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  As Of               Filer                 Filing     As/For/On Docs:Pgs              Issuer               Agent

 2/26/08  Xto Energy Inc                    10-K       12/31/07   12:200                                    RR Donnelley/FA

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML  1,068K 
 2: EX-10.18    Form of Stock Grant Agreement                       HTML     11K 
 3: EX-10.34    Description of Matching Charitable Contribution     HTML      6K 
                          Program                                                
 4: EX-10.39    Fourth Amendment to 5-Year Revolving Credit         HTML     96K 
                          Agreement                                              
 5: EX-10.44    Fourth Amendment to Term Loan Agreement             HTML     97K 
 6: EX-12.1     Computation of Ratio of Earnings to Fixed Charges   HTML     19K 
 7: EX-21.1     Subsidaries of Xto Energy Inc.                      HTML      8K 
 8: EX-23.1     Consent of Kpmg Llp                                 HTML      7K 
 9: EX-23.2     Consent of Miller and Lents, Ltd.                   HTML      9K 
10: EX-31.1     Ceo Certification Pursuant to Section 302           HTML     13K 
11: EX-31.2     Cfo Certification Pursuant to Section 302           HTML     13K 
12: EX-32.1     Ceo and Cfo Certification Pursuant to Section 906   HTML      8K 

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 2007

OR

For the transition period from                      to                     

Commission File Number: 1-10662

XTO Energy Inc.

(Exact name of registrant as specified in its charter)

(817) 870-2800

Registrant’s telephone number, including area code

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

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 29, 2007, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $22.0 billion based on the closing price as reported on the New York Stock Exchange.

Number of Shares of Common Stock outstanding as of February 21, 2008—510,323,631

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, 2008.

Table of Contents

XTO ENERGY INC.

2007 ANNUAL REPORT ON FORM 10-K

 TABLE OF CONTENTS

Table of Contents

PART I

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.

All common stock shares and per share amounts in this Form 10-K have been restated for the effect of the five-for-four stock split effected December 13, 2007.

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 through acquisition of proved oil and gas reserves and unproved properties, development and exploitation activities and purchases of additional interests in or near our acquired properties. We expect growth in the immediate future to continue to be accomplished through a combination of acquisitions and development. During 2008, we plan to continue to review 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.

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Our estimated proved reserves at December 31, 2007 were 9.44 Tcf of natural gas, 67 million Bbls of natural gas liquids and 241 million Bbls of oil, based on December 31, 2007 prices of $6.39 per Mcf for gas, $60.24 per Bbl for natural gas liquids and $91.19 per Bbl for oil. On an energy equivalent basis, our proved reserves were 11.29 Tcfe at December 31, 2007, a 32% increase from proved reserves of 8.55 Tcfe at the prior year end. Increased proved reserves during 2007 were primarily the result of development and exploitation activities and acquisitions. On an Mcfe basis, 66% of proved reserves were proved developed reserves at December 31, 2007. During 2007, our average daily production was 1.46 Bcf of gas, 13,545 Bbls of natural gas liquids and 47,047 Bbls of oil. Fourth quarter 2007 average daily production was 1.67 Bcf of gas, 14,462 Bbls of natural gas liquids and 48,844 Bbls of oil.

Our properties typically have relatively long reserve lives and predictable production profiles. Based on December 31, 2007 proved reserves and projected 2008 production from properties owned as of December 31, 2007, the average reserve-to-production index of our proved reserves is 16.3 years. The projected 2008 production is from proved developed producing reserves as of December 31, 2007. In general, our properties have extensive production histories and production enhancement opportunities. Within each of our geographical regions, we have one or more core areas in which our major producing fields are concentrated. For example, the core area in the North Texas region is the Barnett Shale. This allows for substantial economies of scale in production and cost-effective application of reservoir management techniques gained from prior operations. As of December 31, 2007, we owned interests in 25,163 gross (13,403.8 net) producing wells, and we operated wells representing 88% of the present value of cash flows before income taxes (discounted at 10%) from estimated proved reserves. The high proportion of operated properties allows us to exercise more control over expenses, capital allocation and the timing of development and exploitation activities in our fields.

