 15.888 |     | $ | 13.614       |  | $ | 0.0080 |    
|Second Quarter |  |      | 17.992 |     |   | 14.560       |  |   | 0.0080 |    
|Third Quarter  |  |      | 17.136 |     |   | 14.864       |  |   | 0.0080 | (a)
|Fourth Quarter |  |      | 23.440 |     |   | 16.744       |  |   | 0.0080 |    
|               |  |      |       
|2002           |  |      |        |     |   |              |  |   |        |    
|First Quarter  |  | $    | 12.150 |     | $ | 8.814        |  | $ | 0.0060 |    
|Second Quarter |  |      | 12.930 |     |   | 11.010       |  |   | 0.0060 |    
|Third Quarter  |  |      | 12.594 |     |   | 9.210        |  |   | 0.0060 |    
|Fourth Quarter |  |      | 15.834 |     |   | 12.072       |  |   | 0.0060 |    



|(a) | In September 2003, we distributed as a dividend to our shareholders all of our Cross Timbers Royalty Trust units. This dividend was recorded at a market value of
$28.2 million, or approximately $0.12 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 Companys Board of Directors and will depend on our financial condition, earnings and funds from operations, the
level of our capital expenditures, dividend restrictions in our financing agreements, our future business prospects and other matters as the Board of Directors deems relevant. Although there is a cumulative maximum restriction on distributions to
common stockholders under our 71⁄2% senior note and 61⁄4% senior note covenants, because of retained and projected future earnings, we do not anticipate these restrictions will affect future dividend payments.



On February 17, 2004, the Board of Directors declared a five-for-four stock
split to be effected on March 17, 2004, as well as a quarterly dividend of $0.01 per share payable on April 15, 2004 to stockholders of record on March 31, 2004. Because of the five-for-four stock split, this represents a 25% increase in our
dividend rate. On March 1, 2004, we had 807 stockholders of record.



18



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##### Table of Contents

##### Index to Financial Statements

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



The following table shows selected financial information for the five years
ended December 31, 2003. 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 five-for-four stock split to be effected on March 17, 2004, the four-for-three stock split effected March 18, 2003 and the three-for-two stock splits
effected in September 2000 and June 2001. This information should be read in conjunction with Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements at Item 15(a).



(in thousands except production, per share and per unit data)



|                                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|-------------------------------------------------- |  | ---- | ---------- | --- | ---- | - | --------- | ---- |  | - | --------- | --- |  | ---- | --------- | --- |  | - | --------- | ---
|                                                   |  | 2003 |            |     | 2002 |   |           | 2001 |  |   | 2000      |     |  | 1999 |          
|Consolidated Income Statement Data                 |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Revenues:                                          |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Gas and natural gas liquids                        |  | $    | 1,040,370  |     |      | $ | 681,147   |      |  | $ | 710,348   |     |  | $    | 456,814   |     |  | $ | 239,056   |    
|Oil and condensate                                 |  |      | 135,058    |     |      |   | 115,324   |      |  |   | 116,939   |     |  |      | 128,194   |     |  |   | 86,604    |    
|Gas gathering, processing and marketing            |  |      | 12,982     |     |      |   | 11,622    |      |  |   | 12,832    |     |  |      | 16,123    |     |  |   | 10,644    |    
|Other                                              |  |      | 1,145      |     |      |   | 2,070     |      |  |   | (1,371    | )   |  |      | (280      | )   |  |   | 4,991     |    
|                                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Total Revenues                                     |  | $    | 1,189,555  |     |      | $ | 810,163   |      |  | $ | 838,748   |     |  | $    | 600,851   |     |  | $ | 341,295   |    
|                                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Earnings available to common stock                 |  | $    | 288,279    | (a) |      | $ | 186,059   | (b)  |  | $ | 248,816   | (c) |  | $    | 115,235   | (d) |  | $ | 44,964    | (e)
|                                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Per common share                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Basic                                              |  | $    | 1.28       | (f) |      | $ | 0.89      |      |  | $ | 1.22      | (g) |  | $    | 0.65      |     |  | $ | 0.26      |    
|                                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Diluted                                            |  | $    | 1.27       | (f) |      | $ | 0.88      |      |  | $ | 1.20      | (g) |  | $    | 0.61      |     |  | $ | 0.24      |    
|                                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Weighted average common shares outstanding         |  |      | 224,749    |     |      |   | 208,375   |      |  |   | 204,176   |     |  |      | 177,884   |     |  |   | 175,569   |    
|                                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Cash dividends declared per common share           |  | $    | 0.0320     | (h) |      | $ | 0.0240    |      |  | $ | 0.0220    |     |  | $    | 0.0134    |     |  | $ | 0.0110    |    
|                                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Consolidated Statement of Cash Flows Data          |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Cash provided (used) by:                           |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Operating activities                               |  | $    | 794,181    |     |      | $ | 490,842   |      |  | $ | 542,615   |     |  | $    | 377,421   |     |  | $ | 133,301   |    
|Investing activities                               |  | $    | (1,135,234 | )   |      | $ | (736,817  | )    |  | $ | (610,923  | )   |  | $    | (133,884  | )   |  | $ | (156,370  | )  
|Financing activities                               |  | $    | 333,094    |     |      | $ | 254,119   |      |  | $ | 67,680    |     |  | $    | (241,833  | )   |  | $ | 16,470    |    
|Consolidated Balance Sheet Data                    |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Property and equipment, net                        |  | $    | 3,312,067  |     |      | $ | 2,370,965 |      |  | $ | 1,841,387 |     |  | $    | 1,357,374 |     |  | $ | 1,339,080 |    
|Total assets                                       |  | $    | 3,611,134  |     |      | $ | 2,648,193 |      |  | $ | 2,132,327 |     |  | $    | 1,591,904 |     |  | $ | 1,477,081 |    
|Long-term debt                                     |  | $    | 1,252,000  |     |      | $ | 1,118,170 |      |  | $ | 856,000   |     |  | $    | 769,000   |     |  | $ | 991,100   |    
|Stockholders equity                               |  | $    | 1,465,642  |     |      | $ | 907,786   |      |  | $ | 821,050   |     |  | $    | 497,367   |     |  | $ | 277,817   |    
|Operating Data                                     |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Average daily production:                          |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Gas (Mcf)                                          |  |      | 668,436    |     |      |   | 513,925   |      |  |   | 416,927   |     |  |      | 343,871   |     |  |   | 288,000   |    
|Natural gas liquids (Bbls)                         |  |      | 6,463      |     |      |   | 5,068     |      |  |   | 4,385     |     |  |      | 4,430     |     |  |   | 3,631     |    
|Oil (Bbls)                                         |  |      | 12,943     |     |      |   | 13,033    |      |  |   | 13,637    |     |  |      | 12,941    |     |  |   | 14,006    |    
|Mcfe                                               |  |      | 784,877    |     |      |   | 622,532   |      |  |   | 525,062   |     |  |      | 448,098   |     |  |   | 393,826   |    
|Average sales price:                               |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Gas (per Mcf)                                      |  | $    | 4.07       |     |      | $ | 3.49      |      |  | $ | 4.51      |     |  | $    | 3.38      |     |  | $ | 2.13      |    
|Natural gas liquids (per Bbl)                      |  | $    | 19.99      |     |      | $ | 14.31     |      |  | $ | 15.41     |     |  | $    | 19.61     |     |  | $ | 11.80     |    
|Oil (per Bbl)                                      |  | $    | 28.59      |     |      | $ | 24.24     |      |  | $ | 23.49     |     |  | $    | 27.07     |     |  | $ | 16.94     |    
|Production expense (per Mcfe)                      |  | $    | 0.58       |     |      | $ | 0.57      |      |  | $ | 0.57      |     |  | $    | 0.53      |     |  | $ | 0.53      |    
|Taxes, transportation and other expense (per Mcfe) |  | $    | 0.37       |     |      | $ | 0.25      |      |  | $ | 0.33      |     |  | $    | 0.35      |     |  | $ | 0.23      |    
|Proved reserves:                                   |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Gas (Mcf)                                          |  |      | 3,644,239  |     |      |   | 2,881,181 |      |  |   | 2,235,478 |     |  |      | 1,769,683 |     |  |   | 1,545,623 |    
|Natural gas liquids (Bbls)                         |  |      | 34,678     |     |      |   | 25,433    |      |  |   | 20,299    |     |  |      | 22,012    |     |  |   | 17,902    |    
|Oil (Bbls)                                         |  |      | 55,431     |     |      |   | 56,349    |      |  |   | 54,049    |     |  |      | 58,445    |     |  |   | 61,603    |    
|Mcfe                                               |  |      | 4,184,893  |     |      |   | 3,371,873 |      |  |   | 2,681,566 |     |  |      | 2,252,425 |     |  |   | 2,022,653 |    
|Other Data                                         |  |      |            |     |      |   |           |      |  |   |           |     |  |      |           |     |  |   |           |    
|Ratio of earnings to fixed charges(i)              |  |      | 6.9        |     |      |   | 5.6       |      |  |   | 7.7       |     |  |      | 2.8       |     |  |   | 1.9       |    



19



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##### Index to Financial Statements

|(a) | Includes pre-tax effects of a derivative fair value loss of
$10.2 million, 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 and 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.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(b) | 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.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(c) | 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.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



|(e) | Includes pre-tax effect of a $40.6 million gain on sale of Hugoton Royalty Trust units.
|--- | ---------------------------------------------------------------------------------------



|(f) | Before cumulative effect of accounting change, earnings per share were $1.27 basic and $1.26 diluted.
|--- | -----------------------------------------------------------------------------------------------------



|(g) | Before cumulative effect of accounting change, earnings per share were $1.44 basic and $1.41 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 $0.12 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.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



20



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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 our 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. All shares and per share data have been adjusted for the five-for-four stock split to be effected on March 17, 2004.



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 2003, XTO Energy achieved the
following record financial and operating results:



| |  | Average daily gas production was 668 million cubic feet, a 30% increase from 2002, and average daily natural gas liquid production was 6,463 barrels, a 28% increase from 2002.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Year-end proved reserves were 4.185 trillion cubic feet of gas equivalent, a 24% increase from year-end 2002.
| | - | -------------------------------------------------------------------------------------------------------------



| |  | Net income was $288.3 million, a 55% increase from 2002, and earnings per basic common share was $1.28, a 44% increase from 2002.
| | - | ---------------------------------------------------------------------------------------------------------------------------------



| |  | Cash flow from operating activities was $794.2 million, a 62% increase from 2002.
| | - | ---------------------------------------------------------------------------------



| |  | Stockholders equity was $1.47 billion, a 61% increase from year-end 2002.
| | - | --------------------------------------------------------------------------



| |  | The debt-to-capitalization ratio was 46% at year-end 2003, down from 55% at year-end 2002.
| | - | ------------------------------------------------------------------------------------------



We achieve production and proved reserve growth generally through producing property acquisitions, followed by development.
Development activities are generally funded by cash flow from operating activities. Funding sources for our acquisitions include proceeds from sales of public 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.



After considering acquisitions announced through February 2004, our goal for 2004 is to increase natural gas production by 18% to 20%. 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 approximately 2,700 potential development drilling locations. Our 2004 acquisition
budget is $650 million, of which $243 million was spent on acquisitions in January 2004. We also entered agreements in February 2004 to acquire properties in April 2004 for $200 million. After considering these acquisitions, our 2004 development
budget is $520 million. We cannot ensure that we will be able to find properties that meet our acquisition criteria and that we can purchase on acceptable terms.



The weak U.S. dollar, raw material shortages and strong demand for steel in China and Europe have tightened worldwide steel
supplies, causing prices to rise by more than 50% since November 2003. In response, we have increased our tubular inventory and are currently negotiating contracts with our vendors to support our development program. Should steel prices continue to
escalate, our development budget could rise by as much as 10%. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting our production growth.



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



21



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##### Index to Financial Statements

operating commitments and development program. As of March 5, 2004, we have hedged approximately half of our 2004 projected gas production at an average
NYMEX price of $4.77 per Mcf. Our average realized price on hedged production will be lower than this average NYMEX price because of location, quality and other adjustments.



The combined effect of higher product prices and a 30% increase in gas production resulted in a 47% increase in total
revenues to $1.19 billion in 2003 from $810.2 million in 2002. On an Mcfe produced basis, total revenues were $4.15 in 2003, a 16% increase from $3.57 in 2002.



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



|                                                                      |  |      |      |      |   |                     |  |    |   
|--------------------------------------------------------------------- |  | ---- | ---- | ---- | - | ------------------- |  | -- | --
|                                                                      |  | 2003 |      | 2002 |   | %Increase(Decrease) | 
|Production                                                            |  | $    | 0.58 |      | $ | 0.57                |  | 2  | % 
|Taxes, transportation and other                                       |  |      | 0.37 |      |   | 0.25                |  | 48 | % 
|Depreciation, depletion and amortization                              |  |      | 0.99 |      |   | 0.90                |  | 10 | % 
|General and administrative, excluding non-cash incentive compensation |  |      | 0.19 |      |   | 0.15                |  | 27 | % 
|Interest                                                              |  |      | 0.22 |      |   | 0.24                |  | (8 | %)
|                                                                      |  |      |      |      |   |                     |  |    |   
|                                                                      |  | $    | 2.35 |      | $ | 2.11                |  |    |   
|                                                                      |  |      |      |      |   |                     |  |    |   



The 48% increase in
taxes, transportation and other expense is primarily because of increased product prices. Depreciation, depletion and amortization increased 10% because of higher acquisition and development costs. The 27% 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:



Non-cash 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. Non-cash incentive compensation was $53.1 million in 2003, a 97% increase from the comparable 2002 expense of $27 million. Increased incentive compensation is because of the 53%
increase in the common stock price during 2003 and the resulting increased value of vested awards. After adjusting for the effect of the April 2003 common stock offering, non-cash incentive compensation was approximately 2.8% of the increase in
market capitalization of outstanding common shares during each of 2003 and 2002. Including non-cash incentive compensation, general and administrative expense increased $45.6 million, or 73%.



Derivative fair value (gain) loss.This is the net realized and
unrealized gain or loss on derivative financial instruments that do not qualify for hedge accounting treatment, and fluctuates based on changes in the fair value of underlying commodities. The derivative fair value loss was $10.2 million in 2003 as
compared with a gain of $2.6 million in 2002. The loss in 2003 is generally related to higher natural gas prices during the year.



Accretion of discount in asset retirement obligation.This expense recognizes the increase, related to the passage of time, in the estimated costs
to abandon and remediate our producing properties at the end of their productive lives. The accretion of discount expense was $5.3 million in 2003, the first year of its recognition since the related accounting pronouncement was adopted January 1,
2003.



Our primary sources of liquidity are cash flow from
operating activities, borrowings under our revolving credit facility with commercial banks and public offerings of equity and debt. In September 2003, Moodys assigned to the Company an SGL-1 liquidity rating, its highest rating. 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



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##### Index to Financial Statements

for our revolving credit facility. As a result, Moodys upgraded our existing senior notes to Ba1 from Ba2 and confirmed our Ba1 senior implied rating.



In February 2004, we entered a new revolving credit facility
with an interest rate based on the London Interbank Offered Rate plus 1% and an initial commitment amount of $800 million which may be increased to $1 billion. As of February 27, 2004, our borrowings under this facility were $169 million. Under the
terms of the agreement, we must maintain a debt-to-capitalization ratio, as adjusted for certain accounting items, of no more than 60%.



Our consolidated financial position and results of operations are significantly affected by our critical accounting policies. We utilize the successful
efforts method of oil and gas accounting, under which we expense the costs of unsuccessful exploratory well costs, as well as exploratory geological and geophysical costs. All acquisition and development 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 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.



Significant Events, Transactions and
Conditions



The following events, transactions and
conditions affect the comparability of results of operations and financial condition for the years ended December 31, 2003, 2002 and 2001 and may impact future operations and financial condition.



Acquisitions. We acquired primarily gas-producing properties at a total cost of $629.5
million in 2003, $358.1 million in 2002 and $242 million in 2001, which have been 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 more
significant acquisitions:



|             |  |          |  |                              |  |                  |  |                                                                                               
|------------ |  | -------- |  | ---------------------------- |  | ---------------- |  | ----------------------------------------------------------------------------------------------
|Closing Date |  | Seller   |  | Amount(in millions)          |  | Acquisition Area
|2003         |  | May      |  | Williams of Tulsa, Oklahoma  |  | $381             |  | Raton Basin of Colorado, Hugoton field of southwestern Kansas and San Juan Basin of New Mexico
|             |  | 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                                                                    
|2001         |  | January  |  | Herd Producing Company, Inc. |  | 115              |  | East Texas and Louisiana                                                                      
|             |  | February |  | Miller Energy, Inc.          |  | 45               |  | East Texas                                                                                    



In January 2004, we
acquired from multiple parties producing properties located primarily in East Texas and northern Louisiana for $243 million. In February 2004, we entered definitive agreements with multiple parties to acquire producing properties located primarily
in the Barnett Shale of North Texas and in the Arkoma Basin for $200 million, with an expected closing date of April 2004. See Note 13 to Consolidated Financial Statements.



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##### Index to Financial Statements

2003, 2002 and 2001 Development and Exploration Programs. Gas development focused on the East Texas area and the
Arkoma and San Juan basins during 2003, 2002 and 2001. Oil development was concentrated in Alaska and in the University Block 9 Field during all three years. Development costs totaled $460.2 million in 2003, $354.1 million in 2002 and $385.5 million
in 2001. Exploration activity has been primarily geological and geophysical analysis, including seismic studies, of undeveloped properties. Exploratory expenditures were $1.8 million is 2003, $2.2 million in 2002 and $5.4 million in 2001.
Exploration expense for 2001 includes dry hole expense of $2.2 million. Our development and exploration activities are generally funded by cash flow from operating activities.



2004 Acquisition, Development and Exploration Program. We have budgeted $1.17 billion for our 2004 development and acquisition
programs, which is expected to be substantially funded by cash flow from operations. We plan to allocate $650 million of the 2004 capital budget to acquisitions, including $243 million of acquisitions in January 2004 and $200 million expected to
close in April 2004. The remaining $520 million is to fund development and exploration projects, approximately 5% of which will be used for exploration. The cost of 2004 property acquisitions may alter the amount currently budgeted for development
and exploration. Also, because of recent worldwide steel shortages, our development budget may be increased by as much as 10%. The total capital budget, including acquisitions, will be adjusted throughout 2004 to focus on opportunities offering the
highest rates of return.



As of December 31, 2003, we have an inventory of
approximately 2,700 potential drilling locations. We plan to drill about 420 (336 net) development wells and perform approximately 350 (251 net) workovers and recompletions in 2004. 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. Gas prices were at record highs at the beginning of 2001 because of gas supplies strained by winter weather. Throughout the remainder of 2001, prices
declined because of fuel switching related to higher prices, milder weather and reduced demand from a weaker economy. 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. With colder than normal weather, record low gas storage levels and continued
increasing demand, gas prices remained 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. Prices in 2004 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)                                      |  | 2003                   |      | 2002 |   | 2001
|Average NYMEX price                            |  | $                      | 5.39 |      | $ | 3.22 |  | $ | 4.27
|Average realized sales price                   |  | $                      | 4.07 |      | $ | 3.49 |  | $ | 4.51
|Average realized sales price excluding hedging |  | $                      | 4.86 |      | $ | 2.98 |  | $ | 3.87



At March 5, 2004, the
average NYMEX gas price for the following 12 months was $5.71 per MMBtu. As computed on an energy equivalent basis, our proved reserves were 87% natural gas at December 31, 2003. After considering hedges in place as of March 5, 2004, we estimate
that a $0.10 per Mcf increase or decrease in the average gas sales price would result in a $12.2 million change in 2004 annual operating cash flow.



