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2005

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 2005

OR

For the transition period from              to             

Commission File Number: 1-10662

XTO Energy Inc.

(Exact name of registrant as specified in its charter)

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

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

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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 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 check mark whether the registrant is a large accelerated filer, accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer  x            Accelerated filer  ¨            Non-accelerated filer   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).    Yes  ¨    No  x

As of June 30, 2005, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $11.7 billion based on the closing price as reported on the New York Stock Exchange.

Number of Shares of Common Stock outstanding as of February 24, 2006 - 363,949,471

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Part III of this Report is incorporated by reference from the Registrant’s definitive Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 29, 2006.

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XTO ENERGY INC.

2005 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

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PART I

Items 1. and 2. BUSINESS AND PROPERTIES

General

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

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 acquisition of additional interests in or near such acquired properties. We expect growth in the immediate future to continue to be accomplished through a combination of acquisitions and development. During 2006, we plan to continue to review strategic acquisition opportunities including property divestitures by major energy related companies, public exploration and development companies and private energy companies. Completion of additional acquisitions will depend on the quality of properties available, commodity prices and competitive factors.

Our corporate headquarters are located in Fort Worth, Texas at 810 Houston Street (telephone 817-870-2800). Our proved reserves are principally located in relatively long-lived fields with an extensive base of hydrocarbons in place and well-established production histories concentrated in the following areas:

We use the following volume abbreviations throughout this Form 10-K. “Equivalent” volumes are computed with oil and natural gas liquid quantities converted to Mcf, or natural gas converted to Bbls, on an energy equivalent ratio of one barrel to six Mcf.

Our estimated proved reserves at December 31, 2005 were 6.09 Tcf of natural gas, 47.4 million Bbls of natural gas liquids and 208.7 million Bbls of oil, based on December 31, 2005 prices of $9.26 per Mcf for gas, $36.33 per Bbl for natural gas liquids and $57.02 per Bbl for oil. On an energy equivalent basis, our proved reserves were 7.62 Tcfe at December 31, 2005, a 30% increase from proved reserves of 5.86 Tcfe at the prior year end. Increased proved reserves during 2005 were primarily the result of acquisitions and development and exploitation activities. On an Mcfe basis, 69% of proved reserves were proved developed reserves at December 31, 2005. During 2005, our average daily production was 1,033,143 Mcf of gas, 10,445 Bbls of natural gas liquids and 39,051 Bbls of oil. Fourth quarter 2005 average daily production was 1,102,260 Mcf of gas, 10,643 Bbls of natural gas liquids and 41,976 Bbls of oil.

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Our properties typically have relatively long reserve lives and predictable production profiles. Based on December 31, 2005 proved reserves and projected 2006 production from properties owned as of December 31, 2005, the average reserve-to-production index of our proved reserves is 16.3 years. The projected 2006 production is from proved developed producing reserves as of December 31, 2005. In general, our 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, 2005, we owned interests in 18,863 gross (9,795.5 net) producing wells, and we operated wells representing 91% of the present value of cash flows before income taxes (discounted at 10%) from estimated proved reserves. The high proportion of operated properties allows us to exercise more control over expenses, capital allocation and the timing of development and exploitation activities in our fields.

We have a substantial inventory of between 4,500 and 5,400 identified potential drilling locations. Drilling plans are primarily dependent upon product prices, the availability and pricing of drilling equipment and supplies, and gathering, processing and transmission infrastructure.

We employ a disciplined acquisition program refined by senior management to expand our reserve base in core areas and to add new core areas. Our engineers and geologists use their expertise and experience gained through the management of existing core properties to target properties to be acquired with similar geologic and reservoir characteristics. The Company then uses its development and technology knowledge to increase the reserves of acquired properties.

We operate gas gathering systems in several of our core producing areas. We also operate gas processing plants in East Texas, in Texas County, Oklahoma and the Cotton Valley Field of Louisiana. Our gas gathering and processing operations are only in areas where we have production and are considered activities that facilitate our natural gas production and sales operations.

We market our gas production and the gas output of our gathering and processing systems. A large portion of our natural gas is processed, and the resultant natural gas liquids are marketed by unaffiliated third parties. We use fixed-price physical sales contracts and futures, forward sales contracts and other price risk management instruments to hedge pricing risks.

History of the Company

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

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

In December 1998, we formed the Hugoton Royalty Trust by conveying an 80% net profits interest in principally gas-producing operated working interests in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These net profits interests were conveyed to the trust in exchange for 40 million units of beneficial interest. We sold 17 million units in the trust’s initial public offering in 1999 and 1.3 million units pursuant to an employee incentive plan in 1999 and 2000. We own the remaining 54%, or 21.7 million units, which we account for as producing properties. Hugoton Royalty Trust units are listed on the New York Stock Exchange under the symbol “HGT.”

In January 2006, the Board of Directors declared a dividend of 0.0596 units of the trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will

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be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date.

We also announced in January 2006 that the Company will consider selling its interests in the underlying properties that are subject to the Cross Timbers Royalty Trust and Hugoton Royalty Trust net profits interests. Any sale is dependent upon finding a qualified buyer, receiving sufficient consideration and structuring a tax-efficient transaction.

Industry Operating Environment

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

Business Strategy

The primary components of our business strategy are:

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

We believe that the properties we acquire provide opportunities to increase production and reserves through the implementation of mechanical and operational improvements, workovers, behind-pipe completions, secondary recovery operations, new development wells and other development activities. We also seek to acquire facilities related to gathering, processing, marketing and transporting oil and gas in areas where we own reserves. Such facilities can enhance profitability, reduce costs, and provide marketing flexibility and access to additional markets. The ability to successfully purchase properties is dependent upon, among other things, competition for such purchases and the availability of financing to supplement internally generated cash flow.

