Company: XTO ENERGY INC
CIK: 868809
SIC: 1311
Filing Date: 2010-02-25 00:00:00

ITEM 1 - BUSINESS

ITEM 1A - RISK FACTORS
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 natural gas, oil and natural gas liquids. We sell most of our natural gas, oil and natural gas liquids at current market prices rather than through fixed-price contracts. Historically, the markets for natural gas, oil 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:
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weather conditions;
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political instability or armed conflict in oil-producing regions, such as current conditions in the Middle East, Nigeria and Venezuela;
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the supply of domestic and foreign oil, natural gas and natural gas liquids;
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the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels;
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the level of consumer demand;
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worldwide economic conditions;
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the price and availability of alternative fuels;
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domestic and foreign governmental regulations and taxes;
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the proximity to and capacity of transportation facilities; and
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the effect of worldwide energy conservation measures.
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 natural gas and oil 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.
Our use of hedging arrangements could result in financial losses or reduce our income.
To reduce our exposure to fluctuations in natural gas, oil and natural gas liquids prices, we have entered into and expect in the future to enter into hedging arrangements for a portion of our natural gas, oil and natural gas liquids production. However, we may not be able to hedge our future production at prices we deem attractive. These hedging arrangements expose us to risk of financial loss in some circumstances, including when:
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production is less than expected;
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the counterparty to the hedging contract defaults on its contractual obligations; or
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there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in natural gas, oil and natural gas liquids 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 and commercial paper 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 $3.0 billion in 2009, $3.9 billion in 2008 and $2.8 billion in 2007. During 2009, we spent $30 million on proved property acquisitions and $224 million on unproved property acquisitions. Our exploration and development budget for 2010 is $3.37 billion. An additional $530 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities in 2010.
We believe that, after debt service, we will have sufficient cash from operating activities to finance our exploration and development expenses through 2010. 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.
A financial crisis may impact our business and financial condition in ways that we cannot predict.
The continued uncertainties in the global financial system may continue to have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. We believe that our development and exploration budget allows us to fund our business with anticipated internally generated cash flow. However, if we were to need to access the capital markets, as a result of this crisis we may not have the ability to raise capital. Also, if the current economic conditions do not improve, it is possible that we could have additional receivables become uncollectible and counterparties under our hedging could be unable to perform their obligations or seek bankruptcy protection. Additionally, a worsening economic situation could lead to further reductions in demand for natural gas and oil, or lower prices for natural gas and oil, or both, which could have a negative impact on our revenues.
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, term loans and commercial paper indebtedness is at a variable interest rate, so a rise in interest rates will generate greater interest expense to the extent we do not have 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. Also, if we repurchase or repay any of our term loans or public debt, we cannot re-borrow these funds and may not be able to enter into a new debt arrangement with similar terms or rates.
Our access to the commercial paper market is predicated on continued acceptable short-term ratings by Standard & Poors and Moody’s. Any downgrade in those ratings may impact our borrowing costs as well as our access to the commercial paper market. Additionally, any downgrade to our long-term ratings could increase our borrowing costs and limit our access to capital markets.
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.
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:
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seeking to acquire desirable producing properties or new leases for future exploration;
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marketing our oil and natural gas production;
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integrating new technologies;
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seeking to acquire the equipment and expertise necessary to develop and operate our properties; and
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hiring qualified people.
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, development or exploration 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 in 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 geologic, 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.
One 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 based on a 12-month average price, using the first-day-of-the-month price for each month in the period, and year end costs. Prior to 2009, we used year end oil and gas prices and costs to estimate our discounted future net cash flows from our proved reserves. Actual current and future prices and costs may differ materially from those used in the net present value estimate, and as a result, net present value estimates using current prices and costs may be significantly less than the estimate which is provided in this annual report.
Producing and unproved 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 both producing and unproved 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 and development potential, lease terms, 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 both producing and unproved 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.
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.
Our development and exploratory drilling efforts and our operations of our wells may not be profitable or achieve our targeted returns.
We acquire significant amounts of unproved property in order to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells. Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas and crude oil, costs associated with producing natural
gas and oil and our ability to add reserves at an acceptable cost. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether natural gas or oil is present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies.
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:
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unexpected drilling conditions, including urban drilling;
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title problems;
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restricted access to land for drilling or laying pipeline;
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pressure or irregularities in formations;
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equipment failures or accidents;
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adverse weather conditions, including hurricanes in the Gulf of Mexico; and
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costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment.
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, as well as any delays in constructing new 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.
We are subject to complex federal, state, local and foreign laws and regulations that could adversely affect our business.
Extensive federal, state, local and foreign 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:
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discharge permits for drilling operations;
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drilling bonds;
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spacing of wells;
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unitization and pooling of properties;
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environmental protection;
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greenhouse gas emissions;
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drilling techniques, including hydraulic fracturing;
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reports concerning operations; and
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taxation.
Under these laws and regulations, we could be liable for:
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personal injuries;
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property damage;
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oil spills;
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discharge of hazardous materials;
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reclamation costs;
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remediation and clean-up costs; and
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other environmental damages.
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 U.S. waters 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. 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.
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:
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fires;
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natural disasters;
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explosions;
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pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion;
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weather, including hurricanes in the Gulf of Mexico;
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failure of oilfield drilling and service tools;
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changes in underground pressure in a formation that causes the surface to collapse or crater;
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pipeline ruptures or cement failures; and
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environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases.
Any of these risks can cause substantial losses resulting from:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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repair and remediation costs.
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.
Failure to complete the proposed merger with ExxonMobil could negatively impact our stock price and our future business and financial results.
On December 13, 2009, we entered into a definitive merger agreement with Exxon Mobil Corporation under which we would become a wholly owned subsidiary of ExxonMobil. As a result of the merger, each outstanding share of our common stock will be converted into 0.7098 shares of ExxonMobil common stock. If the merger is not completed, our ongoing business may be adversely affected and, without realizing any of the benefits of having completed the merger, we would be subject to a number of risks, including the following:
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we may experience negative reactions from the financial markets and our customers and employees;
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we may be required to pay ExxonMobil a termination fee of $900 million if the merger is terminated under certain circumstances;
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we will be required to pay certain costs relating to the merger, whether or not the merger is completed;
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the merger agreement places certain restrictions on the conduct of our business prior to the completion of the merger or the termination of the merger agreement. Such restrictions, the waiver of which is subject to the consent of ExxonMobil (not to be unreasonably withheld, conditioned or delayed), may prevent us from making certain acquisitions or taking certain other specified actions during the pendency of the merger; and
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matters relating to the merger (including integration planning) may require substantial commitments of time and resources by our management, which would otherwise have been devoted to other opportunities that may have been beneficial to us as an independent company.
There can be no assurance that the risks described above will not materialize, and if any of them do, they may adversely affect our business, financial results and stock price.
The merger with ExxonMobil may cause disruption in our business and present difficulties attracting, motivating and retaining executives and other key employees in light of the merger.
Parties with which we do business may experience uncertainty associated with the merger, including with respect to current or future business relationships. These disruptions could have an adverse effect on our business, financial condition, results of operations or prospects. The adverse effect of such disruptions could be exacerbated by a delay in the completion of the merger or termination of the merger agreement. In addition, uncertainty about the effect of the merger on our employees may have an adverse effect on us. This uncertainty may impair our ability to attract, retain and motivate key personnel until the merger is completed. Employee retention may be particularly challenging during the pendency of the merger, as employees may experience uncertainty about their future roles with ExxonMobil.
The merger agreement with ExxonMobil limits our ability to pursue alternatives to the merger.
The merger agreement contains provisions that make it more difficult for us to sell the business to a party other than ExxonMobil. These provisions include a general prohibition on us or any of our employees soliciting any acquisition proposal or offer for a competing transaction, the requirement that we pay a termination fee of $900 million in the aggregate if the merger agreement is terminated in specified circumstances and the requirement that we submit the adoption of the merger agreement to a vote of our stockholders even if our board of directors changes its recommendation in favor of the adoption of the merger agreement in a manner adverse to ExxonMobil. While we believe these provisions are reasonable and not preclusive of other offers, the provisions might discourage a third party that has an interest in acquiring all of or a significant part of our business from considering or proposing that acquisition, even if that party were prepared to pay consideration with a higher per-share market price than the currently proposed merger consideration. Furthermore, the termination fee may result in a potential competing acquirer proposing to pay a lower per-share price to acquire us than it might otherwise have proposed to pay because of the added expense of the $900 million termination fee that may become payable in certain circumstances.

ITEM 1B - UNRESOLVED STAFF COMMENTS
Item 1B. UNRESOLVED STAFF COMMENTS
As of December 31, 2009, we do not have any Securities and Exchange Commission staff comments that have been unresolved for more than 180 days.

ITEM 2 - PROPERTIES

ITEM 3 - LEGAL PROCEEDINGS
Item 3. LEGAL PROCEEDINGS
In July 2005 a predecessor company that we acquired, Antero Resources Corporation, was served with a lawsuit styled Threshold Development Company, et al. v. Antero Resources Corp., which lawsuit was filed in the District Court of Wise County, Texas. The plaintiffs are surface owners, royalty owners and prior working interest owners in several oil and gas leases as well as parties to other contractual agreements under which Antero Resources Corporation owned an interest. Antero Resources Corporation, the defendant, was acquired by us on April 1, 2005. The claims related to alleged events pre-dating the acquisition and concern non-payment of royalties, improper calculation of royalties, improper pricing related to royalties, trespass, failure to develop and breach of contract. We settled all claims related to the payment of royalties and trespass. Under the remaining claims, the plaintiffs sought both damages and termination of the existing oil and gas leases covering their interests. In October 2008, the trial court granted our motion for summary judgment, resulting in the dismissal of the plaintiffs’ remaining claims. The plaintiffs have appealed the court’s judgment. Based on a review of the current facts and circumstances with counsel, management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter. While acknowledging the uncertainties of litigation, management believes that the ultimate outcome of this matter will not have a material effect on our earnings, cash flows or financial position.
In November 2008, an action was filed against the Company and our directors styled Freedman v. Adams, et al. in the Delaware Court of Chancery. The plaintiff is alleged to be a stockholder and brings the suit as a derivative action on behalf of the Company. The plaintiff seeks an equitable accounting for the alleged losses by the Company and injunctions mandating that a Section 162(m) plan be submitted to our stockholders for their approval and against further non-deductible payments, along with an award of accountants’, experts’ and attorneys’ fees. We have filed a motion to dismiss. While we did not have in place a Section 162(m) plan at the time the suit was filed for cash payments, the Board of Directors approved a Section 162(m) plan in February 2009 that was approved by our stockholders at our annual meeting in May 2009. Although we are unable to predict the final outcome of this case, we believe that the allegations of this lawsuit are without merit, and we intend to vigorously defend the action.
In September 2008, a class action lawsuit was filed against the Company styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. We removed the case to federal court in Wichita, Kansas. The plaintiffs allege that we have improperly taken post-production
costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma, and Colorado. The plaintiffs also seek to represent all royalty owners in these three states as a class. We have answered, denying all claims, and have filed motions to dismiss a portion of the claims. The federal court recently granted our motion for summary judgment concerning prior settled class actions that overlap plaintiff’s proposed class action. The court also granted our motion to dismiss those portions of plaintiff’s class that are currently being prosecuted in another case. Based on a review of the current facts and circumstances with counsel, management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter. While acknowledging the uncertainties of litigation, management believes that the ultimate outcome of this matter will not have a material effect on our earnings, cash flows or financial position.
On December 14, 2009, Exxon Mobil Corporation and XTO Energy announced that the companies had entered into a definitive agreement under which we would become a wholly owned subsidiary of ExxonMobil. As a result of this announcement, a number of putative shareholder class actions have been filed, alleging breaches of fiduciary duties by the individual members or our Board of Directors. Each lawsuit generally seeks, among other things, declaratory and injunctive relief concerning the alleged fiduciary breaches, injunctive relief prohibiting the defendants from consummating the merger, imposition of constructive trusts in favor of plaintiffs and putative class members and unspecified monetary damages. Several putative shareholders have also filed an individual lawsuit in federal court alleging violations of the federal securities laws based on alleged false and material misrepresentations or omissions in the preliminary proxy filed with the Securities and Exchange Commission in connection with the proposed merger. The federal individual action also seeks to enjoin the proposed merger.
Two putative shareholder class actions were filed in the Delaware Court of Chancery between December 17, 2009 and December 18, 2009. Those cases are styled as (i) Teamsters Allied Benefit Funds, et al. v. XTO Energy Inc., et al., Case No. 5150, filed on December 17, 2009 and (ii) Nicholas Lombardi v. XTO Energy Inc., et al., Case No. 5152, filed on December 18, 2009. On December 22, 2009, the Delaware Court of Chancery entered an order consolidating the complaints filed as of that date under the caption In re XTO Energy Inc. Shareholders Litigation.
Eleven putative shareholder class actions were filed in the District Courts of Tarrant County, Texas between December 14, 2009, and January 6, 2010. Those cases are styled: (i) Mary Pappas, et al. v. XTO Energy Inc., et al., No. 342-242403-09, filed on December 14, 2009; (ii) Sanjay Israni, et al. v. XTO Energy Inc., et al., No. 017-242424-09, filed on December 15, 2009; (iii) Michael Walsh, et al. v. XTO Energy Inc., et al., No. 153-242432-09, filed on December 15, 2009; (iv) Ronald Gross, et al. v. XTO Energy Inc., et al., No. 141-242460-09, filed on December 16, 2009; (v) Jeffrey Fink, et al. v. Bob R. Simpson, et al., No. 048-242500-09, filed on December 17, 2009; (vi) Lawrence Treppel, et al. v. XTO Energy Inc., et al., No. 342-242523-09, filed on December 18, 2009; (vii) Nicholas Weil, et al. v. XTO Energy Inc., et al., No. 096-242526-09, filed on December 18, 2009; (viii) Charles Kreps, et al. v. XTO Energy Inc., et al., Case No. 352-242548-09, filed on December 21, 2009; (ix) Murray Silver, et al. v. XTO Energy Inc., et al., No. 342-242630-09, filed on December 22, 2009; (x) William Stratton, et al. v. XTO Energy Inc., et al., No. 096-242775-09, filed on December 30, 2009; and (xi) United Food and Commercial Workers Union Local 880-Retail Food Employers Joint Pension Fund v. XTO Energy Inc., et al., No. 342-242849-10, filed on January 6, 2010. On January 12, 2010, the court entered orders consolidating the eleven cases filed as of that date under the caption In re XTO Energy Shareholder Class Action Litigation.
Two putative shareholder class actions were filed in the United States District Court for the Northern District of Texas between December 28, 2009 and January 5, 2010. Those cases are styled (i) James Harrison, et al. v. XTO Energy Inc., et al., No. 4:09-cv-768, filed on December 28, 2009 and (ii) Walt Schumann, et al. v. XTO Energy Inc., et al., No. 4:10-cv-007, filed on January 5, 2010. On February 5, 2010, the plaintiffs in the two federal actions filed an unopposed motion to consolidate the cases.
Several putative shareholders filed an individual action in the United States District Court for the Northern District of Texas on February 11, 2010 alleging violations of the federal securities laws based on alleged false
and material misrepresentations or omissions in the preliminary proxy filed with the Securities and Exchange Commission in connection with the proposed merger. That case is styled Mary Pappas, et al. v. Bob R. Simpson, et al., No. 4:10-cv-00094-A, filed February 11, 2010.
We believe that all of the putative shareholder lawsuits are without merit and intend to vigorously defend against such claims.
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 - RESERVED
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 2009.
PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY
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.” On December 13, 2009, we entered into a definitive merger agreement with Exxon Mobil Corporation under which we would become a wholly owned subsidiary of ExxonMobil. As a result of the merger, each outstanding share of our common stock will be converted into 0.7098 shares of ExxonMobil common stock. Completion of the merger remains subject to certain conditions, including the adoption of the merger agreement by our stockholders, as well as certain governmental and regulatory approvals. We currently expect to complete the merger in the second quarter of 2010, however, no assurance can be given as to when, or if, the merger will occur.
The following table sets forth quarterly high and low closing prices and cash dividends declared for each quarter of 2009 and 2008:
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 addition, under the terms of the merger agreement with ExxonMobil, during the period before the closing of the merger, we are prohibited from declaring, setting aside or paying any dividend or other distribution except for our regular quarterly cash dividend, which is not to exceed $0.125 per share. The merger agreement also provides that we will coordinate the declaration of dividends with ExxonMobil before the completion of the merger so that both our shareholders and the shareholders of ExxonMobil only receive, in any quarter, one dividend from each company.
On February 16, 2010, the Board of Directors declared a quarterly dividend of $0.125 per common share, payable on April 15, 2010 to stockholders of record on March 31, 2010. On February 19, 2010, we had 2,294 stockholders of record.
The following summarizes purchases of our common stock during fourth quarter 2009:
(1) The Company has a repurchase program approved by the Board of Directors in August 2004 for the repurchase of up to 25 million shares of the Company’s common stock.
(2) Does not include performance or restricted share forfeitures. Includes 1,459,753 shares of common stock delivered or attested to in satisfaction of the exercise price upon the exercise of employee stock options under both the 1998 and 2004 Stock Incentive Plans. Also includes 518,833 shares of common stock purchased during the quarter from employees in connection with the settlement of income tax withholding obligations upon vesting of restricted shares and performance shares under the 2004 Stock Incentive Plan. These share purchases were not part of a publicly announced program to purchase common shares.

ITEM 6 - SELECTED FINANCIAL DATA
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, 2009. 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 five-for-four stock split effected in December 2007 and the four-for-three stock split effected in March 2005. 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).
(a) Includes pre-tax effects of a $130 million non-cash derivative fair value loss and a $17 million gain on extinguishment of debt.
(b) Includes pre-tax effects of a $72 million non-cash derivative fair value gain and a $128 million impairment of proved properties.
(c) Includes pre-tax effects of a $43 million non-cash derivative fair value loss.
(d) Includes pre-tax effects of a gain on the distribution of Hugoton Royalty Trust units of $469 million, income tax expense related to enactment of a new State of Texas margin tax of $34 million and a $39 million non-cash derivative fair value gain.
(e) Includes pre-tax effects of a $39 million non-cash derivative fair value gain, non-cash performance award compensation of $34 million, and a gain of $10 million on the exchange of producing properties.
(f) Effective January 1, 2009, we adopted the authoritative guidance for earnings per share as it relates to determining whether instruments granted in share based payment transactions are participating securities. Under the guidance, share-based payment awards that contain nonforfeitable rights to dividends, as is the case with our restricted and performance shares, are participating securities and therefore should be included in computing earnings per share using the two-class method. As a result of adoption, we retrospectively adjusted the calculation of our 2008 and prior periods’ earnings per share on a basis consistent with 2009.
(g) Excludes the May 2006 distribution of all of the Hugoton Royalty Trust units owned by the Company to its stockholders as a dividend with a market value of approximately $1.35 per common share.
(h) For purposes of calculating this ratio, earnings are before income tax and fixed charges. Fixed charges include interest costs and the portion of rentals considered to be representative of the interest factor.