Oil. Crude oil prices are generally determined by global supply and demand. After beginning 2001 relatively strong, oil prices declined through the
remainder of the year and in 2002 because of lagging demand caused by a global recession. Rising uncertainties in the Middle East and OPEC production discipline led to higher prices late in 2002. OPEC members agreed to increase daily oil production
1.5 million barrels beginning February 2003, to help stabilize



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##### Index to Financial Statements

a volatile world market. Oil prices remained relatively high in 2003, however, because of the war in Iraq, slower than anticipated resumption of Iraqi oil
exports and unusually low storage levels. OPEC reiterated its intent to maintain oil prices by reducing daily oil production by 2 million barrels beginning June 2003 and by an additional 900,000 barrels beginning November 2003. In January 2004, a
combination of below normal temperatures and low U.S. oil supplies led oil prices to ten-month highs, reaching $36 per Bbl. Despite increasing demand, OPEC members agreed to reduce daily oil production by one million barrels beginning April 2004 to
maintain market balance in the seasonally low demand second quarter. 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)                                      |  | 2003                   |       | 2002 |   | 2001 
|Average NYMEX price                            |  | $                      | 31.08 |      | $ | 26.10 |  | $ | 26.00
|Average realized sales price                   |  | $                      | 28.59 |      | $ | 24.24 |  | $ | 23.49
|Average realized sales price excluding hedging |  | $                      | 29.40 |      | $ | 24.52 |  | $ | 23.49



At March 5, 2004, the
average NYMEX oil price for the following 12 months was $33.90 per Bbl. We estimate that a $1.00 per barrel increase or decrease in the average oil sales price would result in approximately a $4.4 million change in 2004 annual operating cash flow.



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 at commodity prices management deems attractive. While there is a risk we
may not be able to realize the benefit of rising prices, management plans to continue its hedging strategy because of the benefits of more predictable production growth and cash flows.



In 2003, all hedging activities decreased gas revenue by $193 million and decreased oil revenue by $3.9 million, while in
2002, hedging activities increased gas revenue by $95.4 million and decreased oil revenue by $1.3 million. All hedging activities increased gas revenue by $97 million in 2001.



The following summarizes our January 2004 through December 2005 natural gas NYMEX hedging positions at March 5, 2004,
excluding basis adjustments which have been separately hedged. As of February 2004, our daily gas production was approximately 774,000 Mcf. 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 Contractsand Swap Agreements
|Production Period        |  | Mcf perDay                           |  | AverageNYMEX Priceper Mcf
|2004 January to June     |  | 380,000                              |  | $                         | 4.77
|July to December         |  | 400,000                              |  | $                         | 4.77
|2005 January to December |  | 100,000                              |  | $                         | 5.21



Cumulative Effect of Accounting
Change for Derivatives. On January 1, 2001, we adopted Statement of Financial Accounting Standards (SFAS) No. 133 by recording a one-time after-tax charge of $44.6 million in the income statement for the cumulative effect of a change in
accounting principle and an unrealized loss of $67.3 million in accumulated other comprehensive income, which is an element of stockholders equity. The unrealized loss was related to the derivative fair value of cash flow hedges. The charge to
the income statement was primarily related to our gas physical delivery contract with crude oil-based pricing.



Derivative Fair Value Gain/Loss.We record in our income statements realized and unrealized derivative fair value gains and losses related to derivatives that do not qualify for hedge accounting, as well as the
ineffective portion of hedge derivatives. We recorded a $10.2 million loss in 2003, a $2.6 million gain in 2002 and a $54.4 million gain in 2001 related to changes in fair value of these non-hedge derivatives. The 2001 gain includes $29.5 million
related to the change in fair value of call options that we sold in 1999 as part of our hedging activities. Because written call options do not



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##### Index to Financial Statements

provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. Most of the remaining gain in 2001 is related to the
change in fair value of a gas physical delivery contract with crude oil-based pricing, the loss on which was initially recorded in the cumulative effect of accounting change for derivatives.



Unrealized derivative gains and losses associated with effective cash flow
hedges are recorded in accumulated other comprehensive income. At December 31, 2003, we have an unrealized pre-tax loss of $81.9 million in accumulated other comprehensive income related to the fair value of derivatives designated as cash flow
hedges of gas price risk. Based on December 31 mark-to-market prices, $81.4 million of this fair value loss is expected to be reclassified into earnings through December 2004. The actual reclassification to earnings will be based on mark-to-market
prices at contract settlement date.



Non-Cash Incentive Compensation.
Incentive compensation generally results from vesting of performance share awards as our common stock price increases. Non-cash incentive compensation totaled $53.1 million in 2003, $27 million in 2002 and $9.6 million in 2001, which relates to
increases in our stock price of 53% in 2003 and 41% in 2002. After adjusting for the effects of the April 2003 common stock offering, non-cash incentive compensation was approximately 2.8% of the increase in market capitalization of outstanding
common shares during each of 2003 and 2002. As of December 31, 2003, outstanding performance shares comprise 250,000 shares that vest when the common stock price reaches $23.86, 296,000 shares that vest when the common stock prices reaches $24.00,
275,000 shares that vest when the common stock price reaches $26.00 and 275,000 shares that vest when the common stock price reaches $28.00. As of March 2, 2004, the common stock price reached a high of $26.00, resulting in vesting of 821,000
performance shares outstanding at year end 2003, as well as 500,000 additional shares that were granted in February and March 2004 with vesting at $24.86 and $25.86. Total non-cash incentive compensation related to 2004 vesting of performance shares
through March 2 was $32.9 million. In March 2004, an additional 250,000 shares were granted that vest when the common stock price reaches $26.86.



Cross Timbers Royalty Trust Distribution. In August 2003, our Board of Directors declared a dividend of 0.0059 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 $0.12 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. As of December 31, 2003, our recorded asset retirement obligation was $93.4 million, after considering the liability incurred for wells
drilled and acquired and discount accretion during 2003.



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.



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##### Index to Financial Statements

Liquidity and Investment Grade Ratings. In September 2003, Moodys assigned the Company an SGL-1 liquidity
rating, its highest rating. In January 2004, Standard & Poors upgraded our corporate credit rating to investment grade. At that time, all liens on producing properties and other collateral were irrevocably released as security for our revolving
credit agreement with commercial banks. Also in January 2004, Moodys upgraded our existing senior notes to Ba1 from Ba2 and confirmed our Ba1 senior implied rating.



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. 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 sold 17.3 million
shares of common stock 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.



Results of Operations



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 fair value loss on certain derivatives that do not
qualify for hedge accounting, 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 on certain derivatives that do not qualify for hedge accounting.



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 is 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. Excluding derivative fair value (gain) loss, expenses for 2003 totaled $677.7 million, or 46% above total expenses of
$463.9 million for 2002. 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 to $0.58 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 to $0.37 primarily due to higher product prices.



Depreciation, depletion and amortization (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.



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##### Index to Financial Statements

General and administrative expense increased $45.6 million, or 73%, because of an increase of $26.1
million in non-cash incentive compensation and increased expenses from Company growth. Excluding 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 primarily related to the redemption of our 91⁄4% senior subordinated notes. 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. See Notes 3 and 14 to Consolidated Financial Statements.



2002 Compared to 2001



For the year 2002, net income was $186.1 million compared with net income of
$248.8 million for 2001. Earnings for 2002 include the net after-tax effects of non-cash incentive compensation of $17.5 million, loss on extinguishment of debt of $5.5 million, gain on settlement with Enron of $1.3 million and a $1.7 million fair
value gain on derivatives that do not qualify for hedge accounting. The 2001 earnings include a $44.6 million after-tax charge for adoption of the derivative accounting principle, SFAS No. 133, an after-tax derivative fair value gain of $35.3
million and a $6.4 million after-tax charge for incentive compensation and loss on sale of properties.



Revenues for 2002 were $810.2 million, or 3% lower than 2001 revenues of $838.7 million. Gas and natural gas liquids revenue decreased $29.2 million, or
4%, because of a 23% decrease in gas prices from an average of $4.51 per Mcf in 2001 to $3.49 in 2002 and a 7% decrease in natural gas liquids prices from an average price of $15.41 per Bbl in 2001 to $14.31 in 2002 (see Significant Events,
Transactions and Conditions  Product Prices  Gas above). These decreases were largely offset by a 23% increase in gas production and a 16% increase in natural gas liquids production. Increased production was attributable to the
2002 development program.



Oil revenue decreased $1.6 million,
or 1%, because of a 4% decrease in oil production, partially offset by a 3% increase in oil prices from an average of $23.49 per Bbl in 2001 to $24.24 in 2002 (see Significant Events, Transactions and Conditions  Product Prices 
Oil above). Decreased production is the result of natural decline, partially offset by development.



Gas gathering, processing and marketing revenues decreased $1.2 million primarily because of lower natural gas liquids prices and lower margins. Other
revenues of $2.1 million in 2002 represent the gain on the Enron settlement.



Expenses for 2002 totaled $461.3 million as compared with total 2001 expenses of $327.8 million. Excluding derivative fair value (gain) loss, expenses for 2002 totaled $463.9 million, or 21% above total expenses of
$382.2 million for 2001. Most expenses increased in 2002 because of increased production from acquisitions and development.



Production expense increased $19.2 million, or 17%, because of higher production related to acquisitions and development. Production expense per Mcfe
remained unchanged at $0.57. Our 2002 exploration expense was $2.2 million compared with the 2001 expense of $5.4 million, which included dry hole costs of $2.2 million.



Taxes, transportation and other decreased 10%, or $6.4 million, primarily because of lower product prices, lower severance
tax rates on new wells in East Texas and lower transportation fuel prices, partially offset by increased property taxes on certain new East Texas wells. With the combined effect of increased production, per Mcfe taxes, transportation and other
decreased 24% from $0.33 to $0.25.



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##### Index to Financial Statements

DD&A increased $49.8 million, or 32%, primarily because of increased production and higher drilling
costs. On an Mcfe basis, DD&A increased from $0.81 in 2001 to $0.90 in 2002.



General and administrative expense increased $22.9 million, or 58%, because of an increase of $17.4 million in non-cash incentive compensation and increased expenses from Company growth. Excluding incentive
compensation, general and administrative expense per Mcfe remained unchanged at $0.15.



The decrease in derivative fair value gain, from $54.4 million in 2001 to $2.6 million in 2002, is primarily because of significant gains related to call options and the Enron Btu swap contract in 2001. See Note 7 to
Consolidated Financial Statements.



Interest expense decreased
$2 million, or 4%, primarily because of an 18% decrease in the weighted average interest rate, partially offset by a 13% increase in weighted average borrowings related to property acquisitions and by decreased capitalized interest. Interest expense
per Mcfe decreased 17% from $0.29 in 2001 to $0.24 in 2002. In 2002, we also recognized an $8.5 million loss on extinguishment of debt related to the redemption of our 91⁄4% senior subordinated notes and a partial purchase and cancellation of our
83⁄4% senior subordinated notes. See Note 3 to Consolidated Financial Statements.



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 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 2004.



Cash provided by operating activities was $794.2 million in 2003, compared with cash provided by operating activities of $490.8 million in 2002 and $542.6
million in 2001. Increased cash provided by operating activities from 2002 to 2003 was primarily because of increased prices and production from acquisitions and development activity, while decreased cash provided by operating activities from 2001
to 2002 was primarily because of decreased prices. Cash flow from operating activities was increased by changes in operating assets and liabilities of $3.7 million in 2003, and was decreased by changes in operating assets and liabilities of $22.9
million in 2002 and $1.5 million in 2001. Changes in operating assets and liabilities are primarily the result of timing of cash receipts and disbursements. Cash flow from operating activities was also reduced by exploration expense of $1.8 million
in 2003, $2.2 million in 2002 and $5.4 million in 2001. Cash flow from operating activities is largely dependent upon the prices received for oil and gas production. We have hedged approximately half of our projected 2004 gas production. See
Product Prices under Significant Events, Transactions and Conditions 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 36% from $2.6 billion at December 31, 2002 to $3.6
billion at December 31, 2003, primarily because of Company growth related to acquisitions and development. As of December 31, 2003, total capitalization was $2.7 billion, of which 46% was long-term debt. Capitalization at December 31, 2002 was $2
billion of which 55% was long-term debt. The decrease in the debt-to-capitalization ratio from year-end 2002 to 2003 is primarily because of our common stock offering in April 2003 and 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



29



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##### Index to Financial Statements

decreased from a negative position of $41.1 million at December 31, 2002 to negative working capital of $59.4 million at December 31, 2003. Excluding the
effects of current derivative and deferred tax current assets and liabilities, working capital decreased $20.1 million. This decrease is because of increased accounts payable and accrued liabilities primarily related to increased production and
drilling liabilities, partially offset by 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 six weeks. Any interim cash needs are funded by
borrowings under our revolving credit agreement.



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. Because of declining credit ratings of some of our customers, we have greater
concentrations of credit with a few large integrated energy companies with investment grade ratings. Financial and commodity-based futures and swap contracts expose us to credit risk of nonperformance by the counterparty to the contracts. This
exposure is diversified among major investment grade financial institutions. Letters of credit or other appropriate forms of security are obtained as considered necessary to limit risk of loss.



Financing



On December 31, 2003, borrowings under the revolving credit agreement with commercial banks were $502 million with unused
borrowing capacity of $298 million. The interest rate of 2.54% at December 31, 2003 is based on the one-month London Interbank Offered Rate (LIBOR) plus 1.375%. In February 2004, we replaced our revolving credit agreement with a new
five-year revolving credit agreement with commercial banks that matures in February 2009. The new agreement provides for an initial commitment amount of $800 million, which may be increased to a maximum of $1 billion, and an interest rate based on
the LIBOR plus 1%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 60%.



In September 2003, Moodys assigned to the Company an SGL-1 liquidity rating, its highest rating. In January 2004, Standard & Poors upgraded our
corporate credit rating to an investment grade and all liens on producing properties and other collateral were irrevocably released as security for our revolving credit facility. As a result, Moodys upgraded our existing senior notes to Ba1
from Ba2 and confirmed our Ba1 senior implied rating. Our Standard & Poors corporate credit rating is BBB- and our Moodys credit rating is Ba1. None of our debt agreements have payment acceleration provisions in the event of a decline in
our credit ratings.



In June 2003, 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 $1 billion, at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including reduction of bank debt. In January 2004, we sold $500 million
of 4.9% senior notes under the shelf agreement, after which $500 million remains available for future sales of securities. See Note 3 to Consolidated Financial Statements.



Capital Expenditures



In 2003, exploration and development cash expenditures totaled $461.6 million compared with $372.7 million in 2002. We have budgeted $520 million for the
2004 development and exploration program. As we have done historically, we expect to fund the 2004 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.



30



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##### Index to Financial Statements

The weak U.S. dollar, raw material shortages and strong demand for steel in China and Europe have
tightened worldwide steel supplies, causing prices to rise by more than 50% since November 2003. In response, we have increased our tubular inventory and are currently negotiating contracts with our vendors to support our development program. Should
steel prices continue to escalate, our development budget could rise by as much as 10%. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting our
production growth.



Our 2004 acquisitions budget is $650
million, including $243 million of acquisitions in January 2004 and $200 million expected to close in April 2004. We plan to fund future 2004 property acquisitions with cash flow from operations and bank or public debt. If our 2004 acquisitions
exceed $650 million, we expect to fund a portion of our acquisitions with publicly placed equity securities. 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 2004. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.



Dividends



The Board of Directors has historically declared quarterly dividends of
$0.01 per outstanding share. As adjusted for stock splits, the Board declared quarterly dividends of $0.004 per common share for the first quarter 2001, $0.006 per common share each quarter for the remainder of 2001 and 2002 and $0.008 per common
share for each quarter of 2003. In August 2003, the Board also declared a dividend of 0.0059 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 $0.12 per common share. In February 2004, the Board of Directors declared a five-for-four stock split to be effected on March 17, 2004, as well as a first quarter 2004 dividend of $0.01 per common share. Because of the five-for-four
stock split, this represents a 25% increase in our dividend rate. Our ability to pay dividends is dependent upon available cash flow, as well as other factors. Although there is a cumulative maximum restriction on distributions to common
stockholders under our 71⁄2% senior note and 61⁄4% senior note covenants, because of retained and projected future earnings, we do not anticipate these restrictions will affect future dividend payments.



Income Taxes



As of December 31, 2003, we had estimated tax loss carryforwards of approximately $242 million, of which $1 million are
related to capital losses. The capital loss carryforwards expire in 2004, while the remaining ordinary loss carryforwards are scheduled to expire in 2010 through 2023. Approximately $22 million of the tax loss carryforwards are the result of
acquisitions. We have not booked any valuation allowance because we believe we have tax planning strategies available to realize our tax loss carryforwards.



Contractual Obligations and Commitments



The following summarizes our significant obligations and commitments to make future contractual payments as of December 31, 2003. 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.



|                                                                |  |       |           |                      |      |         |      |   |        |  |      |        |            |   |        |  |   |        |  |   |          
|--------------------------------------------------------------- |  | ----- | --------- | -------------------- | ---- | ------- | ---- | - | ------ |  | ---- | ------ | ---------- | - | ------ |  | - | ------ |  | - | ---------
|                                                                |  | Total |           | Payments Due by Year
|(in thousands)                                                  |  |       | 2004      |                      | 2005 |         | 2006 |   | 2007   |  | 2008 |        | After 2008
|Long-term debt                                                  |  | $     | 1,252,000 |                      | $    |        |      | $ |       |  | $    |       |            | $ |       |  | $ |       |  | $ | 1,252,000
|Operating leases                                                |  |       | 126,919   |                      |      | 23,343  |      |   | 20,522 |  |      | 15,712 |            |   | 14,788 |  |   | 14,248 |  |   | 38,306   
|Drilling contracts                                              |  |       | 45,223    |                      |      | 45,223  |      |   |       |  |      |       |            |   |       |  |   |       |  |   |         
|Transportation contracts                                        |  |       | 146,193   |                      |      | 12,982  |      |   | 19,928 |  |      | 20,490 |            |   | 19,591 |  |   | 18,804 |  |   | 54,398   
|Derivative contract liabilities at December 31, 2003 fair value |  |       | 114,697   |                      |      | 96,653  |      |   | 7,643  |  |      | 10,401 |            |   |       |  |   |       |  |   |         
|                                                                |  |       |           |                      |      |         |      |   |        |  |      |        |            |   |        |  |   |        |  |   |          
|Total                                                           |  | $     | 1,685,032 |                      | $    | 178,201 |      | $ | 48,093 |  | $    | 46,603 |            | $ | 34,379 |  | $ | 33,052 |  | $ | 1,344,704
|                                                                |  |       |           |                      |      |         |      |   |        |  |      |        |            |   |        |  |   |        |  |   |          



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##### Index to Financial Statements

Long-Term Debt. At December 31, 2003, borrowings were $502 million under our senior bank revolving credit facility
due in May 2005. In February 2004, we fully repaid this facility and entered a new five-year revolving credit agreement with commercial banks that matures in February 2009, as reflected in the table above. Our senior notes, totaling $750 million at
December 31, 2003, are due in 2012 and 2013. In January 2004, we sold $500 million of 4.9% senior notes which are due in February 2014. 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.