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

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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 between 4,500 and 5,400 identified potential drilling locations. Additionally, we review operations and mechanical data on operated properties to determine if actions can be taken to reduce operating costs or increase production. Such actions include installing, repairing and upgrading lifting equipment, redesigning downhole equipment to improve production from different zones, modifying gathering and other surface facilities and conducting restimulations and recompletions. We may also initiate, upgrade or revise existing secondary recovery operations.

Exploration Activities. During 2006, 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 $70 million of our $1.7 billion 2006 development budget for exploration activities.

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

Experienced Management and Technical Staff. Most senior management and technical staff have worked together for over 20 years and have substantial experience in our core operating areas. Bob R. Simpson, a founder, Chairman and Chief Executive Officer of the Company, was previously an executive officer 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 2006, we announced a strategic goal for 2006 of increasing production by 10% to 12% over 2005 levels. To achieve this growth target, we plan to drill about 1,050 (865 net) development wells and perform approximately 735 (620 net) workovers and recompletions in 2006.

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We have budgeted $1.7 billion for our 2006 development program, which is expected to be funded by cash flow from operations. We plan to spend approximately $700 million in the Eastern Region, $350 million in the North Texas Region, $240 million in the Permian and South Texas Region, $200 million in the San Juan Region and $140 million in the Mid-Continent and Rocky Mountain Region and other areas and approximately $70 million for exploration and acreage leasing activities. An additional $100 million has been budgeted for the construction of pipeline, compression and processing infrastructure that is critical to the transportation and sale of production in several operating regions.

While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2006. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, issuance of public or private debt or equity, or asset sales. Strategic property acquisitions during 2006 may alter the amount currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2006 to focus on opportunities offering the highest rates of return. We also may reevaluate our budget and drilling programs in the event of significant changes in oil and gas prices. Our ability to achieve production goals depends on the success of our planned drilling programs or property acquisitions made in place of a portion of the drilling program.

Raw material shortages and strong global demand for steel have continued to tighten steel supplies and cause prices to remain high. In response, we have increased our tubular inventory and have negotiated supply contracts with our vendors to support our development program. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting production growth and increasing development costs.

Although drilling rigs have recently been in short supply throughout the industry, we have secured or contracted to secure the rigs necessary to support our current drilling program.

Acquisitions

During 2001, we acquired predominantly gas-producing properties for a total cost of $238 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.

During 2002, we acquired predominantly gas-producing properties for a total cost of $354 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 $154 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.

During 2003, we acquired predominantly gas-producing properties for a total cost of $624 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.

During 2004, we acquired proved properties for a total cost of $1.9 billion. In January 2004, we acquired proved properties in East Texas and northwestern Louisiana for $243 million from multiple parties. From February through April, we purchased $223 million of properties located primarily in the Barnett Shale of North Texas and in the Arkoma Basin. Two of these acquisitions were purchases of corporations that primarily owned producing and nonproducing properties. Purchase accounting adjustments related to these acquisitions included a $72 million deferred income tax step-up adjustment. During April, we acquired predominantly oil-producing properties in the Permian Basin of West Texas and in the Powder River Basin of Wyoming from ExxonMobil Corporation for $336 million. In August,

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we acquired properties from ChevronTexaco Corporation for a purchase price of $958 million, as adjusted for subsequent purchase of properties that were subject to preferential purchase rights. These properties expanded our operations in our Eastern Region, the Permian Basin and the Mid-Continent Region and added new coal bed methane properties in the Rocky Mountains and a new operating region in South Texas. Our 2004 acquisitions increased reserves by approximately 716.5 Bcf of natural gas, 2.9 million Bbls of natural gas liquids and 98.2 million Bbls of oil.

During 2005, we acquired proved properties for a total cost of $1.7 billion. In April 2005, we acquired Antero Resources Corporation, which operated in the Barnett Shale in the Fort Worth Basin. The purchase price was approximately $689 million. Including $218 million of debt assumed, $225 million recorded on the step-up of deferred taxes and the assumption of other liabilities, the total purchase price plus liabilities assumed was $1.26 billion. This amount was allocated to assets acquired including approximately $634 million to proved properties, $180 million to unproved properties, $175 million to acquired gas gathering contracts and related gas gathering and pipeline assets, $213 million to goodwill and $57 million to other assets. In May, we acquired proved properties in East Texas and northwestern Louisiana from Plains Exploration & Production Company for an adjusted purchase price of $336 million. In July 2005, we acquired proved properties in the Permian Basin of West Texas and New Mexico from ExxonMobil Corporation for an adjusted purchase price of $200 million. All 2005 acquisitions are subject to typical post-close adjustments. Our 2005 acquisitions increased reserves by approximately 803.4 Bcf of natural gas, 2.8 million Bbls of natural gas liquids and 31.1 million Bbls of oil.

On February 28, 2006, we acquired proved and unproved properties in East Texas and Mississippi from Total E&P USA, Inc. for $300 million. The acquisition is subject to typical post-closing adjustments.

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, 2005:

Eastern Region

We began operations in East Texas and northwestern Louisiana in 1998. These properties produce from various formations at depths between 7,000 feet and 13,000 feet. Subsequent acquisitions and development activity have significantly increased reserves here since we began operations, and we now own an interest in more than 563,000 gross (395,000 net) acres. Approximately half of our total proved reserves are in this region. We have 1,850 to 2,100 identified potential drilling locations in this area. In 2005, we expanded our gathering facilities to increase treating capacity to 730,000 Mcf per day. In 2006, we plan to drill between 290 and 330 wells and perform approximately 50 workovers in the Eastern Region.

Our primary focus in the Eastern Region is in the Freestone Trend where we have an interest in 306,000 gross (234,000 net) acres. The trend consists of the Freestone, Bald Prairie, Oaks, Luna, Teague, Dew, Farrar and Bear Grass fields and was our most active gas development area in 2005. Other areas in the region include the Sabine Uplift and Cotton Valley areas of East Texas and northwestern Louisiana.