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS
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 and dependent upon our production of natural gas, natural gas liquids and crude oil, we have determined that our business comprises only one industry segment.
On December 13, 2009, we entered into a definitive merger agreement with Exxon Mobil Corporation under which we would become a wholly owned subsidiary of ExxonMobil. As a result of the merger, each outstanding share of our common stock will be converted into 0.7098 shares of ExxonMobil common stock. Completion of the merger remains subject to certain conditions, including the adoption of the merger agreement by our stockholders, as well as certain governmental and regulatory approvals. We currently expect to complete the merger in the second quarter of 2010, however, no assurance can be given as to when, or if, the merger will occur.
In 2009, we achieved the following record financial and operating results:
•
Average daily gas production was 2.34 Bcf, a 23% increase from 2008, average daily oil production was 66.3 MBbls, an 18% increase from 2008, and average daily natural gas liquids production was 20.6 MBbls, a 32% increase from 2008.
•
Year-end proved reserves were 14.83 Tcfe, a 7% increase from year-end 2008.
•
Cash flow from operating activities was $6.0 billion, a 14% increase from 2008.
•
Long-term debt including current maturities was $10.5 billion, a $1.5 billion, or 12% decrease from year-end 2008.
We achieve production and proved reserve growth through a combination of low-risk development, generally funded by cash flow from operating activities, and acquisitions of both producing and unproved properties. Funding sources for our acquisitions include proceeds from sales of public and private equity and debt, bank or commercial paper borrowings and cash flow from operating activities. During 2009, we acquired $30 million of proved properties with proved reserves of 22.4 Bcf of natural gas and 0.1 million Bbls of natural gas liquids as well as $224 million of unproved properties. Our 2010 development budget is $3.37 billion. Additionally, $530 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities.
In a trend that began in 2004 and continued until mid-2008, commodity prices for natural gas, natural gas liquids and crude oil increased significantly. However, due to oversupply concerns, tightened credit markets and lower demand in slowing U.S. and global economies, commodity prices declined sharply in the second half of 2008. In 2009, signs of economic improvement resulted in higher oil prices but oversupply concerns continued to weigh on natural gas prices throughout the year (see “Significant Events, Transactions and Conditions-Product Prices”).
The higher prices in recent years led to increased activity in the industry, including the highest drilling rig levels in 25 years and increased demand for oil and gas properties. All of these factors led to significant cost inflation throughout the industry-such as labor, production expenses, drilling costs and acquisition prices. As a result of the U.S. and global recession and tightened credit markets, which led to sharp declines in commodity prices in the latter half of 2008, drilling rig counts decreased, acquisition activity slowed, and all industry costs declined.
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 production. 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.
Our goal for 2010 is to increase production by approximately 10%. To achieve future production and reserve growth, we will continue to evaluate development projects and acquisitions that meet our criteria. 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 (see “Liquidity and Capital Resources-Capital Expenditures”).
Increased activity in the oil and gas producing industry also had an effect on our ability to hire qualified people including not only operational employees, but also all classifications of industry-specific professionals. However, with the recent decrease in industry activity, it has become easier to find qualified employees. We continue to hire the employees we need to adequately staff our operations. Our employee turnover continues to remain low with total turnover of 5.6% in 2009 and 7.2% in 2008.
Sales prices for our natural gas, oil and natural gas liquids 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 2010, we have hedged 1.25 Bcf per day of our 2010 natural gas production at an average NYMEX price of $7.49 per Mcf and 70 MBbls per day of our 2010 crude oil production at an average NYMEX price of $95.70 per Bbl. Our average realized price on hedged production will be lower than these average NYMEX prices because of location, quality and other adjustments.
In 2010, given our hedge position and current commodity strip pricing, we expect to generate enough cash flow from operations to fund our capital expenditures and to have the ability to reduce debt by more than $500 million.
The combined effect of higher oil prices, a 23% increase in gas production, an 18% increase in oil production and a 31% increase in natural gas liquids production partially offset by decreased natural gas and natural gas liquids prices resulted in an 18% increase in total revenues to $9.1 billion in 2009 from $7.7 billion in 2008. On a per Mcfe produced basis, total revenues were $8.67 in 2009, a 4% decrease from $9.00 in 2008.
We analyze on a per Mcfe produced basis, the following expenses, most of which trend with changes in production:
Production expense per Mcfe declined 13% primarily because of decreased power, fuel, compression, carbon dioxide injection and water disposal costs. Power, fuel and carbon dioxide injection costs vary with product prices. Taxes, transportation and other expense is primarily based on product revenues. The 21% decrease in transportation and other expense is primarily because of lower product prices, before hedging, partially offset by higher property taxes primarily due to development and the 2008 acquisitions. The 24% increase in depreciation, depletion and amortization per Mcfe resulted from higher acquisition, development and facility costs, the effect of downward revisions to proved oil and gas reserves due to lower commodity prices and a $91 million, or $0.09 per Mcfe, increase in the impairment of unproved properties. These increases were partially offset by a decrease in the impairment of proved properties of $128 million, or $0.15 per Mcfe. General and administrative expense per Mcfe decreased 16% due to increased production outpacing personnel and other expenses related to Company growth. The 11% decrease in interest expense is primarily because of increased production and a gain on extinguishment of debt of $17 million, which was partially offset by a 10% increase in weighted average borrowings to fund our 2008 acquisitions.
Significant expenses that generally do not trend with production include:
Non-cash stock incentive compensation. Stock incentive compensation expense was $137 million in 2009 compared to $170 million in 2008. The decrease is primarily related to a decline in both the number and value of grants made in 2009 compared to 2008.
Derivative fair value (gain) loss. This is the net realized and unrealized gain or loss on derivative financial instruments that does not qualify for hedge accounting treatment and fluctuates based on changes in the fair value of underlying commodities. The net derivative fair value loss was $24 million in 2009 compared to a gain of $85 million in 2008.
Our primary sources of liquidity are cash flow from operating activities, borrowings under either our revolving credit agreement, our commercial paper program, or our other unsecured and uncommitted lines of credit 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”).
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, 2009, 2008 and 2007 and may impact future operations and financial condition.
Acquisitions. We acquired proved and unproved properties at a total cost of $254 million in 2009, $11.0 billion in 2008 and $4.0 billion in 2007, which were funded by a combination of proceeds from sales of common stock and senior notes, borrowings under either our bank credit facilities or commercial paper program and cash flow from operating activities. We made no significant acquisitions in 2009. The following are significant acquisitions in 2008 and 2007:
Closing Date
Seller
Amount
(in millions)
Acquisition Area
January to June
Various
$ 2,253
Eastern and San Juan Regions, Barnett, Fayetteville, Woodford and Marcellus Shales
May
Southwestern Energy Company
Fayetteville Shale
July
Linn Energy, LLC
Marcellus Shale
Headington Oil Company
1,804
Bakken Shale
September
Hunt Petroleum Corporation
4,315 (a)
Eastern Region, South Texas and Gulf Coast Region and North Sea
October
Hollis R. Sullivan, Inc.
Barnett Shale
July
Dominion Resources, Inc.
2,576
Rocky Mountain Region, San Juan Basin and South Texas
October
Various
Barnett Shale
(a) Represents a portion of the allocated purchase price of Hunt Petroleum Corporation and includes an allocation of $4.1 billion to proved properties and $250 million to unproved properties. See Note 14 to the Consolidated Financial Statements.
2009, 2008 and 2007 Development and Exploration Programs. Gas development was concentrated in East Texas and the Barnett, Fayetteville and Woodford shales in 2009. In 2008 and 2007, gas development focused on East Texas and the Barnett Shale. Oil development was concentrated primarily in the Permian Basin and Bakken Shale in 2009 and primarily the Permian Basin during 2008 and 2007. Development costs totaled $2.5 billion in 2009, $3.4 billion in 2008 and $2.5 billion in 2007. Exploration activity in 2009 and 2008 was primarily drilling and geological and geophysical analysis, including seismic studies in the South Texas and Gulf Coast Region and the Woodford and Fayetteville Shales. Exploratory costs were $500 million in 2009, $517 million in 2008 and $257 million in 2007. Our development and exploration activities are generally funded by cash flow from operations.
2010 Acquisition, Development and Exploration Program. We have budgeted $3.37 billion for our 2010 development and exploration program, which we expect to fund using cash flow from operations. We plan to drill about 988 (833 net) development wells and perform approximately 865 (720 net) workovers and recompletions in 2010. Drilling plans are dependent upon product prices. While we expect to focus primarily on development activities in 2010, as a course of business, we review acquisition opportunities. 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, public or private issuance of debt or equity, or asset sales. Our total budget for acquisitions, development and exploration will be adjusted to focus on opportunities offering the highest rates of return. Additionally, $530 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities.
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 the level of North American production, weather, the U.S. economy, storage levels, crude oil prices and import levels of liquefied natural gas. Natural gas competes with alternative
energy sources as fuel for heating and the generation of electricity. In the first part of 2008, prices for natural gas increased significantly reaching as high as $13 per MMBtu in July 2008. However, higher than average gas in storage caused by shale gas development and lower demand due to the U.S. recession caused natural gas prices to drop below $3 per MMBtu in September 2009. The onset of winter and decreased production has resulted in higher recent gas prices. We expect gas prices to remain volatile. As described under “Hedging Activities” below, we use commodity price hedging instruments to reduce our exposure to gas price fluctuations. The following are comparative average gas prices for the last three years:
At February 19, 2010, the average NYMEX gas price for the following 12 months was $5.50 per MMBtu. As computed on an energy equivalent basis, our proved reserves were 84% natural gas at December 31, 2009. After considering hedges in place as of February 19, 2010, we estimate that a $0.10 per Mcf change in the average gas sales price would result in approximately a $44 million change in 2010 annual operating cash flow before income taxes.
Oil. Crude oil prices are generally determined by global supply and demand. In the first part of 2008, prices for oil increased significantly reaching a record high above $147 per Bbl in July 2008. However, lower demand as a result of the global economic situation caused oil prices to decline to below $40 last winter. Signs of possible economic improvement have resulted in higher oil prices. 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 19, 2010, the average NYMEX oil price for the following 12 months was $81.55 per Bbl. After considering hedges in place as of February 19, 2010, we estimate that a $1.00 per barrel change in the average oil sales price would result in a minimal change in 2010 annual operating cash flow before income taxes.
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 2009, all hedging activities increased gas revenue by $3.0 billion and oil revenue by $1.2 billion. In 2008, all hedging activities decreased gas revenue by $159 million, natural gas liquids revenue by $19 million and oil revenue by $114 million.
The following summarizes our NYMEX hedging positions under futures contracts and swap agreements as of February 2010, excluding basis adjustments.
Our average daily production was 2.37 Bcf of gas, 64.6 MBbls of oil and 21.2 MBbls of natural gas liquids in fourth quarter 2009. 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.
Early Settlement of Hedges. In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which was used to reduce outstanding debt. Of this amount, $453 million ($287 million after-tax) was received in 2008 and the remainder was received in 2009. Under cash flow hedge accounting, the $453 million received in 2008 was included in accumulated other comprehensive income (loss) at December 31, 2008, and was recognized in earnings during 2009 as the hedged production occurred.
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 loss of $24 million in 2009 and net derivative fair value gains of $85 million in 2008 and $11 million in 2007. Of these amounts, a $25 million gain in 2009, a $1 million gain in 2008 and an $11 million gain in 2007 was due to the ineffective portion of hedge derivatives. These ineffective hedge derivative gains and losses are primarily because of fluctuating oil and gas prices and their effect on hedges of production in areas without corresponding basis or location differential swap contracts.
Derivative fair value (gain) loss in 2009 includes a $17 million loss ($11 million after-tax) on certain crude oil swap agreements that did not qualify for hedge accounting. Derivative fair value (gain) loss in 2008 includes a $38 million loss ($24 million after-tax) on certain natural gas futures that no longer qualify for hedge accounting due to the September 2008 bankruptcy filing of Lehman Brothers Holding Inc., the parent company of one of our counterparties. The 2008 derivative fair value (gain) loss also includes a $78 million gain ($50 million after-tax) on certain crude oil swap agreements that did not qualify for hedge accounting.
Unrealized derivative gains and losses associated with effective cash flow hedges are recorded in stockholders’ equity as accumulated other comprehensive income (loss). At December 31, 2009, we have an unrealized pre-tax gain of $1.1 billion in accumulated other comprehensive income (loss) related to the fair value of derivatives designated as cash flow hedges of natural gas and crude oil price risk. Based on December 31 mark-to-market prices, essentially all of this fair value gain is expected to be reclassified into earnings in 2010. The actual reclassification to earnings will be based on mark-to-market prices at contract settlement date.
Stock-Based Compensation. Stock compensation totaled $137 million in 2009, $170 million in 2008 and $65 million in 2007. As of December 31, 2009, stock compensation expense is expected to total $90 million in 2010, $45 million in 2011, $18 million in 2012 and $8 million in 2013 related to all outstanding stock awards. These expected costs are subject to change for stock incentive awards granted after December 31, 2009.
Senior Note Offerings. In July 2007, we sold $300 million of 5.9% senior notes due August 1, 2012, $450 million of 6.25% senior notes due August 1, 2017 and $500 million of 6.75% senior notes due August 1, 2037. In August 2007, we sold an additional $250 million of the 5.9% senior notes, $300 million of the 6.25% senior notes and $450 million of the 6.75% senior notes that constituted a further issuance of the senior notes issued in July 2007. Net proceeds of $2.24 billion were used to fund a portion of the acquisition of properties from Dominion Resources, Inc. and to pay down outstanding commercial paper borrowings.
In April 2008, we sold $400 million of 4.625% senior notes due June 15, 2013, $800 million of 5.50% senior notes due June 15, 2018 and $800 million of 6.375% senior notes due June 15, 2038. In August 2008, we
sold $250 million of 5.00% senior notes due August 1, 2010, $500 million of 5.75% senior notes due December 15, 2013, $1.0 billion of 6.50% senior notes due December 15, 2018 and $500 million of 6.75% senior notes due August 1, 2037. The notes due 2037 constitute a further issuance of the 6.75% senior notes issued in July 2007. Proceeds from the senior notes were used to fund property acquisitions and reduce bank debt.
Common Stock Transactions. In June 2007, we completed a public offering of 21.6 million common shares at $48.40 per share. After underwriting discount and other offering costs of $35 million, net proceeds of $1.0 billion were used to fund a portion of the acquisition of natural gas and oil properties from Dominion Resources, Inc.
In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 million, net proceeds of $1.2 billion were used to fund a portion of the $2.3 billion of property acquisitions closed in the first six months of 2008 and to repay indebtedness under our commercial paper program.
In August 2008, we completed a public offering of 29.9 million common shares at $48.00 per share. After underwriting discount and other offering costs of $48 million, net proceeds of $1.4 billion were used to fund property acquisitions and to pay down outstanding commercial paper borrowings.
Shelf Registration Statement. In June 2009, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities or common stock. The securities will be offered at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities are to be used for general corporate purposes, including the reduction of bank debt.
In July 2008, we registered 11.7 million shares of our common stock, which were issued to the sellers in the acquisition of properties from Headington Oil Company. In September 2008, we registered 23.5 million shares of our common stock, which were issued to the sellers in the acquisition of Hunt Petroleum Corporation.
Repurchase of Senior Notes. In 2009, we repurchased $200 million total face amount of senior notes, including $2 million of our 5.00% senior notes due 2015, $15 million of our 6.25% senior notes due 2017, $27 million of our 5.50% senior notes due 2018, $9 million of our 6.10% senior notes due 2036, $51 million of our 6.75% senior notes due 2037 and $96 million of our 6.375% senior notes due 2038. In connection with these repurchases, we recognized a $17 million gain on extinguishment of debt, net of unamortized discounts and the write-off of deferred debt offering costs. These gains were netted against interest expense in the consolidated income statements.
Results of Operations
2009 Compared to 2008
For the year 2009, net income was $2.0 billion compared with net income of $1.9 billion for 2008. Earnings for 2009 include a $130 million ($83 million after-tax) non-cash derivative fair value loss and a $17 million ($11 million after-tax) gain on extinguishment of debt. Earnings for 2008 include a $72 million ($46 million after-tax) non-cash derivative fair value gain and a $128 million ($81 million after-tax) impairment of proved properties.
Revenues for 2009 were $9.1 billion, or 18% higher than 2008 revenues of $7.7 billion. Gas and natural gas liquids revenue increased $594 million because of a 23% increase in gas production and a 31% increase in natural gas liquids production partially offset by a 9% decrease in gas prices from an average of $7.81 per Mcf in 2008 to $7.13 in 2009 and a 38% decrease in natural gas liquids prices from an average price of $48.76 per Bbl in 2008 to $30.03 in 2009 (see “Significant Events, Transactions and Conditions - Product Prices - Gas” above). Increased production was attributable to our 2009 development program and the 2008 acquisitions.
Oil revenue increased $809 million because of an 18% increase in production, primarily due to our 2009 development program and the 2008 acquisitions, and a 23% increase in oil prices from an average of $87.59 per Bbl in 2008 to $107.65 in 2009 (see “Significant Events, Transactions and Conditions - Product Prices - Oil” above).
Expenses for 2009 totaled $5.4 billion, or 28% higher than total 2008 expenses of $4.2 billion. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $57 million primarily because of increased overall production and increased maintenance costs, partially offset by decreased power, fuel and carbon dioxide injection costs. Production expense per Mcfe decreased from $1.10 in 2008 to $0.96 in 2009 primarily because of decreased power, fuel, compression, carbon dioxide injection and water disposal costs. Power, fuel and carbon dioxide injection costs vary with product prices. Taxes, transportation and other expense decreased $25 million and per Mcfe decreased from $0.82 in 2008 to $0.65 in 2009 primarily because of lower production taxes and transportation costs related to lower product prices, before hedging, partially offset by higher property taxes related to development and the 2008 acquisitions. Exploration expense decreased $11 million primarily because of decreased seismic costs, partially offset by increased dry hole expense.
Depreciation, depletion and amortization (DD&A) increased $1.1 billion primarily because of higher acquisition, development and facility costs and increased production. On a per Mcfe basis, DD&A increased from $2.37 in 2008 to $2.95 in 2009 because of higher acquisition, development and facility costs per Mcfe, the effect of net downward revisions to proved oil and gas reserves due to lower commodity prices and a $91 million, or $0.09 per Mcfe, increase in the impairment of unproved properties. This was partially offset by a $128 million decrease in the impairment of proved properties. Excluding the proved property impairment, 2008 DD&A would have been $2.22 per Mcfe.
General and administrative expense decreased $26 million. Of this decrease, $33 million was the result of a decrease in non-cash incentive award compensation primarily due to a decline in both the number and value of incentive award grants made in 2009 compared to 2008. Increased general and administrative expense, excluding non-cash incentive award compensation, is primarily because of higher employee expenses related to Company growth. Excluding non-cash incentive award compensation, general and administrative expense per Mcfe was $0.21 in 2009 compared to $0.25 in 2008 as increased production outpaced increased personnel and other expenses related to Company growth.
The derivative fair value loss for 2009 was $24 million compared to a gain of $85 million in 2008. The 2009 loss and 2008 gain were primarily related to certain crude oil swap agreements that did not qualify for hedge accounting. See Note 7 to Consolidated Financial Statements.
Interest expense increased $42 million, primarily because of a 10% increase in the weighted average borrowings to partially fund 2008 property acquisitions partially offset by a $17 million gain on the extinguishment of debt. Interest expense per Mcfe decreased from $0.56 in 2008 to $0.50 in 2009 due to increased production and the gain on extinguishment of debt.
The 2009 effective income tax rate was 36.2%, as compared to a 36.8% effective rate for 2008. The current portion of total income taxes was 29% in 2009 and 13% in 2008. The higher current portion of total income taxes was primarily due to decreased development costs. Development costs are generally deducted for income tax purposes over a shorter term than for financial accounting purposes.
2008 Compared to 2007
For the year 2008, net income was $1.9 billion compared with net income of $1.7 billion for 2007. Earnings for 2008 include a $72 million ($46 million after-tax) non-cash derivative fair value gain and a $128 million ($81 million after-tax) impairment of proved properties. Earnings for 2007 include a $43 million ($28 million after-tax) non-cash derivative fair value loss.
Revenues for 2008 were $7.7 billion, or 40% higher than 2007 revenues of $5.5 billion. Gas and natural gas liquids revenue increased $1.5 billion because of a 31% increase in gas production, a 16% increase in natural gas liquids production, a 4% increase in gas prices from an average of $7.50 per Mcf in 2007 to $7.81 in 2008 and a
7% increase in natural gas liquids prices from an average price of $45.37 per Bbl in 2007 to $48.76 in 2008 (see “Significant Events, Transactions and Conditions - Product Prices - Gas” above). Increased production was attributable to the 2008 acquisition and development program.
Oil revenue increased $592 million because of a 19% increase in production, primarily due to the 2008 acquisition and development program, and a 25% increase in oil prices from an average of $70.08 per Bbl in 2007 to $87.59 in 2008 (see “Significant Events, Transactions and Conditions - Product Prices - Oil” above).
Expenses for 2008 totaled $4.2 billion, or 60% higher than total 2007 expenses of $2.6 billion. Increased expenses are generally related to increased production from acquisitions and development and related Company growth. Production expense increased $327 million and per Mcfe increased from $0.93 in 2007 to $1.10 in 2008 primarily because of overall price increases as well as increased water disposal, power and fuel costs and certain one-time and discretionary items related to recent property acquisitions including increased compression, maintenance and workover costs. Taxes, transportation and other expense increased $259 million and per Mcfe increased from $0.67 in 2007 to $0.82 in 2008 primarily because of higher product prices and higher transportation costs related to higher throughput volumes. Exploration expense increased $36 million primarily because of increased seismic costs in the Gulf of Mexico and the Woodford and Fayetteville shales.
Depreciation, depletion and amortization (DD&A) increased $838 million primarily because of increased production. On an Mcfe basis, DD&A increased 33% from $1.78 in 2007 to $2.37 in 2008 because of higher acquisition, development and facility costs as well as an impairment of proved properties of approximately $128 million, or $0.15 per Mcfe, and a $107 million, or $0.13 per Mcfe, increase in the impairment of unproved properties.
General and administrative expense increased $151 million. Of this increase, $105 million was the result of an increase in non-cash incentive award compensation primarily as a result of additional incentive award grants in 2007 and 2008. Increased general and administrative expense, excluding non-cash incentive award compensation, is primarily because of higher employee expenses related to Company growth. Excluding non-cash incentive award compensation, general and administrative expense per Mcfe was $0.25 in 2008 and 2007 as increased personnel and other costs were offset by increased production.
The derivative fair value gain for 2008 was $85 million compared to $11 million in 2007. The 2008 gain is primarily related to the gain on certain crude oil swap agreements that did not qualify for hedge accounting. The 2007 gain is primarily related to the ineffective portion of hedge derivatives. See Note 7 to Consolidated Financial Statements.
Interest expense increased $232 million, primarily because of a 97% increase in the weighted average borrowings to partially fund property acquisitions. Interest expense per Mcfe increased from $0.38 in 2007 to $0.56 in 2008.
The 2008 effective income tax rate was 36.8%, as compared to a 36.0% effective rate for 2007. The current portion of total income taxes was 13% in 2008 and 31% in 2007. The decline in the current portion of total income taxes was primarily due to increased development costs and accelerated tax depreciation as allowed by changes to the tax rules in 2008. Development costs are generally deducted for income tax purposes over a shorter term than for financial accounting purposes.
Liquidity and Capital Resources
Our primary sources of liquidity are cash provided by operating activities, borrowings under either our revolving credit agreement, our other unsecured and uncommitted lines of credit or our commercial paper program, occasional proved property sales and private or public offerings of equity and debt. Other than for operations, our cash requirements are generally for the acquisition, exploration and development of oil and gas
properties, and debt and dividend payments. Exploration and development expenditures and dividend payments have generally been funded by cash flow from operations. We believe that our sources of liquidity are adequate to fund our cash requirements in 2010.