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, 2003, market prices generally exceeded the fixed prices specified by these
contracts, resulting in a derivative fair value current liability of $96.7 million and long-term liability of $18.0 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 will be funded by higher prices received from the sale of our production, production receipts may be received as much as six weeks after payment to counterparties and can result in draws on our
revolving credit facility. See Note 8 to Consolidated Financial Statements.



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 may qualify as a retiree with any combination of age and qualified years of service that total 60, with a minimum age
of 45 and a minimum of five years full-time service. Directors are eligible to receive benefits when their combined age and years of service on the Board totals 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 2003 was $1.8 million. 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



We have limited related party transactions, as further disclosed in Note 2
to Consolidated Financial Statements. In February 2004, our Board of Directors approved an agreement with a firm, partially owned by one of our directors, to establish fees that will be paid in connection with any advisory services the firm provides
for up to $800 million in future acquisitions. The agreement is effective as of November 2003. For the first acquisition, we will pay a fee of $250,000 plus a transaction fee equal to 0.75% of the purchase price. For any subsequent acquisition
closing, we will pay only the transaction fee. The initial term of the agreement expires December 31, 2004. To date, we have not paid the director-related company any amounts under this agreement. This same director-related company represented the
seller of properties for acquisitions totaling approximately $186 million that we closed in January 2004.



In connection with our sale of properties in 1999, the same director-related Company represented the purchaser and also invested in the purchase. We
invested $584,000 in a limited partnership that purchased a small interest in these properties. Based on an impairment evaluation in 2003, we have written down this investment to $100,000.



During 2002, the same director-related company performed consulting services
in connection with our acquisition of properties in East Texas, Louisiana and the San Juan Basin of New Mexico. See Note 13 to Consolidated Financial Statements. The director-related company received a fee of $2.4 million for these services, which
was 1% of the total of the property purchase price and the related exchange transaction value.



The same director-related company performed consulting services in connection with a 1998 acquisition and was entitled to receive, at its election, either a 20% working interest or a 1% overriding royalty interest
conveyed from our 100% working interest in the properties after payout of acquisition and operating costs. The Board of Directors



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##### Index to Financial Statements

authorized the purchase of this potential interest from the director-related company and other parties in November 2001 for $15 million, as supported by a
third-party fairness opinion. The director-related company received $10 million of the total purchase price.



Critical Accounting Policies



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.



Property costs that exceed managements estimate of future cash flows of proved reserves must be expensed through an impairment provision. We
evaluate possible impairment of producing properties, generally aggregated on a field-level basis, when conditions indicate that they may be impaired. Cash flow pricing estimates are based on existing proved reserve and production information and
pricing assumptions that management believes are reasonable. Individually significant undeveloped properties are reviewed for impairment on a property-by-property basis, and impairment of other undeveloped properties is done on a total basis. Our
impairment of producing properties has been limited to a $2 million provision recorded in 1998. Our impairment provisions have been limited, and we do not expect significant impairment provisions in the near future, because of our relatively low
acquisition and development costs compared with expected product prices. By comparison, full cost companies must record impairment under a ceiling test which is computed on an aggregate country basis using discounted estimated future
after-tax cash flows based on current market prices. This generally results in more frequent and higher impairment provisions under the full cost method when prices decline significantly.



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. 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. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from previous estimates.



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. If estimated proved reserves decline, future DD&A expense will increase and net income will be reduced. A decline in proved reserves also can result in a required impairment provision, as discussed under Oil and Gas Property
Accounting above.



The standardized measure of discounted
future net cash flows and changes in such cash flows, as reported in Note 16 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



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##### Index to Financial Statements

prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate.
Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent managements estimated current market value of proved reserves.



Asset Retirement Obligation



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



Our liability is determined using significant assumptions,
including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life 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. 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 life of most of our wells, the costs to ultimately retire our wells may vary significantly from previous 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 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 will not be able to realize the 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 operating results and financial condition. As required under generally accepted accounting principles, we adopted SFAS No. 133 on January 1, 2001 with a significant charge to our income statement and equity related to
recording derivative financial instruments at their market value. Subsequent to that date, we recorded significant derivative fair value gains in the 2001 income statement and equity related to decline in natural gas prices. In each instance, these
are 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. Because hedge accounting is not required under generally accepted accounting principles, our operating results as reflected in our financial statements may not be comparable
to other companies.



See Item 7A, Commodity Price
Risk for the effect of price changes on derivative fair value gains and losses.



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##### Index to Financial Statements

Accounting Pronouncements



An issue within the oil and gas industry has recently arisen regarding whether SFAS No. 141, Business Combinations,
and SFAS No. 142, Goodwill and Other Intangible Assets, require costs associated with mineral rights be accounted for and separately reported on the balance sheet as intangible assets. As is the common practice in the oil and gas industry, we
include leasehold acquisition costs as a component of both producing properties and undeveloped properties on our consolidated balance sheets. This question of SFAS No. 141 and SFAS No. 142 applicability has been referred to the Financial Accounting
Standards Board. If it is ultimately determined that SFAS No. 141 and SFAS No. 142 require intangible asset accounting treatment for costs associated with mineral rights, the following amounts would be reclassified on the consolidated balance sheets
from producing properties, undeveloped properties and accumulated depreciation, depletion and amortization:



|                                                 |  |             |           |   |      |   |           |  
|------------------------------------------------ |  | ----------- | --------- | - | ---- | - | --------- | -
|                                                 |  | December 31 |          
|(in thousands)                                   |  | 2003        |           |   | 2002 |  
|Intangible Assets:                               |  |             |           |   |      |   |           |  
|Producing property leasehold acquisition costs   |  | $           | 2,093,318 |   |      | $ | 1,542,343 |  
|Undeveloped property leasehold acquisition costs |  |             | 12,627    |   |      |   | 12,163    |  
|                                                 |  |             |           |   |      |   |           |  
|Total leasehold acquisition costs                |  |             | 2,105,945 |   |      |   | 1,554,506 |  
|Accumulated depletion                            |  |             | (438,151  | ) |      |   | (336,374  | )
|                                                 |  |             |           |   |      |   |           |  
|Net leasehold acquisition costs                  |  | $           | 1,667,794 |   |      | $ | 1,218,132 |  
|                                                 |  |             |           |   |      |   |           |  



Accounting for the
costs of mineral rights as intangible assets under SFAS No. 141 and SFAS No. 142 would also require additional financial statement disclosures but would not affect our method of amortization or assessment of impairment. Therefore, any resulting
accounting change would have no effect on our consolidated income statements or statements of cash flows.



In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity,which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Such financial instruments include mandatorily redeemable shares of
stock, obligations to repurchase the issuers equity shares and obligations that an issuer may settle by issuing a variable number of its equity shares. The Statement is effective for financial instruments entered into or modified after May 31,
2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. In November 2003, the effective date for SFAS No. 150 was deferred for provisions relating to certain financial instruments issued by
consolidated subsidiaries. None of our consolidated entities currently have any of these financial instruments, and we do not anticipate SFAS No. 150 will have a material effect on future financial position or earnings.



In December 2003, the Financial Accounting Standards Board issued a revision
of Interpretation No. 46 to clarify consolidation requirements for variable interest entities. We do not anticipate this interpretation to have an effect on our financial statements since we do not have interests in variable interest entities.



Also in December 2003, the Financial Accounting Standards
Board issued SFAS No. 132, revising disclosures required about pensions and other post-retirement benefits. These revised disclosures are included in Note 12 to Consolidated Financial Statements for our post-retirement health plan. In accordance
with a deferred effective date, future annual reporting will disclose future plan benefit payments expected to be paid for each of the five years following the latest balance sheet date and in the aggregate for the following five years.



In January 2004, the Financial Accounting Standards Board issued Staff
Position No. 106-1 regarding treatment in post-retirement health plan accounting and disclosures for the effects of the Medicare Prescription Drug, Improvement and Modernization Act, which was signed by the President into law in December 2003.
Because our post-retirement health plan does not provide prescription drug coverage beyond the date of eligibility for Medicare coverage, this change in Medicare coverage does not impact estimates for our benefit costs.



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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 |        
|                                                        |  | 2003        |         |   | 2002 |       
|(in thousands)                                          |  | Amount      |         |   | Mcf  |        |   | Amount |   |         | Mcf | 
|Accounts receivable - current underproduction           |  | $           | 23,949  |   |      | 7,135  |   |        | $ | 17,248  |     |  | 6,178  |  
|Accounts payable - current overproduction               |  |             | (19,366 | ) |      | (5,900 | ) |        |   | (14,381 | )   |  | (5,165 | )
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net current gas underproduction balancing receivable    |  | $           | 4,583   |   |      | 1,235  |   |        | $ | 2,867   |     |  | 1,013  |  
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Other assets - noncurrent underproduction               |  | $           | 19,385  |   |      | 6,148  |   |        | $ | 14,934  |     |  | 5,642  |  
|Other long-term liabilities - noncurrent overproduction |  |             | (29,776 | ) |      | (9,353 | ) |        |   | (23,027 | )   |  | (8,492 | )
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net long-term gas overproduction balancing payable      |  |             | (10,391 | ) |      | (3,205 | ) |        |   | (8,093  | )   |  | (2,850 | )
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Other assets - carbon dioxide underproduction           |  |             | 1,977   |   |      | 12,354 |   |        |   | 1,868   |     |  | 11,675 |  
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net long-term overproduction balancing payable          |  | $           | (8,414  | ) |      |        |   |        | $ | (6,225  | )   |  |        |  
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  



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, cash flow, drilling activity, drilling locations, acquisition and development activities, 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, 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 condition. If the oil and gas industry experiences significant price declines, we may, among other things, be
unable to meet our financial obligations or make planned capital expenditures.



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##### Index to Financial Statements

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 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. Many 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. 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 successfully 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.



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



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##### Index to Financial Statements

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.



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.



Government Regulations. Extensive federal, state and local regulation of the oil and gas industry significantly affects our operations. In particular, our oil and
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 gas wells and other related facilities. These regulations may become more demanding in the future. We may need to expend significant financial and managerial resources to comply with environmental regulations and
permitting requirements. Although we believe that our operations generally comply with applicable laws and regulations, we may incur substantial additional costs and liabilities in our operations as a result of stricter environmental laws,
regulations and enforcement policies.



Operating Hazards and Uninsured
Risks. Our operations are subject to inherent hazards and risks, such as fire, explosions, blowouts, formations with abnormal pressures, uncontrollable flows of underground gas, oil and formation water 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.



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|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, 2003, our variable rate debt had a carrying value of $502 million, which approximated its fair value, and our fixed rate debt had a carrying value of $750 million and an approximate
fair value of $773.3 million. 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.



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) |   |            | HypotheticalChange inFair Value
|December 31, 2003 |  |                |            |   |                |   |            |                                 |  |   |       
|Long-term debt    |  | $              | (1,252,000 | ) |                | $ | (1,275,285 | )                               |  | $ | 51,085
|December 31, 2002 |  |                |            |   |                |   |            |                                 |  |   |       
|Long-term debt    |  | $              | (1,118,170 | ) |                | $ | (1,146,572 | )                               |  | $ | 29,264

---

|(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, 2003, 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 $84.7 million at December 31, 2003 and a net fair value loss of $93.7 million at December 31, 2002. Of the December
31, 2003 fair value, a $91.6 million loss has been determined based on the exchange-trade value of NYMEX contracts and a $6.9 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. As of December 31, 2003, we had no outstanding oil futures contracts and differential swaps. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $63.5
million in the fair value of gas futures contracts and swap agreements at December 31, 2003. None of our derivative contracts have margin requirements or collateral



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##### Index to Financial Statements

provisions which 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 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, 2003 was $18 million. The effect of a hypothetical 10% change in gas prices would result in a change of approximately $4.2 million in the fair value of
these contracts, while a 10% change in crude oil prices would result in a change of approximately $2.4 million.



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



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



|                                                                                                  |  |     
|------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                  |  | Page
|Consolidated Balance Sheets                                                                       |  | 44  
|Consolidated Income Statements                                                                    |  | 45  
|Consolidated Statements of Cash Flows                                                             |  | 46  
|Consolidated Statements of Stockholders Equity                                                   |  | 47  
|Notes to Consolidated Financial Statements                                                        |  | 48  
|Selected Quarterly Financial Data (Note 15 to Consolidated Financial Statements)                  |  | 73  
|Information about Oil and Gas Producing Activities (Note 16 to Consolidated Financial Statements) |  | 73  
|Independent Auditors Reports                                                                     |  | 77  



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



On May 20, 2002, we appointed KPMG LLP as independent auditors for fiscal 2002 to replace Arthur Andersen LLP effective with such appointment. The change
in independent auditors was approved by the Board of Directors upon the recommendation of the Audit Committee. Information regarding this change in independent auditors is included in our current report on Form 8-K dated May 20, 2002.



There have been no other 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, 2003 and 2002.



|Item 9A. | 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.



There have been no significant changes in our internal controls or in other factors that could affect these controls subsequent to the date of their
evaluation.



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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 and 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 30, 2004.



|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.



Our Board of Directors has adopted Corporate Governance Guidelines and
charters for the Audit Committee, Compensation Committee and the Corporate Governance and Nominating Committee. You can find these documents on our web site at http://www.xtoenergy.com. You can also obtain a free copy of any of the materials
referred to above by contacting us at 810 Houston Street, Fort Worth, Texas 76102, Attn: Corporate Secretary.



|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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PART IV



|Item 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
|-------- | ---------------------------------------------------------------



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



|   |  |                                                                                                                                                                                                                   |  |     
|-- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|   |  |                                                                                                                                                                                                                   |  | Page
|1. |  | Financial Statements:                                                                                                                                                                                             |  |     
|   |  |                                                                                                                                                                                                                  
|   |  | Consolidated Balance Sheets at December 31, 2003 and 2002                                                                                                                                                         |  | 44  
|   |  |                                                                                                                                                                                                                  
|   |  | Consolidated Income Statements for the years ended December 31, 2003, 2002 and 2001                                                                                                                               |  | 45  
|   |  |                                                                                                                                                                                                                  
|   |  | Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001                                                                                                                        |  | 46  
|   |  |                                                                                                                                                                                                                  
|   |  | Consolidated Statements of Stockholders Equity for the years ended December 31, 2003, 2002 and 2001                                                                                                              |  | 47  
|   |  |                                                                                                                                                                                                                  
|   |  | Notes to Consolidated Financial Statements                                                                                                                                                                        |  | 48  
|   |  |                                                                                                                                                                                                                  
|   |  | Independent Auditors Reports                                                                                                                                                                                     |  | 77  
|   |  |                                                                                                                                                                                                                  
|2. |  | Financial Statement Schedules:                                                                                                                                                                                    |  |     
|   |  |                                                                                                                                                                                                                  
|   |  | Schedule II - Consolidated Valuation and Qualifying Accounts                                                                                                                                                      |  | 79  
|   |  |                                                                                                                                                                                                                  
|   |  | 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) | Reports on Form 8-K
| | --- | -------------------



We filed the following reports on Form 8-K during the quarter ended December 31, 2003 and through March 15, 2004:



On October 16, 2003, we filed a report on Form 8-K dated October 15, 2003,
to announce the acquisition of properties in East Texas and the Arkoma and San Juan Basins.



On January 8, 2004, we filed a report on Form 8-K dated January 8, 2004 to announce we entered an agreement to purchase properties in East Texas and northern Louisiana, and that our Board of Directors approved a $500
million development and exploration budget for 2004.



On
January 14, 2004, we filed a report on Form 8-K dated January 14, 2004 to report the filing of a preliminary prospectus supplement and provided exhibits to the Prospectus, dated July 7, 2003.



On January 16, 2004, we filed a report on Form 8-K dated January 16, 2004 to
report the filing of a prospectus supplement and provided exhibits to the Prospectus, dated July 7, 2003.



On February 2, 2004, we filed a report on Form 8-K dated January 30, 2004 to announce the completion of previously announced purchases of East Texas and
northern Louisiana producing properties.



On February 24,
2004, we filed a report on Form 8-K dated February 19, 2004 to announce the appointment of a new Director and that we entered definitive agreements with multiple parties to acquire producing properties located primarily in the Barnett Shale of North
Texas and in the Arkoma Basin for a total of $200 million.



We
have furnished two reports on Form 8-K under Item 12 during this time period.



| | (c) | Exhibits
| | --- | --------



See Index to Exhibits at page 81 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.



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XTO ENERGY INC.

Consolidated Balance Sheets



|                                                                                                        |  |             |            |   |      |   |           |  
|------------------------------------------------------------------------------------------------------- |  | ----------- | ---------- | - | ---- | - | --------- | -
|                                                                                                        |  | December 31 |           
|(in thousands, except shares)                                                                           |  | 2003        |            |   | 2002 |  
|ASSETS                                                                                                  |  |             |            |   |      |   |           |  
|Current Assets:                                                                                         |  |             |            |   |      |   |           |  
|Cash and cash equivalents                                                                               |  | $           | 6,995      |   |      | $ | 14,954    |  
|Accounts receivable, net                                                                                |  |             | 193,666    |   |      |   | 145,356   |  
|Derivative fair value                                                                                   |  |             | 11,351     |   |      |   | 40,628    |  
|Current income tax receivable                                                                           |  |             | 4,503      |   |      |   |          |  
|Deferred income tax benefit                                                                             |  |             | 32,455     |   |      |   | 32,680    |  
|Other                                                                                                   |  |             | 12,193     |   |      |   | 11,172    |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Total Current Assets                                                                                    |  |             | 261,163    |   |      |   | 244,790   |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Property and Equipment, at cost  successful efforts method:                                            |  |             |            |   |      |   |           |  
|Producing properties                                                                                    |  |             | 4,253,221  |   |      |   | 3,081,488 |  
|Undeveloped properties                                                                                  |  |             | 12,627     |   |      |   | 12,163    |  
|Other                                                                                                   |  |             | 70,494     |   |      |   | 51,861    |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Total Property and Equipment                                                                            |  |             | 4,336,342  |   |      |   | 3,145,512 |  
|Accumulated depreciation, depletion and amortization                                                    |  |             | (1,024,275 | ) |      |   | (774,547  | )
|                                                                                                        |  |             |            |   |      |   |           |  
|Net Property and Equipment                                                                              |  |             | 3,312,067  |   |      |   | 2,370,965 |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Other Assets:                                                                                           |  |             |            |   |      |   |           |  
|Derivative fair value                                                                                   |  |             | 646        |   |      |   | 1,032     |  
|Other                                                                                                   |  |             | 37,258     |   |      |   | 31,406    |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Total Other Assets                                                                                      |  |             | 37,904     |   |      |   | 32,438    |  
|                                                                                                        |  |             |            |   |      |   |           |  
|TOTAL ASSETS                                                                                            |  | $           | 3,611,134  |   |      | $ | 2,648,193 |  
|                                                                                                        |  |             |            |   |      |   |           |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                    |  |             |            |   |      |   |           |  
|Current Liabilities:                                                                                    |  |             |            |   |      |   |           |  
|Accounts payable and accrued liabilities                                                                |  | $           | 218,710    |   |      | $ | 150,107   |  
|Payable to royalty trusts                                                                               |  |             | 4,848      |   |      |   | 6,466     |  
|Derivative fair value                                                                                   |  |             | 96,653     |   |      |   | 128,001   |  
|Current income taxes payable                                                                            |  |             |           |   |      |   | 517       |  
|Other                                                                                                   |  |             | 346        |   |      |   | 805       |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Total Current Liabilities                                                                               |  |             | 320,557    |   |      |   | 285,896   |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Long-term Debt                                                                                          |  |             | 1,252,000  |   |      |   | 1,118,170 |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Other Long-term Liabilities:                                                                            |  |             |            |   |      |   |           |  
|Derivative fair value                                                                                   |  |             | 18,044     |   |      |   | 22,953    |  
|Deferred income taxes payable                                                                           |  |             | 426,730    |   |      |   | 286,472   |  
|Asset retirement obligation                                                                             |  |             | 93,379     |   |      |   |          |  
|Other                                                                                                   |  |             | 34,782     |   |      |   | 26,916    |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Total Other Long-term Liabilities                                                                       |  |             | 572,935    |   |      |   | 336,341   |  
|                                                                                                        |  |             |            |   |      |   |           |  
|Commitments and Contingencies (Note 6)                                                                  |  |             |            |   |      |   |           |  
|Stockholders Equity:                                                                                   |  |             |            |   |      |   |           |  
|Common stock ($.01 par value, 250,000,000 shares authorized, 234,251,352 and 226,224,970 shares issued) |  |             | 2,343      |   |      |   | 2,262     |  
|Additional paid-in capital                                                                              |  |             | 753,900    |   |      |   | 533,902   |  
|Treasury stock, at cost (-0- and 14,596,856 shares)                                                     |  |             |           |   |      |   | (76,561   | )
|Retained earnings                                                                                       |  |             | 762,640    |   |      |   | 509,756   |  
|Accumulated other comprehensive income (loss)                                                           |  |             | (53,241    | ) |      |   | (61,573   | )
|                                                                                                        |  |             |            |   |      |   |           |  
|Total Stockholders Equity                                                                              |  |             | 1,465,642  |   |      |   | 907,786   |  
|                                                                                                        |  |             |            |   |      |   |           |  
|TOTAL LIABILITIES AND STOCKHOLDERS EQUITY                                                              |  | $           | 3,611,134  |   |      | $ | 2,648,193 |  
|                                                                                                        |  |             |            |   |      |   |           |  



See accompanying notes
to consolidated financial statements.