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North Texas Region

Our operations in the Barnett Shale of North Texas began in January 2004 and, with our 2005 acquisition of Antero Resources Corporation, we are now the second largest producer in the area. We own interests in approximately 160,000 net acres, 50% of which are in the core productive area, approximately 360 producing wells and gas gathering and pipeline assets. We have 750 to 950 identified potential drilling locations in this area and plan to drill approximately 240 wells in 2006. We also own 300,000 Mcf per day of treating capacity, which allows us to add new wells as they are completed.

San Juan Region

Our San Juan Region includes properties in the San Juan and Raton Basins of New Mexico and Colorado, as well as properties in the Uinta Basin of Utah. Production is from conventional as well as coal bed methane sources. We have 700 to 900 identified potential drilling locations to develop these complex, multi-pay basins. In 2005, we entered a new tight-gas play in the Piceance Basin of Colorado through a farm-out agreement with ExxonMobil and began drilling our first well in December 2005.

Permian and South Texas Region

The Permian and South Texas Region is made up of properties in West Texas, southeastern New Mexico and South Texas. In both 2004 and 2005, we significantly expanded our holdings in the area through acquisitions and trades with ChevronTexaco, ExxonMobil, ConocoPhillips and others. Our activities on these properties have increased oil production by returning shut-in wells to production, optimizing existing well performance, fracture stimulation and drilling. We have also experienced successful results in multiple fields including Yates, University Block 9, Goldsmith, Russell, Prentice and Cornell. We have 850 to 950 identified potential well locations in this area.

Mid-Continent and Rocky Mountain Region

Our Mid-Continent and Rocky Mountain Region includes fields in Wyoming, Kansas, Oklahoma and Arkansas. We have operations in the Anadarko Basin, Fontenelle area and the Arkoma Basin. While most of our production in the Mid-Continent region is from conventional sources, we recently began developing coal bed methane in the Powder River Basin of Wyoming. A substantial portion of our properties in the Mid-Continent Region are subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust in December 1998. We own 54.3% of the Hugoton Royalty Trust units. In January 2006, we announced we would distribute these trust units as a dividend to our stockholders in May 2006. We also announced we will consider selling our interests in the properties underlying the Hugoton Royalty Trust net profits interest.

We operate a gathering system and pipeline in Major County, Oklahoma and a gas plant in Texas County, Oklahoma, and its associated gathering system. We are currently building a gas gathering and water disposal system in the Hartzog Draw area of Wyoming to service our coal bed methane wells.

Alaska Cook Inlet and Other

We own a 100% interest in two State of Alaska offshore leases and installations in the Middle Ground Shoal Field of the Cook Inlet. The properties include 27 wells on two platforms and a 100% interest in operated production pipelines and onshore processing facilities.

Reserves

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

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

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

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

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

Present value of estimated future net cash flows - The computational result of discounting estimated future net revenues at a rate of 10% annually. The present value of estimated future net cash flows after income tax is also referred to herein as “standardized measure of discounted future net cash flows” or “standardized measure.”

The following are estimated quantities of proved reserves and related cash flows as of December 31, 2005, 2004 and 2003:

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, 2005, 2004 and 2003. As prescribed by the Securities and Exchange Commission, such proved reserves were estimated using oil and gas prices and production and development costs as of December 31 of each such year, without escalation. None of our natural gas liquid proved reserves are attributable to gas plant ownership.

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Estimated future net cash flows, and the related 10% discounted present value, of year-end 2005 proved reserves are significantly higher than at year-end 2004 because of increased reserves related to acquisitions and development and higher gas, natural gas liquids and oil prices used in the estimation of year-end proved reserves. Year-end 2005 average realized prices used in the estimation of proved reserves were $9.26 per Mcf for gas, $36.33 per Bbl for natural gas liquids and $57.02 per Bbl for oil. Year-end 2004 product prices were $5.69 per Mcf for gas, $28.24 per Bbl for natural gas liquids and $41.03 per Bbl for oil. See Note 15 to Consolidated Financial Statements for additional information regarding estimated proved reserves.

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 2005, we filed estimates of oil and gas reserves as of December 31, 2004 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, 2004 in Note 15 to Consolidated Financial Statements, with the exception that Form EIA-23 includes only reserves from properties that we operate.

Exploration and Production Data

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

Producing Wells

The following table summarizes producing wells as of December 31, 2005, all of which are located in the United States:

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Drilling Activity

The following table summarizes the number of wells drilled during the years indicated. As of December 31, 2005, we were in the process of drilling 462 gross (307.1 net) wells.

Acreage

The following table summarizes developed and undeveloped leasehold acreage in which we own a working interest as of December 31, 2005. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

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Oil and Gas Sales Prices and Production Costs

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

Delivery Commitments

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

Competition and Markets

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

Federal and State Laws and 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 existing laws often is difficult and costly and may carry substantial penalties for noncompliance. The following are some specific laws and regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives.

Federal Regulation of Natural Gas

The interstate transportation and certain sales for resale of natural gas, including transportation rates charged and various other matters, are subject to federal regulation by the Federal Energy Regulatory Commission. Federal wellhead price controls on all domestic gas were terminated on January 1, 1993, and none of our gathering systems are currently subject to FERC regulation. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. We cannot predict the impact of future government regulation on any natural gas facilities.

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

Federal Regulation of Oil

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

State Regulation

Oil and gas operations are subject to various types of regulation at the state and local levels. Such regulation includes requirements for drilling permits, the method of developing new fields, the spacing and operation of wells and waste prevention. The production rate may be regulated and the maximum daily production allowable from oil and gas wells may be established on a market demand or conservation basis. These regulations may limit production by well and the number of wells that can be drilled.

We may become a party to agreements relating to the construction or operations of pipeline systems for the transportation of natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the state’s administrative authority charged with regulating pipelines. The rates that can be charged for gas, the transportation of gas, and the construction and operation of such pipelines would be subject to the regulations governing such matters. One of our gathering subsidiaries is designated a gas utility and is subject to such state regulations. Certain states have recently adopted regulations with respect to gathering systems, and other states are considering similar regulations. New regulations have not had a material effect on the operations of our gathering systems, but we cannot predict whether any further rules will be adopted or, if adopted, the effect these rules may have on our gathering systems.

