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.

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:

  • Eastern Region, including the East Texas Basin, northwestern Louisiana and Mississippi;
  • North Texas Region, including the Barnett Shale;
  • San Juan Region;
  • Permian and South Texas Region; and
  • Mid-Continent and Rocky Mountain Region, including the Fayetteville and Woodford Shales.

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

  • Bbl Barrel (of oil or natural gas liquids)
  • Bcf Billion cubic feet (of natural gas)
  • Bcfe Billion cubic feet of natural gas equivalent
  • BOE Barrels of oil equivalent
  • Mcf Thousand cubic feet (of natural gas)
  • Mcfe Thousand cubic feet of natural gas equivalent
  • MMBtu One million British Thermal Units, a common energy measurement
  • Tcf Trillion cubic feet (of natural gas)
  • Tcfe Trillion cubic feet equivalent

Our estimated proved reserves at December 31, 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 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 oil and gas properties, including undeveloped leases,
  • increasing production and reserves through efficient management of operations and through development, exploitation and exploration activities,
  • hedging a portion of our production to provide adequate cash flow to fund our development budget and protect the economic return on development projects and acquisitions, and
  • retaining management and technical staff that have substantial experience in our core areas.

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

  • contain complex, multiple-producing horizons with the potential for increases in reserves and production,
  • produce from nonconventional sources, including tight natural gas reservoirs, coal bed methane and natural gas-producing shale formations,
  • are in core operating areas or in areas with similar geologic and reservoir characteristics, and
  • provide opportunities to improve operating efficiencies.

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:

  • ability to more efficiently plan and execute our development program, which facilitates predictable production growth,
  • ability to help assure the economic return on acquisitions,
  • ability to enter long-term arrangements with drilling contractors, allowing us to continue development projects when product prices decline,
  • more consistent returns on investment, and
  • better utilization of our personnel.

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

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.

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:

 
Proved Reserves
  
(in millions)
Gas (Mcf)
Natural Gas Liquids (Bbls)
Oil (Bbls)
Natural Gas Equivalents (Mcfe)
Discounted
Present Value
before Income Tax
of Proved Reserves (a)
Eastern Region 3,861.1 15.8 11.8 4,026.8 $ 9,242 32%
North Texas Region 2,288.6 6.3 – 2,326.4   4,501 15%
San Juan Region 1,129.1 42.5 2.2 1,397.3   3,164 11%
Permian and
South Texas Region		 560.2 2.2 192.4 1,728.0   8,127 28%
Mid-Continent and
Rocky Mountain Region		 1,598.8 – 18.5 1,709.3   3,681 13%
Other 3.3 – 16.3 101.2   454 1%
Total 9,441.1 66.8 241.2 11,289.0 $ 29,169 100%

(a) We believe that the discounted present value of estimated future net cash flows before income tax is a useful supplemental disclosure to the standardized measure, or after-tax amount, of $19.5 billion. While the standardized measure is dependent on the unique tax situation of each company, the pre-tax discounted amount is based on prices and discount factors that are consistent for all companies. Because of this, the pre-tax discounted amount can be used within the industry and by securities analysts to evaluate estimated future net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the pre-tax discounted amount is the discounted estimated future income tax of $9.6 billion 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.

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.

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:

 
December 31
(in millions)
2007
2006
2005
Proved developed:  
Gas (Mcf)   6,031.5   4,481.6   4,033.1
Natural gas liquids (Bbls)   52.9   40.1   36.5
Oil (Bbls)   184.8   167.3   168.5
Mcfe   7,457.7   5,725.9   5,262.9
Proved undeveloped:  
Gas (Mcf)   3,409.6   2,462.6   2,052.5
Natural gas liquids (Bbls)   13.9   12.9   10.9
Oil (Bbls)   56.4   47.1   40.2
Mcfe   3,831.3   2,822.7   2,359.3
Total proved:  
Gas (Mcf)   9,441.1   6,944.2   6,085.6
Natural gas liquids (Bbls)   66.8   53.0   47.4
Oil (Bbls)   241.2   214.4   208.7
Mcfe   11,289.0   8,548.6   7,622.2
Estimated future net cash flows:  
Before income tax (a) $ 57,949 $ 32,259 $ 50,897
After income tax $ 39,526 $ 22,008 $ 34,074
Present value of estimated future net cash flows, discounted at 10%:  
Before income tax (a) $ 29,169 $ 16,228 $ 25,816
After income tax $ 19,538 $ 10,828 $ 17,094

(a) We believe that the estimated future net cash flows before income tax and the discounted present value of estimated future net cash flows before income tax are useful supplemental disclosures to the after-tax estimated future net cash flows and the standardized measure, or after-tax amount. While the after-tax estimated future net cash flows and the standardized measure are dependent on the unique tax situation of each company, the pre-tax measures are based on prices and discount factors that are consistent for all companies. Because of this, the pre-tax measures can be used within the industry and by securities analysts to evaluate estimated future net cash flows from proved reserves on a more comparable basis. The difference between the after-tax and the pre-tax estimates of future net cash flows is estimated future income tax of $18.4 billion at December 31, 2007, $10.3 billion at December 31, 2006 and $16.8 billion at December 31, 2005. The difference between the standardized measure and the pre-tax discounted amount is the discounted estimated future income tax of $9.6 billion at December 31, 2007, $5.4 billion at December 31, 2006 and $8.7 billion at December 31, 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 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:

 
Operated Wells
  
Nonoperated Wells
  
Total (a)
 
Gross
Net
  
Gross
Net
  
Gross
Net
Gas 10,524.3 9,148.3   7,504.8 1,399.6   18,029.1 10,547.9
Oil 2,611.7 2,280.8   4,522.2 575.1   7,133.9 2,855.9
Total 13,136.0 11,429.1   12,027.0 1,974.7   25,163.0 13,403.8

(a) 930.1 gross (681.8 net) gas wells and 19.9 gross (18.0 net) oil wells are dual completions.
Drilling Activity

The following table summarizes the number of wells drilled during the years indicated. As of December 31, 2007, we were in the process of drilling 595 gross (422.4 net) wells.