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XTO ENERGY INC.

Consolidated Income Statements



|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|------------------------------------------------------------------- |  | ---------------------- | --------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                                    |  | Year Ended December 31 |          
|(in thousands, except per share data)                               |  | 2003                   |           |   | 2002 |   |         | 2001 | 
|REVENUES                                                            |  |                        |           |   |      |   |         |      |  |   |         |  
|Gas and natural gas liquids                                         |  | $                      | 1,040,370 |   |      | $ | 681,147 |      |  | $ | 710,348 |  
|Oil and condensate                                                  |  |                        | 135,058   |   |      |   | 115,324 |      |  |   | 116,939 |  
|Gas gathering, processing and marketing                             |  |                        | 12,982    |   |      |   | 11,622  |      |  |   | 12,832  |  
|Other                                                               |  |                        | 1,145     |   |      |   | 2,070   |      |  |   | (1,371  | )
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|Total Revenues                                                      |  |                        | 1,189,555 |   |      |   | 810,163 |      |  |   | 838,748 |  
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|EXPENSES                                                            |  |                        |           |   |      |   |         |      |  |   |         |  
|Production                                                          |  |                        | 164,864   |   |      |   | 129,182 |      |  |   | 110,005 |  
|Taxes, transportation and other                                     |  |                        | 104,654   |   |      |   | 57,225  |      |  |   | 63,656  |  
|Exploration                                                         |  |                        | 1,811     |   |      |   | 2,186   |      |  |   | 5,438   |  
|Depreciation, depletion and amortization                            |  |                        | 284,006   |   |      |   | 204,109 |      |  |   | 154,322 |  
|Accretion of discount in asset retirement obligation                |  |                        | 5,330     |   |      |   |        |      |  |   |        |  
|Gas gathering and processing                                        |  |                        | 9,350     |   |      |   | 9,114   |      |  |   | 9,522   |  
|General and administrative                                          |  |                        | 107,675   |   |      |   | 62,114  |      |  |   | 39,217  |  
|Derivative fair value (gain) loss                                   |  |                        | 10,201    |   |      |   | (2,599  | )    |  |   | (54,370 | )
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|Total Expenses                                                      |  |                        | 687,891   |   |      |   | 461,331 |      |  |   | 327,790 |  
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|OPERATING INCOME                                                    |  |                        | 501,664   |   |      |   | 348,832 |      |  |   | 510,958 |  
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|OTHER INCOME (EXPENSE)                                              |  |                        |           |   |      |   |         |      |  |   |         |  
|Gain on distribution of royalty trust units                         |  |                        | 16,216    |   |      |   |        |      |  |   |        |  
|Loss on extinguishment of debt                                      |  |                        | (9,601    | ) |      |   | (8,528  | )    |  |   |        |  
|Interest expense, net                                               |  |                        | (63,769   | ) |      |   | (53,555 | )    |  |   | (55,601 | )
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|Total Other Expense                                                 |  |                        | (57,154   | ) |      |   | (62,083 | )    |  |   | (55,601 | )
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE |  |                        | 444,510   |   |      |   | 286,749 |      |  |   | 455,357 |  
|INCOME TAX EXPENSE                                                  |  |                        | 158,009   |   |      |   | 100,690 |      |  |   | 161,952 |  
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE            |  |                        | 286,501   |   |      |   | 186,059 |      |  |   | 293,405 |  
|Cumulative effect of accounting change, net of tax                  |  |                        | 1,778     |   |      |   |        |      |  |   | (44,589 | )
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|NET INCOME                                                          |  | $                      | 288,279   |   |      | $ | 186,059 |      |  | $ | 248,816 |  
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|EARNINGS PER COMMON SHARE                                           |  |                        |           |   |      |   |         |      |  |   |         |  
|Basic:                                                              |  |                        |           |   |      |   |         |      |  |   |         |  
|Net income before cumulative effect of accounting change            |  | $                      | 1.27      |   |      | $ | 0.89    |      |  | $ | 1.44    |  
|Cumulative effect of accounting change, net of tax                  |  |                        | 0.01      |   |      |   |        |      |  |   | (0.22   | )
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|Net income                                                          |  | $                      | 1.28      |   |      | $ | 0.89    |      |  | $ | 1.22    |  
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|Diluted:                                                            |  |                        |           |   |      |   |         |      |  |   |         |  
|Net income before cumulative effect of accounting change            |  | $                      | 1.26      |   |      | $ | 0.88    |      |  | $ | 1.41    |  
|Cumulative effect of accounting change, net of tax                  |  |                        | 0.01      |   |      |   |        |      |  |   | (0.21   | )
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|Net income                                                          |  | $                      | 1.27      |   |      | $ | 0.88    |      |  | $ | 1.20    |  
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  
|WEIGHTED AVERAGE COMMON SHARES OUTSTANDING                          |  |                        | 224,749   |   |      |   | 208,375 |      |  |   | 204,176 |  
|                                                                    |  |                        |           |   |      |   |         |      |  |   |         |  



See accompanying notes
to consolidated financial statements.



45



---

##### Table of Contents

##### Index to Financial Statements

XTO ENERGY INC.

Consolidated Statements of Cash Flows



|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|--------------------------------------------------------------------------------- |  | ---------------------- | ---------- | - | ---- | - | --------- | ---- |  | - | -------- | -
|                                                                                  |  | Year Ended December 31 |           
|(in thousands)                                                                    |  | 2003                   |            |   | 2002 |   |           | 2001 | 
|OPERATING ACTIVITIES                                                              |  |                        |            |   |      |   |           |      |  |   |          |  
|Net income                                                                        |  | $                      | 288,279    |   |      | $ | 186,059   |      |  | $ | 248,816  |  
|Adjustments to reconcile net income to net cash provided by operating activities: |  |                        |            |   |      |   |           |      |  |   |          |  
|Depreciation, depletion and amortization                                          |  |                        | 284,006    |   |      |   | 204,109   |      |  |   | 154,322  |  
|Accretion of discount in asset retirement obligation                              |  |                        | 5,330      |   |      |   |          |      |  |   |         |  
|Non-cash incentive compensation                                                   |  |                        | 53,123     |   |      |   | 26,990    |      |  |   | 9,246    |  
|Deferred income tax                                                               |  |                        | 157,715    |   |      |   | 100,368   |      |  |   | 161,105  |  
|Gain on distribution of royalty trust units                                       |  |                        | (16,216    | ) |      |   |          |      |  |   |         |  
|Non-cash derivative fair value (gain) loss                                        |  |                        | 10,771     |   |      |   | 6,890     |      |  |   | (69,147  | )
|Cumulative effect of accounting change, net of tax                                |  |                        | (1,778     | ) |      |   |          |      |  |   | 44,589   |  
|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                                                              |  |                        | (386       | ) |      |   | (3,084    | )    |  |   | (4,802   | )
|Changes in operating assets and liabilities (a)                                   |  |                        | 3,736      |   |      |   | (22,876   | )    |  |   | (1,514   | )
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|Cash Provided by Operating Activities                                             |  |                        | 794,181    |   |      |   | 490,842   |      |  |   | 542,615  |  
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|INVESTING ACTIVITIES                                                              |  |                        |            |   |      |   |           |      |  |   |          |  
|Proceeds from sale of property and equipment                                      |  |                        |           |   |      |   | 149       |      |  |   | 319      |  
|Property acquisitions                                                             |  |                        | (653,742   | ) |      |   | (358,087  | )    |  |   | (224,906 | )
|Development costs                                                                 |  |                        | (459,762   | ) |      |   | (370,558  | )    |  |   | (381,026 | )
|Other property and asset additions                                                |  |                        | (21,730    | ) |      |   | (8,321    | )    |  |   | (13,438  | )
|Officer loan repayments                                                           |  |                        |           |   |      |   |          |      |  |   | 8,128    |  
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|Cash Used by Investing Activities                                                 |  |                        | (1,135,234 | ) |      |   | (736,817  | )    |  |   | (610,923 | )
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|FINANCING ACTIVITIES                                                              |  |                        |            |   |      |   |           |      |  |   |          |  
|Proceeds from long-term debt                                                      |  |                        | 1,835,000  |   |      |   | 1,156,000 |      |  |   | 640,000  |  
|Payments on long-term debt                                                        |  |                        | (1,701,170 | ) |      |   | (893,830  | )    |  |   | (553,000 | )
|Net proceeds from common stock offering                                           |  |                        | 247,972    |   |      |   |          |      |  |   |         |  
|Dividends                                                                         |  |                        | (6,640     | ) |      |   | (4,984    | )    |  |   | (4,413   | )
|Senior note offering and debt costs                                               |  |                        | (7,797     | ) |      |   | (8,381    | )    |  |   |         |  
|Proceeds from exercise of stock options and warrants                              |  |                        | 16,248     |   |      |   | 23,745    |      |  |   | 14,325   |  
|Payments upon exercise of stock options                                           |  |                        | (18,183    | ) |      |   | (1,440    | )    |  |   | (11,717  | )
|Subordinated note redemption costs                                                |  |                        | (7,139     | ) |      |   | (3,794    | )    |  |   |         |  
|Purchases of treasury stock and other                                             |  |                        | (25,197    | ) |      |   | (13,197   | )    |  |   | (17,515  | )
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|Cash Provided by Financing Activities                                             |  |                        | 333,094    |   |      |   | 254,119   |      |  |   | 67,680   |  
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                  |  |                        | (7,959     | ) |      |   | 8,144     |      |  |   | (628     | )
|Cash and Cash Equivalents, January 1                                              |  |                        | 14,954     |   |      |   | 6,810     |      |  |   | 7,438    |  
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|Cash and Cash Equivalents, December 31                                            |  | $                      | 6,995      |   |      | $ | 14,954    |      |  | $ | 6,810    |  
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|(a)Changes in Operating Assets and Liabilities                                    |  |                        |            |   |      |   |           |      |  |   |          |  
|Accounts receivable                                                               |  | $                      | (49,628    | ) |      | $ | (19,088   | )    |  | $ | 58,706   |  
|Other current assets                                                              |  |                        | (5,523     | ) |      |   | 2,758     |      |  |   | (3,855   | )
|Other operating assets                                                            |  |                        | 1,103      |   |      |   | 4,293     |      |  |   | (1,738   | )
|Enron Btu swap contract                                                           |  |                        |           |   |      |   | (43,272   | )    |  |   |         |  
|Current liabilities                                                               |  |                        | 57,784     |   |      |   | 32,433    |      |  |   | (54,627  | )
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  
|                                                                                  |  | $                      | 3,736      |   |      | $ | (22,876   | )    |  | $ | (1,514   | )
|                                                                                  |  |                        |            |   |      |   |           |      |  |   |          |  



See accompanying notes
to consolidated financial statements.



46



---

##### Table of Contents

##### Index to Financial Statements

XTO ENERGY INC.

Consolidated Statements of Stockholders Equity



|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|------------------------------------------------------------------------------------------------------------------------------------------------- |  | -------------- | ------- | - | ----------- | - | ----- | ------------------------ |  | - | ------------- | - |  | ---------------- | ------- | - | ------------------------------------------ | - | ------- | ----- |  | - | -------- | - |  | - | --------- | -
|(in thousands, except per share amounts)                                                                                                          |  | PreferredStock |         |   | CommonStock |   |       | AdditionalPaid-inCapital |  |   | TreasuryStock |   |  | RetainedEarnings |         |   | AccumulatedOtherComprehensiveIncome (Loss) |   |         | Total | 
|Balances, December 31, 2000                                                                                                                       |  | $              | 27,217  |   |             | $ | 2,065 |                          |  | $ | 434,496       |   |  | $                | (50,829 | ) |                                            | $ | 84,418  |       |  | $ |         |   |  | $ | 497,367   |  
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|Net income                                                                                                                                        |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   | 248,816 |       |  |   |         |   |  |   | 248,816   |  
|Cumulative effect of change in accounting for hedge derivatives, net of applicable income tax benefit of $36,251                                  |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   |        |       |  |   | (67,323  | ) |  |   | (67,323   | )
|Change in hedge derivative fair value, net of applicable income tax of $69,153                                                                    |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   |        |       |  |   | 128,428  |   |  |   | 128,428   |  
|Hedge derivative contract settlements reclassified into earnings from other comprehensive income, net of applicable income tax of
$5,133          |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   |        |       |  |   | 9,533    |   |  |   | 9,533     |  
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|Comprehensive income                                                                                                                              |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   | 319,454   |  
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|Issuance/vesting and forfeiture of performance shares                                                                                             |  |                |        |   |             |   | 11    |                          |  |   | 5,180         |   |  |                  | (4,226  | ) |                                            |   |        |       |  |   |         |   |  |   | 965       |  
|Stock option exercises, including income tax benefits                                                                                             |  |                |        |   |             |   | 35    |                          |  |   | 17,410        |   |  |                  | (410    | ) |                                            |   |        |       |  |   |         |   |  |   | 17,035    |  
|Treasury stock purchases                                                                                                                          |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  | (9,249  | ) |                                            |   |        |       |  |   |         |   |  |   | (9,249    | )
|Common stock dividends ($0.0220 per share)                                                                                                        |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   | (4,522  | )     |  |   |         |   |  |   | (4,522    | )
|Preferred stock converted to common                                                                                                               |  |                | (27,217 | ) |             |   | 89    |                          |  |   | 27,128        |   |  |                  |        |   |                                            |   |        |       |  |   |         |   |  |   |          |  
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|Balances, December 31, 2001                                                                                                                       |  |                |        |   |             |   | 2,200 |                          |  |   | 484,214       |   |  |                  | (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 benefit of $51,543                                                            |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   |        |       |  |   | (95,723  | ) |  |   | (95,723   | )
|Hedge derivative contract settlements reclassified into earnings from other comprehensive income, net of applicable income tax benefit of
$19,647 |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   |        |       |  |   | (36,488  | ) |  |   | (36,488   | )
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|Comprehensive income                                                                                                                              |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   | 53,848    |  
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|Issuance/vesting of performance shares                                                                                                            |  |                |        |   |             |   | 16    |                          |  |   | 25,602        |   |  |                  | (10,276 | ) |                                            |   |        |       |  |   |         |   |  |   | 15,342    |  
|Stock option and warrant exercises, including income tax benefits                                                                                 |  |                |        |   |             |   | 46    |                          |  |   | 24,086        |   |  |                  | (35     | ) |                                            |   |        |       |  |   |         |   |  |   | 24,097    |  
|Treasury stock purchases                                                                                                                          |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  | (1,536  | ) |                                            |   |        |       |  |   |         |   |  |   | (1,536    | )
|Common stock dividends ($0.0240 per share)                                                                                                        |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   | (5,015  | )     |  |   |         |   |  |   | (5,015    | )
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|Balances, December 31, 2002                                                                                                                       |  |                |        |   |             |   | 2,262 |                          |  |   | 533,902       |   |  |                  | (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 benefit of $65,850                                                            |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   |        |       |  |   | (122,293 | ) |  |   | (122,293  | )
|Hedge derivative contract settlements reclassified into earnings from 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                                                                                             |  |                |        |   |             |   | 33    |                          |  |   | 51,092        |   |  |                  | (23,124 | ) |                                            |   |        |       |  |   |         |   |  |   | 28,001    |  
|Stock option exercises, including income tax benefits                                                                                             |  |                |        |   |             |   | 34    |                          |  |   | 22,929        |   |  |                  |        |   |                                            |   |        |       |  |   |         |   |  |   | 22,963    |  
|Treasury stock purchases                                                                                                                          |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  | (2,296  | ) |                                            |   |        |       |  |   |         |   |  |   | (2,296    | )
|Common stock offering                                                                                                                             |  |                |        |   |             |   | 173   |                          |  |   | 247,799       |   |  |                  |        |   |                                            |   |        |       |  |   |         |   |  |   | 247,972   |  
|Fair value of royalty trust unit distribution                                                                                                     |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   | (28,151 | )     |  |   |         |   |  |   | (28,151   | )
|Common stock dividends ($0.0320 per share)                                                                                                        |  |                |        |   |             |   |      |                          |  |   |              |   |  |                  |        |   |                                            |   | (7,244  | )     |  |   |         |   |  |   | (7,244    | )
|Cancellation of treasury stock                                                                                                                    |  |                |        |   |             |   | (159  | )                        |  |   | (101,822      | ) |  |                  | 101,981 |   |                                            |   |        |       |  |   |         |   |  |   |          |  
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  
|Balances, December 31, 2003                                                                                                                       |  | $              |        |   |             | $ | 2,343 |                          |  | $ | 753,900       |   |  | $                |        |   |                                            | $ | 762,640 |       |  | $ | (53,241  | ) |  | $ | 1,465,642 |  
|                                                                                                                                                  |  |                |         |   |             |   |       |                          |  |   |               |   |  |                  |         |   |                                            |   |         |       |  |   |          |   |  |   |           |  



See accompanying notes
to consolidated financial statements.



47



---

##### Table of Contents

##### Index to Financial Statements

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 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 five-for-four stock split to be effected March 17, 2004, the four-for-three stock split effected on March 18, 2003 and the three-for-two stock split effected on June 5, 2001.



We are an independent oil and gas company with production and exploration
concentrated in Texas, Oklahoma, Arkansas, Kansas, New Mexico, Colorado, Wyoming, Alaska 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 $80.6 million at December 31, 2003 and $62.4 million at December 31, 2002 related to wells in process of drilling, and $24.3 million at December 31, 2003 related to advance payments for acquisitions that
subsequently closed. Inventory held for future use on our producing properties totaled $6.5 million at December 31, 2003 and $5.4 million at December 31, 2002, 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.