Federal, State or Native American Leases

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

Environmental Regulations

Various federal, state and local laws relating to protection of the environment directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters of the United States, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas. In some jurisdictions, the laws and regulations are constantly being revised, creating the potential for delays in development plans.

Although we have used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released onto or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, petroleum hydrocarbons or wastes may have been disposed of or released by prior operators of properties we are acquiring as well as by current third party operators of properties in which we have an ownership interest. Properties impacted by any such disposal or releases could be subject to costly and stringent investigatory or remedial requirements under environmental laws, some of which impose strict, joint and several liability without regard to fault or the legality of the original conduct, including

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the Comprehensive Environmental Response, Compensation, and Liability Act, also known as “CERCLA” or the “Superfund” law and analogous state laws.

We are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations. We have made and will continue to make expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or operations. However, due to continuing changes in these laws and regulations and judicial construction of same, we are unable to predict with any reasonable degree of certainty our future costs of complying with these governmental requirements. We have been able to plan for and comply with new initiatives without materially changing our operating strategies.

We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. We are not fully insured against all environmental risks, and no coverage is maintained with respect to any penalty or fine required to be paid by us.

Future Laws and Regulations

The oil and gas industry is highly regulated and, from time to time, Congress and state legislatures consider broad and sweeping policy changes that may affect the industry. We cannot predict the impact of such future legislative or regulatory initiatives.

Employees

We had 1,680 employees as of December 31, 2005. 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, 57, was a founder of the Company and has been Chairman and Chief Executive Officer since July 1, 1996. Prior thereto, Mr. Simpson served as Vice Chairman and Chief Executive Officer or held similar positions with the Company since 1986. Mr. Simpson was Vice President of Finance and Corporate Development (1979-1986) and Tax Manager (1976-1979) of Southland Royalty Company.

Keith A. Hutton, 47, has been President since May 1, 2005. Prior thereto, Mr. Hutton served as Executive Vice President-Operations or held similar positions with the Company since 1987. From 1982 to 1987, Mr. Hutton was a Reservoir Engineer with Sun Exploration & Production Company.

Vaughn O. Vennerberg II, 51, has been Senior Executive Vice President and Chief of Staff since May 1, 2005. Prior thereto, Mr. Vennerberg served as 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).

Louis G. Baldwin, 56, 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.

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Timothy L. Petrus, 51, has been Executive Vice President - Acquisitions since May 1, 2005. Prior thereto, Mr. Petrus served as Senior Vice President-Acquisitions or held similar positions with the Company since 1988. Prior to that time, Mr. Petrus was employed by Texas American Bank and Exxon Corporation.

Bennie G. Kniffen, 55, 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 1A. RISK FACTORS

The following factors, among others, could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by management from time to time. Such factors, among others, may have a material adverse effect upon our business, financial condition, and results of operations.

The following discussion of our risk factors should be read in conjunction with the consolidated financial statements and related notes included herein. Because of these and other factors, past financial performance should not be considered an indication of future performance.

Oil, natural gas and natural gas liquids prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect our financial condition.

Our results of operations depend upon the prices we receive for our oil, natural gas and natural gas liquids. We sell most of our oil, natural gas and natural gas liquids at current market prices rather than through fixed-price contracts. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and are likely to remain volatile in the future. The prices we receive depend upon factors beyond our control, which include:

Government regulations, such as regulations of natural 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 natural gas.

To the extent we have not hedged our production, any decline in oil and natural 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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Our use of hedging arrangements could result in financial losses or reduce our income.

To reduce our exposure to fluctuations in oil and natural gas prices, we have entered into and expect in the future to enter into hedging arrangements for a portion of our oil and natural gas production. These hedging arrangements expose us to risk of financial loss in some circumstances, including when:

In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in oil and natural gas prices.

We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.

We make, and will continue to make, substantial capital expenditures for the acquisition, development, exploration and abandonment of our oil and natural gas reserves. We intend to finance our capital expenditures primarily through cash flow from operations, bank borrowings and public and private equity and debt offerings. Lower oil and natural gas prices, however, would reduce our cash flow and could affect our access to the capital markets. Costs of exploration and development were $1.4 billion in 2005, $587 million in 2004 and $462 million in 2003. During 2005, we spent $1.7 billion on proved property acquisitions. Our exploration and development budget for 2006 is $1.7 billion. An additional $100 million has been budgeted for the construction of pipeline, compression and processing infrastructure in 2006.

We believe that, after debt service, we will have sufficient cash from operating activities to finance our exploration and development expenses through 2006. If revenues decrease, however, and we are unable to obtain additional debt or equity financing, we may lack the capital necessary to replace our reserves or to maintain production at current levels.

We have substantial indebtedness and may incur substantially more debt.  Any failure to meet our debt obligations would adversely affect our business and financial condition.

We have incurred substantial debt. As a result of our indebtedness, we will need to use a portion of our cash flow to pay principal and interest, which will reduce the amount available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our bank revolving credit indebtedness is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have applicable interest rate protection hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

Together with our subsidiaries, we may incur substantially more debt in the future. The indentures governing our outstanding public debt do not contain restrictions on our incurrence of additional indebtedness. To the extent new debt is added to our current debt levels, the risks resulting from indebtedness could substantially increase.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets or sell shares of common stock on terms that we do not find attractive if it can be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under the indebtedness, which could adversely affect our business, financial condition and results of operations.

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Competition in the oil and natural gas industry is intense, and some of our competitors have greater financial, technological and other resources than we have.

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:

Some of our competitors have financial, technological and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural 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. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to develop and exploit our oil and natural 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.