 
Year Ended December 31
 
2007
  
2006
  
2005
 
Gross
Net
  
Gross
Net
  
Gross
Net
Development wells:  
Completed as —  
Gas wells 1,275 901.2   1,148 725.1   791 499.8
Oil wells 269 139.3   316 169.1   255 121.4
Non-productive 12 7.6   11 3.3   19 9.6
Total 1,556 1,048.1   1,475 897.5   1,065 630.8
Exploratory wells:  
Completed as —  
Gas wells 51 17.4   22 8.1   7 4.7
Oil wells 1 1.0   – –   – –
Non-productive 9 6.8   10 7.2   2 2.0
Total 61 25.2   32 15.3   9 6.7
Total (a) 1,617 1,073.3   1,507 912.8   1,074 637.5

(a) Included in totals are 535 gross (106.0 net) wells in 2007, 581 gross (119.5 net) wells in 2006 and 472 gross (96.7 net) wells in 2005, drilled on nonoperated interests.
Acreage

The following table summarizes developed and undeveloped leasehold acreage in which we own a working interest as of December 31, 2007. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

 
Developed
Acres (a)(b)
  
Undeveloped Acres
(in thousands)
Gross
Net
  
Gross
Net
Texas 1,191 831   663 544
Arkansas 610 333   135 121
Oklahoma 580 407   254 129
New Mexico 562 350   19 17
Utah 289 168   154 99
Montana 272 44   85 36
Kansas 211 167   – –
Louisiana 139 73   86 28
Colorado 112 87   5 5
Wyoming 99 67   67 60
Other 34 15   33 13
Total 4,099 2,542   1,501 1,052

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

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

Substantially all of our undeveloped acreage is subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. We do not expect to lose any significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

Oil and Gas Production, Sales Prices and Production Costs

The following table shows the total and average daily production, the average sales prices per unit of production and the production expense and taxes, transportation and other expense per Mcfe for the indicated periods:

 
Year Ended December 31
 
2007
2006
2005
Total production:  
Gas (Mcf)   532,097,846   433,010,577   377,097,181
Natural gas liquids (Bbls)   4,943,781   4,326,853   3,812,420
Oil (Bbls)   17,172,191   16,440,079   14,253,718
Mcfe   664,793,678   557,612,169   485,494,009
Average daily production:  
Gas (Mcf)   1,457,802   1,186,330   1,033,143
Natural gas liquids (Bbls)   13,545   11,854   10,445
Oil (Bbls)   47,047   45,041   39,051
Mcfe   1,821,353   1,527,705   1,330,121
Average sales prices (a):  
Gas (per Mcf) $ 7.50 $ 7.69 $ 7.04
Natural gas liquids (per Bbl) $ 45.37 $ 37.03 $ 34.10
Oil (per Bbl) $ 70.08 $ 60.96 $ 47.03
Production expense per Mcfe $ 0.93 $ 0.88 $ 0.84
Production and property taxes per Mcfe $ 0.38 $ 0.41 $ 0.42
Transportation and other expense per Mcfe $ 0.29 $ 0.26 $ 0.21

(a) The sales prices shown include the effects of hedging. The effect of hedging on gas prices was to increase realized prices by $1.24 in 2007 and $1.43 in 2006 and to decrease realized prices by $0.34 in 2005. The effect of hedging on oil prices was to increase realized prices by $1.40 in 2007 and $0.17 in 2006 and to decrease realized prices by $5.25 in 2005.

Delivery Commitments

Under a production payment sold in 1998, we committed to deliver 16 Bcf beginning September 2006. The committed volumes are in East Texas. As of December 31, 2007, remaining volumes to be delivered under this commitment are 12 Bcf.

As part of the July 2007 Dominion acquisition, Dominion retained interests in certain of the acquired properties. Under the terms of the acquisition and the retained interest agreements, Dominion retained the rights to approximately 13 Bcf of gas beginning from the date of acquisition through February 2009. As of December 31, 2007, remaining volumes to be delivered to Dominion are 7 Bcf.

The Company‘s production and reserves are adequate to meet these delivery commitments. See Note 8 to Consolidated Financial Statements.

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 liquefied 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. FERC has promulgated new regulations to implement the Energy Policy Act. We cannot predict the impact of future government regulation on any natural gas facilities.

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

Federal Regulation of Oil

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

On December 19, 2007, the President signed into law the Energy Independence & Security Act of 2007 (PL 110-140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline, or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder. We cannot predict the impact of future government regulation on any natural gas facilities.

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. Two of our gathering subsidiaries are designated gas utilities and are 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 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 2,361 employees as of December 31, 2007. 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, 59, 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, 49, 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, 53, 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, 58, 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.

Timothy L. Petrus, 53, 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, 57, 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.