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



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##### Index to Financial Statements

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.



Intangible Assets



An issue within the oil and gas industry has recently arisen regarding
whether SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, require costs associated with mineral rights be accounted for and separately reported on the balance sheet as intangible assets. As is
the common practice in the oil and gas industry, we include leasehold acquisition costs as a component of both producing properties and undeveloped properties on our consolidated balance sheets. This question of SFAS No. 141 and SFAS No. 142
applicability has been referred to the Financial Accounting Standards Board. If it is ultimately determined that SFAS No. 141 and SFAS No. 142 require intangible asset accounting treatment for costs associated with mineral rights, the following
amounts would be reclassified on the consolidated balance sheets from producing properties, undeveloped properties and accumulated depreciation, depletion and amortization:



|                                                 |  |             |           |   |      |   |           |  
|------------------------------------------------ |  | ----------- | --------- | - | ---- | - | --------- | -
|(in thousands)                                   |  | December 31 |          
|                                                 |  | 2003        |           |   | 2002 |  
|Intangible Assets:                               |  |             |           |   |      |   |           |  
|Producing property leasehold acquisition costs   |  | $           | 2,093,318 |   |      | $ | 1,542,343 |  
|Undeveloped property leasehold acquisition costs |  |             | 12,627    |   |      |   | 12,163    |  
|                                                 |  |             |           |   |      |   |           |  
|Total leasehold acquisition costs                |  |             | 2,105,945 |   |      |   | 1,554,506 |  
|Accumulated depletion                            |  |             | (438,151  | ) |      |   | (336,374  | )
|                                                 |  |             |           |   |      |   |           |  
|Net leasehold acquisition costs                  |  | $           | 1,667,794 |   |      | $ | 1,218,132 |  
|                                                 |  |             |           |   |      |   |           |  



Accounting for the
costs of mineral rights as intangible assets under SFAS No. 141 and SFAS No. 142 would also require additional financial statement disclosures, but would not affect our method of amortization or assessment of impairment. Therefore, any resulting
accounting change would have no effect on our consolidated income statements or statements of cash flows.



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 0.0059 units of Cross Timbers Royalty Trust units for each share of our common stock outstanding on September 2, 2003 (Note 14). 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. Amounts due the trusts, net of amounts retained by our ownership of Hugoton Royalty Trust units, are
deducted from our revenues, taxes, production expenses and development costs.



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##### Index to Financial Statements

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 tax assets are calculated using enacted tax rates applicable to taxable income in the years when we anticipate these timing differences
will reverse. The effect of changes in tax rates is recognized in the period of enactment.



Other Assets



Other
assets primarily include deferred debt costs that are amortized to interest expense over the term of the related debt (Note 3) and the long-term portion of gas balancing receivable (see Revenue Recognition below). Other than potential
treatment of leasehold acquisition costs as intangible assets (see Intangible Assets above), 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 $19. 8 million at December 31, 2003 and $18.3 million at December 31, 2002.



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.
On January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137, 138 and 149 (Note 7). SFAS No. 133 requires that all derivatives be recorded on the balance sheet at fair
value. We generally determine the fair value of futures contracts and swap contracts based on the difference between the derivatives fixed contract price and the underlying market price at the determination date. The fair value of call options
and collars are generally determined under the Black-Scholes option-pricing model. Most values are confirmed by counterparties to the derivative.



Realized and unrealized gains and losses on derivatives that are not designated as hedges, as well as on the ineffective portion of hedge derivatives, are
recorded as a derivative fair value gain or loss in the income statement. Unrealized gains and losses on effective cash flow hedge derivatives, as well as any deferred gain or loss realized upon early termination of effective hedge derivatives, are
recorded as a component of accumulated other comprehensive income. 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 to earnings. Gains and losses on commodity hedge derivatives are recognized in oil and gas revenues, and 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.



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##### Index to Financial Statements

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 |          | Unrealized and Realized  |                                                                                                                      | Derivative fair value (gain) loss in the Consolidated Income Statements                          
|                                                                 
|Hedge derivatives  effective portion                             |          | Unrealized               |                                                                                                                      | Accumulated other comprehensive income in Stockholders Equity on 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 or the designated hedged transaction is not likely to occur, any unrealized gains or losses on the
derivative 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 which 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).



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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 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)                                          |  | 2003        |         |   | 2002 |       
|                                                        |  | Amount      |         |   | Mcf  |        |   | Amount |   |         | Mcf | 
|Accounts receivable - current underproduction           |  | $           | 23,949  |   |      | 7,135  |   |        | $ | 17,248  |     |  | 6,178  |  
|Accounts payable - current overproduction               |  |             | (19,366 | ) |      | (5,900 | ) |        |   | (14,381 | )   |  | (5,165 | )
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net current gas underproduction balancing receivable    |  | $           | 4,583   |   |      | 1,235  |   |        | $ | 2,867   |     |  | 1,013  |  
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Other assets - noncurrent underproduction               |  | $           | 19,385  |   |      | 6,148  |   |        | $ | 14,934  |     |  | 5,642  |  
|Other long-term liabilities - noncurrent overproduction |  |             | (29,776 | ) |      | (9,353 | ) |        |   | (23,027 | )   |  | (8,492 | )
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net long-term gas overproduction balancing payable      |  |             | (10,391 | ) |      | (3,205 | ) |        |   | (8,093  | )   |  | (2,850 | )
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Other assets - carbon dioxide underproduction           |  |             | 1,977   |   |      | 12,354 |   |        |   | 1,868   |     |  | 11,675 |  
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  
|Net long-term overproduction balancing payable          |  | $           | (8,414  | ) |      |        |   |        | $ | (6,225  | )   |  |        |  
|                                                        |  |             |         |   |      |        |   |        |   |         |     |  |        |  



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 $66. 3 million for 2003, $55.6 million for 2002 and $108.6 million for 2001. These amounts are net of intercompany eliminations.



Other Revenues



Other 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 $553,000 in 2003, $836,000 in 2002 and $716,000 in 2001, and net of capitalized interest of $2.2 million in 2003, $4.3 million in 2002 and $6.6 million in 2001. Interest
is capitalized as producing property cost based on the weighted average interest rate and the cost of wells in process of drilling.



Stock-Based Compensation



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



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



|                                                                                                                               |  |                        |         |   |      |   |         |      |  |   |         |  
|------------------------------------------------------------------------------------------------------------------------------ |  | ---------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                                                                                               |  | Year Ended December 31 |        
|(in thousands, except per share data)                                                                                          |  | 2003                   |         |   | 2002 |   |         | 2001 | 
|Net income as reported                                                                                                         |  | $                      | 288,279 |   |      | $ | 186,059 |      |  | $ | 248,816 |  
|Add stock-based compensation expense included in the income statement, net of related tax effects                              |  |                        | 34,530  |   |      |   | 17,543  |      |  |   | 5,674   |  
|Deduct stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects |  |                        | (33,498 | ) |      |   | (19,762 | )    |  |   | (49,947 | )
|                                                                                                                               |  |                        |         |   |      |   |         |      |  |   |         |  
|Pro forma net income                                                                                                           |  | $                      | 289,311 |   |      | $ | 183,840 |      |  | $ | 204,543 |  
|                                                                                                                               |  |                        |         |   |      |   |         |      |  |   |         |  
|Earnings per share:                                                                                                            |  |                        |         |   |      |   |         |      |  |   |         |  
|Basic - as reported                                                                                                            |  | $                      | 1.28    |   |      | $ | 0.89    |      |  | $ | 1.22    |  
|                                                                                                                               |  |                        |         |   |      |   |         |      |  |   |         |  
|Basic - pro forma                                                                                                              |  | $                      | 1.29    |   |      | $ | 0.88    |      |  | $ | 1.00    |  
|                                                                                                                               |  |                        |         |   |      |   |         |      |  |   |         |  
|Diluted - as reported                                                                                                          |  | $                      | 1.27    |   |      | $ | 0.88    |      |  | $ | 1.20    |  
|                                                                                                                               |  |                        |         |   |      |   |         |      |  |   |         |  
|Diluted - pro forma                                                                                                            |  | $                      | 1.27    |   |      | $ | 0.87    |      |  | $ | 0.98    |  
|                                                                                                                               |  |                        |         |   |      |   |         |      |  |   |         |  



Earnings per Common
Share



In accordance with SFAS No. 128, Earnings Per
Share, we report basic earnings per share, which excludes the effect of potentially dilutive securities, and diluted earnings per share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive.
Unvested performance stock awards are included in the basic earnings per share calculation. 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, 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. For the year ended December 31, 2001, sales to each of
three purchasers were approximately 13%, 12% and 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.
Because of declining credit ratings of some of our customers, we have greater concentrations of credit with a few large integrated energy companies with investment-grade ratings.



New Accounting Pronouncements



In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, Accounting for Certain Financial Instruments
with Characteristics of Both Liabilities and Equity,which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Such financial instruments include
mandatorily redeemable shares of stock, obligations to repurchase the issuers equity shares and obligations that an issuer may settle by issuing a variable number of its equity shares. The Statement is effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. In November 2003, the effective date for SFAS No. 150 was deferred for provisions relating to certain
financial instruments issued by consolidated subsidiaries. None of our consolidated entities currently have any of these financial instruments, and we do not anticipate SFAS No. 150 will have a material effect on future financial position or
earnings.



In December 2003, the Financial Accounting
Standards Board issued a revision of Interpretation No. 46 to clarify consolidation requirements for variable interest entities. We do not anticipate this interpretation to have an effect on our financial statements since we do not have interests in
variable interest entities.



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Also in December 2003, the Financial Accounting Standards Board revised SFAS No. 132, revising
disclosures required about pensions and other post-retirement benefits. These revised disclosures are included in Note 12 for our post-retirement health plan. In accordance with a deferred effective date, future annual reporting will disclose future
plan benefit payments expected to be paid for each of the five years following the latest balance sheet date and in the aggregate for the following five years.



In January 2004, the Financial Accounting Standards Board issued Staff Position No. 106-1 regarding treatment in post-retirement health plan
accounting and disclosures for the effects of the Medicare Prescription Drug, Improvement and Modernization Act, which was signed by the President into law in December 2003. Because our post-retirement health plan does not provide prescription drug
coverage beyond the date of eligibility for Medicare coverage, this change in Medicare coverage does not impact estimates for our benefit costs.



2. Related Party Transactions



Loans to Officers



In 1998 and 1999, five officers were loaned a total of $7.3 million to provide margin support for broker accounts where the officers held company Common
stock. The loans were full recourse and due in December 2003, with an interest rate equal to our bank debt rate. In 2001, the officers fully repaid the loans and accrued interest. A portion of the repayment was funded by our market price purchase of
503,000 shares of our common stock from the officers for $6.5 million.



Other Transactions



In February 2004, our
Board of Directors approved an agreement with a firm, partially owned by one of our directors, to establish fees that will be paid in connection with any advisory services the firm provides for up to $800 million in future acquisitions. The
agreement is effective as of November 2003. For the first acquisition, we will pay a fee of $250,000 plus a transaction fee equal to 0.75% of the purchase price. For any subsequent acquisition closing, we will pay only the transaction fee. The
initial term of the agreement expires December 31, 2004. To date, we have not paid the director-related company any amounts under this agreement. This director-related company represented the seller of properties for acquisitions totaling
approximately $186 million that we closed in January 2004.



In
connection with our sale of properties in 1999, the same director-related Company represented the purchaser and also invested in the purchase. We invested $584,000 in a limited partnership which had a small interest in these properties. Based on an
impairment evaluation in 2003, we have written down this investment to $100,000.



The same director-related company performed consulting services in connection with our acquisition of properties in East Texas, Louisiana and the San Juan Basin of New Mexico during 2002 (Note 13). The
director-related company received a fee of $2.4 million for these services, which was 1% of the total of the property purchase price and the related exchange transaction value.



The same director-related company performed consulting services in connection with a 1998 acquisition and was entitled to
receive, at its election, either a 20% working interest or a 1% overriding royalty interest conveyed from our 100% working interest in the properties after payout of acquisition and operating costs. The Board of Directors authorized the purchase of
this potential interest from the director-related company and other parties in November 2001 for $15 million, as supported by a third-party fairness opinion. The director-related company received $10 million of the total purchase price.



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##### Index to Financial Statements

3. Debt



Our long-term debt consists of the following:



|                                                                                            |  |             |           |      |   |          
|------------------------------------------------------------------------------------------- |  | ----------- | --------- | ---- | - | ---------
|                                                                                            |  | December 31
|(in thousands)                                                                              |  | 2003        |           | 2002
|Senior debt-                                                                                |  |             |           |      |   |          
|Bank debt under revolving credit agreements due May 12, 2005(a), 2.54% at December 31, 2003 |  | $           | 502,000   |      | $ | 605,000  
|71⁄2% senior notes due April 15, 2012                                                         |  |             | 350,000   |      |   | 350,000  
|61⁄4% senior notes due April 15, 2013                                                         |  |             | 400,000   |      |   |         
|Subordinated debt-                                                                          |  |             |           |      |   |          
|83⁄4% senior subordinated notes due November 1, 2009                                          |  |             |          |      |   | 163,170  
|                                                                                            |  |             |           |      |   |          
|Total long-term debt                                                                        |  | $           | 1,252,000 |      | $ | 1,118,170
|                                                                                            |  |             |           |      |   |          

---

|(a) | In February 2004, we extended the maturity of bank debt
upon entering a new revolving credit agreement that is due in February 2009.
|--- | ------------------------------------------------------------------------------------------------------------------------------------



Senior Debt



In May 2000, we entered a revolving credit agreement with commercial banks with a commitment of $800 million. Borrowings at December 31, 2003 under the
loan agreement were $502 million with unused borrowing capacity of $298 million. Borrowings under the loan agreement at December 31, 2003 were based on London Interbank Offered Rates (LIBOR) with maturity of one to six months and accrued
at the applicable LIBOR rate plus 1.375%. The weighted average interest rate on bank debt was 2.6% during 2003, 3.2% during 2002 and 5.7% during 2001.



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 new agreement provides for an initial commitment amount of $800 million, which may be increased to a maximum of $1 billion, and an interest rate based on LIBOR plus 1%. The loan agreement provides the option of borrowing at
floating interest rates based on the prime rate or at fixed rates for periods of up to six months based on 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 2004. 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. Our borrowings under the loan agreement were $169 million at February 27, 2004, with an interest rate of 2.16% and unused borrowing capacity of $631 million.



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 from the sale of notes 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 pursuant to Rule 144A under the Securities Act of 1933, which allows unregistered transactions with qualified institutional buyers. The notes were effectively registered with the Securities and Exchange Commission in June 2003. Interest is
payable each April 15 and October 15. Net proceeds of $393.4 million from the sale of notes, 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. Net proceeds of approximately
$490 million were used to fund our January 2004 property acquisitions of $243 million (Note 13) and to reduce bank debt. The notes mature on February 1, 2014 and interest is payable each February 1 and August 1 beginning August 1, 2004.



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##### Index to Financial Statements

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 1⁄2%. All of our senior notes are general unsecured senior indebtedness ranking equal to our other senior unsecured notes and above any senior subordinated notes.



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



Our effective income tax rate was different than the statutory federal income tax rate for the following reasons:



|                                                       |  |      |         |      |   |         |      |  |   |        
|------------------------------------------------------ |  | ---- | ------- | ---- | - | ------- | ---- |  | - | -------
|(in thousands)                                         |  | 2003 |         | 2002 |   |         | 2001
|Income tax expense at the federal statutory rate (35%) |  | $    | 155,579 |      | $ | 100,362 |      |  | $ | 159,375
|State and local income taxes and other                 |  |      | 2,430   |      |   | 328     |      |  |   | 2,577  
|                                                       |  |      |         |      |   |         |      |  |   |        
|Income tax expense                                     |  | $    | 158,009 |      | $ | 100,690 |      |  | $ | 161,952
|                                                       |  |      |         |      |   |         |      |  |   |        
|                                                       |  |      |        
|Components of income tax expense are as follows:       |  |      |         |      |   |         |      |  |   |        
|                                                       |  |      |        
|(in thousands)                                         |  | 2003 |         | 2002 |   |         | 2001
|Current income tax                                     |  | $    | 294     |      | $ | 322     |      |  | $ | 847    
|Deferred income tax expense                            |  |      | 148,304 |      |   | 121,396 |      |  |   | 159,257
|Net operating loss carryforwards (added) used          |  |      | 9,411   |      |   | (21,028 | )    |  |   | 1,848  
|                                                       |  |      |         |      |   |         |      |  |   |        
|Income tax expense                                     |  | $    | 158,009 |      | $ | 100,690 |      |  | $ | 161,952
|                                                       |  |      |         |      |   |         |      |  |   |        



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 $32.5 million and a
long-term liability of $426.7 million at December 31, 2003 and as a current asset of $32.7 million and a long-term liability of $286.5 million at December 31, 2002. Significant components of net deferred tax assets and liabilities are:



|                                 |  |             |          |   |      |   |          |  
|-------------------------------- |  | ----------- | -------- | - | ---- | - | -------- | -
|                                 |  | December 31 |         
|(in thousands)                   |  | 2003        |          |   | 2002 |  
|Deferred tax assets:             |  |             |          |   |      |   |          |  
|Net operating loss carryforwards |  | $           | 84,001   |   |      | $ | 88,549   |  
|Derivative fair value loss       |  |             | 40,144   |   |      |   | 52,834   |  
|Other                            |  |             | 6,720    |   |      |   | 7,981    |  
|                                 |  |             |          |   |      |   |          |  
|Total deferred tax assets        |  |             | 130,865  |   |      |   | 149,364  |  
|                                 |  |             |          |   |      |   |          |  
|Deferred tax liabilities:        |  |             |          |   |      |   |          |  
|Property and equipment           |  |             | 507,447  |   |      |   | 374,614  |  
|Derivative fair value gain       |  |             | 4,199    |   |      |   | 14,581   |  
|Other                            |  |             | 13,494   |   |      |   | 13,961   |  
|                                 |  |             |          |   |      |   |          |  
|Total deferred tax liabilities   |  |             | 525,140  |   |      |   | 403,156  |  
|                                 |  |             |          |   |      |   |          |  
|Net deferred tax liabilities     |  | $           | (394,275 | ) |      | $ | (253,792 | )
|                                 |  |             |          |   |      |   |          |  



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As of December 31, 2003, we had estimated tax loss carryforwards of approximately $242 million, of which
$1 million are related to capital losses. The capital loss carryforwards expire in 2004, while the remaining ordinary loss carryforwards are scheduled to expire in 2010 through 2023. Approximately $22 million of the tax loss carryforwards are the
result of acquisitions. We have not booked any valuation allowance because we believe we have tax planning strategies available to realize our tax loss carryforwards.



5. 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. As of the January 1, 2003 adoption date of SFAS 143, we recorded 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. The
following is a reconciliation of the asset retirement obligation for the year ended December 31, 2003:



|                                                     |  |   |        |  
|---------------------------------------------------- |  | - | ------ | -
|(in thousands)                                       |  |   |       
|Asset retirement obligation, January 1               |  | $ | 75,256 |  
|Liability incurred upon acquiring and drilling wells |  |   | 13,879 |  
|Liability settled upon plugging and abandoning wells |  |   | (1,086 | )
|Accretion of discount expense                        |  |   | 5,330  |  
|                                                     |  |   |        |  
|Asset retirement obligation, December 31             |  | $ | 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 and $54.7 million at January 1, 2001, if we had adopted SFAS No. 143 as of
those dates. The estimated pro forma effect of earlier adoption on 2002 and 2001 net income and earnings per share is not material.