The failure to replace our reserves could adversely affect our financial condition.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when oil and natural gas are produced unless we continue to conduct successful exploitation or development activities or acquire properties containing proved reserves, or both. We may not be able to economically find, develop or acquire additional reserves. Furthermore, while our revenues may increase if oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions or changes of conditions could cause the quantities and net present value of our reserves to be overstated.

To prepare estimates of economically recoverable oil and natural gas reserves and future net cash flows, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs. Actual results most likely will vary from our estimates. Any significant variance could reduce the estimated quantities and present value of reserves shown in this annual report.

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You should not assume that the present value of future net cash flows from our proved reserves shown in this annual report is the current market value of our estimated oil and natural gas reserves. In accordance with Securities and Exchange Commission requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual current and future prices and costs may differ materially from those used in the earlier net present value estimate, and as a result, net present value estimates using current prices and costs may be significantly less than the earlier estimate which is provided in this annual report.

Property acquisitions are a component of our growth strategy, and our failure to complete future acquisitions successfully could reduce our earnings and slow our growth.

Our business strategy has emphasized growth through 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 significant acquisitions are completed in particular periods.

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities.

Our recent growth is due in part to acquisitions of producing properties, and we expect acquisitions will continue to contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not allow us to become sufficiently familiar with the properties, and we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited.

We generally are not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities, on acquisitions. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. If material breaches are discovered by us prior to closing, we could require adjustments to the purchase price, or, if the claims are significant, we or the seller may have a right to terminate the agreement. We could also fail to discover breaches or defects prior to closing and incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, for which we would have limited or no contractual remedies or insurance coverage.

There are risks in acquiring producing properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, and costs of increased scope, geographic diversity and complexity of our operations.

Increasing our reserve base through acquisitions is an important part of our business strategy. Our failure to integrate acquired businesses successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations.

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Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.

Drilling oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could harm our business. We deliver oil and natural gas through gathering systems and pipelines that we do not own. These facilities may be temporarily unavailable due to market conditions or mechanical reasons, or may not be available to us in the future. For example, during 2004, we experienced temporary curtailments of our natural gas production in the San Juan Basin and in East Texas due to infrastructure limitations and plant closings for maintenance reasons.

We are subject to complex federal, state and local laws and regulations that could adversely affect our business.

Extensive federal, state and local regulation of the oil and gas industry significantly affects our operations. In particular, our oil and natural gas exploration, development and production, and our storage and transportation of liquid hydrocarbons, are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other related facilities. These regulations may become more demanding in the future. Matters subject to regulation include:

Under these laws and regulations, we could be liable for:

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Although we believe that our operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could make it more expensive for us to conduct our business or cause us to limit or curtail some of our operations.

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

Our operations in the coastal waters of Cook Inlet of Alaska are subject to the federal Oil Pollution Act, which imposes a variety of requirements related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The Oil Pollution Act imposes strict joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Liability limits for offshore facilities require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was caused by gross negligence or willful misconduct of the party, if the spill resulted from violation of a federal safety, construction or operation regulation, or if the party failed to report the spill or cooperate fully in any resulting cleanup. The Oil Pollution Act also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe that our operations are in substantial compliance with Oil Pollution Act requirements.

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

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Our business involves many operating risks that may result in substantial losses, and insurance may be unavailable or inadequate to protect us against these risks.

Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:

Any of these risks can cause substantial losses resulting from:

We do not insure against the loss of oil or natural gas reserves as a result of operating hazards or insure against business interruption. Losses could occur from uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.

Terrorist activities and military and other actions could adversely affect our business.

On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scope, and the United States and others instituted military action in response. These conditions caused instability in world financial markets and generated global economic instability. The continued threat of terrorism and the impact of military and other action, including U.S. military operations in Afghanistan and Iraq, will likely lead to continued volatility in crude oil and natural gas prices and could affect the markets for our operations. In addition, future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund for their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns or lead to unexpected future costs.

Item 1B. UNRESOLVED STAFF COMMENTS

As of December 31, 2005, we do not have any Securities and Exchange Commission staff comments that have been unresolved for more than 180 days.

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Item 3. LEGAL PROCEEDINGS

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U.S. District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against the Company and certain of our subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other companies have been consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion occurred in March 2005, and in May 2005, the special master, who was appointed by the district judge to expedite matters and make recommendations to the district judge in the case, issued a report and recommendation to dismiss the case against some of the defendants but to retain jurisdiction of the case involving us and other defendants. We and the other defendants filed motions to modify the special master’s report, requesting the district judge to also dismiss the case as to us and other defendents. The district judge heard oral arguments on December 9, 2005, as to all motions seeking adoption, modification or reversal of the special master’s report, and we are awaiting the decision of the district court. While we are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

In June 2001, we were served with a lawsuit styled Price, et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against us and one of our subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims to cover all oil and gas leases (other than the federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas delivered into their pipelines, resulting in underpayments to the plaintiffs. The plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of action. The amount of damages was not specified in the complaint. In February 2002, we, along with one of our subsidiaries, were dismissed from the suit and another subsidiary of the Company was added. A hearing was held in January 2003, and the court held that a class should not be certified. The plaintiffs’ counsel has filed an amended class action petition, which reduces the proposed class to only royalty owners, reduces the claims to mismeasurement of volume only, conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court held an evidentiary hearing in April 2005 to determine whether the amended class should be certified, and we are awaiting the decision of the court. While we are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

On August 5, 2003, the Price plaintiffs served one of our subsidiaries with a new original class action petition styled Price, et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against natural gas pipeline owners and operators. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas royalty owners either from whom the defendants had purchased natural gas or measured natural gas since January 1, 1974 to the present. The new petition alleges the same improper analysis of gas heating content that had previously been alleged in the Price case discussed above until it was removed from the case by the filing of the amended class action petition. In all other respects, the new petition appears to be identical to the amended class action petition in that it has a proposed class of only royalty owners, alleges conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court held an evidentiary hearing in April 2005 to determine whether the amended class should be certified, and we are awaiting the decision of the court. The amount of damages was not specified in the complaint. While we are unable to predict the outcome of this case, we believe that