Cash provided by operating activities was $6.0 billion in 2009, compared with cash provided by operating activities of $5.2 billion in 2008 and $3.6 billion in 2007. Increased cash provided by operating activities from 2008 to 2009 and from 2007 to 2008 was primarily because of increased production from acquisitions and development activity, and higher price realizations in 2008 compared to 2007. Also, 2008 benefited from the early settlement and reset arrangements with one of our financial counterparties (see “Significant Events, Transactions and Conditions - Early Settlement of Hedges” above). Cash provided by operating activities was decreased by changes in operating assets and liabilities of $265 million in 2009 and $72 million in 2007 and was increased by changes in operating assets and liabilities of $171 million in 2008. Changes in operating assets and liabilities are primarily the result of timing of cash receipts and disbursements. Cash provided by operating activities was also reduced by exploration expense, excluding dry hole expense, of $33 million in 2009, $66 million in 2008 and $31 million in 2007. Cash provided by operating activities is largely dependent on our production volumes as well as the prices received for oil and gas production. As of February 2010, we have hedged 1.25 Bcf per day of our 2010 natural gas production and 70 MBbls per day of our 2010 crude oil production. See “Significant Events, Transactions and Conditions-Product Prices” above.
During 2009, cash provided by operating activities of $6.0 billion was used to fund development costs, net property acquisitions and other net capital additions of $4.1 billion, dividends of $287 million and to pay down $1.5 billion of debt. The resulting decrease in cash and cash equivalents for the period was $16 million. During 2008, cash provided by operating activities of $5.2 billion, proceeds from the February and July 2008 common stock offerings of $2.6 billion, proceeds from the April and August 2008 debt offerings of $4.2 billion and proceeds from other borrowings of $1.1 billion were used to fund net property acquisitions, development costs and other net capital additions of $13.0 billion and dividends of $250 million. The resulting increase in cash and cash equivalents for the period was $25 million. During 2007, cash provided by operating activities of $3.6 billion, proceeds from the June 2007 common stock offering of $1.0 billion, proceeds from the July and August 2007 debt offerings of $2.2 billion and proceeds from other borrowings of $620 million were used to fund net property acquisitions, development costs and other net capital additions of $7.3 billion and dividends of $170 million. The decrease in cash and cash equivalents for the period was $5 million.
Financial Condition
Total assets decreased 5% from $38.3 billion at December 31, 2008 to $36.3 billion at December 31, 2009, primarily because of a $2.5 billion decrease in the fair value of outstanding derivatives contracts, partially offset by Company growth related to development. As of December 31, 2009, total capitalization was $27.8 billion, of which 38% was debt. Capitalization at December 31, 2008 was $29.3 billion, of which 41% was debt. The improvement in the debt-to-capitalization ratio from year-end 2008 to 2009 is primarily because of decreased debt.
Working Capital
We generally maintain low cash and cash equivalent balances because we use available funds to reduce either bank debt or borrowings under our commercial paper program. Short-term liquidity needs are satisfied by either bank commitments under our loan agreements or our commercial paper program (see “Financing” below). Because of this, and since our principal source of operating cash flows (i.e., proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. Working capital declined from a positive position of $1.3 billion at December 31, 2008 to a positive position of $247 million at December 31, 2009. Excluding the effects of derivative fair value and deferred tax current assets and liabilities, working capital decreased $34 million from a negative position of $432 million at December 31, 2008 to a negative position of $466 million at December 31, 2009. This decrease is a result of decreased accounts
receivable due to lower product prices, excluding hedges, and the increase in current maturities of long-term debt, partially offset by decreased accounts payable and accrued liabilities primarily related to lower commodity prices, excluding hedges, and lower drilling activity. Any cash settlement of hedge derivatives should generally be offset by increased or decreased cash flows from our sales of related production. Therefore, we believe that most of the changes in derivative fair value assets and liabilities are offset by changes in value of our oil and gas reserves. This offsetting change in value of oil and gas reserves, however, is not recorded in the financial statements.
When the monthly cash settlement amount under our hedge derivatives is calculated, if market prices are higher than the fixed contract prices, we are required to pay the contract counterparties. While this payment will ultimately be funded by higher prices received from sale of our production, production receipts lag payments to the counterparties by as much as 55 days. Any interim cash needs are funded by borrowings under either our revolving credit agreement, our other unsecured and uncommitted lines of credit, or our commercial paper program. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.
We believe that our expected cash flow from operations, as well as our various funding facilities provide us with adequate liquidity to meet our current obligations. In 2010, given our hedge position and current commodity strip pricing, we expect to generate enough cash flow from operations to fund our capital expenditures and to have the ability to reduce debt by more than $500 million. The expected debt reduction may include bank facilities, commercial paper or senior notes.
Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated companies. Letters of credit or other appropriate forms of security are obtained as considered necessary to limit risk of loss. Financial and commodity-based futures and swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, and we have master netting agreements with most counterparties that provide for offsetting payables against receivables from separate derivative contracts. In September 2008, the parent company of one of our counterparties, Lehman Brothers Holdings Inc, filed for bankruptcy, and we recognized a $38 million ($24 million after-tax) loss in derivative fair value (gain) loss in the income statement.
Financing
On December 31, 2009, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $2.2 billion net of our commercial paper borrowings. We use the facility for general corporate purposes and as a backup facility for our commercial paper program. We have the option, with bank approval, to increase the commitment up to an additional $660 million. The interest rate on any borrowing is generally based on LIBOR plus 0.40%. When utilization of available commitments is greater than 50%, then the interest rate on our borrowings is increased by 0.05%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing commitments, which is 0.09%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 65%.
Our commercial paper program availability is $2.84 billion. Borrowings under the commercial paper program reduce our available capacity under the revolving credit facility on a dollar-for-dollar basis. The commercial paper borrowings may have terms up to 397 days and bear interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. On December 31, 2009, borrowings under our commercial paper program were $622 million at a weighted average interest rate of 0.3%.
We have unsecured and uncommitted lines of credit with commercial banks totaling $100 million. As of December 31, 2009, there were no borrowings under these lines.
In 2009, we repurchased $200 million total face amount of senior notes, including $2 million of our 5.00% senior notes due 2015, $15 million of our 6.25% senior notes due 2017, $27 million of our 5.50% senior notes due 2018, $9 million of our 6.10% senior notes due 2036, $51 million of our 6.75% senior notes due 2037 and $96 million of our 6.375% senior notes due 2038. In connection with these repurchases, we recognized a $17 million gain on extinguishment of debt, net of unamortized discounts and the write-off of deferred debt offering costs. These gains were netted against interest expense in the consolidated income statements.
During 2009, we utilized cash flow from operations to reduce our long-term debt including current maturities by $1.5 billion, reducing total debt to $10.5 billion at December 31, 2009.
Our revolving credit and term loan agreements contain no clauses that permit the lenders to accelerate payments or refuse to lend based on any unspecified material adverse change. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if we default on any principal or interest payments under the loan agreements or our swap agreements or under any other payment obligation in excess of $100 million. We were in compliance with the terms of the credit and term loan agreements as of December 31, 2009.
Our ability to access funds under our credit agreements is not directly subject to a “material adverse effect” clause, rather we have to make certain representations, some of which contain a specific “material adverse effect” provision which limits our scope to the representation made, though none are related to our current financial situation. We are in compliance with the representations and do not believe that making the representations is a material restriction on our ability to access funds under our credit agreements.
Our senior unsecured long-term debt is currently rated Baa2 by Moody’s and BBB by Standard & Poor’s. Our short-term debt rating for our commercial paper program is currently rated P-2 by Moody’s and A-2 by Standard & Poor’s. The outlook from both rating agencies is under review pending the outcome of the proposed merger with ExxonMobil. ExxonMobil is currently rated Aaa by Moody’s and AAA by Standard & Poor’s.
A decline in our credit ratings with Moody’s and Standard & Poor’s does not trigger any drawdown restrictions or acceleration of maturity under our credit agreements. However, our cost of borrowing under our credit agreements is determined by our credit ratings. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our revolving credit facility and term loans. Additionally, any downgrade to those ratings could increase our future borrowing costs and limit our access to debt capital markets.
Capital Expenditures
In 2009, exploration and development cash expenditures totaled $3.2 billion compared with $3.7 billion in 2008. We have budgeted $3.37 billion for the 2010 development and exploration program and an additional $530 million for the construction of pipeline infrastructure and compression and processing facilities. As we have done historically, we expect to fund the 2010 development program with cash flow from operations. Actual costs may vary significantly due to many factors, including development results and changes in drilling and service costs. We also may reevaluate our budget and drilling programs as a result of significant changes in oil and gas prices.
While we expect to focus on development activities in 2010, as a course of business, we actively review acquisition opportunities. 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. Other than the requirement for us to maintain a debt-to-total capitalization ratio of not more than 65%, there are no restrictions under our revolving credit agreement that would affect our ability to use our remaining borrowing capacity.
To date, we have not incurred significant expenditures to comply with environmental or safety regulations, and we do not expect to during 2010. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Greenhouse Gas Emissions and Climate Change Regulation
There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Various regulatory bodies have announced their intent to regulate GHG emissions. As these regulations are under development, we are unable to predict the total impact of the potential regulations upon our business, and it is possible that we could face increases in operating costs in order to comply with GHG emissions legislation. We are reviewing, through our Climate Change Committee, issues involving GHG emissions, including assisting management in monitoring the science of climate change and making recommendations to help develop emission reduction programs.
Dividends
The Board of Directors declared quarterly dividends of $0.096 per common share for the first three quarters of 2007, $0.12 per common share for fourth quarter 2007 and each quarter in 2008 and $0.125 per common share for each quarter in 2009. On February 16, 2010, the Board of Directors declared a first quarter 2010 dividend of $0.125 per common share. In addition, under the terms of the merger agreement with ExxonMobil, during the period before the closing of the merger, we are prohibited from declaring, setting aside or paying any dividend or other distribution except for our regular quarterly cash dividend, which is not to exceed $0.125 per share. The merger agreement also provides that we will coordinate the declaration of dividends with ExxonMobil before the completion of the merger so that both our shareholders and the shareholders of ExxonMobil only receive, in any quarter, one dividend from each company.
Our ability to pay dividends is dependent upon our financial condition, earnings and cash flow from operations, the level of our capital expenditures, our future business prospects and other matters our Board deems relevant.
Off-Balance Sheet Arrangements
We do not have any investments in unconsolidated entities or persons that could materially affect the liquidity or the availability of capital resources. Under the terms of some of our operating leases for compressors, airplanes and vehicles, we have various residual value guarantees and other payment provisions upon our election to return the equipment under certain specified conditions. Guarantees related to these leases are not material. The only material off-balance sheet arrangements that we have entered into are those disclosed in the following table of contractual obligations and commitments.
Contractual Obligations and Commitments
The following summarizes our significant obligations and commitments to make future contractual payments as of December 31, 2009. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt or losses.
Debt. Debt amounts represent scheduled maturities of our debt obligations at December 31, 2009, excluding $35 million of net discounts on our senior notes included in the carrying value of debt. At December 31, 2009, borrowings were $622 million under our commercial paper program. Because we had the intent and ability to refinance the balance due with borrowings under our credit facility due in April 2013, the $622 million outstanding under the commercial paper program is reflected in the table above as due in 2013. Borrowings of $600 million under our term loans are due in 2013, and our senior notes, totaling $9.3 billion, are due 2010 through 2038. For further information regarding long-term debt, see Note 3 to Consolidated Financial Statements.
Drilling Contracts. We have contracts with various drilling contractors to use 50 drilling rigs with terms of up to three years. Early termination of these contracts at December 31, 2009 would have required us to pay maximum penalties of $66 million. Based upon our planned drilling activities, we do not expect to pay significant early termination penalties.
Transportation Contracts. We have entered firm transportation contracts with various pipelines for various terms through 2022. Under these contracts we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. We have generally delivered at least minimum volumes under these firm transportation contracts, therefore avoiding payment for deficiencies.
In November 2008, we completed an agreement to enter into a twelve-year firm transportation contract, contingent upon obtaining regulatory approvals and completion of a new pipeline that connects the Fayetteville Shale to ANR Pipeline and Trunkline Pipeline in Quitman County, Mississippi. Upon the pipeline’s completion, currently expected in fourth quarter 2010, we will transport gas volumes for a transportation fee of up to $1.25 million per month plus fuel, currently expected to be 0.86% of the sales price. The potential effect of this agreement is not included in the above summary of our transportation contract commitments since our commitment is contingent upon completion of the pipeline.
Derivative Contracts. We have entered into futures contracts and swaps to hedge our exposure to natural gas and oil price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of December 31, 2009, the current liability related to such contracts was $167 million and the noncurrent liability was $6 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts may be received as much as 55 days after payment to counterparties and can result in draws on our revolving credit facility, our other unsecured and uncommitted lines of credit or our commercial paper program. See Note 7 to Consolidated Financial Statements.
Related Party Transactions
Jack Randall, one of our nonemployee directors, was a co-founder and director of Randall & Dewey Partners, L.P., which was acquired by Jefferies Group, Inc. in 2005 and now operates as Jefferies & Company, Inc. Jefferies served as one of our financial advisors in connection with the announced merger with ExxonMobil. If the merger is completed, we have agreed to pay Jefferies a transaction fee of $24 million. In addition, we agreed to reimburse Jefferies for all reasonable and documented out-of-pocket expenses, including legal fees, incurred in connection with the services it provides to us in connection with the merger and have agreed to indemnify Jefferies against certain liabilities. In addition, Jefferies performed property acquisition advisory services for us in prior years. A division of Jefferies also performed co-manager services on our February and August 2008 and June 2007 common stock offerings and our April and July 2008 and July and August 2007 senior note offerings. We paid, for the credit of Jefferies, total fees of $11.8 million in 2008 and $3.4 million in 2007. There were no amounts payable at December 31, 2009 or 2008.
In February 2007, in recognition of the Chairman of the Board and Founder and as part of a charitable giving program to support higher education, the Board of Directors approved a conditional contribution of $6.8
million to assist in building an athletics and academic center at Baylor University. This contribution was paid in two equal installments of $3.4 million in each of 2007 and 2008. Concurrently, our Chairman of the Board and Founder, made a $3.2 million pledge for the same project. He fulfilled his obligation in 2008. In return for these contributions, we, along with our Chairman of the Board and Founder, obtained naming rights for the building and certain facilities within the building.
In November 2007, the Board of Directors approved and we paid our Chairman of the Board and Founder $150,000 for an easement across his property in North Texas plus an additional $36,000 for damages. The easement was for approximately 10,000 feet at the standard easement rate in the area of $15 per foot.
Critical Accounting Policies and Estimates
Our financial position and results of operations are significantly affected by accounting policies and estimates related to our oil and gas properties, proved reserves, asset retirement obligation and commodity prices and risk management, as summarized below.
Oil and Gas Property Accounting
Oil and gas exploration and production companies may elect to account for their property costs using either the “successful efforts” or “full cost” accounting method. Under the successful efforts method, unsuccessful exploratory well costs, as well as all exploratory geological and geophysical costs, are expensed. Under the full cost method, all exploration costs are capitalized, regardless of success. Selection of the oil and gas accounting method can have a significant impact on a company’s financial results. We use the successful efforts method of accounting and generally pursue acquisitions and development of proved reserves as opposed to exploration activities.
We evaluate possible impairment of producing properties when conditions indicate that the properties may be impaired. Such conditions include a significant decline in product prices which we believe to be other than temporary or a significant downward revision in estimated proved reserves for a field or area. An impairment provision must be recorded to adjust the net book value of the property to its estimated fair value if the net book value exceeds management’s estimate of future net cash flows from the property. The estimated fair value of the property is generally calculated as the discounted present value of future net cash flows. Our estimates of cash flows are based on the latest available proved reserve and production information and management’s estimates of future product prices and costs, based on available information such as forward strip prices and industry forecasts and analysis.
The impairment assessment process is primarily dependent upon the estimate of proved reserves. Any overstatement of estimated proved reserve quantities would result in an overstatement of estimated future net cash flows, which could result in an understated assessment of impairment. The subjectivity and risks associated with estimating proved reserves are discussed under “Oil and Gas Reserves” below. Prediction of product prices is subjective since prices are largely dependent upon supply and demand resulting from global and national conditions generally beyond our control. However, management’s assessment of product prices for purposes of impairment is consistent with that used in its business plans and investment decisions. While there is judgment involved in management’s estimate of future product prices, the potential impact on impairment has not been significant since product prices have been substantially higher than our net acquisition and development costs per Mcfe. However, with the deepening U.S. recession and the slowing global economy, product prices declined significantly, resulting in a change in our development drilling plans. Though projected product prices less expenses are still expected by management to be higher than our net acquisition and development costs per Mcfe for most of our properties, we recognized a $128 million impairment of proved properties in 2008. Prior to 2008, our historical impairment of proved properties had been limited to an immaterial impairment in 1998. We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impracticable to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.
Oil and Gas Reserves
Our proved oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using the 12-month average prices, estimated reserve quantities can be significantly impacted by changes in product prices.
Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in timing of when DD&A expense is recognized. Downward revisions of proved reserves result in an acceleration of DD&A expense, while upward revisions tend to lower the rate of DD&A expense recognition. As shown in Note 16 to the Consolidated Financial Statements, net downward revisions of proved reserves on an Mcfe basis occurred in 2009 and 2008, which will result in an increase in DD&A expense of approximately 3% in 2010 and resulted in an increase in DD&A expense of approximately 8% in 2009. Net upward revisions occurred to proved reserves on an Mcfe basis in 2007, resulting in a decrease in DD&A expense of approximately 1% in 2008. Based on proved reserves at December 31, 2009, we estimate that a 1% change in proved reserves would increase or decrease 2010 DD&A expense by approximately $34 million.
During 2009, development and exploration activities resulted in extensions, additions, discoveries and net revisions of proved reserves that were 190% of our 2009 production. Over the last five years, our proved reserve extensions, additions, discoveries and net revisions averaged 230% of our production for this period. Our proved reserve extensions, additions and discoveries in 2009 included an increase of 1.8 Tcfe in proved undeveloped reserves, or approximately 73% of our total extensions, additions and discoveries. The remaining extensions, additions and discoveries were proved developed reserves. Over the past five years, approximately 73% of our proved reserves extensions, additions and discoveries were proved undeveloped reserves. Our 2009 development drilling program resulted in the conversion of approximately 16% of our proved undeveloped reserves into proved developed reserves during the year. Development of our proved undeveloped reserves is not subject to significant uncertainties such as regulatory approvals, and we believe that we have adequate resources to develop these reserves, dependent on commodity prices not declining significantly. We believe that reserve additions, comparable to these historical reserve additions, are attainable in the near term future, subject to product prices and development costs remaining at levels to ensure economic viability.
The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 16 to Consolidated Financial Statements, are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures. Prior to 2009, standardized measure was calculated using year end oil and gas prices and costs. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves.
Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and international laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.
Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2009, we revised our existing estimated asset retirement obligation by $7 million, or approximately 1% of the asset retirement obligation at December 31, 2008, based on a review of current plugging and abandonment costs. Over the past five years, revisions to the estimated asset retirement obligation averaged approximately 10% of the asset retirement obligation at the beginning of the year. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Commodity Prices and Risk Management
Commodity prices significantly affect our operating results, financial condition, cash flows and ability to borrow funds. Current market oil and gas prices are affected by supply and demand as well as seasonal, political and other conditions which we generally cannot control. Oil and gas prices and markets are expected to continue their historical volatility. See “Significant Events, Transactions and Conditions-Product Prices” above.
We attempt to reduce our price risk on a portion of our production by entering into financial instruments such as futures contracts, collars and basis swap agreements, as well as fixed-price physical delivery contracts. While these instruments secure a certain price and, therefore, a certain cash flow, there is the risk that we may not be able to realize the full benefit of rising prices. These contracts also expose us to credit risk of nonperformance by the contract counterparties, all of which are major investment grade financial institutions. We attempt to limit our credit risk by obtaining letters of credit or other appropriate forms of security.
While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under U.S. generally accepted accounting principles, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements. Derivatives that provide effective cash flow hedges are designated as hedges, and, to the extent the hedge is determined to be effective, we defer related unrealized fair value gains and losses in accumulated other comprehensive income (loss) until the hedged transaction occurs. See “Derivatives” under Note 1 to Consolidated Financial Statements regarding our accounting policy related to derivatives.
See also “Commodity Price Risk” under Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for the effect of price changes on derivative fair value gains and losses.
Goodwill
Goodwill is not amortized to earnings but is tested, at least annually, for impairment at the reporting unit level. We conduct the goodwill impairment test effective October 1 of each year. Other events and changes in circumstances may also require goodwill to be tested for impairment between annual measurement dates. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets. If the estimated fair value is greater than the carrying amount of the reporting unit, then no impairment loss is required. The annual test indicated no impairment.
Although we cannot predict if or when goodwill may become impaired in the future, impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for
example, lower sustained oil and gas prices) reduce the fair value of the associated reporting unit. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.
Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates.
Production Imbalances
We have gas production imbalance positions that are the result of partial interest owners selling more or less than their proportionate share of gas on jointly owned wells. Imbalances are generally settled by disproportionate gas sales over the remaining life of the well, or by cash payment by the overproduced party to the underproduced party. We use the entitlement method of accounting for natural gas sales. Accordingly, revenue is deferred for gas deliveries in excess of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. Our net gas imbalances at December 31, 2009 and 2008, were immaterial.
Forward-Looking Statements
Certain information included in this annual report and other materials filed or to be filed by us with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by us, contain projections and forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to our operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures in total or by region, capital budget and funding thereof, cash flow, drilling activity, drilling locations, the number of wells to be drilled, worked over or recompleted in total or by region, acquisition and development activities and funding thereof, production and reserve growth, pricing differentials, reserve potential, operating costs, operating margins, production and exploration activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, unused borrowing capacity, estimated stock award vesting periods, completion of pipelines and processing facilities, regulatory matters, competition and value of non-cash dividends. Such forward-looking statements are based on management’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “predicts,” “anticipates,” “believes,” “estimates,” “goal,” “should,” “could,” “assume,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are discussed in Item 1A, Risk Factors.

ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We only enter derivative financial instruments in conjunction with our hedging activities. These instruments principally include commodity futures, collars, swaps and interest rate swap agreements. These financial and commodity-based derivative contracts are used to limit the risks of fluctuations in interest rates and natural gas, crude oil and natural gas liquids prices. Gains and losses on these derivatives are generally offset by losses and gains on the respective hedged exposures.
Our Board of Directors has adopted a policy governing the use of derivative instruments, which requires that all derivatives used by us relate to an underlying, offsetting position, anticipated transaction or firm commitment, and prohibits the use of speculative, highly complex or leveraged derivatives. Risk management programs using derivatives must be authorized by the Chairman of the Board and the President. These programs are also reviewed quarterly by our internal risk management committee and annually by the Board of Directors.
Hypothetical changes in interest rates and prices chosen for the following estimated sensitivity effects are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. It is not possible to accurately predict future changes in interest rates and product prices. Accordingly, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.
Interest Rate Risk
We are exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At December 31, 2009, our variable rate debt had a carrying value of $1.2 billion, which approximated its fair value, and our fixed rate debt had a carrying value of $9.3 billion and an approximate fair value of $10.3 billion. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest cost, interest rate volatility and financing risk. This is accomplished through a mix of bank debt with short-term variable rates and fixed rate senior and subordinated debt, as well as the occasional use of interest rate swaps.
The following table shows the carrying amount and fair value of long-term debt and the hypothetical change in fair value that would result from a 100-basis point change in interest rates. Unless otherwise noted, the hypothetical change in fair value could be a gain or a loss depending on whether interest rates increase or decrease.
(a) Fair value is based upon current market quotes and is the estimated amount required to purchase our debt on the open market. This estimated value does not include any redemption premium.
Commodity Price Risk
We have hedged a portion of our price risks associated with our natural gas and crude oil sales. As of December 31, 2009, our outstanding futures contracts and swap agreements had a net fair value gain of $1.1 billion. The following table shows the fair value of our derivative contracts and the hypothetical change in fair value that would result from a 10% change in commodities prices or basis prices at December 31, 2009. The hypothetical change in fair value could be a gain or a loss depending on whether prices increase or decrease.
Because most of our futures contracts and swap agreements have been designated as hedge derivatives, changes in their fair value generally are reported as a component of accumulated other comprehensive income (loss) until the related sale of production occurs. At that time, the realized hedge derivative gain or loss is transferred to product revenues in the consolidated income statement. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following financial statements and supplementary information are included under Item 15(a):
Page
Consolidated Balance Sheets
Consolidated Income Statements
Consolidated Statements of Comprehensive Income
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity
Notes to Consolidated Financial Statements
Selected Quarterly Financial Data
(Note 15 to Consolidated Financial Statements)
Information about Oil and Gas Producing Activities
(Note 16 to Consolidated Financial Statements)
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm

ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There have been no changes in accountants or any disagreements with accountants on any matter of accounting principles or practices or financial statement disclosures during the two years ended December 31, 2009.

ITEM 9A - CONTROLS AND PROCEDURES
Item 9A. CONTROLS AND PROCEDURES
a) Evaluation of Disclosure Controls and Procedures
We performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in our periodic filings with the Securities and Exchange Commission and that our disclosure controls and procedures are effective to ensure that information required to be disclosed in Exchange Act reports is recorded, processed, summarized and reported within the specific time periods. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected.
b) Management’s Report on Internal Control over Financial Reporting
Our management’s report on internal control over financial reporting is set forth in Item 8 of this Annual Report on Form 10-K and is incorporated by reference herein.
c) Changes in Internal Control over Financial Reporting
There were no changes in our internal controls over financial reporting during the quarter ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B - OTHER INFORMATION
Item 9B. OTHER INFORMATION
None.
PART III
Except for the portion of

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
We have a Code of Business Conduct and Ethics that applies to all directors, officers and employees, including the chief executive officer and senior financial officers. We also have a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. You can find our Code of Business Conduct and Ethics and our Code of Ethics for the Chief Executive Officer and Senior Financial Officers on our web site at http://www.xtoenergy.com. You can also obtain a free copy of these materials by contacting us at 810 Houston Street, Fort Worth, Texas 76102, Attn: Corporate Secretary. Any amendments to or waivers from these codes that apply to our executive officers will be posted on the Company’s web site or by other appropriate means in accordance with the rules of the Securities and Exchange Commission.

ITEM 11 - EXECUTIVE COMPENSATION
Item 11. EXECUTIVE COMPENSATION

ITEM 12 - SECURITY OWNERSHIP
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV

ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this report:
Page
1.
Financial Statements:
Consolidated Balance Sheets at December 31, 2009 and 2008
Consolidated Income Statements for the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
2.
Financial Statement Schedules:
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to consolidated financial statements
(b) Exhibits
See Index to Exhibits at page 96 for a description of the exhibits filed as a part of this report. Documents filed prior to June 1, 2001, were filed with the Securities and Exchange Commission under our prior name, Cross Timbers Oil Company.
XTO ENERGY INC.
Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
XTO ENERGY INC.
Consolidated Income Statements
See accompanying notes to consolidated financial statements.
XTO ENERGY INC.
Consolidated Statements of Comprehensive Income
See accompanying notes to consolidated financial statements.
XTO ENERGY INC.
Consolidated Statements of Cash Flows
See accompanying notes to consolidated financial statements.
XTO ENERGY INC.
Consolidated Statements of Stockholders’ Equity
See accompanying notes to consolidated financial statements.
XTO ENERGY INC.
Notes to Consolidated Financial Statements
1. Organization and Summary of Significant Accounting Policies
XTO Energy Inc., a Delaware corporation, was organized under the name Cross Timbers Oil Company in October 1990 to ultimately acquire the business and properties of predecessor entities that were created from 1986 through 1989. Cross Timbers Oil Company completed its initial public offering of common stock in May 1993 and changed its name to XTO Energy Inc. in June 2001.
On December 13, 2009, we entered into a definitive merger agreement with Exxon Mobil Corporation under which we would become a wholly owned subsidiary of ExxonMobil. As a result of the merger, each outstanding share of our common stock will be converted into 0.7098 shares of ExxonMobil common stock. Completion of the merger remains subject to certain conditions, including the adoption of the merger agreement by our stockholders, as well as certain governmental and regulatory approvals. We currently expect to complete the merger in the second quarter of 2010, however, no assurance can be given as to when, or if, the merger will occur.
The accompanying consolidated financial statements include the financial statements of XTO Energy Inc. and all of its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation.
We are an independent oil and gas company with production and exploration concentrated in the southwestern and central United States. We also have international operations located in the North Sea that do not have a material impact on either our financial position or earnings. Additionally, we gather, process and market gas, transport and market oil and conduct other activities directly related to our oil and gas producing activities.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
•
estimates of proved reserves and related estimates of the present value of future revenues;
•
the carrying value of oil and gas properties;
•
asset retirement obligations;
•
income taxes;
•
derivative financial instruments;
•
obligations related to employee benefits; and
•
legal and environmental risks and exposure.
Property and Equipment
We follow the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are
expensed as incurred. All developmental costs are capitalized. We generally pursue acquisition and development of proved reserves as opposed to exploration activities. A significant portion of the property costs reflected in the accompanying consolidated balance sheets are from acquisitions of proved and unproved properties from other oil and gas companies. Proved properties balances include costs of $923 million at December 31, 2009 and $1.4 billion at December 31, 2008 related to wells in process of drilling. Successful drill well costs are transferred to proved properties generally within one month of the well completion date. Inventory held for future use on our producing properties totaled $147 million at December 31, 2009 and $182 million at December 31, 2008, and is included in other current assets on the consolidated balance sheet.
Depreciation, depletion and amortization (DD&A) of proved producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. Other property and equipment is generally depreciated using either the unit-of-production method for assets associated with specific reserves or the straight-line method over estimated useful lives which range from 3 to 40 years. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.
If conditions indicate that producing properties may be impaired, the carrying value of property is compared to management’s future estimated pre-tax cash flow from properties generally aggregated on a field-level basis. If impairment is necessary, the asset carrying value is written down to fair value. Cash flow pricing estimates are based on estimated reserves and production information and pricing assumptions that management believes are reasonable. We recognized an impairment of proved properties of $128 million in 2008.
Impairment of individually significant unproved properties is assessed on a property-by-property basis using an impairment analysis similar to the proved property model discussed above. Impairment of other unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. We recognized in DD&A an impairment of unproved properties of $247 million in 2009, $156 million in 2008 and $49 million in 2007.
Asset Retirement Obligation
If the fair value for asset retirement obligation can be reasonably estimated, the liability is recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. The retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to proved properties on the balance sheet. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. See Note 5.
Royalty Trusts
We created Cross Timbers Royalty Trust in February 1991 and Hugoton Royalty Trust in December 1998 by conveying defined net profits interests in certain of our properties. Units of both trusts are traded on the New York Stock Exchange. We make monthly net profits payments to each trust based on revenues and costs from the related underlying properties. Amounts due the trusts are deducted from our revenues, taxes, production expenses and development costs. We no longer have any ownership interest in these trusts.
Cash and Cash Equivalents
Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less.
Income Taxes
We record deferred income tax assets and liabilities to recognize timing differences between recognition of income for financial statement and income tax reporting purposes. Deferred income tax assets are calculated
using enacted tax rates for each jurisdiction applicable to taxable income in the years when we anticipate these timing differences will reverse. The effect of changes in tax rates is recognized in the period of enactment.
Financial statement recognition of a tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense and general and administrative expense, respectively. See Note 4.
Other Assets
Other assets primarily include deferred debt costs that are amortized to interest expense over the term of the related debt (Note 3) and the long-term portion of gas balancing receivable (see Revenue Recognition and Gas Balancing below). Other assets are presented net of accumulated amortization of $39 million at December 31, 2009 and $31 million at December 31, 2008.
We determined that a portion of the purchase price of the 2005 Antero Resources Corporation acquisition was allocable to gas gathering contracts and goodwill. Gas gathering contracts are associated with the pipeline acquired, and the value of $140 million was determined based on the estimated discounted cash flows from those contracts. The gas gathering contracts are amortized, as a component of depreciation, depletion and amortization expense, on a unit-of-production basis using the estimated proved reserves of the related Barnett Shale properties. Accumulated amortization of acquired gas gathering contracts was $43 million as of December 31, 2009 and $35 million as of December 31, 2008. Amortization expense is expected to be approximately $6 million to $7 million annually from 2010 through 2014, depending on Barnett Shale production.
Goodwill of $1.5 billion represents the excess of the purchase price paid for Hunt Petroleum Corporation (Note 14) and Antero Resources over their respective fair value of the assets acquired and liabilities assumed. Goodwill is not amortized, but instead is subject to an annual assessment of impairment based on a fair value test performed as of October 1. The annual test indicated no impairment.
Derivatives
We use derivatives to hedge against changes in cash flows related to product price and interest rate risks, as opposed to their use for trading purposes. We record all derivatives on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. The fair value of call options and collars are generally determined under the Black-Scholes option-pricing model. Most values are confirmed by counterparties to the derivative.
Realized and unrealized gains and losses on derivatives that are not designated as hedges, as well as on the ineffective portion of hedge derivatives, are recorded as a derivative fair value gain or loss in the income statement. Unrealized gains and losses on effective cash flow hedge derivatives, as well as any deferred gain or loss realized upon early termination of effective hedge derivatives, are recorded as a component of accumulated other comprehensive income (loss). When the hedged transaction occurs, the realized gain or loss, as well as any deferred gain or loss, on the hedge derivative is transferred from accumulated other comprehensive income (loss) to earnings. Realized gains and losses on commodity hedge derivatives are recognized in oil and gas revenues, and realized gains and losses on interest hedge derivatives are recorded as adjustments to interest expense. Settlements of derivatives are included in cash flows from operating activities.
To summarize, we record our derivatives at fair value in our consolidated balance sheets. Gains and losses resulting from changes in fair value and upon settlement are reported as follows:
Derivative Type
Fair Value
Gains/Losses
Financial Statement Reporting
Non-hedge derivatives
and
Hedge derivatives-
ineffective portion
Unrealized
and
Realized
Reported in the Consolidated Income Statements
as derivative fair value (gain) loss
Hedge derivatives-
effective portion
Unrealized
Reported in Stockholders’ Equity
in the Consolidated Balance Sheets
as accumulated other comprehensive income (loss)
Realized
Reported in the Consolidated Income Statements
and classified based on the hedged item
(e.g., gas revenue, oil revenue or interest expense)
To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as oil or gas revenue or interest expense when the underlying transaction occurs. If it is determined that the designated hedge transaction is not probable to occur, any unrealized gains or losses are recognized immediately in the income statement as a derivative fair value gain or loss. During 2009, 2008 and 2007, there were no gains or losses reclassified into earnings as a result of the discontinuance of hedge accounting treatment for any of our derivatives.
Physical delivery contracts that are not expected to be net cash settled are deemed to be normal sales. However, physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a non-hedge derivative.
Revenue Recognition and Gas Balancing
Oil, gas and natural gas liquids revenues are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured. At times we may sell more or less than our entitled share of gas production. When this happens, we use the entitlement method of accounting for gas sales, based on our net revenue interest in production. Accordingly, revenue is deferred for gas deliveries in excess of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. Our net gas imbalances at December 31, 2009 and 2008, were immaterial.
Gas Gathering, Processing and Marketing Revenues
We market our gas, as well as some gas produced by third parties, to brokers, local distribution companies and end-users. Gas gathering and marketing revenues are recognized in the month of delivery based on customer
nominations and adjusted based on actual deliveries. Gas processing and marketing revenues are recorded net of cost of gas sold of $809 million in 2009, $872 million for 2008 and $517 million for 2007. These amounts are net of intercompany eliminations.
Other Revenues
Other revenues result from and are related to our ongoing major operations. These revenues include dividends, foreign currency transaction adjustments, and various gains and losses, including from lawsuits and other disputes, as well as from non-significant sales of property and equipment.
Loss Contingencies
When management determines that it is probable that an asset has been impaired or a liability has been incurred, we accrue our best estimate of the loss if it can be reasonably estimated. Our legal costs related to litigation are expensed as incurred. See Note 6.
Interest
Interest expense includes amortization of deferred debt costs and is presented net of interest income of $1 million in 2009, $13 million in 2008 and $17 million in 2007, and net of capitalized interest of $42 million in 2009, $39 million in 2008 and $30 million in 2007. Interest is capitalized as proved property cost based on the weighted average interest rate and the cost of wells in process of drilling. Included in accounts payable and accrued liabilities is accrued interest of $132 million at December 31, 2009 and $139 million at December 31, 2008.
Stock-Based Compensation
We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their estimated grant-date fair value. We estimate expected forfeitures and we recognize compensation expense only for those awards expected to vest. Compensation expense is amortized over the estimated service period, which is the shorter of the award’s time vesting period or the derived service period as implied by any accelerated vesting provisions when the common stock price reaches specified levels. All compensation must be recognized by the time the award vests. See Note 13.
Earnings per Common Share
We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. See Note 10.
Segment Reporting
We evaluated how the Company is organized and managed and have identified only one operating segment, which is the exploration and production of oil, natural gas and natural gas liquids. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. Substantially all of our assets are located in the United States, and substantially all revenues are attributable to United States customers. Our North Sea assets and revenues comprised approximately 1% of total consolidated assets as of December 31, 2009 and less than 1% of total consolidated revenues for the year ended December 31, 2009.
Our production is sold to various purchasers, based on their credit rating and the location of our production. For the year ended December 31, 2009, no single purchaser comprised more than 10% of total revenues. For the year ended December 31, 2008, sales to one purchaser were approximately 16% of total revenues. For the year
ended December 31, 2007, sales to each of two purchasers were approximately 18% and 11% of total revenues. We believe that alternative purchasers are available, if necessary, to purchase production at prices substantially similar to those received from these significant purchasers.
New Accounting Pronouncements
In May 2009, we adopted the authoritative guidance of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We have evaluated subsequent events through February 24, 2010.
2. Related Party Transactions
Jack Randall, one of our nonemployee directors, was a co-founder and director of Randall & Dewey Partners, L.P., which was acquired by Jefferies Group, Inc. in 2005 and now operates as Jefferies & Company, Inc. Jefferies served as one of our financial advisors in connection with the announced merger with ExxonMobil. If the merger is completed, we have agreed to pay Jefferies a transaction fee of $24 million. In addition, we agreed to reimburse Jefferies for all reasonable and documented out-of-pocket expenses, including legal fees, incurred in connection with the services it provides to us in connection with the merger and have agreed to indemnify Jefferies against certain liabilities. In addition, Jefferies performed property acquisition advisory services for us in prior years. A division of Jefferies also performed co-manager services on our February and August 2008 and June 2007 common stock offerings and our April and July 2008 and July and August 2007 senior note offerings. We paid, for the credit of Jefferies, total fees of $11.8 million in 2008 and $3.4 million in 2007. There were no amounts payable at December 31, 2009 or 2008.
In February 2007, in recognition of the Chairman of the Board and Founder and as part of a charitable giving program to support higher education, the Board of Directors approved a conditional contribution of $6.8 million to assist in building an athletics and academic center at Baylor University. This contribution was paid in two equal installments of $3.4 million. The first payment was made May 2007 and the second was paid in July 2008. Since this was a conditional contribution, the first payment was included as general and administrative expense in 2007, and the second payment was included in general administrative expense when the condition was satisfied in second quarter 2008. Concurrently, our Chairman of the Board and Founder, made a $3.2 million pledge for the same project. He fulfilled his obligation in 2008. In return for these contributions, we, along with our Chairman of the Board and Founder, obtained naming rights for the building and certain facilities within the building.
In November 2007, the Board of Directors approved and we paid our Chairman of the Board and Founder $150,000 for an easement across his property in North Texas plus an additional $36,000 for damages. The easement was for approximately 10,000 feet at the standard easement rate in the area of $15 per foot.
3. Debt
Because we had both the intent and ability to refinance the commercial paper balance outstanding with borrowings under our revolving credit facility due in April 2013, we have classified these borrowings as long-term debt in our consolidated balance sheets. Before the stated maturities of April 2013, we may renegotiate the revolving credit agreement and term loans to increase the borrowing commitment and/or extend the maturity. Maturities of long-term debt as of December 31, 2009, excluding net discounts, are as follows:
Commercial Paper
Our commercial paper program availability is $2.84 billion. Borrowings under the commercial paper program reduce our available capacity under the revolving credit facility on a dollar-for-dollar basis. The commercial paper borrowings may have terms up to 397 days and bear interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. On December 31, 2009, borrowings under our commercial paper program were $622 million at a weighted average interest rate of 0.3%. The weighted average interest rate on commercial paper borrowings was 0.6% during 2009.
Bank Debt
On December 31, 2009, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $2.22 billion net of our commercial paper borrowings. We use the facility for general corporate purposes and as a backup facility for our commercial paper program. We have the option, with bank approval, to increase the commitment up to an additional $660 million. The interest rate on any borrowing is generally based on LIBOR plus 0.40%. When utilization of available commitments is greater than 50%, then the interest rate on our borrowings is increased by 0.05%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing commitments, which is 0.09%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 65%. The weighted average interest rate on revolver borrowings was 1.7% until all outstanding borrowings were repaid in mid-January 2009.
In February 2008, we amended our $300 million term loan credit agreement to increase outstanding borrowings to $500 million and to extend the maturity date to April 1, 2013. The proceeds were used for general corporate purposes. The weighted average interest rate on this term loan borrowing was 0.8% during 2009.
Additionally in February 2008, we borrowed $100 million under a five-year unsecured term loan agreement in a single advance that matures February 5, 2013. The proceeds were used for general corporate purposes. The weighted average interest rate on this term loan borrowing was 0.7% during 2009.
We have unsecured and uncommitted lines of credit with commercial banks totaling $100 million. As of December 31, 2009, there were no borrowings under these lines.
Repurchase of Senior Notes
In 2009, we repurchased $200 million total face amount of senior notes, including $2 million of our 5.00% senior notes due 2015, $15 million of our 6.25% senior notes due 2017, $27 million of our 5.50% senior notes due 2018, $9 million of our 6.10% senior notes due 2036, $51 million of our 6.75% senior notes due 2037 and $96 million of our 6.375% senior notes due 2038. In connection with these repurchases, we recognized a $17 million gain on extinguishment of debt, net of unamortized discounts and the write-off of deferred debt offering costs. These gains were netted against interest expense in the consolidated income statements.
Senior Notes
In July 2007, we sold $300 million of 5.9% senior notes due August 1, 2012, $450 million of 6.25% senior notes due August 1, 2017 and $500 million of 6.75% senior notes due August 1, 2037. In August 2007, we sold an additional $250 million of the 5.9% senior notes, $300 million of the 6.25% senior notes and $450 million of the 6.75% senior notes that constituted a further issuance of the senior notes issued in July 2007. Together, the 5.9% senior notes were issued at 100.585% of par to yield 5.761% to maturity. The 6.25% senior notes were issued at 100.419% of par to yield 6.193% to maturity. The 6.75% senior notes were issued at 100.022% of par to yield 6.748% to maturity. Interest is payable on each series of notes on February 1 and August 1 of each year, beginning February 1, 2008. Net proceeds of $2.24 billion were used to fund a portion of the acquisition of properties from Dominion Resources, Inc. (Note 14) and to pay down outstanding commercial paper borrowings.
In April 2008, we sold $400 million of 4.625% senior notes due June 15, 2013, $800 million of 5.50% senior notes due June 15, 2018 and $800 million of 6.375% senior notes due June 15, 2038. The 4.625% senior notes were issued at 99.888% of par to yield 4.651% to maturity. The 5.50% senior notes were issued at 99.539% of par to yield 5.561% to maturity. The 6.375% senior notes were issued at 99.864% of par to yield 6.386% to maturity. Net proceeds of $1.98 billion were used to fund property acquisitions that closed during the second and third quarters of 2008 (Note 14), to pay down outstanding commercial paper borrowings and for general corporate purposes.
In August 2008, we sold $250 million of 5.00% senior notes due August 1, 2010, $500 million of 5.75% senior notes due December 15, 2013, $1.0 billion of 6.50% senior notes due December 15, 2018 and $500 million of 6.75% senior notes due August 1, 2037. The notes due 2037 constitute a further issuance of the 6.75% senior notes issued in July 2007. The 5.00% senior notes were issued at 99.988% of par to yield 5.007% to maturity. The 5.75% senior notes were issued at 99.931% of par to yield 5.767% to maturity. The 6.50% senior notes were issued at 99.713% of par to yield 6.540% to maturity. The 6.75% senior notes were issued at 94.391% of par to yield 7.214% to maturity. Net proceeds of $2.2 billion were used to partially fund the cash portion of the Hunt acquisition (Note 14).
The senior notes require no sinking fund. We may redeem all or a part of the senior notes at any time at a price of 100% of their principal balance plus accrued interest and a make-whole premium payment. The make-whole premium is calculated as any excess over the principal balance of the present value of remaining principal and interest payments at the U.S. Treasury rate for a comparable maturity plus no more than 0.375%.
If we are the subject of a change in control, such as the proposed merger with ExxonMobil, we are required to offer to purchase at 101% of par our 7.50% senior notes due 2012 and our 6.25% senior notes due 2013. Our other senior notes are not subject to this provision.
4. Income Tax
The following reconciles our income tax expense to the amount calculated at the statutory federal income tax rate:
Components of income tax expense are as follows:
(a) The current income tax provision exceeds cash tax expense by the benefit realized upon exercise of stock options or vesting of stock awards in excess of amounts expensed in the financial statements. This benefit, which is recorded in additional paid-in capital, was $20 million in 2009, $69 million in 2008 and $64 million in 2007.
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a current liability of $342 million and a long-term liability of $5.5 billion at December 31, 2009 and as a current
liability of $940 million and a long-term liability of $5.2 billion at December 31, 2008. Significant components of net deferred tax assets and liabilities are:
We had estimated tax loss carryforwards of $43 million at December 31, 2009 and $36 million at December 31, 2008 related to our United Kingdom subsidiary acquired from Hunt Petroleum (Note 14). A valuation allowance for the full amount of these carryforwards has been recorded.
As of December 31, 2009 and 2008, we did not have any unrecognized tax benefits. As a result, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our consolidated balance sheets.
In 2007, the Internal Revenue Service completed its examination of our federal income tax returns for 2003 and 2004. Additional federal tax resulting from this examination was fully accrued in prior years. Under the terms of the final settlement with the IRS, we incurred immaterial interest expense and no penalties. Subsequent amendment of our state tax returns for these years did not have a significant effect on our results of operations or financial position. Tax years 2003 and 2004 remain subject to examination by state jurisdictions, and subsequent years are open to both federal and state examination.
5. Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state, federal and international laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of asset retirement obligation activity for the years ended December 31, 2009 and 2008:
6. Commitments and Contingencies
Leases
We lease compressors, offices, vehicles, aircraft and certain other equipment in our primary locations under noncancelable operating leases. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2009, minimum future lease payments for all noncancelable lease agreements were as follows:
Amounts expensed under operating leases (including renewable monthly leases) were $101 million in 2009, $86 million in 2008 and $57 million in 2007.
Purchase Commitments
As of December 31, 2009, we have contracts with various providers to purchase compressors. These future commitments will result in expected payments of $30 million in 2010.
Transportation Contracts
We have entered firm transportation contracts with various pipelines. Under these contracts we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. We have generally delivered at least minimum volumes under our firm transportation contracts, therefore avoiding payment for deficiencies. As of December 31, 2009, maximum commitments under our transportation contracts were as follows:
In November 2008, we completed an agreement to enter into a twelve-year firm transportation contract, contingent upon obtaining regulatory approvals and completion of a new pipeline that connects the Fayetteville Shale to ANR Pipeline and Trunkline Pipeline in Quitman County, Mississippi. Upon the pipeline’s completion, currently expected in fourth quarter 2010, we will transport gas volumes for a transportation fee of up to $1.25 million per month plus fuel, currently expected to be 0.86% of the sales price. The potential effect of this agreement is not included in the above summary of our transportation contract commitments since our commitment is contingent upon completion of the indicated project.
Employment Agreements
The Company has entered into employment agreements with Messrs. Simpson, Hutton and Vennerberg. Each agreement is for a one-year term, which automatically continues year to year thereafter unless terminated by either party upon thirty days written notice prior to each November 30. Mr. Simpson is to receive an annual base salary of $3,600,000. He is not eligible to participate in the Company’s cash bonus program. On the first business day of January during the term of his agreement, he will be entitled to receive grants of 110,000 shares of common stock with no vesting criteria and 40,000 performance shares that will have vesting criteria set by the Compensation Committee at the time of grant. In September 2009, the compensation committee approved an amendment to Mr. Simpson’s employment agreement to provide that in the event of a change in control, he will receive a cash payment equal to three times the value of his annual stock awards based on the value of the stock on the date of the change in control in addition to other payments he would receive upon a change in control. The employment agreements with Messrs. Hutton and Vennerberg provide for minimum base salaries of $1,400,000 and $900,000, respectively. The Compensation Committee has authority to pay base salaries in excess of the minimum base salaries provided for in the agreements. The agreements also provide that, in the event (i) the officer terminates his employment for good reason, as defined in the agreement, (ii) we terminate the employee without cause, (iii) the officer dies or becomes disabled, or (iv) a change in control of the Company occurs, the officer is entitled to a lump-sum payment of three times the officer’s most recent annual compensation, including bonuses. In addition, Messrs. Hutton and Vennerberg are entitled to receive a payment sufficient to make the officer whole for any excise tax on excess parachute payments imposed by the Internal Revenue Code. Mr. Simpson’s employment agreement provides that the total aggregate payments to be made under the employment agreement and any other agreement providing payments upon a change in control be reduced to the maximum amount that can be paid without the imposition of the excise tax. In December 2009, the compensation committee approved amendments to the employment agreements of Messrs. Hutton and Vennerberg to eliminate the requirement to pay minimum bonus amounts equal to their annual base salaries and to remove the annual cap on total cash compensation they could receive each year paid in the form of salary and bonuses. Prior to the amendment, the annual cap on total cash compensation for Messrs. Hutton and Vennerberg was $12,500,000 and $7,500,000, respectively.
Upon retirement, each of these officers will enter into an eighteen-month consulting agreement under which the officer will receive a monthly payment based on his annual salary at the time of retirement, plus $10,000 a month for expenses. The officer will also become fully vested in any outstanding share-based awards unless otherwise provided in the award agreement.
Commodity Commitments
We have entered into futures contracts and swap agreements that effectively fix natural gas and crude oil prices. See Note 8.
Drilling Contracts
As of December 31, 2009, we have contracts with various drilling contractors to use 50 drilling rigs with terms of up to three years and minimum future commitments of $104 million in 2010, $23 million in 2011 and $2 million in 2012. Early termination of these contracts at December 31, 2009 would have required us to pay maximum penalties of $66 million. Based upon our planned drilling activities, we do not expect to pay significant early termination penalties.
Litigation
In July 2005 a predecessor company that we acquired, Antero Resources Corporation, was served with a lawsuit styled Threshold Development Company, et al. v. Antero Resources Corp., which lawsuit was filed in the