We have not estimated the fair value of assets legally restricted for purposes of settling asset retirement obligations because such determination
involves complex assumptions and considerable analysis. See Note 16 for information reporting the standardized measure of future net cash flows from proved reserves, using assumptions required by the Financial Accounting Standards Board.



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, 2003, minimum future lease payments for all noncancelable lease agreements (including the sale and
operating leaseback agreements described below) were as follows:



|               |  |   |        
|-------------- |  | - | -------
|(in thousands) |  |  
|2004           |  | $ | 23,343 
|2005           |  |   | 20,522 
|2006           |  |   | 15,712 
|2007           |  |   | 14,788 
|2008           |  |   | 14,248 
|Remaining      |  |   | 38,306 
|               |  |   |        
|Total          |  | $ | 126,919
|               |  |   |        



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Amounts incurred under operating leases (including renewable monthly leases) were $31.7 million in 2003,
$26.6 million in 2002 and $20.6 million in 2001.



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. Rentals are adjusted monthly based on the 30-day LIBOR rate and may be irrevocably
fixed by us with 20 days advance notice. As of December 31, 2003, annual rentals were $1.4 million. 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, 2003 was $1 million.



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, 2003, maximum
commitments under our transportation contracts were as follows:





|               |  |   |        
|-------------- |  | - | -------
|(in thousands) |  |  
|2004           |  | $ | 12,982 
|2005           |  |   | 19,928 
|2006           |  |   | 20,490 
|2007           |  |   | 19,591 
|2008           |  |   | 18,804 
|Remaining      |  |   | 54,398 
|               |  |   |        
|               |  | $ | 146,193
|               |  |   |        



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



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



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##### Index to Financial Statements

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 prices. See Note 8.



Drilling Contracts



We have agreements to use 22 drilling rigs in 2004 with total commitments of
$45.2 million. Early termination of these contracts would require fees totaling $4.4 million in lieu of these commitments.



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 against us and certain of our subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The plaintiff alleges that we underpaid
royalties on gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% during at least the past 10 years as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. The
plaintiff also alleges that we have failed to pay the fair market value of the carbon dioxide produced. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each
violation and attorney fees and expenses. The plaintiff also seeks an order for us to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene and asked the court to unseal
the case. The court unsealed the case in May 1999. A multi-district litigation panel ordered that the lawsuits against us and other companies filed by Grynberg be transferred and consolidated to the federal district court in Wyoming. We believe that
the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.



In June 2001, we were served with a lawsuit styled Price,
et al. v. Gas Pipelines, et al.(formerly Quinque case). The action was filed in the District Court of Stevens County, Kansas, against us and one of our subsidiaries, along with over 200 natural gas transmission companies, producers,
gatherers and processors of natural gas. Plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the defendants had purchased
natural gas or who received economic benefit from the sale of such gas since January 1, 1974. The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims to cover all oil and gas
leases (other than the Federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas delivered into their pipelines
resulting in underpayments to the plaintiffs. Plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other
common law causes of action. The amount of damages was not specified in the complaint. In February 2002, we, 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. 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 as to gas measured in Kansas, Colorado and Wyoming. We believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability
from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.



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. 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, which 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



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##### Index to Financial Statements

petition in that it has a proposed class of only royalty owners, alleges conspiracy, unjust enrichment and accounting, and only applies as to gas measured in
Kansas, Colorado and Wyoming. The amount of damages was not specified in the complaint. 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 April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross Timbers Oil Company, was filed against us in the District Court of Dewey
County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which we have assumed the obligation to pay royalties.
The plaintiffs alleged that we reduced royalty payments by post-production deductions and entered into contracts with subsidiaries that were not arms-length transactions. The plaintiffs further alleged that these actions reduced the royalties
paid to the plaintiffs and those similarly situated, and that such actions were a breach of the leases under which the royalties are paid. In July 2003, we paid $2.5 million to settle the plaintiffs claims for the period January 1, 1993
through June 30, 2002. Our portion of this liability, net of amounts allocable to Hugoton Royalty Trust units we do not own, was $2.1 million, which had been accrued in our financial statements.



In February 2000, the Department of Interior notified us and several other
producers that certain Native American leases located in the San Juan Basin had expired because of the failure of the leases to produce in paying quantities from February through August 1990. The Department of Interior demanded abandonment of the
property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. In January 2004, the Department of Interior withdrew its claim against us.



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.



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.



On January 1, 2001, we adopted SFAS No. 133, as amended by SFAS Nos. 137, 138 and 149, by recording a one-time after-tax charge of $44.6 million in the income statement for the cumulative effect of a change in accounting principle and an
unrealized loss of $67.3 million in accumulated other comprehensive income. The unrealized loss was related to the derivative fair value of cash flow hedges. The charge to the income statement was primarily related to our physical delivery contract
with crude oil-based pricing, also referred to as the Enron Btu swap contract.



We often 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.



In accordance with SFAS No. 133, all derivatives are recorded on the balance sheet at estimated fair market value.



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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. Because the contract pricing was not clearly and closely associated with natural gas prices, it was considered a non-hedge derivative financial instrument under SFAS No. 133 beginning
January 1, 2001, 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 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. 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 related $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 natural gas sales through December 2005. See Note 8.



Interest Rate Swap Agreements



In September 1998, to reduce variable interest rate exposure on debt, we entered into a series of interest rate swap agreements, effectively fixing our interest rate at an average of 6.9% on a total notional balance of $150 million until
September 2005. In 1999 and 2000, we terminated these interest rate swaps, resulting in a gain of $2 million. This gain has been deferred and is being amortized against interest expense through September 2005.



Derivative Fair Value (Gain) Loss



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



|                                                                                   |  |      |        |   |      |   |        |      |  |   |         |  
|---------------------------------------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------- | -
|(in thousands)                                                                     |  | 2003 |        |   | 2002 |   |        | 2001 | 
|Change in fair value of Btu swap contracts                                         |  | $    | 5,115  |   |      | $ | 1,046  |      |  | $ | (23,428 | )
|Change in fair value of other derivatives that do not qualify for hedge accounting |  |      | (2,187 | ) |      |   | (6,505 | )    |  |   | (31,099 | )
|Ineffective portion of derivatives qualifying for hedge accounting                 |  |      | 7,273  |   |      |   | 2,860  |      |  |   | 157     |  
|                                                                                   |  |      |        |   |      |   |        |      |  |   |         |  
|Derivative fair value (gain) loss                                                  |  | $    | 10,201 |   |      | $ | (2,599 | )    |  | $ | (54,370 | )
|                                                                                   |  |      |        |   |      |   |        |      |  |   |         |  



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##### Index to Financial Statements

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, 2003 and 2002. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:



|                                           |  |                   |            |   |                   |   |            |                 |  |   |            |   |  |   |            |  
|------------------------------------------ |  | ----------------- | ---------- | - | ----------------- | - | ---------- | --------------- |  | - | ---------- | - |  | - | ---------- | -
|                                           |  | Asset (Liability) |           
|                                           |  | December 31, 2003 |            |   | December 31, 2002 |  
|(in thousands)                             |  | Carrying Amount   |            |   | Fair Value        |   |            | Carrying Amount |  |   | Fair Value |  
|Derivative Assets:                         |  |                   |            |   |                   |   |            |                 |  |   |            |   |  |   |            |  
|Fixed-price natural gas futures and swaps  |  | $                 | 11,997     |   |                   | $ | 11,997     |                 |  | $ | 41,483     |   |  | $ | 41,483     |  
|Fixed-price crude futures and differential |  |                   |           |   |                   |   |           |                 |  |   | 177        |   |  |   | 177        |  
|Derivative Liabilities:                    |  |                   |            |   |                   |   |            |                 |  |   |            |   |  |   |            |  
|Fixed-price natural gas futures and swaps  |  |                   | (96,702    | ) |                   |   | (96,702    | )               |  |   | (135,188   | ) |  |   | (135,188   | )
|Fixed-price crude futures and differential |  |                   |           |   |                   |   |           |                 |  |   | (2,886     | ) |  |   | (2,886     | )
|Btu swap contracts                         |  |                   | (17,995    | ) |                   |   | (17,995    | )               |  |   | (12,880    | ) |  |   | (12,880    | )
|                                           |  |                   |            |   |                   |   |            |                 |  |   |            |   |  |   |            |  
|Net derivative asset (liability)           |  | $                 | (102,700   | ) |                   | $ | (102,700   | )               |  | $ | (109,294   | ) |  | $ | (109,294   | )
|                                           |  |                   |            |   |                   |   |            |                 |  |   |            |   |  |   |            |  
|Long-term debt                             |  | $                 | (1,252,000 | ) |                   | $ | (1,275,285 | )               |  | $ | (1,118,170 | ) |  | $ | (1,146,572 | )
|                                           |  |                   |            |   |                   |   |            |                 |  |   |            |   |  |   |            |  



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



Changes in fair value of derivative assets and liabilities are the result of changes in oil and gas prices and interest rates. 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 until the hedged transaction occurs. We do not hold derivatives for trading or
speculative purposes.



Concentrations of Credit Risk



Although our cash equivalents and derivative financial
instruments 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. Because of declining credit ratings of some of our customers, we have greater concentrations of credit with a
few large integrated energy companies with investment grade ratings. Financial and commodity-based swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major
investment grade financial institutions, and we have master netting agreements with most counterparties that provide for offsetting payables against receivables from separate swap contracts. Letters of credit or other appropriate security are
obtained as considered necessary to limit risk of loss. We recorded an allowance for collectibility of all accounts receivable of $6.3 million at December 31, 2003 and $5.5 million at December 31, 2002. Our bad debt provision was $1.3 million in
2003, $980,000 in 2002 and $978,000 in 2001.



8. Commodity Sales Commitments



Our policy is to routinely hedge a portion of our
production at commodity prices management deems attractive. While there is a risk we may not be able to realize the benefit of rising prices, management plans to continue this strategy because of the benefits of more predictable production growth
and cash flows. 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. We have
hedged a portion of our exposure to variability in future cash flows from natural gas sales through December 2005.



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Natural Gas



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



|                         |  |                                      |  |                           |     
|------------------------ |  | ------------------------------------ |  | ------------------------- | ----
|                         |  | Futures Contractsand Swap Agreements
|Production Period        |  | Mcf perDay                           |  | AverageNYMEX Priceper Mcf
|2004 March to June       |  | 380,000                              |  | $                         | 4.77
|July to December         |  | 400,000                              |  |                           | 4.77
|2005 January to December |  | 100,000                              |  |                           | 5.21



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 |   |         | Mid -Continent |  |   | Rockies |   |  | San JuanBasin |        |   | Total
|2004                 |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|March                |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|Mcf per day          |  |                   | 50,000 |   |                    |   | 120,000 |                |  |   | 70,000  |   |  |               | 10,000 |   |       |   | 65,000 |   |  | 315,000
|Basis per Mcf(a)     |  | $                 | (0.11  | ) |                    | $ | (0.04   | )              |  | $ | (0.24   | ) |  | $             | (0.56  | ) |       | $ | (0.57  | ) |  |        
|                     |  |                   |        |   |                    |  
|April to June        |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|Mcf per day          |  |                   | 70,000 |   |                    |   | 210,000 |                |  |   | 60,000  |   |  |               | 10,000 |   |       |   | 55,000 |   |  | 405,000
|Basis per Mcf(a)     |  | $                 | (0.12  | ) |                    | $ | (0.04   | )              |  | $ | (0.26   | ) |  | $             | (0.68  | ) |       | $ | (0.66  | ) |  |        
|                     |  |                   |        |   |                    |  
|July                 |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|Mcf per day          |  |                   | 70,000 |   |                    |   | 200,000 |                |  |   | 60,000  |   |  |               | 10,000 |   |       |   | 55,000 |   |  | 395,000
|Basis per Mcf (a)    |  | $                 | (0.12  | ) |                    | $ | (0.04   | )              |  | $ | (0.26   | ) |  | $             | (0.68  | ) |       | $ | (0.66  | ) |  |        
|                     |  |                   |        |   |                    |  
|August               |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|Mcf per day          |  |                   | 70,000 |   |                    |   | 180,000 |                |  |   | 60,000  |   |  |               | 10,000 |   |       |   | 55,000 |   |  | 375,000
|Basis per Mcf(a)     |  | $                 | (0.12  | ) |                    | $ | (0.04   | )              |  | $ | (0.26   | ) |  | $             | (0.68  | ) |       | $ | (0.66  | ) |  |        
|                     |  |                   |        |   |                    |  
|September to October |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|Mcf per day          |  |                   | 70,000 |   |                    |   | 160,000 |                |  |   | 60,000  |   |  |               | 10,000 |   |       |   | 55,000 |   |  | 355,000
|Basis per Mcf(a)     |  | $                 | (0.12  | ) |                    | $ | (0.04   | )              |  | $ | (0.26   | ) |  | $             | (0.68  | ) |       | $ | (0.66  | ) |  |        
|                     |  |                   |        |   |                    |  
|November to December |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|Mcf per day          |  |                   | 60,000 |   |                    |   | 30,000  |                |  |   | 60,000  |   |  |               | 5,000  |   |       |   | 55,000 |   |  | 210,000
|Basis per Mcf(a)     |  | $                 | (0.11  | ) |                    | $ | (0.05   | )              |  | $ | (0.26   | ) |  | $             | (0.66  | ) |       | $ | (0.66  | ) |  |        
|                     |  |                   |        |   |                    |  
|2005                 |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|January to March     |  |                   |        |   |                    |   |         |                |  |   |         |   |  |               |        |   |       |   |        |   |  |        
|Mcf per day          |  |                   | 10,000 |   |                    |   |        |                |  |   |        |   |  |               | 5,000  |   |       |   | 30,000 |   |  | 45,000 
|Basis per Mcf(a)     |  | $                 | (0.05  | ) |                    |   |        |                |  |   |        |   |  | $             | (0.66  | ) |       | $ | (0.66  | ) |  |        

---

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



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Net gains and losses on futures, collars and basis swap hedge contracts decreased gas revenue by $193
million in 2003 and $11.1 million in 2001, and 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 and $97 million in
2001. There were no fixed price physical delivery contracts in 2003. As of December 31, 2003, an unrealized pre-tax derivative fair value loss of $81.9 million, related to cash flow hedges of gas price risk, was recorded in accumulated other
comprehensive income. Based on December 31 mark-to-market prices, $81.4 million of this fair value loss is expected to be reclassified into earnings in 2004. 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 and February 2004 gas production resulted in reduced gas revenue of approximately $19.5 million, or $0.41 per Mcf.



Crude Oil



In 2003, net losses on oil futures hedge contracts decreased oil revenue by $3.9 million. 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, 2003, there were no outstanding oil futures, collars or basis swap contracts.



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 three-for-two common stock split on June 5, 2001, a
four-for-three stock split on March 18, 2003 and will effect a five-for-four stock split on March 17, 2004. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits.



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Common Stock



The following reflects our common stock activity:



|                                       |  |               |   |                    |         |  |         |  |         |   |  |        |  |       
|-------------------------------------- |  | ------------- | - | ------------------ | ------- |  | ------- |  | ------- | - |  | ------ |  | ------
|                                       |  | Shares Issued |   | Shares in Treasury
|(in thousands)                         |  | 2003          |   |                    | 2002    |  | 2001    |  | 2003    |   |  | 2002   |  | 2001  
|Balance, January 1                     |  | 226,225       |   |                    | 219,981 |  | 206,466 |  | 14,597  |   |  | 13,694 |  | 12,579
|Issuance/vesting of performance shares |  | 3,332         |   |                    | 1,668   |  | 1,110   |  | 1,188   |   |  | 784    |  | 361   
|Stock option and warrant exercises     |  | 3,342         |   |                    | 4,576   |  | 3,590   |  |        |   |  | 3      |  | 39    
|Treasury stock purchases               |  |              |   |                    |        |  |        |  | 113     |   |  | 116    |  | 715   
|Common stock offering                  |  | 17,250        |   |                    |        |  |        |  |        |   |  |       |  |      
|Preferred stock converted to common    |  |              |   |                    |        |  | 8,815   |  |        |   |  |       |  |      
|Cancellation of shares                 |  | (15,898       | ) |                    |        |  |        |  | (15,898 | ) |  |       |  |      
|                                       |  |               |   |                    |         |  |         |  |         |   |  |        |  |       
|Balance, December 31                   |  | 234,251       |   |                    | 226,225 |  | 219,981 |  |        |   |  | 14,597 |  | 13,694
|                                       |  |               |   |                    |         |  |         |  |         |   |  |        |  |       



In April 2003, we
completed a public offering of 17.3 million shares of common stock at $15.00 per share. 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.



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 15,898,000 shares.



As of March 15, 2004, 10.8 million shares remain under the May 2000 Board of
Directors authorization to repurchase 11.3 million shares of our common stock.



Stockholder Rights Plan



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



Shelf Registration
Statement



In June 2003, 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 $1 billion, at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including reduction of bank debt. In January 2004, we sold $500 million of 4.9%
senior notes under the shelf registration statement. See Note 3.



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##### Index to Financial Statements

Common Stock Warrants



As partial consideration for producing properties acquired in December 1997, we issued warrants to purchase 3.6 million
shares of common stock at a price of $4.02 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.



Common
Stock Dividends



The Board of Directors declared quarterly
dividends of $0.004 per common share for first quarter 2001 and $0.006 per common share each quarter for the remainder of 2001 and 2002 and $0.008 per common share for each quarter in 2003. In February 2004, the Board of Directors declared a first
quarter 2004 dividend of $0.01 per share. Because of the five-for-four stock split to be effected on March 17, 2004, this represents a 25% increase in the dividend rate.



Our ability to pay dividends is dependent upon available cash flow, as well as other factors. Although there is a cumulative
maximum restriction on distributions to common stockholders under our 71⁄2% senior note and 61⁄4% senior note covenants, because of retained and projected future earnings, we do not anticipate these restrictions will affect future dividends.



Series A Convertible Preferred Stock



During 2001, 1.1 million shares of convertible preferred stock were
converted into 8.8 million shares of common stock.



See also
Note 12.