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the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

In September 2004, we were served with a lawsuit styled Burkett, et al. v. J.M. Huber Corp. and XTO Energy Inc. The action was filed in the District Court of La Plata County, Colorado against us and J.M. Huber Corporation. The plaintiffs alleged that the defendants deducted in their calculation of royalty payments expenses of compression, gathering, treatment, dehydration, or other costs to place the natural gas produced in a marketable condition at a marketable location. The plaintiffs sought to represent a class consisting of all lessors and their successors in interest who own or have owned mineral interests located in La Plata County, Colorado and that were leased to or operated by Huber or us, except to the extent that the lessors or their successors expressly authorized deduction of post-production expenses from royalties. We acquired the interests of Huber in producing properties in La Plata County effective October 1, 2002, and assumed the responsibility for certain liabilities of Huber prior to the effective date, which included liability for post-production deductions made by Huber. As of December 31, 2004, based on an evaluation of available information, we accrued a $3.1 million estimated liability for this claim in our consolidated financial statements. On February 17, 2005, we agreed to a settlement of $5.1 million, resulting in an additional loss of approximately $2 million that was recorded in our consolidated income statement for 2005. On June 21, 2005, the court entered a final judgment approving the settlement on a class-wide basis. The final judgment releases XTO from any royalty claims concerning post-production costs relating to the properties. No appeals from the final judgment were filed, so the litigation is concluded. We paid this settlement in August 2005.

On March 31, 2005, the Division of Air Quality of the Department of Environmental Conservation of the State of Alaska issued us a Notice of Violation regarding nitrogen oxide emissions from one of our cranes that exceed the limitations of our operational permit for one of our platforms in the Cook Inlet of Alaska. In February 2006, the Division of Air Quality proposed a fine of less than $100,000, which we are discussing with them.

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

There were no matters submitted to a vote of security holders during the fourth quarter of 2005.

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PART II

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

Our common stock is listed on the New York Stock Exchange and trades under the symbol “XTO.” The following table sets forth quarterly high and low sales prices and cash dividends declared for each quarter of 2005 and 2004, (as adjusted for the four-for-three stock split effected in March 2005 and the five-for-four stock split effected in March 2004):

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

In November 2005, the Board of Directors increased our quarterly dividend to $0.075 per common share. On February 21, 2006, the Board of Directors declared a quarterly dividend of $0.075 per common share payable on April 13, 2006 to stockholders of record on March 31, 2006. On February 23, 2006, we had 1,537 stockholders of record.

In January 2006, the Board of Directors declared a dividend of 0.0596 units of Hugoton Royalty Trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date. As of the January 26, 2006 declaration date, this dividend has a fair value of approximately $830 million, or $2.28 per common share.

The following summarizes purchases of our common stock during fourth quarter 2005:

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Item 6. SELECTED FINANCIAL DATA

The following table shows selected financial information for each of the years in the five-year period ended December 31, 2005. Significant producing property acquisitions in each of the years presented affect the comparability of year-to-year financial and operating data. See Items 1 and 2, Business and Properties, “Acquisitions.” All weighted average shares and per share data have been adjusted for the four-for-three stock split effected in March 2005, the five-for-four stock split effected in March 2004, the four-for-three stock split effected in March 2003 and the three-for-two stock split effected in June 2001. This information should be read in conjunction with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements at Item 15(a).

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

Our business is to produce and sell natural gas, natural gas liquids and crude oil from our predominantly southwestern and central U.S. properties, most of which we operate. Because our gathering, processing and marketing functions are ancillary to our production of natural gas, natural gas liquids and crude oil, we have determined that our business comprises only one industry segment.

In 2005, we achieved the following record financial and operating results:

We achieve production and proved reserve growth primarily through producing property acquisitions, followed by low-risk development generally funded by cash flow from operating activities. Funding sources for our acquisitions include proceeds from sales of public and private equity and debt, bank borrowings and cash flow from operating activities. Maintaining or improving our debt-to-capitalization ratio is a primary consideration in selecting our method of acquisition financing. During 2005, we acquired $1.7 billion of proved properties with proved reserves of 803 Bcf of natural gas, 3 million Bbls of natural gas liquids and 31 million Bbls of oil.

In a trend that began in 2004 and accelerated during 2005, commodity prices for natural gas, natural gas liquids and oil increased significantly (see “Significant Events, Transactions and Conditions – Product Prices”). The higher prices have led to increased activity in the industry and, consequently, rising costs. Drilling rig counts are at levels not seen since the last boom in the early 1980s and labor to run the rigs is in short supply. This was further aggravated by the damage in the Gulf of Mexico as a result of the August and September hurricanes (see “Significant Events, Transactions and Conditions – Gulf of Mexico Hurricanes”). These cost trends have put pressure not only on our operating costs but also our capital costs. With the increased activity, there is also increased demand for oil and gas properties which has resulted in higher acquisition prices.

Like all oil and gas exploration and production companies, we face the challenge of natural production decline. An oil and gas exploration and production company depletes part of its asset base with each unit of oil and gas it produces. Despite this natural decline, we have been able to grow our production through acquisitions and drilling, adding more reserves than we produce. We also attempt to manage our natural decline by combining the acquisition of mature properties with shallower decline rates with the drilling of new wells that have higher decline rates. This has allowed us to keep our natural decline rate lower than the industry average. Future growth will depend on our ability to continue to add reserves in excess of production.

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Our goal for 2006 is to increase production by 10% to 12%. To achieve future production and reserve growth, we will continue to pursue acquisitions that meet our criteria, and to complete development projects included in our inventory of between 4,500 and 5,400 identified potential drilling locations. Our 2006 development budget is $1.7 billion. While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2006. We cannot ensure that we will be able to find properties that meet our acquisition criteria and that we can purchase such properties on acceptable terms.