We have a substantial inventory of between 9,500 and 10,300 identified potential drilling locations. Of these locations, approximately 3,100 have proved undeveloped reserves attributed to them. 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 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 commodities future contracts, collars and price and basis swap agreements, fixed-price physical sales 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

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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, the Board of Directors declared a dividend of 0.0036 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. Hugoton Royalty Trust units are listed on the New York Stock Exchange under the symbol “HGT.” We sold 17 million units in the trust’s initial public offering in 1999 and issued 1.3 million units pursuant to an employee incentive plan in 1999 and 2000. In January 2006, the Board of Directors declared a dividend of 0.047688 trust units for each share of our common stock outstanding on April 26, 2006. As a result of this dividend, all of the remaining 21.7 million trust units were distributed on May 12, 2006.

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 and are increasingly being affected by imports of liquefied natural gas. 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:

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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. Our ability to successfully purchase properties is dependent upon, among other things, competition for such purchases and the availability of financing to supplement internally generated cash flow.

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

Increasing Production and Reserves. A principal component of our strategy is to increase production and reserves through aggressive management of operations and low-risk development. We believe that our principal properties possess geologic and reservoir characteristics that make them well suited for production increases through drilling and other development programs. 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 2008, 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 $125 million of our $2.6 billion 2008 development budget for exploration activities.

Hedging Activities. To reduce production price risk, we may enter futures contracts, collars and price 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.

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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 February 2008, we announced a strategic goal for 2008 of increasing production by 20% over 2007 levels and to increase proved reserves to 15 Tcfe by December 31, 2009. To achieve these growth targets, we plan to drill about 1,160 (980 net) development wells and perform approximately 750 (600 net) workovers and recompletions in 2008. No development budget has been announced for 2009.

We have budgeted $2.6 billion for our 2008 development program, which is expected to be funded by cash flow from operations. We plan to spend approximately $850 million in the Eastern Region, $700 million in the North Texas Region, $425 million in the Permian and South Texas Region, $300 million in the San Juan Region and $200 million in the Mid-Continent and Rocky Mountain Region and other areas and approximately $125 million for exploration activities. An additional $400 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities that are critical to the transportation and sale of production in several operating regions.

While an acquisition budget has not been formalized, we expect to complete acquisitions of both producing and unproved properties for approximately $1.0 billion, during the first quarter of 2008. These acquisitions will be funded both by commercial paper borrowings and by proceeds from the February 2008 common stock offering and are subject to typical post-closing adjustments. We plan to actively review additional acquisition opportunities during 2008. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, issuance of public or private debt or equity, or asset sales. Strategic property acquisitions during 2008 may alter the amount currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2008 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 or additional acquisitions. 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.

Continued raw material shortages and strong global demand for steel have caused prices to remain high. In response, we have maintained a higher tubular inventory and have negotiated supply contracts with our suppliers 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 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 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.

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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 gas-producing properties in the Powder River Basin of Wyoming from ExxonMobil Corporation for $336 million. In August, 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 new properties 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, $215 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. 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.

During 2006, we acquired proved properties for a total cost of $561 million. In February 2006, we acquired proved and unproved properties in East Texas and Mississippi from Total E&P USA, Inc. for $300 million. In June 2006, we acquired Peak Energy Resources, Inc., which operated gas-producing properties and owned unproved properties in the Barnett Shale in the Fort Worth Basin. The purchase price was $108 million, which was primarily funded by issuance of 3.2 million shares of common stock valued at $102 million, $5 million cash for additional leasehold interests and $1 million cash for other transaction costs. After recording estimated deferred taxes of $36 million and other liabilities, the purchase price allocated to proved properties was $97 million and unproved properties was $53 million. Our 2006 acquisitions increased reserves by approximately 157.9 Bcf of natural gas, 4.2 million Bbls of natural gas liquids and 3.3 million Bbls of oil.