10. Earnings Per Share



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



|                                      |  |          |         |        |         |                   |   |     
|------------------------------------- |  | -------- | ------- | ------ | ------- | ----------------- | - | ----
|(in thousands, except per share data) |  | Earnings |         | Shares |         | Earningsper Share
|2003                                  |  |          |         |        |         |                   |   |     
|Basic                                 |  | $        | 288,279 |        | 224,749 |                   | $ | 1.28
|                                      |  |          |         |        |         |                   |   |     
|Effect of dilutive securities:        |  |          |         |        |         |                   |   |     
|Stock options                         |  |          |        |        | 3,065   |                   |   |     
|                                      |  |          |         |        |         |                   |   |     
|Diluted                               |  | $        | 288,279 |        | 227,814 |                   | $ | 1.27
|                                      |  |          |         |        |         |                   |   |     
|2002                                  |  |          |         |        |         |                   |   |     
|Basic                                 |  | $        | 186,059 |        | 208,375 |                   | $ | 0.89
|                                      |  |          |         |        |         |                   |   |     
|Effect of dilutive securities:        |  |          |         |        |         |                   |   |     
|Stock options                         |  |          |        |        | 1,034   |                   |   |     
|Warrants                              |  |          |        |        | 1,406   |                   |   |     
|                                      |  |          |         |        |         |                   |   |     
|Diluted                               |  | $        | 186,059 |        | 210,815 |                   | $ | 0.88
|                                      |  |          |         |        |         |                   |   |     
|2001                                  |  |          |         |        |         |                   |   |     
|Basic                                 |  | $        | 248,816 |        | 204,176 |                   | $ | 1.22
|                                      |  |          |         |        |         |                   |   |     
|Effect of dilutive securities:        |  |          |         |        |         |                   |   |     
|Stock options                         |  |          |        |        | 806     |                   |   |     
|Preferred stock                       |  |          |        |        | 628     |                   |   |     
|Warrants                              |  |          |        |        | 2,100   |                   |   |     
|                                      |  |          |         |        |         |                   |   |     
|Diluted                               |  | $        | 248,816 |        | 207,710 |                   | $ | 1.20
|                                      |  |          |         |        |         |                   |   |     



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11. Supplemental Cash Flow Information



The consolidated statements of cash flows exclude the following non-cash transactions (Notes 9, 12 and 14):



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



| |  | Conversion of 1.1 million shares of preferred stock to 8.8 million shares of common stock in 2001
| | - | -------------------------------------------------------------------------------------------------



| |  | Performance shares activity, including:
| | - | ---------------------------------------



| |  | Grants of 3.3 million shares in 2003, 1.8 million shares in 2002 and 1.5 million shares in 2001 to key employees and nonemployee directors
| | - | ------------------------------------------------------------------------------------------------------------------------------------------



| |  | Vesting of 2.6 million in 2003, 2.1 million shares in 2002 and 1 million shares in 2001
| | - | ---------------------------------------------------------------------------------------



| |  | Forfeiture of 15,000 shares in 2003 and 15,000 shares in 2001
| | - | -------------------------------------------------------------



Interest payments in 2003 totaled $60.9 million (including $2.2 million of capitalized interest), $52.1 million in 2002 (including $4.3 million of
capitalized interest) and $59.6 million in 2001 (including $6.6 million of capitalized interest). Net income tax payments were $5.3 million during 2003 and $405,000 during 2002; income tax refunds were $140,000 in 2001.



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 is a non-cash tax benefit which is part of our net operating loss carryforward, and accordingly, is not reflected in our
consolidated statements of cash flows (Note 4). This tax benefit from exercise of stock options was $22.7 million in 2003, $1.8 million in 2002 and $14.1 million in 2001.



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 $5.2 million in 2003, $4.5 million in 2002 and $3.9 million in 2001.



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 for directors age 55 or older, with a minimum
of five years service. During 2003, our retiree medical plan was amended to provide benefits to employees with any combination of age and qualified years of service that total 60, with a minimum age of 45 and a minimum of five years full-time
service. Directors are eligible to receive benefits when their combined age and years of service on the Board totals 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 2003, 2002 and 2001 is as follows:



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|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|----------------------------------------------------------------------------------------- |  | ----------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                                                          |  | December 31 |       
|(in thousands)                                                                            |  | 2003        |        |   | 2002 |   |        | 2001 | 
|Change in benefit obligation:                                                             |  |             |        |   |      |   |        |      |  |   |        |  
|Benefit obligation at January 1                                                           |  | $           | 3,096  |   |      | $ | 1,078  |      |  | $ | 804    |  
|Service cost                                                                              |  |             | 729    |   |      |   | 477    |      |  |   | 221    |  
|Interest cost                                                                             |  |             | 275    |   |      |   | 185    |      |  |   | 62     |  
|Plan amendments                                                                           |  |             | 2,380  |   |      |   | 490    |      |  |   |       |  
|Actuarial (gain) loss                                                                     |  |             | (3,273 | ) |      |   | 904    |      |  |   | 1      |  
|Benefit payments                                                                          |  |             | (85    | ) |      |   | (38    | )    |  |   | (10    | )
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Benefit obligation at December 31                                                         |  | $           | 3,122  |   |      | $ | 3,096  |      |  | $ | 1,078  |  
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Amounts recognized in the consolidated balance sheet:                                     |  |             |        |   |      |   |        |      |  |   |        |  
|Funded status                                                                             |  | $           | (3,122 | ) |      | $ | (3,096 | )    |  | $ | (1,078 | )
|Unrecognized net actuarial (gain) loss                                                    |  |             | (3,391 | ) |      |   | 698    |      |  |   | (9     | )
|Unrecognized prior service cost                                                           |  |             | 2,738  |   |      |   | 424    |      |  |   |       |  
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Accrued benefit liability, as recognized in the consolidated balance sheet at December 31 |  | $           | (3,775 | ) |      | $ | (1,974 | )    |  | $ | (1,087 | )
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Components of net periodic benefit cost:                                                  |  |             |        |   |      |   |        |      |  |   |        |  
|Service cost                                                                              |  |             | 729    |   |      | $ | 477    |      |  | $ | 221    |  
|Interest cost                                                                             |  |             | 275    |   |      |   | 185    |      |  |   | 62     |  
|Amortization of prior service cost                                                        |  |             | 66     |   |      |   | 66     |      |  |   | 804    |  
|Recognized net actuarial loss                                                             |  |             | 731    |   |      |   | 159    |      |  |   |       |  
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  
|Net periodic benefit cost                                                                 |  | $           | 1,801  |   |      | $ | 887    |      |  | $ | 1,087  |  
|                                                                                          |  |             |        |   |      |   |        |      |  |   |        |  



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 2004 accrued benefit cost is expected to be less
than $1 million.



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



|                                                                              |  |      |   |  |      |   |  |      |  
|----------------------------------------------------------------------------- |  | ---- | - |  | ---- | - |  | ---- | -
|                                                                              |  | 2003 |   |  | 2002 |   |  | 2001 |  
|Weighted average discount rate                                                |  | 6.5  | % |  | 6.5  | % |  | 7.5  | %
|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                            |  | 2009 |   |  | 2008 |   |  | 2007 |  



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, 2003:



|                                                 |  |                      |     |          |   |    
|------------------------------------------------ |  | -------------------- | --- | -------- | - | ---
|                                                 |  | One Percentage Point
|(in thousands)                                   |  | Increase             |     | Decrease
|Effect on total service and interest cost        |  | $                    | 74  |          | $ | 63 
|Effect on the post-retirement benefit obligation |  | $                    | 370 |          | $ | 323



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1998 Stock Incentive Plan



Under the 1998 Stock Incentive Plan, a total of 22.5 million shares of common stock may be issued pursuant to grants of
stock options or performance shares. Grants under the 1998 Plan are subject to the provision that outstanding stock options and performance shares cannot exceed 6% of our outstanding common stock at the time such grants are made. Stock options
generally vest and become exercisable annually in equal amounts over a five-year period, with provision for accelerated vesting when the common stock price reaches specified levels. There were 4 million options outstanding at December 31, 2003 that
are exercisable, 14,000 options outstanding that vest when the common stock price reaches $23.86, 642,000 options outstanding that vest when the common stock price reaches $24.00, 642,000 options outstanding that vest when the common stock price
reaches $26.00 and 642,000 options outstanding that vest when the common stock price reaches $28.00. At December 31, 2003, there were 256,000 shares available for grant under the 1998 Plan. General and administrative expense includes compensation
related to stock options of $2.3 million in 2003 and $900,000 in 2001.



In February and March 2004, 14,000 options vested when the stock price reached $23.86, 642,000 options vested when the stock price reached $24.00 and 642,000 options vested when the stock price reached $26.00.



Performance Shares



Performance shares granted under the 1998 Plan are subject to restrictions
determined by the Compensation Committee of the Board of Directors and are subject to forfeiture if performance targets are not met. Otherwise, holders of performance shares generally have all the voting, dividend and other rights of other common
stockholders. We issued performance shares to key employees and nonemployee directors totaling 3.3 million in 2003, 1.8 million in 2002 and 1.5 million in 2001. The weighted average fair value of performance shares when granted was $19.61 per share
in 2003, $12.98 per share in 2002 and $10.98 per share in 2001. Performance shares vested, totaling 2.6 million in 2003, 2.1 million in 2002 and 1 million in 2001, when the common stock price reached specified levels. In 2003 and 2001, 15,000
performance shares issued in each of those years were forfeited. General and administrative expense includes compensation related to performance shares of $50.8 million in 2003, $27 million in 2002 and $8.7 million in 2001. Treasury stock purchases
related to vested performance shares totaled $22.7 million is 2003, $10.3 million in 2002 and $4.2 million in 2001.



At December 31, 2003, deferred compensation of $24.8 million was recorded as an offset to additional paid-in-capital for 1,096,000 performance shares
outstanding. These performance shares vest when the common stock reaches the following prices:



|                                        |  |              
|--------------------------------------- |  | -------------
|Shares Outstanding at December 31, 2003 |  | Vesting Price
|250,000                                 |  | $23.86       
|296,000                                 |  | $24.00       
|275,000                                 |  | $26.00       
|275,000                                 |  | $28.00       
|                                        |  |              
|1,096,000                               |  |              
|                                        |  |              



As of March 2, 2004,
the common stock price reached a high of $26.00, resulting in vesting of 821,000 performance shares outstanding at year end 2003, as well as 500,000 additional shares that were granted in February and March 2004 with vesting at $24.86 and $25.86.
Total non-cash incentive compensation related to 2004 vesting of performance shares through March 2 was $33.2 million. In March 2004, an additional 250,000 shares were granted that vest when the common stock price reaches $26.86.



As adjusted for stock splits, it has been the historical practice since 2001
for the Board of Directors to grant executive officers 250,000 performance shares with vesting that generally occurs at $1.00 increments in the common stock price. Before adjustment for stock splits, the grant to executive officers initially was for
100,000 performance shares with vesting and additional grants at $2.50 increments in the common stock price.



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##### Table of Contents

##### Index to Financial Statements

In 2001, the Board approved an agreement with certain executive officers under which the officers,
immediately prior to a change in control of the Company, will receive a total grant of 250,000 performance shares for every $1.00 increment in the closing price of our common stock above $12.00. Unless otherwise designated by the Board, the number
of performance shares granted under the agreement will be reduced by the number of performance shares awarded to the officers between the date of the agreement and the date of the change in control. Certain officers will also receive a total grant
of 387,500 performance shares immediately prior to a change in control without regard to the price of our common stock.



Option Activity and Balances



The following summarizes option activity and balances from 2001 through 2003:



|                           |  |                              |       |              |            |  
|-------------------------- |  | ---------------------------- | ----- | ------------ | ---------- | -
|                           |  | WeightedAverageExercisePrice |       | StockOptions |           
|                           |  |                             
|2001                       |  |                              |       |              |            |  
|Beginning of year          |  | $                            | 8.06  |              | 10,978,693 |  
|Grants                     |  |                              | 11.25 |              | 9,592,818  |  
|Exercises                  |  |                              | 7.91  |              | (8,876,091 | )
|Forfeitures                |  |                              | 11.29 |              | (135,000   | )
|                           |  |                              |       |              |            |  
|End of year                |  |                              | 10.76 |              | 11,560,420 |  
|                           |  |                              |       |              |            |  
|Exercisable at end of year |  |                              | 10.82 |              | 10,902,246 |  
|                           |  |                              |       |              |            |  
|                           |  |                             
|2002                       |  |                              |       |              |            |  
|Beginning of year          |  | $                            | 10.76 |              | 11,560,420 |  
|Grants                     |  |                              | 13.66 |              | 828,508    |  
|Exercises                  |  |                              | 8.69  |              | (1,193,579 | )
|Forfeitures                |  |                              | 10.53 |              | (54,798    | )
|                           |  |                              |       |              |            |  
|End of year                |  |                              | 11.20 |              | 11,140,551 |  
|                           |  |                              |       |              |            |  
|Exercisable at end of year |  |                              | 11.10 |              | 10,754,354 |  
|                           |  |                              |       |              |            |  
|                           |  |                             
|2003                       |  |                              |       |              |            |  
|Beginning of year          |  | $                            | 11.20 |              | 11,140,551 |  
|Grants                     |  |                              | 20.08 |              | 2,647,656  |  
|Exercises                  |  |                              | 11.27 |              | (7,822,592 | )
|Forfeitures                |  |                              | 18.51 |              | (41,250    | )
|                           |  |                              |       |              |            |  
|End of year                |  |                              | 14.87 |              | 5,924,365  |  
|                           |  |                              |       |              |            |  
|Exercisable at end of year |  |                              | 12.30 |              | 3,983,245  |  
|                           |  |                              |       |              |            |  



The following
summarizes information about outstanding options at December 31, 2003:



|                         |  |                     |  |                              |  |                              |       |        |           |                              |   |      
|------------------------ |  | ------------------- |  | ---------------------------- |  | ---------------------------- | ----- | ------ | --------- | ---------------------------- | - | -----
|                         |  | Options Outstanding |  | Options Exercisable         
|Range of Exercise Prices |  | Number              |  | WeightedAverageRemainingTerm |  | WeightedAverageExercisePrice |       | Number |           | WeightedAverageExercisePrice
|$ 6.06 - $  8.07         |  | 8,509               |  | 6.6 years                    |  | $                            | 6.16  |        | 8,509     |                              | $ | 6.16 
|$ 8.08 - $10.10          |  | 1,684,167           |  | 7.2 years                    |  | $                            | 9.43  |        | 1,684,167 |                              | $ | 9.43 
|$10.11 - $12.11          |  | 914,240             |  | 7.0 years                    |  | $                            | 10.97 |        | 914,240   |                              | $ | 10.97
|$12.12 - $14.13          |  | 703,543             |  | 8.8 years                    |  | $                            | 13.52 |        | 703,543   |                              | $ | 13.52
|$14.14 - $16.14          |  | 5,042               |  | 9.1 years                    |  | $                            | 14.27 |        | 5,042     |                              | $ | 14.27
|$16.15 - $18.17          |  | 28,364              |  | 9.6 years                    |  | $                            | 16.24 |        | 14,181    |                              | $ | 16.24
|$18.18 - $20.18          |  | 2,580,500           |  | 9.8 years                    |  | $                            | 20.18 |        | 653,563   |                              | $ | 20.18
|                         |  |                     |  |                              |  |                              |       |        |           |                              |   |      
|                         |  | 5,924,365           |  | 8.5 years                    |  | $                            | 14.87 |        | 3,983,245 |                              | $ | 12.30
|                         |  |                     |  |                              |  |                              |       |        |           |                              |   |      





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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 $7.30 in 2003, $5.82 in 2002 and $5.21 in 2001. Black-Scholes and alternative option-pricing models do not consider the effects of forfeitability and nontransferability on the valuation of employee stock options.



|                                |  |         |   |  |         |   |  |         |  
|------------------------------- |  | ------- | - |  | ------- | - |  | ------- | -
|                                |  | 2003    |   |  | 2002    |   |  | 2001    |  
|Risk-free interest rates        |  | 3.1     | % |  | 3.1     | % |  | 4.9     | %
|Dividend yield                  |  | 0.2     | % |  | 0.2     | % |  | 0.2     | %
|Weighted average expected lives |  | 4 years |   |  | 4 years |   |  | 4 years |  
|Volatility                      |  | 42      | % |  | 50      | % |  | 54      | %



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 2003, 2002 and 2001, 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) |  | 2003 |         | 2002 |   | 2001   
|Earnings available to common stock:   |  |      |         |      |   |         |  |   |        
|As reported                           |  | $    | 288,279 |      | $ | 186,059 |  | $ | 248,816
|Pro forma                             |  | $    | 289,311 |      | $ | 183,840 |  | $ | 204,543
|Earnings per common share:            |  |      |         |      |   |         |  |   |        
|Basic                                 |  |      |         |      |   |         |  |   |        
|As reported                           |  | $    | 1.28    |      | $ | 0.89    |  | $ | 1.22   
|Pro forma                             |  | $    | 1.29    |      | $ | 0.88    |  | $ | 1.00   
|Diluted                               |  |      |         |      |   |         |  |   |        
|As reported                           |  | $    | 1.27    |      | $ | 0.88    |  | $ | 1.20   
|Pro forma                             |  | $    | 1.27    |      | $ | 0.87    |  | $ | 0.98   



13. Acquisitions



In April 2003, we entered into a definitive agreement with units of Williams
of Tulsa, Oklahoma to acquire 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 $400 million. The transaction closed
in May 2003. After typical closing adjustments, the 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 entered into an agreement to acquire coal bed methane and natural gas producing properties in the San Juan
Basin of New Mexico and Colorado from Markwest Hydrocarbon, Inc. for $60.5 million. After typical closing adjustments and a reduction of $7.9 million withheld for a preferential purchase right, the final purchase price was $51 million, which was
funded through bank borrowings. The acquisition was completed in June 2003 and 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.



71



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##### Index to Financial Statements

In April 2002, we entered agreements to purchase properties in East Texas, Louisiana and the San Juan
Basin of New Mexico with a total cost of $144 million. These purchases, funded by our sale of senior notes in April 2002, were as follows:



| |  | Properties in the Powder River Basin of Wyoming from CMS Oil and Gas Co., a subsidiary of CMS Energy Corporation, for $101 million in May 2002,
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------



| |  | An exchange of the above Powder River Basin properties with Marathon Oil Company (Marathon), for gas-producing properties in East Texas and Louisiana in May 2002, and
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Gas-producing properties in the San Juan Basin of New Mexico from Marathon for $43 million in July 2002.
| | - | --------------------------------------------------------------------------------------------------------



In December 2002, we acquired from J. M. Huber Corporation coal bed methane gas-producing properties in the San Juan Basin
of southwestern Colorado for $153.8 million funded with bank debt.



Acquisitions were recorded using the purchase method of accounting. The following presents unaudited pro forma results of operations for 2003 and 2002, as if the Williams, Marathon and Huber 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
|                                                         |  | 2003                   |           | 2002
|Revenues                                                 |  | $                      | 1,230,967 |      | $ | 895,065
|                                                         |  |                        |           |      |   |        
|Net income before cumulative effect of accounting change |  | $                      | 292,989   |      | $ | 175,884
|                                                         |  |                        |           |      |   |        
|Net income                                               |  | $                      | 294,768   |      | $ | 175,884
|                                                         |  |                        |           |      |   |        
|Earnings per common share:                               |  |                        |           |      |   |        
|Basic                                                    |  | $                      | 1.31      |      | $ | 0.84   
|                                                         |  |                        |           |      |   |        
|Diluted                                                  |  | $                      | 1.29      |      | $ | 0.83   
|                                                         |  |                        |           |      |   |        
|Weighted average shares outstanding                      |  |                        | 224,749   |      |   | 208,375
|                                                         |  |                        |           |      |   |        



In January 2004, we
acquired producing properties located primarily in East Texas and northern Louisiana for $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).



On February 23, 2004, we announced that we entered into agreements with multiple parties to acquire producing properties located primarily in the Barnett
Shale of North Texas and in the Arkoma Basin for $200 million. The majority of the acquisitions are scheduled to close on or before April 15, 2004 and are subject to typical closing and post-closing adjustments. Funding will be provided by bank debt
and cash flow.



14. Cross Timbers Royalty Trust Distribution



In August 2003, our Board of Directors declared a dividend of 0.0059
units of Cross Timbers Royalty Trust for each share of our common stock outstanding on September 2, 2003. This dividend, totaling 1,360,000 trust 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, the
fair market value of the units based on the September 18, 2003 average high and low New York Stock Exchange trade price of $20.70. After considering the cost of the units, we recorded a gain on distribution of $16.2 million.