Raw material shortages and strong global demand for steel have continued to tighten steel supplies and cause prices to remain high. In response, we have increased our tubular inventory and have negotiated supply contracts with our vendors to support our development program. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting production growth and increasing development costs.

Although drilling rigs have recently been in short supply throughout the industry, we have secured or contracted to secure the rigs necessary to support our current drilling program.

The increased activity in the oil and gas producing industry has also had an effect on our ability to hire qualified people including not only field operators and drillers, but also all classifications of industry-specific professionals. We continue to find the employees we need to adequately staff our operations; however, the cost of hiring and the time to fill positions has increased since 2004. Our employee turnover continues to remain low with total turnover of 7.1% in 2005 and 7.8% in 2004.

In the event that our operating cash flow exceeds our development, exploration and acquisition capital needs, we will consider other alternative uses for this cash including, but not limited to, debt repayment or stock repurchases. In August 2004, the Board of Directors authorized the repurchase of up to 20 million shares of our common stock from time to time in the open market or negotiated transactions. As of December 31, 2005, 33,600 shares have been repurchased under this authorization.

In January 2006, the Board of Directors declared a dividend of 0.0596 units of Hugoton Royalty Trust for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all 21.7 million trust units owned by us will be distributed to our stockholders on May 12, 2006. The dividend ratio is subject to change based on our outstanding share count on the record date. Based on the January 26, 2006 declaration date, this dividend has a fair value of approximately $830 million, or $2.28 per common share.

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 may hedge a portion of our production at commodity prices management deems attractive to ensure stable cash flow margins to fund our operating commitments and development program. As of February 2006, we have hedged approximately 50% of our first quarter 2006 projected gas production at an average NYMEX price of $12.95 per Mcf, and 20% of our last nine months 2006 projected gas production at an average NYMEX price of $11.06 per Mcf, and about 35% of our 2006 crude oil production at an average NYMEX price of $59.53 per Bbl. Our average realized price on hedged production will be lower than these average NYMEX prices because of location, quality and other adjustments.

The combined effect of higher product prices, a 23% increase in gas production and a 72% increase in oil production resulted in an 81% increase in total revenues to $3.52 billion in 2005 from $1.95 billion in 2004. On an Mcfe produced basis, total revenues were $7.25 in 2005, a 38% increase from $5.24 in 2004.

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

Production expense per Mcfe rose 27% primarily because of the 72% increase in oil production, which is more expensive to produce than natural gas. Increased maintenance and labor costs and the higher cost of gas used for fuel also contributed to higher production expense. Taxes, transportation and other expense generally is based on product revenues, and the 34% increase in this expense per Mcfe is primarily caused by increased product prices. The 24% increase in depreciation, depletion and amortization per Mcfe resulted from higher acquisition, development and infrastructure costs. The 25% increase in general and administrative expense per Mcfe is because of increased personnel and other costs related to Company growth.

Significant expenses that generally do not trend with production include:

Stock-based incentive compensation. This is a component of general and administrative expense and primarily relates to performance shares that vest when the common stock price reaches specified target levels. Incentive compensation was $34 million in 2005, a 62% decrease from the comparable 2004 expense of $89 million. Included in 2004 incentive compensation is $22 million of cash compensation related to vesting of cash-equivalent performance shares. Otherwise, stock-based incentive compensation was non-cash. Decreased incentive compensation is because performance shares were not awarded to the executive officers named in the proxy. Including stock-based incentive compensation, general and administrative expense decreased $10 million, or 6%.

As required by SFAS No. 123 (Revised 2004), as of January 1, 2006, we will begin recognizing compensation expense in our consolidated financial statements related to the estimated fair value of all stock-based awards, including stock options, granted in 2006 and after. In addition, we will record compensation expense of $17 million in 2006 related to the estimated fair value of unvested stock awards outstanding at December 31, 2005.

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 net derivative fair value gain was $13 million in 2005 compared to a $12 million loss in 2004. In 2005, a $37 million gain primarily related to natural gas basis swap agreements not qualifying for hedge accounting was partially offset by a loss on the Btu swap contracts. The derivative loss in 2004 was primarily attributable to the ineffective portion of hedge derivatives.

Our primary sources of liquidity are cash flow from operating activities, borrowings under our revolving credit facility with commercial banks and public and private offerings of equity and debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest cost, interest rate volatility and financing risk (See “Liquidity and Capital Resources – Financing”).

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Significant Events, Transactions and Conditions

The following events, transactions and conditions affect the comparability of results of operations and financial condition for each of the years ended December 31, 2005, 2004 and 2003 and may impact future operations and financial condition.

Acquisitions. We acquired proved and unproved properties at a total cost of $2 billion per year in 2005 and 2004 and $629 million in 2003, which were funded by a combination of proceeds from sales of common stock and senior notes, bank borrowings and cash flow from operating activities. The following are the significant acquisitions:

On February 28, 2006, we acquired proved and unproved properties from Total E&P USA, Inc. for $300 million. The acquisition is subject to typical post-closing adjustments.

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2005, 2004 and 2003 Development and Exploration Programs. Gas development focused on the Eastern and North Texas Regions during 2005 and on the Eastern and Mid-Continent Regions in 2004 and 2003. Oil development was concentrated primarily in the Permian Region during all three years. Development costs totaled $1.34 billion in 2005, $570 million in 2004 and $443 million in 2003. Exploration activity in 2005 was primarily drilling and geological and geographical analysis, including seismic studies of underdeveloped properties in the North Texas Region. Exploration activity in 2004 was primarily geological and geophysical analysis, including seismic studies of undeveloped properties. Exploration activity in 2003 consisted primarily of drilling successful wells in the Eastern Region. Exploratory costs were $52 million in 2005, $17 million in 2004 and $19 million in 2003. Our development and exploration activities are generally funded by cash flow from operations.