District Court of Wise County, Texas. The plaintiffs are surface owners, royalty owners and prior working interest owners in several oil and gas leases as well as parties to other contractual agreements under which Antero Resources Corporation owned an interest. Antero Resources Corporation, the defendant, was acquired by us on April 1, 2005. The claims related to alleged events pre-dating the acquisition and concern non-payment of royalties, improper calculation of royalties, improper pricing related to royalties, trespass, failure to develop and breach of contract. We settled all claims related to the payment of royalties and trespass. Under the remaining claims, the plaintiffs sought both damages and termination of the existing oil and gas leases covering their interests. In October 2008, the trial court granted our motion for summary judgment, resulting in the dismissal of the plaintiffs’ remaining claims. The plaintiffs have appealed the court’s judgment. Based on a review of the current facts and circumstances with counsel, management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter. While acknowledging the uncertainties of litigation, management believes that the ultimate outcome of this matter will not have a material effect on our earnings, cash flows or financial position.
In November 2008, an action was filed against the Company and our directors styled Freedman v. Adams, et al. in the Delaware Court of Chancery. The plaintiff is alleged to be a stockholder and brings the suit as a derivative action on behalf of the Company. The plaintiff seeks an equitable accounting for the alleged losses by the Company and injunctions mandating that a Section 162(m) plan be submitted to our stockholders for their approval and against further non-deductible payments, along with an award of accountants’, experts’ and attorneys’ fees. We have filed a motion to dismiss. While we did not have in place a Section 162(m) plan at the time the suit was filed for cash payments, the Board of Directors approved a Section 162(m) plan in February 2009 that was approved by our stockholders at our annual meeting in May 2009. Although we are unable to predict the final outcome of this case, we believe that the allegations of this lawsuit are without merit, and we intend to vigorously defend the action.
In September 2008, a class action lawsuit was filed against the Company styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. We removed the case to federal court in Wichita, Kansas. The plaintiffs allege that we have improperly taken post-production costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma, and Colorado. The plaintiffs also seek to represent all royalty owners in these three states as a class. We have answered, denying all claims, and have filed motions to dismiss a portion of the claims. The federal court recently granted our motion for summary judgment concerning prior settled class actions that overlap plaintiff’s proposed class action. The court also granted our motion to dismiss those portions of plaintiff’s class that are currently being prosecuted in another case. Based on a review of the current facts and circumstances with counsel, management has provided for what is believed to be a reasonable estimate of the loss exposure for this matter. While acknowledging the uncertainties of litigation, management believes that the ultimate outcome of this matter will not have a material effect on our earnings, cash flows or financial position.
On December 14, 2009, Exxon Mobil Corporation and XTO Energy announced that the companies had entered into a definitive agreement under which we would become a wholly owned subsidiary of ExxonMobil. As a result of this announcement, a number of putative shareholder class actions have been filed, alleging breaches of fiduciary duties by the individual members or our Board of Directors. Each lawsuit generally seeks, among other things, declaratory and injunctive relief concerning the alleged fiduciary breaches, injunctive relief prohibiting the defendants from consummating the merger, imposition of constructive trusts in favor of plaintiffs and putative class members and unspecified monetary damages. Several putative shareholders have also filed an individual lawsuit in federal court alleging violations of the federal securities laws based on alleged false and material misrepresentations or omissions in the preliminary proxy filed with the Securities and Exchange Commission in connection with the proposed merger. The federal individual action also seeks to enjoin the proposed merger.
Two putative shareholder class actions were filed in the Delaware Court of Chancery between December 17, 2009 and December 18, 2009. Those cases are styled as (i) Teamsters Allied Benefit Funds, et al. v. XTO Energy
Inc., et al., Case No. 5150, filed on December 17, 2009 and (ii) Nicholas Lombardi v. XTO Energy Inc., et al., Case No. 5152, filed on December 18, 2009. On December 22, 2009, the Delaware Court of Chancery entered an order consolidating the complaints filed as of that date under the caption In re XTO Energy Inc. Shareholders Litigation.
Eleven putative shareholder class actions were filed in the District Courts of Tarrant County, Texas between December 14, 2009, and January 6, 2010. Those cases are styled: (i) Mary Pappas, et al. v. XTO Energy Inc., et al., No. 342-242403-09, filed on December 14, 2009; (ii) Sanjay Israni, et al. v. XTO Energy Inc., et al., No. 017-242424-09, filed on December 15, 2009; (iii) Michael Walsh, et al. v. XTO Energy Inc., et al., No. 153-242432-09, filed on December 15, 2009; (iv) Ronald Gross, et al. v. XTO Energy Inc., et al., No. 141-242460-09, filed on December 16, 2009; (v) Jeffrey Fink, et al. v. Bob R. Simpson, et al., No. 048-242500-09, filed on December 17, 2009; (vi) Lawrence Treppel, et al. v. XTO Energy Inc., et al., No. 342-242523-09, filed on December 18, 2009; (vii) Nicholas Weil, et al. v. XTO Energy Inc., et al., No. 096-242526-09, filed on December 18, 2009; (viii) Charles Kreps, et al. v. XTO Energy Inc., et al., Case No. 352-242548-09, filed on December 21, 2009; (ix) Murray Silver, et al. v. XTO Energy Inc., et al., No. 342-242630-09, filed on December 22, 2009; (x) William Stratton, et al. v. XTO Energy Inc., et al., No. 096-242775-09, filed on December 30, 2009; and (xi) United Food and Commercial Workers Union Local 880-Retail Food Employers Joint Pension Fund v. XTO Energy Inc., et al., No. 342-242849-10, filed on January 6, 2010. On January 12, 2010, the court entered orders consolidating the eleven cases filed as of that date under the caption In re XTO Energy Shareholder Class Action Litigation.
Two putative shareholder class actions were filed in the United States District Court for the Northern District of Texas between December 28, 2009 and January 5, 2010. Those cases are styled (i) James Harrison, et al. v. XTO Energy Inc., et al., No. 4:09-cv-768, filed on December 28, 2009 and (ii) Walt Schumann, et al. v. XTO Energy Inc., et al., No. 4:10-cv-007, filed on January 5, 2010. On February 5, 2010, the plaintiffs in the two federal actions filed an unopposed motion to consolidate the cases.
Several putative shareholders filed an individual action in the United States District Court for the Northern District of Texas on February 11, 2010 alleging violations of the federal securities laws based on alleged false and material misrepresentations or omissions in the preliminary proxy filed with the Securities and Exchange Commission in connection with the proposed merger. That case is styled Mary Pappas, et al. v. Bob R. Simpson, et al., No. 4:10-cv-00094-A, filed February 11, 2010.
We believe that all of the putative shareholder lawsuits are without merit and intend to vigorously defend against such claims.
We are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on our financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year.
Other
To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Most 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 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.
7. Financial Instruments
We use commodity-based and financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also may enter gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered normal sales contracts. Therefore, these contracts are not recorded in the financial statements.
Commodity Price Hedging Instruments
We periodically enter into futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on natural gas, crude oil and natural gas liquids sales. When actual commodity prices exceed the fixed price provided by these contracts, we pay this excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. See Note 8.
The fair value of our derivative contracts consists of the following:
The effects of our cash flow hedges on accumulated other comprehensive income (loss) on the consolidated balance sheets are summarized below.
(a) For realized gains upon contract settlements, the reduction to comprehensive income is offset by contract settlements generally recorded as increases to gas, natural gas liquids or oil revenue. For realized losses upon contract settlements, the increase to other comprehensive income is offset by contract settlements generally recorded as reductions to gas, natural gas liquids or oil revenue.
The effects of our non-hedge derivatives and the ineffective portion of our hedge derivatives on the consolidated income statements are summarized below.
Derivative Fair Value (Gain) Loss
Derivative fair value (gain) loss comprises the following realized and unrealized components related to non-hedge derivatives and the ineffective portion of hedge derivatives:
Fair Value of Financial Instruments
Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at December 31, 2009 and 2008. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:
The fair value of our debt is based upon current market quotes and is the estimated amount required to purchase our debt on the open market. The estimated value does dot include any redemption premium.
Fair Value Measurements
Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.
Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:
Level I-Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
Level II-Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level III-Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
The fair value of our derivative contracts are measured using Level II inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are generally A- or better rated companies, the fair value of our derivative contracts have been adjusted to account for the risk of nonperformance by the counterparty.
Our asset retirement obligation is measured using primarily Level III inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. See Note 5 for a rollforward of the asset retirement obligation.
The following table summarizes our fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall.
Concentrations of Credit Risk
Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated companies. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. Financial and commodity-based swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, and we have master netting agreements with most counterparties that provide for offsetting payables against receivables from separate derivative contracts. None of our derivative contracts contain credit-risk related contingent features that would require collateralization based on any triggering events. In September 2008, the parent company of one of our counterparties, Lehman Brothers Holdings Inc., filed for bankruptcy, and we recognized a $38 million loss ($24 million after-tax) in derivative fair value (gain) loss in the income statement.
8. Commodity Sales Commitments
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 benefit of rising prices, management may enter into hedging agreements because of the benefits of predictable, stable cash flows.
In addition to selling gas under fixed-price physical delivery contracts, we enter futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on natural gas, crude oil and natural gas liquids sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We have hedged most of our crude oil sales through December 2010 and a portion of our natural gas sales through December 2011.
Natural Gas
We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 7 regarding accounting for commodity hedges.
The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered sell basis swap agreements that effectively fix the basis adjustment as shown below. Not all of our sell basis swap agreements are designated as hedges for hedge accounting purposes. The table below does not include our physical delivery contracts tied to indices at various delivery points.
Net gains on futures and sell basis swap hedge contracts increased gas revenue by $3.0 billion in 2009 and $658 million in 2007. Net losses on these contracts decreased gas revenues by $159 million in 2008. As of December 31, 2009, an unrealized pre-tax derivative fair value gain of approximately $785 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss) (Note 11). Based on December 31 mark-to-market prices, $728 million of this gain is expected to be reclassified into earnings in 2010. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.
Crude Oil
We have entered into crude oil futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. Not all of our 2010 crude oil swap agreements are designated as hedges for hedge accounting purposes. See Note 7 regarding accounting for commodity hedges.
Net gains on these contracts increased oil revenue by $1.2 billion in 2009 and $24 million in 2007. Net losses on futures and differential swap hedge contracts decreased oil revenue by $114 million in 2008. As of December 31, 2009, an unrealized pre-tax derivative fair value gain of approximately $343 million, related to cash flow hedges of oil price risk, was recorded in accumulated other comprehensive income (loss) (Note 11). Based on December 31 mark-to-market prices, this fair value gain is expected to be reclassified into earnings in 2010. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.
Early Settlement of Hedges
In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which was used to reduce outstanding debt. Of this amount, $453 million ($287 million after-tax) was received in 2008 and the remainder was received in 2009. Under cash flow hedge accounting, the $453 million received in 2008 was included in accumulated other comprehensive income (loss) at December 31, 2008, and was recognized in earnings during 2009 as the hedged production occurred.
Natural Gas Liquids
Net losses on futures contracts decreased natural gas liquids revenue by $19 million in 2008.
Purchase Basis Swaps
We have entered purchase basis swap agreements that effectively fix the basis adjustment as shown below. Some of our purchase basis swap agreements are used to offset our physical delivery basis contracts. This effectively converts the fixed price to a floating price. The remaining purchase basis swap agreements are related to potential purchase of gas volumes to be transported in connection with our commitments under our transportation contracts (Note 6). Purchase basis swap agreements are not designated as hedges for hedge accounting purposes.
9. Equity
Stock Splits
We effected a five-for-four stock split on December 13, 2007. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect this stock split.
Common Stock
The following reflects our common stock activity:
In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 million, net proceeds of $1.2 billion were used to fund a portion of the $2.3 billion of property acquisitions closed in the first six months of 2008 and to repay indebtedness under our commercial paper program (Note 14).
Our acquisition of properties from Headington Oil Company in July 2008 was partially funded through issuance to the sellers of 11.7 million shares of our common stock (Note 14). We registered these shares under our then outstanding shelf registration statement.
In August 2008, we completed a public offering of 29.9 million common shares at $48.00 per share. After underwriting discount and other offering costs of $48 million, net proceeds of $1.4 billion were used to fund property acquisitions (Note 14) and to pay down outstanding commercial paper borrowings.
Our acquisition of Hunt Petroleum Corporation and other associated entities in September 2008 was partially funded through issuance to the sellers of 23.5 million shares of our common stock (Note 14). We registered these shares under our then outstanding shelf registration statement.
In June 2007, we completed a public offering of 21.6 million common shares at $48.40 per share. After underwriting discount and other offering costs of $35 million, net proceeds of $1.0 billion were used to fund a portion of the acquisition of natural gas and oil properties from Dominion Resources, Inc. (Note 14).
Treasury Stock
In August 2004, our Board of Directors authorized the repurchase of up to 25 million shares of our common stock which may be purchased from time to time in open market or negotiated transactions. As of December 31, 2009, we have repurchased 2.8 million shares.
Shelf Registration Statement
In June 2009, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities or common stock. The securities will be offered at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including reduction of bank debt.
Common Stock Warrants
Our purchase of Antero Resources Corporation in 2005 was partially funded by issuance of warrants to purchase 2.6 million shares of common stock at $20.78 per share. The warrants expire on April 1, 2010.
Common Stock Dividends
The Board of Directors declared quarterly dividends of $0.096 per common share for the first three quarters of 2007, $0.12 per common share for fourth quarter 2007 and for each quarter in 2008 and $0.125 for each quarter in 2009. On February 16, 2010, the Board of Directors declared a first quarter 2010 dividend of $0.125 per common share.
The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and will depend on our financial condition, earnings and cash flow from operations, the level of our capital expenditures, our future business prospects and other matters the Board of Directors deems relevant. In addition, under the terms of the merger agreement with ExxonMobil, during the period before the closing of the merger, we are prohibited from declaring, setting aside or paying any dividend or other distribution except for our regular quarterly cash dividend, which is not to exceed $0.125 per share. The merger agreement also provides that we will coordinate the declaration of dividends with ExxonMobil before the completion of the merger so that both our shareholders and the shareholders of ExxonMobil only receive, in any quarter, one dividend from each company.
See Note 13.
10. Earnings Per Share
Effective January 1, 2009, we adopted the authoritative guidance for earnings per share as it relates to determining whether instruments granted in share based payment transactions are participating securities. Under the guidance, share-based payment awards that contain nonforfeitable rights to dividends, as is the case with our restricted and performance shares, are participating securities and therefore should be included in computing earnings per share using the two-class method. As a result of adoption, we retrospectively adjusted the calculation of our 2008 and prior periods’ earnings per share on a basis consistent with 2009. The following reconciles earnings and shares used in the computation of basic and diluted earnings per common share:
Certain options to purchase shares of our common stock have been excluded from the 2009 and 2008 diluted calculations because the options are anti-dilutive. Anti-dilutive options for 7.7 million shares in the year ended December 31, 2009 with a weighted average exercise price of $52.18 and 8.0 million shares in the year ended December 31, 2008 period with a weighted average exercise price of $51.01 were excluded.
11. Accumulated Other Comprehensive Income (Loss)
Our comprehensive income (loss) information is included in the consolidated statements of comprehensive income. The following are components of accumulated other comprehensive income (loss) as of December 31, 2009, 2008 and 2007, and changes during those years:
12. Supplemental Cash Flow Information
The consolidated statements of cash flows exclude the following non-cash transactions:
•
The following restricted share activity (Note 13):
•
Grants of 1.6 million shares in 2009, 2.5 million shares in 2008 and 1.4 million shares in 2007
•
Vesting of 1.7 million shares in 2009, 865,000 shares in 2008 and 427,000 shares in 2007
•
Forfeitures of 83,000 shares in 2009, 51,000 shares in 2008 and 48,000 shares in 2007
•
Grants and immediate vesting of unrestricted common shares to nonemployee directors totaling 25,000 shares in each of 2009, 2008 and 2007 (Note 13)
•
Grant and immediate vesting of 110,000 unrestricted common shares to our Chairman of the Board and Founder in 2009 (Note 13)
•
The following performance share activity (Note 13):
•
Grants of 826,000 shares in 2009 and 1.2 million shares in 2008
•
Vesting of 571,000 shares in 2009, 363,000 shares in 2008 and 166,000 shares in 2007
•
Forfeitures of 15,000 shares in 2007
•
Common shares delivered or attested to in satisfaction of the exercise price of employee stock options totaled 700,000 shares at a weighted average price of $46.76 per share in 2009 and 1.5 million shares at a weighted average exercise price of $56.76 per share in 2008.
•
Non-cash component of the July 2008 Headington Oil Company acquisition purchase price, including issuance to the sellers of 11.7 million shares of common stock (Note 14)
•
Non-cash components of the September 2008 Hunt Petroleum acquisition purchase price, including issuance to the sellers of 23.5 million shares of common stock and assumption of debt and other liabilities (Note 14)
Interest payments totaled $577 million (including $42 million of capitalized interest) in 2009, $499 million (including $39 million of capitalized interest) in 2008 and $231 million (including $30 million of capitalized interest) in 2007. Net income tax payments were $430 million in 2009, $45 million in 2008 and $284 million in 2007.
13. Employee Benefit Plans
401(k) Plan
We sponsor a 401(k) benefit plan that allows employees to contribute and defer a portion of their wages. We match employee contributions up to 14% of wages, subject to annual dollar maximums established by the federal government and plan limitations. Employee contributions vest immediately while our matching contributions vest 100% upon completion of three years of service. All employees over 18 years of age may participate. Company contributions under the plan were $25 million in 2009, $20 million in 2008 and $14 million in 2007.
Stock Incentive Plans
Stock awards under the 2004 Stock Incentive Plan include stock options, performance shares, restricted shares and unrestricted shares. In May 2008, stockholders approved certain amendments and restatements to the 2004 Plan including increasing the shares available for grants of stock awards by 12 million shares, of which 6 million can be granted as full-value awards and authorizing the compensation committee of our board to grant full-value awards to our executive officers. Prior to approval of the 2004 Plan, grants of stock awards were made pursuant to the 1998 Stock Incentive Plan. No further grants will be made under the 1998 Plan. Stock award grants are subject to certain limitations as specified in the Plan. The maximum term of stock awards is ten years under the 1998 Plan and seven years under the 2004 Plan.
The table below summarizes stock incentive compensation expense included in the consolidated financial statements and related amounts for each year:
(a) Recorded as additional paid-in-capital
Stock Options
Stock options granted under the 2004 Plan generally vest and become exercisable ratably over a three-year period, and may include a provision for accelerated vesting when the common stock price reaches specified levels as determined by the Compensation Committee of the Board of Directors. Some stock options granted in 2009, 2008 and 2007 vest only when the common stock price reaches specified levels. There were a total of 18.4 million options outstanding under the 2004 and 1998 Plans at December 31, 2009, including 14.3 million that were exercisable at that date. The table below shows the terms under which the remaining options vest.
Unvested
Stock
Options
(in thousands)
Vesting
2,053
Ratably over 3 years
$ 50
$ 54
$ 55
$ 90
The following summarizes option activity and balances for the year ended December 31, 2009:
As a result of options exercised in 2009, outstanding common stock increased by 1.5 million shares and stockholders’ equity increased by $11 million.
Performance Shares
Performance shares granted under the 2004 Plan are subject to restrictions determined by the Compensation Committee of the Board of Directors and are subject to forfeiture if performance criteria are not met. Otherwise, holders of performance shares generally have all the voting, dividend and other rights of other common stockholders. To date, the performance criteria for all awards has been the achievement of specified increases in the common stock price above the market price at the grant date. We granted 826,000 performance shares in 2009 and 1,216,000 performance shares in 2008. There were a total of 1,108,000 performance shares outstanding at December 31, 2009. The table below shows the number of shares and vesting prices of these performance shares.
Performance Shares
(in thousands)
Vesting Price
$ 50
$ 55
$ 77
$ 85
The November 2009 performance share grant totaled 456,000 shares, with half of the shares vesting when the common stock price closes at or above $50 and the other half vesting when the common stock price closes at or above $55. Under the terms of the grant agreement, when the merger agreement with ExxonMobil was signed, the vesting criteria for these shares changed to time vesting, with all of the shares vesting one year after the merger closes. If the merger is not completed, the vesting criteria for the shares would revert to the original price vesting terms.
Restricted Shares
We granted 1,568,000 restricted shares in 2009, 2,537,000 restricted shares in 2008 and 1,388,000 restricted shares in 2007 to key employees other than executive officers. Of the shares granted in 2009, 1,544,000 vest over 42 months, with one-third vesting each at 18, 30 and 42 months. The remaining shares granted in 2009 and previous years vest over three years, with one-third vesting at each grant anniversary date. Holders of restricted shares generally have all the voting, dividend and other rights of other common stockholders.
Unrestricted Share Awards
Nonemployee directors are each eligible to receive discretionary stock awards under the 2004 Plan covering up to 25,000 shares annually, as approved by the Corporate Governance and Nominating Committee and the
Board of Directors. Subsequent to the November 2008 grant, the directors approved a director compensation program whereby nonemployee directors no longer receive stock options and are limited to annual unrestricted grants not to exceed 6,000 shares per director subject to a cap in value of $300,000 as defined in the compensation program.
Nonemployee directors received 4,166 shares each totaling approximately 25,000 unrestricted shares in 2009, 2008 and 2007 under the 2004 Plan. In November 2007, nonemployee directors received 20,000 stock options each totaling 120,000 stock options, 50% of which vested when the common stock price closed above the target price of $56 in 2008 and 50% of which vested when the common stock price closed above the target price of $60 in 2008. In November 2008, nonemployee directors received 20,000 stock options each totaling 120,000 stock options, 50% of which vested when the common stock price closed above the target price of $40 in 2009 and 50% of which vested when the common stock price closed at or above the target price of $45 in 2009.
In January 2009, our Chairman of the Board and Founder received 110,000 unrestricted common shares.
Nonvested Stock Awards
The following summarizes the status of the nonvested stock options, performance shares and restricted shares as of December 31, 2009 and changes for the year then ended:
As of December 31, 2009, the remaining unrecognized compensation expense related to nonvested stock options was $12 million. Total deferred compensation at December 31, 2009 related to performance shares was $15 million and related to restricted shares was $134 million. For these nonvested stock awards at December 31, 2009, we estimate that stock incentive compensation for service periods after December 31, 2009 will be $90 million in 2010, $45 million in 2011, $18 million in 2012 and $8 million in 2013. The weighted-average remaining vesting period is 1.0 years for stock options, 0.4 years for performance shares, and 2.4 years for restricted shares.
Estimated Fair Value of Grants
We use a trinomial lattice model to value stock option grants that time vest and a Monte Carlo simulation model to value performance shares and stock options that vest, or include a provision for accelerated vesting, when the common stock price reaches specified levels.
During 2009, 2008 and 2007, we used both a trinomial lattice model and a Monte Carlo simulation model to determine the fair value of options granted, and we used a Monte Carlo simulation model to determine the fair value of performance shares granted. For restricted stock grants, the fair value is equal to the closing price of our common stock on the grant date.
The trinomial lattice model requires inputs for risk-free interest rate, dividend yield, volatility, contract term, average vesting period, post-vest turnover rate and suboptimal exercise factor. Both expected life and fair
value are outputs of this model. The Monte Carlo simulation model requires inputs for risk-free interest rate, dividend yield, volatility, contract term, target vesting price, post-vest turnover rate and suboptimal exercise factor. The suboptimal exercise factor does not affect the valuation of the performance shares since ownership is transferred at vesting. Expected life, derived vesting period and fair value are outputs of this model.
The risk-free interest rate is based on the constant maturity nominal rates of U.S. Treasury securities with remaining lives throughout the contract term on the day of the grant. The dividend yield is the expected common stock annual dividend yield over the expected life of the option or performance share, expressed as a percentage of the stock price on the date of grant. The volatility factors are based on a combination of both the historical volatilities of our stock and the implied volatility of traded options on our common stock. Contract term is seven years. For options subject to time vesting, the average vesting period is two years, based on each grant vesting ratably over a three-year period. For options subject to vesting when the common stock reaches a specified price, the target vesting price is specified by the award. The post-vesting turnover rate is 1.13% and the suboptimal exercise factor is 1.78, and are both based on actual historical exercise activity. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by certain employees who receive stock option grants, and subsequent events are not indicative of the reasonableness of the original fair value estimates.
We record stock incentive compensation only for awards expected to vest. During 2009, we estimated annual forfeitures using a rate of 0% for stock options, 2% for restricted shares and 0% for performance shares.
During the year ended December 31, 2009, we granted 1.6 million options with an estimated total grant-date fair value of $19 million and a weighted-average fair value of $11.68 per option. During 2008, we granted 2.7 million options with an estimated total grant-date fair value of $47 million and a weighted-average fair value of $17.10 per option. During 2007, we granted 4.3 million options with an estimated total grant-date fair value of $65 million and a weighted-average fair value of $15.29 per option. Fair values were determined using the following assumptions:
14. Acquisitions
During the first six months of 2008, we completed acquisitions of both producing and unproved properties for approximately $2.3 billion. These acquisitions included bolt-on acquisitions of additional producing properties, mineral interests and undeveloped leasehold primarily in our Eastern and San Juan Regions and the Barnett, Fayetteville, Woodford and Marcellus Shales. These acquisitions were funded by commercial paper borrowings, proceeds from the February 2008 common stock offering (Note 9) and proceeds from the April 2008 issuance of senior notes (Note 3).
Additionally, in May 2008, we acquired producing properties, leasehold acreage and gathering infrastructure in the Fayetteville Shale from Southwestern Energy Company for approximately $520 million. The purchase price was allocated primarily to unproved properties. The acquisition was funded by proceeds from the April 2008 issuance of senior notes.
In July 2008, we acquired producing properties, leasehold acreage and pipeline and gathering infrastructure in the Marcellus Shale in western Pennsylvania and West Virginia from Linn Energy, LLC for approximately $600 million. The purchase price was allocated primarily to proved and unproved properties. The acquisition was funded in part by proceeds from the April 2008 issuance of senior notes as well as commercial paper borrowings.
In July 2008, we acquired producing and undeveloped acreage located in the Bakken Shale in Montana and North Dakota from Headington Oil Company. The total purchase price was $1.8 billion, and was funded by cash of $1.05 billion and the issuance of 11.7 million shares of common stock to the sellers valued at $742 million (Note 9). The purchase price was allocated primarily to proved properties. The cash portion of the transaction was funded by a combination of operating cash flow and commercial paper.
In September 2008, we acquired Hunt Petroleum Corporation and other associated entities for approximately $4.2 billion, funded by cash of $2.6 billion and the issuance of 23.5 million shares of common stock to the sellers valued at $1.6 billion (Note 9). Hunt Petroleum owned natural gas and oil producing properties primarily concentrated in our Eastern Region, including East Texas and central and north Louisiana. Additional producing properties, both onshore and offshore, are along the Gulf Coast of Texas, Louisiana, Mississippi and Alabama. Non-operating interests, including producing and undeveloped acreage in the North Sea were also conveyed in the transaction. The cash portion of the transaction was funded by a combination of operating cash flow, commercial paper and the August 2008 issuance of senior notes (Note 3).
We believe that the overlap of Hunt Petroleum’s assets with ours, primarily in the Eastern Region, as well as the addition of new operating areas in the Gulf Coast and offshore Gulf of Mexico was a significant benefit of the Hunt acquisition. Another important contributing factor of the acquisition was the ability to secure intellectual talent to help exploit these areas as well as others.
Following is the final calculation of the purchase price of Hunt Petroleum Corporation and the allocation to assets and liabilities as of September 2, 2008. The fair value of consideration issued was determined as of June 10, 2008, the date the acquisition was announced.
In October 2008, we acquired 12,900 acres in the Barnett Shale for approximately $800 million. The acquisition was funded through proceeds from the August 2008 common stock offering (Note 9), our commercial paper program and our revolving credit facility.
On July 31, 2007, we acquired both producing and unproved properties from Dominion Resources, Inc. for $2.5 billion. 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 (Note 9), the issuance of $1.25 billion of senior notes in July 2007 (Note 3) 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 (Note 3). After recording asset retirement obligation of $32 million, other liabilities and transaction costs of $18 million, $2.5 billion was allocated to proved properties and $38 million to unproved properties.
Acquisitions were recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for 2008 and 2007 as if the Hunt acquisition was made at the beginning of 2008 and 2007 and the 2007 Dominion acquisition was made at the beginning of 2007. These pro forma results are not necessarily indicative of future results.
15. Quarterly Financial Data (Unaudited)
The following are summarized quarterly financial data for the years ended December 31, 2009 and 2008:
(a) Operating income before general and administrative expense.
(b) Because quarterly earnings per share is based on the weighted average shares outstanding during the quarter, the sum of quarterly earnings per share may not equal earnings per share for the year. See Note 10 related to our January 1, 2009 adoption of the authoritative guidance regarding calculating earnings per share using the two-class method.
(c) Included in fourth quarter net income is an after-tax impairment of proved properties of $81 million (Note 1).
16. Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited)
Substantially all of our operations are directly related to oil and gas producing activities located in the United States. Our international oil and gas producing activities, located in the North Sea, comprise less than 1% of our 2009 and 2008 revenues, costs incurred, reserves and standardized measure.
Costs Incurred Related to Oil and Gas Producing Activities
The following table summarizes costs incurred whether such costs are capitalized or expensed for financial reporting purposes:
(a) Represents a portion of the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties (Note 14).
(b) Includes capitalized interest of $42 million in 2009, $39 million in 2008 and $30 million in 2007.
(c) Includes revisions of ($7) million in 2009, $52 million in 2008 and $39 million in 2007.
Proved Reserves
Our proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. Proved reserves exclude volumes deliverable to others under production payments or retained interests.
Standardized Measure
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Prior to 2009, standardized measure was calculated using year end oil and gas prices and costs.
Prices are not adjusted for the effect of hedge derivatives. Discounted future net cash flows are calculated using a 10% rate. Estimated future income taxes are calculated by applying year-end statutory rates to future pre-tax net cash flows, less the tax basis of related assets and applicable tax credits.
Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. Such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values as of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired (Note 5).
The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as effected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.
(a) Includes positive price revisions of 165.2 Bcfe in 2007 and negative price revisions of 545.8 Bcfe in 2008 and 620.0 Bcfe in 2009.
The additions to our proved reserves from extensions, additions and discoveries in the last three years are due to the success of our development drilling program. Gas development was concentrated in East Texas and the Barnett, Fayetteville and Woodford shales in 2009. In 2008 and 2007, gas development focused on East Texas and the Barnett Shale. Oil development was concentrated in the Permian Basin and Bakken Shale in 2009 and primarily the Permian Basin in 2008 and 2007. Development and exploration costs totaled $3.0 billion in 2009, $3.9 billion in 2008 and $2.8 billion in 2007. As a result of our 2009 development program, we added approximately 1.8 Tcfe of new undeveloped reserves.
(a) Generally based on the year-end present value plus the cash flow received from such properties during the year, rather than the estimated present value at the date of acquisition.
(b) Generally based on beginning of the year present value less the cash flow received from such properties during the year, rather than the estimated present value at the date of sale.
(c) The December 31, 2009 standardized measure includes a reduction of $96 million ($151 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2009 includes a liability of $812 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.
(d) The December 31, 2008 standardized measure includes a reduction of $93 million ($147 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2008 includes a liability of $759 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.
(e) The December 31, 2007 standardized measure includes a reduction of $43 million ($68 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2007 includes a liability of $453 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.
Price and cost revisions are primarily the net result of changes in prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.
Average realized gas prices used in the estimation of proved reserves and calculation of the standardized measure were $3.16 for 2009, $4.66 for 2008, $6.39 for 2007 and $5.46 for 2006. Average realized natural gas liquids prices were $27.18 for 2009, $18.26 for 2008, $60.24 for 2007 and $31.96 for 2006. Average realized oil prices were $55.96 for 2009, $38.12 for 2008, $91.19 for 2007 and $55.47 for 2006. In 2009, we used 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period. For periods prior to 2009, we used year end oil and gas prices.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended). Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. Our management has concluded that, based on these criteria, we have maintained in all material respects, effective internal control over financial reporting as of December 31, 2009.
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected.
February 24, 2010
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
XTO Energy Inc.:
We have audited the accompanying consolidated balance sheets of XTO Energy Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, cash flows, and comprehensive income for each of the years in the three-year period ended December 31, 2009. We also have audited XTO Energy Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). XTO Energy Inc. management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures, as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of XTO Energy Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, XTO Energy Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
As discussed in Note 10 to the consolidated financial statements, as of January 1, 2009, the Company adopted the authoritative guidance for earnings per share as it relates to determining whether instruments granted in share based payment transactions are participating securities.
KPMG LLP
Fort Worth, Texas
February 24, 2010
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 24th day of February 2010.
XTO ENERGY INC.
By
/S/ KEITH A. HUTTON
Keith A. Hutton,
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 24th day of February 2010.
PRINCIPAL EXECUTIVE OFFICERS
(AND DIRECTORS)
DIRECTORS
/S/ BOB R. SIMPSON
/S/ WILLIAM H. ADAMS III
Bob R. Simpson,
Chairman of the Board and Founder
William H. Adams III
/S/ KEITH A. HUTTON
Keith A. Hutton,
Chief Executive Officer
/S/ LANE G. COLLINS
Lane G. Collins
/S/ VAUGHN O. VENNERBERG II
/S/ PHILLIP R. KEVIL
Vaughn O. Vennerberg II,
President
Phillip R. Kevil
/S/ JACK P. RANDALL
Jack P. Randall
/S/ SCOTT G. SHERMAN
Scott G. Sherman
/S/ HERBERT D. SIMONS
Herbert D. Simons
PRINCIPAL FINANCIAL OFFICER
PRINCIPAL ACCOUNTING OFFICER
/S/ LOUIS G. BALDWIN
/S/ BENNIE G. KNIFFEN
Louis G. Baldwin,
Executive Vice President and Chief Financial Officer
Bennie G. Kniffen,
Senior Vice President and Controller
INDEX TO EXHIBITS
Documents filed prior to June 1, 2001 were filed with the Securities and Exchange Commission under our prior name, Cross Timbers Oil Company.
Exhibit
No.
Description
Page
2.1+
Agreement and Plan of Merger dated January 9, 2005 among XTO Energy Inc., XTO Barnett Inc., and Antero Resources Corporation (incorporated by reference to Exhibit 2.2 to Form 10-K for the year ended December 31, 2004)
2.2+
Amendment No. 1 to Agreement and Plan of Merger dated February 3, 2005 among XTO Energy Inc., XTO Barnett Inc., and Antero Resources Corporation (incorporated by reference to Exhibit 2.3 to Form 10-K for the year ended December 31, 2004)
2.3+
Amendment No. 2 to Agreement and Plan of Merger dated March 22, 2005 among the Company, XTO Barnett Inc., XTO Barnett LLC and Antero Resources Corporation (incorporated by reference to Exhibit 2.1 to Form 8-K filed March 28, 2005)
2.4+
Amendment No. 3 to Agreement and Plan of Merger dated March 31, 2005 among the Company, XTO Barnett Inc., XTO Barnett LLC and Antero Resources Corporation (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 5, 2005)
2.5+
Gulf Coast/Rockies/San Juan Package Purchase Agreement dated as of June 1, 2007 between Dominion Exploration & Production, Inc., Dominion Energy, Inc., Dominion Oklahoma Texas Exploration & Production, Inc., Dominion Reserves, Inc., LDNG Texas Holdings, LLC and DEPI Texas Holdings, LLC as Sellers and XTO Energy Inc. as Buyer (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 6, 2007)
2.6+
Agreement of Sale and Purchase dated May 23, 2008 between Headington Oil Company LLC, et al. and XTO Energy Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K filed July 18, 2008)
2.7+
Acquisition Agreement dated June 9, 2008 among XTO Energy Inc., HPC Acquisition Corporation, HHEC Acquisition Corporation, Hunt Petroleum Corporation, Hassie Hunt Exploration Company and Hassie Hunt Production Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed July 18, 2008)
2.8+
Purchase and Sale Agreement dated July 18, 2008 between XTO Energy Inc. and Hollis R. Sullivan Inc., et al. (incorporated by reference to Exhibit 2.1 to Form 8-K filed July 24, 2008)
2.9+
Agreement and Plan of Merger dated December 13, 2009 among XTO Energy Inc., Exxon Mobil Corporation and ExxonMobil Investment Corporation (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2009)
3.1
Restated Certificate of Incorporation of the Company, as restated on June 21, 2006 (incorporated by reference to Exhibit 3.1 to Form 10-Q for the quarter ended June 30, 2006)
3.2
Amended and Restated Bylaws of the Company as of May 19, 2009 (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 22, 2009)
4.1
Form of Indenture for Senior Debt Securities dated as of April 23, 2002 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed April 17, 2002)
4.2
First Supplemental Indenture dated as of April 23, 2002 between the Company and the Bank of New York, as Trustee for the 7 1/2% Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 to Form 10-K for the year ended December 31, 2002)
Exhibit
No.
Description
Page
4.3
Second Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 7 1/2% Senior Notes due 2012 (incorporated by reference to Exhibit 4.3 to Form 10-Q for the quarter ended March 31, 2006)
4.4
Registration Rights Agreement among the Company and partners of Cross Timbers Oil Company, L.P. (incorporated by reference to Exhibit 10.9 to Registration Statement on Form S-1, File No. 33-59820)
4.5
Indenture dated as of April 23, 2003 between the Company and the Bank of New York, as Trustee for the 6 1/4% Senior Notes due 2013 (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2003)
4.6
First Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 6 1/4% Senior Notes due 2013 (incorporated by reference to Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2006)
4.7
Indenture for Senior Debt Securities dated as of January 22, 2004 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed January 16, 2004)
4.8
First Supplemental Indenture dated as of January 22, 2004 between the Company and the Bank of New York, as Trustee for the 4.90% Senior Notes due 2014 (incorporated by reference to Exhibit 4.3.2 to Form 8-K filed January 16, 2004)
4.9
Second Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 4.90% Senior Notes due 2014 (incorporated by reference to Exhibit 4.5 to Form 10-Q for the quarter ended March 31, 2006)
4.10
Indenture dated as of September 23, 2004 between the Company and the Bank of New York, as Trustee for the 5% Senior Notes due 2015 (incorporated by reference to Exhibit 4.1 to Form 8-K filed September 24, 2004)
4.11
First Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 5% Senior Notes due 2015 (incorporated by reference to Exhibit 4.6 to Form 10-Q for the quarter ended March 31, 2006)
4.12
Indenture for Senior Debt Securities dated as of April 13, 2005 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed April 12, 2005)
4.13
First Supplemental Indenture dated as of April 13, 2005 between the Company and the Bank of New York, as Trustee for 5.30% Senior Notes due 2015 (incorporated by reference to Exhibit 4.3.2 to Form 8-K filed April 12, 2005)
4.14
Second Supplemental Indenture dated as of October 1, 2005 between the Company and The Bank of New York Trust Company, as Successor Trustee, for 5.30% Senior Notes due 2015 (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006)
4.15
Third Supplemental Indenture dated as of March 30, 2006 between the Company and The Bank of New York Trust Company, as Trustee, for 5.65% Senior Notes due 2016 and 6.10% Senior Notes due 2036 (incorporated by reference to Exhibit 4.2 to Form 10-Q for the quarter ended March 31, 2006)
Exhibit
No.
Description
Page
4.16
Registration Rights Agreement dated April 1, 2005 among the Company and the security holders of Antero Resources Corporation (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 2005)
4.17
Indenture for Senior Debt Securities dated as of July 19, 2007 between the Company and the Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.3.1 to Form 8-K filed July 16, 2007)
4.18
First Supplemental Indenture dated as of July 19, 2007 between the Company and the Bank of New York Trust Company, N.A., as Trustee for 5.90% Senior Notes due 2012, 6.25% Senior Notes due 2017 and 6.75% Senior Notes due 2037 (incorporated by reference to Exhibit 4.3.2 to Form 8-K filed July 16, 2007)
4.19
Second Supplemental Indenture dated as of April 18, 2008 between the Company and the Bank of New York Trust Company, N.A., as Trustee for 4.625% Senior Notes due 2013, 5.50% Senior Notes due 2018 and 6.375% Senior Notes due 2038 (incorporated by reference to Exhibit 4.3.3 to Form 8-K filed April 16, 2008)
4.20
Third Supplemental Indenture dated as of August 7, 2008 between the Company and the Bank of New York Trust Company, N.A., as Trustee for 5% Senior Notes due 2010, 5.75% Senior Notes due 2013 and 6.50% Senior Notes due 2018 (incorporated by reference to Exhibit 4.3.4 to Form 8-K filed August 5, 2008)
10.1*
Employment Agreement between the Company and Bob R. Simpson, dated May 16, 2006 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2006)
10.2*
Amendment to Employment Agreement between the Company and Bob R. Simpson, dated December 31, 2007 (incorporated by reference to Exhibit 10.1 to Form 8-K filed January 7, 2008)
10.3*
Employment Agreement between the Company and Bob R. Simpson, dated November 18, 2008 (incorporated by reference to Exhibit 10.3 to Form 10-K for the year ended December 31, 2008)
10.4*
Amendment to Employment Agreement between the Company and Bob R. Simpson, dated September 16, 2009 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2009)
10.5*
Amendment No. 2 to Employment Agreement between the Company and Bob R. Simpson, dated December 13, 2009
10.6*
Employment Agreement between the Company and Keith A. Hutton, dated May 16, 2006 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2006)
10.7*
Employment Agreement between the Company and Keith A. Hutton, dated November 18, 2008 (incorporated by reference to Exhibit 10.5 to Form 10-K for the year ended December 31, 2008)
10.8*
Amendment to Employment Agreement between the Company and Keith A. Hutton, dated December 13, 2009
10.9*
Employment Agreement between the Company and Vaughn O. Vennerberg II, dated May 16, 2006 (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended June 30, 2006)
Exhibit
No.
Description
Page
10.10*
Employment Agreement between the Company and Vaughn O. Vennerberg II, dated November 18, 2008 (incorporated by reference to Exhibit 10.7 to Form 10-K for the year ended December 31, 2008)
10.11*
Amendment to Employment Agreement between the Company and Vaughn O. Vennerberg II, dated December 13, 2009
10.12*
1998 Stock Incentive Plan, as amended March 17, 2004 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2004)
10.13*
Consulting Agreement among XTO Energy Inc., Exxon Mobil Corporation and Bob R. Simpson, dated December 13, 2009 (incorporated by reference to Exhibit 99.1 to Form 8-K filed December 15, 2009) **
10.14*
Consulting Agreement among XTO Energy Inc., Exxon Mobil Corporation and Keith A. Hutton, dated December 13, 2009 (incorporated by reference to Exhibit 99.2 to Form 8-K filed December 15, 2009) **
10.15*
Consulting Agreement among XTO Energy Inc., Exxon Mobil Corporation and Vaughn O. Vennerberg II, dated December 13, 2009 (incorporated by reference to Exhibit 99.3 to Form 8-K filed December 15, 2009) **
10.16*
Consulting Agreement among XTO Energy Inc., Exxon Mobil Corporation and Louis G. Baldwin, dated December 13, 2009 (incorporated by reference to Exhibit 99.4 to Form 8-K filed December 15, 2009) **
10.17*
Consulting Agreement among XTO Energy Inc., Exxon Mobil Corporation and Timothy L. Petrus, dated December 13, 2009 (incorporated by reference to Exhibit 99.5 to Form 8-K filed December 15, 2009) **
10.18*
XTO Energy Inc. Amended and Restated 2004 Stock Incentive Plan (incorporated by reference to Appendix B to the Proxy Statement dated April 13, 2006 for the Annual Meeting of Stockholders held May 16, 2006)
10.19*
XTO Energy Inc. Amended and Restated 2004 Stock Incentive Plan (as amended and restated through November 21, 2006) (incorporated by reference to Exhibit 10.10 to Form 10-K for the year ended December 31, 2006)
10.20*
XTO Energy Inc. 2004 Stock Incentive Plan, as Amended and Restated as of May 20, 2008 (incorporated by reference to Appendix B to the Proxy Statement dated April 21, 2008 for the Annual Meeting of Stockholders held May 20, 2008)
10.21*
Form of Nonqualified Stock Option Agreement for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 8-K filed November 22, 2004)
10.22*
Form of Nonqualified Stock Option Agreement for Employees with Employment Agreements under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2006)
10.23*
Form of Stock Award Agreement for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed November 22, 2004)
10.24*
Second Form of Stock Award Agreement for Employees under the 2004 Stock Incentive Plan
Exhibit
No.
Description
Page
10.25*
Form of Nonqualified Stock Option Agreement for Non-Employee Directors under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.4 to Form 8-K filed November 22, 2004)
10.26*
Form of Stock Award Agreement for Non-Employee Directors under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 8-K filed November 22, 2004)
10.27*
Form of Stock Grant Agreement for Non-Employee Directors under Section 11 of the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 22, 2005)
10.28*
Form of Stock Grant Agreement (With Restrictions) for Non-Employee Directors under Section 11 of the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.18 to Form 10-K for the year ended December 31, 2007)
10.29*
Form of Stock Award Agreement (Restricted Shares) for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.30 to Form 10-K for the year ended December 31, 2006)
10.30*
Second Form of Stock Award Agreement (Restricted Shares) for Employees under the 2004 Stock Incentive Plan
10.31*
Form of Stock Award Agreement for Employees with Employment Agreements under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2008)
10.32*
Form of Stock Grant Agreement to Chairman under Section 11 of the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.21 to Form 10-K for the year ended December 31, 2008)
10.33*
Second Form of Stock Award Agreement for Employees with Employment Agreements under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.22 to Form 10-K for the year ended December 31, 2008)
10.34*
Second Form of Nonqualified Stock Option Agreement for Employees with Employment Agreements under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.23 to Form 10-K for the year ended December 31, 2008)
10.35*
Second Amended and Restated Management Group Employee Severance Protection Plan, as amended August 15, 2006 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2006)
10.36*
Third Amended and Restated Management Group Employee Severance Protection Plan, as amended November 18, 2008 (incorporated by reference to Exhibit 10.25 to Form 10-K for the year ended December 31, 2008)
10.37*
Fourth Amended and Restated Management Group Employee Severance Protection Plan, as amended December 13, 2009 **
10.38*
Amended and Restated Outside Directors Severance Plan, as amended August 15, 2006 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2006)
10.39*
Amended and Restated Outside Directors Severance Plan, as amended November 18, 2008 (incorporated by reference to Exhibit 10.27 to Form 10-K for the year ended December 31, 2008)
Exhibit
No.
Description
Page
10.40*
Form of Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, Keith A. Hutton, Vaughn O. Vennerberg II and Louis G. Baldwin, dated October 15, 2004 (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 21, 2004)
10.41*
Form of Amendment No. One to Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, Keith A. Hutton, Vaughn O. Vennerberg II and Louis G. Baldwin, dated November 21, 2006 (incorporated by reference to Exhibit 10.26 to Form 10-K for the year ended December 31, 2006)
10.42*
Amendment Number Two to Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, dated December 31, 2007 (incorporated by reference to Exhibit 10.2 to Form 8-K filed January 7, 2008)
10.43*
Agreement (relating to change in control) between the Company and Timothy L Petrus, dated November 21, 2006 (incorporated by reference to Exhibit 10.27 to Form 10-K for the year ended December 31, 2006)
10.44*
Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, dated November 18, 2008 (incorporated by reference to Exhibit 10.32 to Form 10-K for the year ended December 31, 2008)
10.45*
Form of Amended and Restated Agreement (relating to change in control) between the Company and Keith A. Hutton, Vaughn O. Vennerberg II, Louis G. Baldwin and Timothy L. Petrus, dated November 18, 2008 (incorporated by reference to Exhibit 10.33 to Form 10-K for the year ended December 31, 2008)
10.46*
Amendment to Amended and Restated Agreement (relating to change in control) between the Company and Bob R. Simpson, dated December 13, 2009 (incorporated by reference to Exhibit 99.6 to Form 8-K filed December 15, 2009)
10.47*
Amendment to Amended and Restated Agreement (relating to change in control) between the Company and Keith A. Hutton, dated December 13, 2009 (incorporated by reference to Exhibit 99.7 to Form 8-K filed December 15, 2009)
10.48*
Amendment to Amended and Restated Agreement (relating to change in control) between the Company and Vaughn O. Vennerberg II, dated December 13, 2009 (incorporated by reference to Exhibit 99.8 to Form 8-K filed December 15, 2009)
10.49*
Amendment to Amended and Restated Agreement (relating to change in control) between the Company and Louis G. Baldwin, dated December 13, 2009 (incorporated by reference to Exhibit 99.9 to Form 8-K filed December 15, 2009)
10.50*
Amendment to Amended and Restated Agreement (relating to change in control) between the Company and Timothy L. Petrus, dated December 13, 2009 (incorporated by reference to Exhibit 99.10 to Form 8-K filed December 15, 2009)
10.51*
XTO Energy Inc. 2009 Executive Incentive Compensation Plan (incorporated by reference to Appendix C to the Proxy Statement dated April 17, 2009 for the Annual Meeting of Stockholders held May 19, 2009)
10.52*
Form of Indemnification Agreement dated November 15, 2005 between the Company and each director, executive officer and certain other officers (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 18, 2005)
Exhibit
No.
Description
Page
10.53*
Description of Matching Charitable Contribution Program for officers and directors (incorporated by reference to Exhibit 10.34 to Form 10-K for the year ended December 31, 2007)
10.54
Amended and Restated 5-Year Revolving Credit Agreement dated April 1, 2005 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 2005)
10.55
First Amendment to Five-Year Revolving Credit Agreement dated March 10, 2006 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2006)
10.56
Second Amendment to Five-Year Revolving Credit Agreement dated October 25, 2006 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2006)
10.57
Third Amendment to 5-Year Revolving Credit Agreement dated March 19, 2007 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.1 to Form 8-K filed March 23, 2007)
10.58
Fourth Amendment to 5-Year Revolving Credit Agreement dated February 6, 2008 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.39 to Form 10-K for the year ended December 31, 2007)
10.59
Commitment Increase and Accession Agreement dated July 17, 2008 between XTO Energy Inc. and certain banks named therein (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2008)
10.60
Term Loan Credit Agreement dated November 10, 2004 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.20 to Form S-4 dated December 13, 2004)
10.61
First Amendment to Term Loan Agreement dated April 1, 2005 between the Company and certain banks named therein (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ended March 31, 2005)
10.62
Second Amendment to Term Loan Agreement dated March 10, 2006 between the Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2006)
10.63
Third Amendment to Term Loan Agreement dated March 19, 2007 between the Company and certain banks named therein (incorporated by reference to Exhibit 10.2 to Form 8-K filed March 23, 2007)
10.64
Fourth Amendment to Term Loan Agreement dated February 6, 2008 between the Company and certain banks named therein (incorporated by reference to Exhibit 10.44 to Form 10-K for the year ended December 31, 2007)
10.65
Form of Commercial Paper Dealer Agreement dated October 27, 2006 between the Company and each of Lehman Brothers Inc., Citigroup Global Markets Inc., Goldman, Sachs & Co. and JP Morgan Securities Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 2, 2006)
10.66
Issuing and Paying Agency Agreement dated October 27, 2006 between the Company and JP Morgan Chase Bank, National Association (incorporated by reference to Exhibit 10.2 to Form 8-K filed November 2, 2006)
Exhibit
No.
Description
Page
10.67
Firm Intrastate Gas Transportation Agreement dated July 1, 2005 between the Company, XTO Resources I, LP and Energy Transfer Fuel, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2005) (Material has been omitted from this Exhibit pursuant to an order of confidential treatment and the omitted material has been separately filed with the Securities and Exchange Commission.)
12.1
Computation of Ratio of Earnings to Fixed Charges
21.1
Subsidiaries of XTO Energy Inc.
23.1
Consent of KPMG LLP
23.2
Consent of Miller and Lents, Ltd.
31.1
Chief Executive Officer Certification required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
31.2
Chief Financial Officer Certification required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
32.1
Chief Executive Officer and Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
99.1
Miller and Lents, Ltd. Report
The following financial statements from XTO Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 25, 2010, formatted in XBRL; (i) Consolidated Balance Sheets, (ii) Consolidated Income Statements, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Stockholders’ Equity and (vi) the Notes to Consolidated Financial Statements, tagged as blocks of text.
+ All schedules and similar attachments have been omitted. The Company agrees to furnish supplementally a copy of the omitted schedules and similar attachments to the Securities and Exchange Commission upon request.
* Management contract or compensatory plan
** To be effective upon completion of the merger with Exxon Mobil Corporation.
Copies of the above exhibits not contained herein are available, at the cost of reproduction, to any security holder upon written request to the Secretary, XTO Energy Inc., 810 Houston Street, Fort Worth, Texas 76102.

Market Capitalization: 26536300.18850708
1-Year Return: -0.00522188562899828
252-Day Return: $252_day_return