72



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##### Index to Financial Statements

15. Quarterly Financial Data(Unaudited)



The following are summarized quarterly financial data for the years ended
December 31, 2003 and 2002:



|                                      |  |         |         |     |   |         |  |     |         |  |   |        
|------------------------------------- |  | ------- | ------- | --- | - | ------- |  | --- | ------- |  | - | -------
|                                      |  | Quarter
|(in thousands, except per share data) |  | 1st     |         | 2nd |   | 3rd     |  | 4th
|2003                                  |  |         |         |     |   |         |  |     |         |  |   |        
|Revenues                              |  | $       | 253,484 |     | $ | 282,159 |  | $   | 322,058 |  | $ | 331,854
|Gross profit (a)                      |  | $       | 125,532 |     | $ | 140,274 |  | $   | 172,789 |  | $ | 170,744
|Net income                            |  | $       | 66,230  |     | $ | 57,335  |  | $   | 102,806 |  | $ | 61,908 
|Earnings per common share:            |  |         |         |     |   |         |  |     |         |  |   |        
|Basic                                 |  | $       | 0.31    |     | $ | 0.25    |  | $   | 0.45    |  | $ | 0.27   
|Diluted                               |  | $       | 0.31    |     | $ | 0.25    |  | $   | 0.44    |  | $ | 0.26   
|Average shares outstanding            |  |         | 211,697 |     |   | 225,206 |  |     | 229,740 |  |   | 232,073
|2002                                  |  |         |         |     |   |         |  |     |         |  |   |        
|Revenues                              |  | $       | 179,964 |     | $ | 189,151 |  | $   | 201,708 |  | $ | 239,340
|Gross profit (a)                      |  | $       | 92,962  |     | $ | 88,782  |  | $   | 100,812 |  | $ | 128,390
|Net income                            |  | $       | 45,068  |     | $ | 34,610  |  | $   | 50,293  |  | $ | 56,088 
|Earnings per common share:            |  |         |         |     |   |         |  |     |         |  |   |        
|Basic                                 |  | $       | 0.22    |     | $ | 0.17    |  | $   | 0.24    |  | $ | 0.27   
|Diluted                               |  | $       | 0.22    |     | $ | 0.16    |  | $   | 0.24    |  | $ | 0.26   
|Average shares outstanding            |  |         | 206,367 |     |   | 206,835 |  |     | 209,043 |  |   | 211,196

---

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



16. 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)                           |  | 2003 |           | 2002 |   | 2001   
|Acquisitions:                            |  |      |           |      |   |         |  |   |        
|Producing properties                     |  | $    | 623,775   |      | $ | 354,110 |  | $ | 238,041
|Undeveloped properties                   |  |      | 5,678     |      |   | 3,977   |  |   | 3,980  
|Development (a)                          |  |      | 460,241   |      |   | 354,083 |  |   | 385,479
|Exploration:                             |  |      |           |      |   |         |  |   |        
|Geological and geophysical studies       |  |      | 639       |      |   | 792     |  |   | 2,123  
|Dry hole expense                         |  |      | 26        |      |   | 242     |  |   | 2,189  
|Rental expense and other                 |  |      | 1,146     |      |   | 1,152   |  |   | 1,126  
|Asset retirement obligation accrual:     |  |      |           |      |   |         |  |   |        
|As of January 1, 2003 (b)                |  |      | 75,256    |      |   |        |  |   |       
|For the year ended December 31, 2003 (c) |  |      | 13,879    |      |   |        |  |   |       
|                                         |  |      |           |      |   |         |  |   |        
|Total                                    |  | $    | 1,180,640 |      | $ | 714,356 |  | $ | 632,938
|                                         |  |      |           |      |   |         |  |   |        

---

|(a) | Includes capitalized interest of $2.2 million in 2003, $4.3 million in 2002 and $6.6 million in 2001.
|--- | -----------------------------------------------------------------------------------------------------



|(b) | Recorded upon adoption of SFAS No. 143 on January 1, 2003.
|--- | ----------------------------------------------------------



|(c) | Recorded upon acquiring and drilling wells in 2003, as required by SFAS No. 143.
|--- | --------------------------------------------------------------------------------



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##### Index to Financial Statements

Proved Reserves



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



Standardized Measure



The standardized measure of discounted future net cash
flows (standardized measure) 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).



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 of discounted cash flows, 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) |  
|Proved Reserves                       |  |           |   |  |                           |   |  |           |  
|December 31, 2000                     |  | 1,769,683 |   |  | 22,012                    |   |  | 58,445    |  
|Revisions                             |  | (96,990   | ) |  | (2,193                    | ) |  | (4,201    | )
|Extensions, additions and discoveries |  | 469,602   |   |  | 2,081                     |   |  | 3,317     |  
|Production                            |  | (152,178  | ) |  | (1,601                    | ) |  | (4,978    | )
|Purchases in place                    |  | 248,339   |   |  |                          |   |  | 1,484     |  
|Sales in place                        |  | (2,978    | ) |  |                          |   |  | (18       | )
|                                      |  |           |   |  |                           |   |  |           |  
|December 31, 2001                     |  | 2,235,478 |   |  | 20,299                    |   |  | 54,049    |  
|Revisions                             |  | 76,400    |   |  | 2,433                     |   |  | 5,465     |  
|Extensions, additions and discoveries |  | 426,541   |   |  | 2,395                     |   |  | 1,144     |  
|Production                            |  | (187,583  | ) |  | (1,850                    | ) |  | (4,757    | )
|Purchases in place                    |  | 330,387   |   |  | 2,156                     |   |  | 449       |  
|Sales in place                        |  | (42       | ) |  |                          |   |  | (1        | )
|                                      |  |           |   |  |                           |   |  |           |  
|December 31, 2002                     |  | 2,881,181 |   |  | 25,433                    |   |  | 56,349    |  
|Revisions                             |  | (11,644   | ) |  | 5,487                     |   |  | 1,792     |  
|Extensions, additions and discoveries |  | 559,773   |   |  | 1,610                     |   |  | 424       |  
|Production                            |  | (243,979  | ) |  | (2,359                    | ) |  | (4,724    | )
|Purchases in place                    |  | 465,732   |   |  | 4,508                     |   |  | 2,204     |  
|Sales in place                        |  | (6,824    | ) |  | (1                        | ) |  | (614      | )
|                                      |  |           |   |  |                           |   |  |           |  
|December 31, 2003                     |  | 3,644,239 |   |  | 34,678                    |   |  | 55,431    |  
|                                      |  |           |   |  |                           |   |  |           |  



74



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##### Index to Financial Statements

|                          |  |           |  |                           |  |          
|------------------------- |  | --------- |  | ------------------------- |  | ---------
|(in thousands)            |  | Gas (Mcf) |  | Natural GasLiquids (Bbls) |  | Oil(Bbls)
|Proved Developed Reserves |  |           |  |                           |  |          
|December 31, 2000         |  | 1,328,953 |  | 16,448                    |  | 46,334   
|                          |  |           |  |                           |  |          
|December 31, 2001         |  | 1,452,222 |  | 14,774                    |  | 41,231   
|                          |  |           |  |                           |  |          
|December 31, 2002         |  | 2,042,661 |  | 19,367                    |  | 47,178   
|                          |  |           |  |                           |  |          
|December 31, 2003         |  | 2,651,259 |  | 28,187                    |  | 47,882   
|                          |  |           |  |                           |  |          



|                                                                                     |  |             |            |   |      |   |            |      |  |   |            |  
|------------------------------------------------------------------------------------ |  | ----------- | ---------- | - | ---- | - | ---------- | ---- |  | - | ---------- | -
|                                                                                     |  | December 31 |           
|Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves |  | 2003        |            |   | 2002 |   |            | 2001 | 
|(in thousands)                                                                       |  |             |            |   |      |   |            |      | 
|Future cash inflows                                                                  |  | $           | 23,213,223 |   |      | $ | 14,734,787 |      |  | $ | 6,366,557  |  
|Future costs:                                                                        |  |             |            |   |      |   |            |      |  |   |            |  
|Production                                                                           |  |             | (5,207,502 | ) |      |   | (3,518,614 | )    |  |   | (1,989,344 | )
|Development                                                                          |  |             | (875,665   | ) |      |   | (687,723   | )    |  |   | (620,611   | )
|                                                                                     |  |             |            |   |      |   |            |      |  |   |            |  
|Future net cash flows before income tax                                              |  |             | 17,130,056 |   |      |   | 10,528,450 |      |  |   | 3,756,602  |  
|Future income tax                                                                    |  |             | (5,292,609 | ) |      |   | (3,144,235 | )    |  |   | (879,874   | )
|                                                                                     |  |             |            |   |      |   |            |      |  |   |            |  
|Future net cash flows                                                                |  |             | 11,837,447 |   |      |   | 7,384,215  |      |  |   | 2,876,728  |  
|10% annual discount                                                                  |  |             | (5,709,208 | ) |      |   | (3,510,630 | )    |  |   | (1,354,679 | )
|                                                                                     |  |             |            |   |      |   |            |      |  |   |            |  
|Standardized measure(a)                                                              |  | $           | 6,128,239  |   |      | $ | 3,873,585  |      |  | $ | 1,522,049  |  
|                                                                                     |  |             |            |   |      |   |            |      |  |   |            |  

---

|(a) | Before income tax, the year-end standardized measure (or discounted present value of future net cash flows) was $8.8 billion in
2003, $5.5 billion in 2002 and $1.9 billion in 2001.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



75



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##### Index to Financial Statements

|                                                                    |  |      |           |     |      |   |            |      |  |   |            |  
|------------------------------------------------------------------- |  | ---- | --------- | --- | ---- | - | ---------- | ---- |  | - | ---------- | -
|Changes in Standardized Measure of Discounted Future Net Cash Flows |  | 2003 |           |     | 2002 |   |            | 2001 | 
|(in thousands)                                                      |  |      |           |     |      |   |            |      | 
|Standardized measure, January 1                                     |  | $    | 3,873,585 |     |      | $ | 1,522,049  |      |  | $ | 5,262,030  |  
|                                                                    |  |      |           |     |      |   |            |      |  |   |            |  
|Revisions:                                                          |  |      |           |     |      |   |            |      |  |   |            |  
|Prices and costs                                                    |  |      | 1,469,243 |     |      |   | 2,554,295  |      |  |   | (6,285,062 | )
|Quantity estimates                                                  |  |      | 207,955   |     |      |   | 209,061    |      |  |   | 173,587    |  
|Accretion of discount                                               |  |      | 338,895   |     |      |   | 136,924    |      |  |   | 455,788    |  
|Future development costs                                            |  |      | (493,856  | )   |      |   | (344,531   | )    |  |   | (408,772   | )
|Income tax                                                          |  |      | (961,584  | )   |      |   | (1,122,283 | )    |  |   | 2,278,522  |  
|Production rates and other                                          |  |      | 2,372     |     |      |   | 821        |      |  |   | 1,090      |  
|                                                                    |  |      |           |     |      |   |            |      |  |   |            |  
|Net revisions                                                       |  |      | 563,025   |     |      |   | 1,434,287  |      |  |   | (3,784,847 | )
|Extensions, additions and discoveries                               |  |      | 1,114,577 |     |      |   | 632,200    |      |  |   | 252,524    |  
|Production                                                          |  |      | (905,910  | )   |      |   | (610,064   | )    |  |   | (653,626   | )
|Development costs                                                   |  |      | 434,554   |     |      |   | 326,219    |      |  |   | 312,435    |  
|Purchases in place(a)                                               |  |      | 1,064,533 |     |      |   | 568,940    |      |  |   | 148,111    |  
|Sales in place(b)                                                   |  |      | (16,125   | )   |      |   | (46        | )    |  |   | (14,578    | )
|                                                                    |  |      |           |     |      |   |            |      |  |   |            |  
|Net change                                                          |  |      | 2,254,654 |     |      |   | 2,351,536  |      |  |   | (3,739,981 | )
|                                                                    |  |      |           |     |      |   |            |      |  |   |            |  
|Standardized measure, December 31                                   |  | $    | 6,128,239 | (c) |      | $ | 3,873,585  |      |  | $ | 1,522,049  |  
|                                                                    |  |      |           |     |      |   |            |      |  |   |            |  

---

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



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



|(c) | The December 31, 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 $5.71 for 2003, $4.41 for 2002, $2.36 for 2001 and $9.55 for 2000. Year-end average realized natural gas liquids prices were $23.17 for 2003, $17.86 for 2002, $8.70 for 2001 and $26.33 for 2000. Year-end average realized oil prices were $30.55
for 2003, $29.69 for 2002, $17.39 for 2001 and $25.49 for 2000. Proved oil and gas reserves at December 31, 2003 include 200,705,000 Mcf of gas and 1,636,000 Bbls of oil and discounted present value before income tax of $426.8 million related to our
ownership of approximately 54% of Hugoton Royalty Trust units at December 31, 2003.



76



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##### Index to Financial Statements

INDEPENDENT AUDITORS REPORTS



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, 2003 and 2002, and the related consolidated income
statements, statements of cash flows and statements of stockholders equity for the years then ended. In connection with our audits of the 2003 and 2002 financial statements, we also have audited the 2003 and 2002 financial statement schedules.
These financial statements and financial statement schedules are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
The 2001 financial statements and financial statement schedule of XTO Energy Inc. were audited by other auditors who have ceased operations. Those auditors report dated March 28, 2002, on those financial statements and financial statement
schedule, was unqualified and included an explanatory paragraph that described the Companys change in method of accounting for its derivative instruments and hedging activities as discussed in Note 1 to the financial statements.



We conducted our audits in accordance with auditing standards generally accepted in the
United States of America. 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 2003 and 2002 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, 2003 and 2002, and the results of their
operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related 2003 and 2002 financial statement schedules, when considered in
relation to the basic 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.



KPMG LLP



Dallas, Texas

March 5, 2004



77



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##### Index to Financial Statements

To the Board of Directors and Stockholders of

XTO Energy Inc.



We have audited the
accompanying consolidated balance sheets of XTO Energy Inc. and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated income statements, statements of cash flows and stockholders equity for each of the three years in
the period ended December 31, 2001. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.



We conducted our audits in accordance with auditing standards generally accepted in the
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 the Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.



As discussed in Note 6 to Consolidated Financial Statements, the Company changed its method of accounting for its derivative instruments and hedging activities effective
January 1, 2001, in connection with its adoption of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended.



ARTHUR ANDERSEN LLP



Fort Worth, Texas

March 28, 2002



The above report of Arthur
Andersen LLP (Arthur Andersen) is a copy of a report previously issued by Arthur Andersen on March 28, 2002. This audit report has not been reissued by Arthur Andersen in connection with this filing on Form 10-K. After reasonable
efforts, we have been unable to obtain the consent of Arthur Andersen, our former independent auditors, as to the incorporation by reference of their report for our fiscal years ended December 31, 2001 and 2000 into the Companys previously
filed registration statements under the Securities Act of 1933, and we have not filed that consent with this Annual Report on Form 10-K in reliance on Rule 437a of the Securities Act of 1933. Because we have not been able to obtain Arthur
Andersens consent, you will not be able to recover against Arthur Andersen under Section ll of the Securities Act for any untrue statements of a material fact contained in our financial statements audited by Arthur Andersen or any omissions to
state a material fact required to be stated therein. For further information, see Exhibit 23.2 to this Annual Report on Form 10-K.



78



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##### Index to Financial Statements

SCHEDULE II



XTO ENERGY INC.

Consolidated Valuation and Qualifying Accounts



|                                                                       |  |                               |       |              |   |               |  |   |          |   |                        |   |     |  |   |      
|---------------------------------------------------------------------- |  | ----------------------------- | ----- | ------------ | - | ------------- |  | - | -------- | - | ---------------------- | - | --- |  | - | -----
|(in thousands)                                                         |  | Balance atBeginning of Period |       | Additions(a) |   | Deductions(b) |  |   | Other(c) |   | Balance atEnd ofPeriod
|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 |  | $ | 5,537
|                                                                       |  |                               |       |              |   |               |  |   |          |   |                        |   |     |  |   |      
|Year Ended December 31, 2001                                           |  |                               |       |              |   |               |  |   |          |   |                        |   |     |  |   |      
|Allowance for doubtful accounts - Joint interest and other receivables |  | $                             | 3,121 |              | $ | 978           |  | $ | (1       | ) |                        | $ |    |  | $ | 4,098
|                                                                       |  |                               |       |              |   |               |  |   |          |   |                        |   |     |  |   |      

---

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



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



|(c) | Adjustment related to reclassified account balance of company acquired in 1999.
|--- | -------------------------------------------------------------------------------



79



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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 15th day of March 2004.



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 15th day of March 2004.



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



80



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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.



|           |  |                                                                                                                                                                                                                                                            |  |     
|---------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|ExhibitNo. |  | Description                                                                                                                                                                                                                                                |  | Page
|           |  |                                                                                                                                                                                                                                                           
|3.1        |  | Restated Certificate of Incorporation of the Company, as restated on August 22, 2001 (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-3, File No.
333-71762)                                                                  |  |     
|           |  |                                                                                                                                                                                                                                                           
|3.2        |  | Amended Bylaws of the Company                                                                                                                                                                                                                              |  |     
|           |  |                                                                                                                                                                                                                                                           
|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)                                                |  |     
|           |  |                                                                                                                                                                                                                                                           
|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)                     |  |     
|           |  |                                                                                                                                                                                                                                                           
|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)                                                          |  |     



81



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##### Index to Financial Statements

|           |  |                                                                                                                                                                                                                                                                                                           |  |     
|---------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|ExhibitNo. |  | Description                                                                                                                                                                                                                                                                                               |  | Page
|           |  |                                                                                                                                                                                                                                                                                                          
|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 August 19, 2003 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2003)                                                                                                                                                   |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.6 *     |  | Amended Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.14 to Form 10-K for the year ended December 31, 1999)                                                                                                                                   |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.7 *     |  | 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)                                                                                                                     |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.8 *     |  | 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)                                                                                                     |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.9 *     |  | 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)                                                                                       |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.10*     |  | 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)                                                                                                                                                 |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.11*     |  | 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)                           |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.12*     |  | 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) |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.13*     |  | 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)                                                        |  |     
|           |  |                                                                                                                                                                                                                                                                                                          
|10.14*     |  | 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)                                                      |  |     



82



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##### Index to Financial Statements

|           |  |                                                                                                                                                                                                                                                             |  |     
|---------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|ExhibitNo. |  | Description                                                                                                                                                                                                                                                 |  | Page
|           |  |                                                                                                                                                                                                                                                            
|10.15 *    |  | 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)        |  |     
|           |  |                                                                                                                                                                                                                                                            
|10.16 *    |  | 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)         |  |     
|           |  |                                                                                                                                                                                                                                                            
|10.17 *    |  | 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) |  |     
|           |  |                                                                                                                                                                                                                                                            
|10.18      |  | Five-Year Revolving Credit Agreement dated February 17, 2004, between the Company and certain commercial banks named therein                                                                                                                                |  |     
|           |  |                                                                                                                                                                                                                                                            
|12.1       |  | Computation of Ratio of Earnings to Fixed Charges                                                                                                                                                                                                           |  |     
|           |  |                                                                                                                                                                                                                                                            
|21.1       |  | Subsidiaries of XTO Energy Inc.                                                                                                                                                                                                                             |  |     
|           |  |                                                                                                                                                                                                                                                            
|23.1       |  | Consent of KPMG LLP                                                                                                                                                                                                                                         |  |     
|           |  |                                                                                                                                                                                                                                                            
|23.2       |  | Notice Regarding Consent of Arthur Andersen 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                                                                          |  |     



|* | 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.



83