2006 Acquisition, Development and Exploration Program. We have budgeted $1.7 billion for our 2006 development and exploration program, which we expect to fund using cash flow from operations. While an acquisition budget has not been formalized, we plan to continue to actively review additional acquisition opportunities during 2006. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, public or private issuance of debt or equity, or asset sales. The cost of 2006 property acquisitions may alter the amount currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2006 to focus on opportunities offering the highest rates of return.

As of December 31, 2005, we have an inventory of between 4,500 and 5,400 identified potential drilling locations. We plan to drill about 1,050 (865 net) development wells and perform approximately 735 (620 net) workovers and recompletions in 2006. Drilling plans are dependent upon product prices.

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 affected by weather, the U.S. economy, the level of North American production, crude oil prices and import levels of liquified natural gas. Natural gas competes with alternative energy sources as fuel for heating and the generation of electricity. Since late 2002, gas prices have generally been increasing due primarily to increased demand and declining North American production. These trends accelerated in the second half of 2005 due to the effects of hurricanes on Gulf of Mexico production. During the last half of 2005 and the first two months of 2006, gas prices have ranged from a high in excess of $15.00 per MMBtu to a low of almost $7.00 per MMBtu. We expect prices to remain volatile. As described under “Hedging Activities” below, we use commodity price hedging instruments to reduce our exposure to gas price fluctuations. The following are comparative average gas prices for the last three years:

At February 24, 2006, the average NYMEX gas price for the following 12 months was $8.46 per MMBtu. As computed on an energy equivalent basis, our proved reserves were 80% natural gas at December 31, 2005. After considering hedges in place as of February 24, 2006, we estimate that a $0.10 per Mcf change in the average gas sales price would result in approximately a $27 million change in 2006 annual operating cash flow before income taxes.

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Oil. Crude oil prices are generally determined by global supply and demand. Since late 2002, oil prices have generally been rising primarily because of increasing global demand and supply shortage concerns, inadequate refining capacity, reduced production as a result of tropical storms and hurricanes in the Gulf of Mexico and political instability. Oil prices increased to record levels in August 2005, exceeding $70.00 per Bbl. We expect oil prices to remain volatile. 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:

At February 24, 2006, the average NYMEX oil price for the following 12 months was $66.33 per Bbl. After considering hedges in place as of February 24, 2006, we estimate that a $1.00 per barrel change in the average oil sales price would result in approximately a $9 million change in 2006 annual operating cash flow before income taxes.

Gulf of Mexico Hurricanes. In late August and September 2005, hurricanes in the Gulf of Mexico disrupted a significant portion of U.S. oil and gas production, leading to higher and more volatile commodity prices. The Company’s field operations and production were substantially unaffected by these hurricanes. Production expense and development costs, however, have increased throughout the industry because of storm damages and related supply shortages and higher insurance costs.

Hedging Activities. We may 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 consider hedging a portion of our production at commodity prices management deems attractive. While there is a risk we may not be able to realize the full benefit of rising prices, management plans to continue its hedging strategy because of the benefits of predictable, stable cash flows.

In 2005, all hedging activities decreased gas revenue by $127 million and decreased oil revenue by $75 million, while in 2004, all hedging activities decreased gas revenue by $156 million and decreased oil revenue by $15 million. In 2003, hedging activities decreased gas revenue by $193 million and decreased oil revenue by $4 million.

The following summarizes our January 2006 through December 2006 NYMEX hedging positions as of February 2006, excluding basis adjustments which are separately hedged. Our average daily production was 1,102,260 Mcf of gas and 41,976 Bbls of oil in fourth quarter 2005. Prices to be realized for hedged production will be less than these NYMEX prices because of location, quality and other adjustments. See Note 8 to the Consolidated Financial Statements.

Derivative Fair Value (Gain) Loss. We record in our income statements realized and unrealized derivative fair value gains and losses related to derivatives that do not qualify for hedge accounting, as well as the ineffective portion of hedge derivatives. We recorded a net derivative fair value gain of $13 million in 2005, and net losses of $12 million in 2004 and $10 million in 2003. The 2005 gain includes a $1 million loss on the ineffective portion of hedge derivatives, or approximately 1% of total hedge derivative losses. The 2004 loss includes a $12 million loss on the ineffective portion of hedge derivatives, or approximately 8% of total hedge derivative losses. The 2003 loss includes a $7 million loss on the ineffective portion of hedge derivatives, or approximately 4% of total hedge derivative losses. These ineffective hedge derivative losses are primarily because of increasing oil and gas prices and their effect on hedges of production in areas without corresponding basis or location differential swap contracts.

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Derivative fair value (gain) loss includes a net loss related to our Btu swap contracts of $23 million in 2005, $1 million in 2004 and $5 million in 2003. The remaining portion of these contracts was terminated as of February 28, 2006, resulting in a net Btu swap contract gain of approximately $16 million in first quarter 2006.

Unrealized derivative gains and losses associated with effective cash flow hedges are recorded in stockholders’ equity as accumulated other comprehensive income. At December 31, 2005, we have an unrealized pre-tax gain of $106 million in accumulated other comprehensive income related to the fair value of derivatives designated as cash flow hedges of gas and crude oil price risk. This fair value gain is expected to be reclassified into earnings in 2006. The actual reclassification to earnings will be based on mark-to-market prices at contract settlement date.

Stock-based Incentive Compensation. Through 2005, incentive compensation generally resulted from vesting of performance share awards as our common stock price increased. Incentive compensation totaled $34 million in 2005, $89 million in 2004 and $53 million in 2003, which relates to increases in our stock price of 66% in 2005, 56% in 2004 and 53% in 2003. Included in 2004 incentive compensation is $22 million of cash compensation related to vesting of cash-equivalent performance shares. Otherwise, stock-based compensation was non-cash. As of December 31, 2005, outstanding performance shares comprise 154,500 shares that vest when the common stock price closes above $50 and 1,250 shares that vest when the common stock price closes above $55. Based on management’s estimated probable vesting period, $2 million of related stock incentive compensation was accrued at December 31, 2005.