During 2007, we acquired proved reserves for a total of $3.2 billion. We also acquired $831 million of unproved properties in 2007. In July 2007, we acquired both producing and unproved properties from Dominion Resources, Inc. for $2.5 billion, subject to typical post-closing adjustments. These properties are located in the Rocky Mountain Region, the San Juan Basin and South Texas. The acquisition was funded by the issuance of 21.6 million shares of our common stock in June 2007 for net proceeds of $1.0 billion, the issuance of $1.25 billion of senior notes in July 2007 and with borrowings under our commercial paper program, which was repaid with a portion of the proceeds from the issuance of $1.0 billion of senior notes in August 2007. After recording an asset retirement obligation of $32 million, other liabilities and transaction costs of $18 million, the purchase price allocated to proved properties was $2.5 billion and unproved properties was $73 million. In October 2007, we announced acquisitions from multiple parties of both producing and unproved properties in the Barnett Shale for approximately $550 million. All 2007 acquisitions are subject to typical post-closing adjustments. Our 2007 acquisitions increased reserves by approximately 1.3 Tcf of natural gas, 2.7 million Bbls of natural gas liquids and 11.3 million Bbls of oil.

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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, 2007:

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 14,000 feet. Subsequent acquisitions and development activity have significantly increased reserves here since we began operations, and we now own an interest in approximately 690,000 net acres. Over 35% of our total proved reserves are in this region. We have 2,650 to 2,950 identified potential drilling locations in this area. In 2005, we expanded our gathering facilities to increase treating capacity to 730,000 Mcf per day. An additional 330,000 Mcf per day of treating capacity is expected to be completed in mid 2008. In 2008, we plan to drill between 340 and 380 wells in the Eastern Region.

Our primary focus in the Eastern Region is in the Freestone Trend where we have an interest in approximately 347,000 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 2007. Other areas in the region include the Sabine Uplift and Cotton Valley areas of East Texas and northwestern Louisiana.

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, 2006 acquisition of Peak Energy Resources and various 2007 acquisitions, we are one of the largest producers in the area. We own approximately 250,000 net acres, 50% of which is in the core productive area, 841 producing wells and gas gathering and pipeline assets. We have 2,200 to 2,300 identified potential drilling locations in this area and plan to drill approximately 250 to 300 wells in 2008. We also own 225,000 Mcf per day of treating capacity allowing us to add new wells as they are completed. An additional 330,000 Mcf per day of treating capacity is expected to be completed during second quarter 2008.

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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. As a result of the 2007 Dominion acquisition, we significantly expanded our holdings in the Uinta Basin. Production is from conventional as well as coal bed methane sources. We have 1,500 to 1,600 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 farmout agreement with ExxonMobil, and in 2007 we completed the final well of a four-well commitment.

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 2004, 2005 and 2007, we significantly expanded our holdings in the area through acquisitions and trades with ChevronTexaco, ExxonMobil, ConocoPhillips, Dominion and others. Our activities on these properties have increased oil production by returning shut-in wells to production, optimizing existing well performance, using 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 1,250 to 1,350 identified potential drilling locations in this area.

Mid-Continent and Rocky Mountain Region

Our Mid-Continent and Rocky Mountain Region includes fields in Wyoming, Montana, Kansas, Oklahoma and Arkansas. We have operations in the Anadarko Basin, Fontenelle area, Powder River Basin and the Arkoma Basin. During 2008, we plan to continue drilling activities in the Fayetteville Shale in Arkansas and the Woodford Shale in Southeast Oklahoma. While most of our production in the region is from conventional sources, we are developing coal bed methane in the Powder River Basin of Wyoming. We have 1,900 to 2,100 identified potential drilling locations in this area. A 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 operate a gathering system and pipeline in Major County, Oklahoma and a gas plant in Texas County, Oklahoma, and its associated gathering system. We also completed a gas gathering and water disposal system in the Hartzog Draw area of Wyoming to service our coal bed methane wells.

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/about/forms/regs-x.pdf.

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

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

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

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

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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, 2007, 2006 and 2005:

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, 2007, 2006 and 2005. 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.

Estimated future net cash flows, and the related 10% discounted present value, of year-end 2007 proved reserves are significantly higher than at year-end 2006 because of higher commodity prices used in estimation of year-end proved reserves and increased reserves related to development and acquisitions. Year-end 2007 average

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realized prices used in the estimation of proved reserves were $6.39 per Mcf for gas, $60.24 per Bbl for natural gas liquids and $91.19 per Bbl for oil. Year-end 2006 product prices were $5.46 per Mcf for gas, $31.96 per Bbl for natural gas liquids and $55.47 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 2007, we filed estimates of oil and gas reserves as of December 31, 2006 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, 2006 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, 2007, all of which are located in the United States: