SEC Form 10-K Filing Report

Company: DEVON ENERGY CORP/DE
CIK: 1090012
SIC Code: 1311
Filing Date: 2011-02-25 00:00:00
Market Capitalization: 39022164.3409729

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ITEM 1. BUSINESS
Item 1.
Business
General
Devon Energy Corporation, including its subsidiaries (“Devon”), is an independent energy company engaged primarily in exploration, development and production of natural gas and oil. Our operations are concentrated in various North American onshore areas in the United States and Canada. We also have offshore operations located in Brazil and Angola that are currently in the process of being divested.
To complement our upstream oil and gas operations in North America, we have a large marketing and midstream operation. With these operations, we market gas, crude oil and NGLs. We also construct and operate pipelines, storage and treating facilities and natural gas processing plants. These midstream facilities are used to transport oil, gas, and NGLs and process natural gas.
We began operations in 1971 as a privately held company. We have been publicly held since 1988, and our common stock is listed on the New York Stock Exchange. Our principal and administrative offices are located at 20 North Broadway, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).
Strategy
As an enterprise, we aspire to be the premier independent natural gas and oil company in North America. To achieve this, we continuously strive to optimize value for our shareholders by growing cash flows, earnings, production and reserves, all on a per debt-adjusted share basis. We do this by:
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exercising capital discipline;
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investing in oil and gas properties with high operating margins;
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balancing our reserves and production mix between natural gas and liquids;
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maintaining a low overall cost structure;
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improving performance through our marketing and midstream operations; and
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preserving financial flexibility.
Over the decade leading up to 2010, we captured an abundance of resources by carrying out this strategy. We pioneered horizontal drilling in the Barnett Shale and extended this technique to other natural gas shale plays in the United States and Canada. We became proficient with steam-assisted gravity drainage with our Jackfish oil sands development in Alberta, Canada. We achieved key oil discoveries with our drilling in the deepwater Gulf of Mexico and offshore Brazil. We have tripled our proved oil and gas reserves since 2000, and have also assembled an extensive inventory of exploration assets representing additional unproved resources.
Building off our past successes, in November 2009, we announced plans to strategically reposition Devon as a North American onshore exploration and production company. As part of this strategic repositioning, we are bringing forward the value of our offshore assets located in the Gulf of Mexico and countries outside North America by divesting them. As of the end of 2010, we had sold our properties in the Gulf of Mexico, Azerbaijan, China and other International regions, generating $5.6 billion in after-tax proceeds. Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the divestitures. Once the pending transactions are complete, we expect to have generated more than $8 billion in after-tax proceeds.
This repositioning has allowed us to focus our operations on our premier portfolio of North American onshore assets. Historically, our North American onshore assets have consistently provided us our highest risk-adjusted investment returns. By selling our offshore assets, we are able to conduct an aggressive, yet disciplined, pursuit of the untapped value of these North American onshore opportunities. More specifically,
given the current challenged market for natural gas prices, our near-term focus is on the oil and liquids-rich opportunities that exist within our balanced portfolio of properties.
Besides investing in our onshore exploration and development opportunities, we are also using the divestiture proceeds to reduce our debt significantly and conduct up to a $3.5 billion common share repurchase program.
Presentation of Discontinued Operations
As a result of our November 2009 repositioning announcement, all amounts in this document related to our International operations are presented as discontinued. Therefore, financial data and operational data, such as reserves, production, wells and acreage, provided in this document exclude amounts related to our International operations unless otherwise provided.
Our U.S. Offshore operations do not qualify as discontinued operations under accounting rules. As such, financial and operational data provided in this document that pertain to our continuing operations include amounts related to our U.S. Offshore operations that were divested in 2010. Where appropriate, we have presented amounts related to our U.S. Offshore assets separate from those of our North American Onshore assets.
Development of Business
Since our first issuance of common stock to the public in 1988, we have executed strategies that have been focused on growth and value creation for our shareholders. We increased our total proved reserves from 8 MMBoe at year-end 1987 to 2,873 MMBoe at year-end 2010. During this same time period, we increased annual production from 1 MMBoe in 1987 to 228 MMBoe in 2010. Our expansion over this time period is attributable to a focused mergers and acquisitions program spanning a number of years, as well as active and successful exploration and development programs in more recent years. Additionally, our growth has provided meaningful value creation for our shareholders. The growth statistics from 1987 to 2010 translate into annual per share growth rates of 8% for production and 11% for reserves.
As a result of this growth, we have become one of the largest independent oil and gas companies in North America. During 2010, we continued to build off our past successes with a number of key accomplishments, including those discussed below.
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Drilling Success - We drilled 1,584 gross wells in 2010 on our North American onshore properties with a 99% success rate. We increased oil and NGL production from our North American onshore properties by 6% in 2010, to an average of 193 MBoe per day.
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Cana-Woodford Shale - We drilled 87 wells in the Cana-Woodford Shale play in western Oklahoma and more than doubled our industry-leading leasehold position in the play to more than 240,000 net acres. Our 2010 production exit rate from the Cana-Woodford increased more than 210% over the prior year to an average of 147 MMcf of gas equivalent per day, including 4 MBbls per day of liquids production. We also completed construction and commenced operation of our Cana gas processing plant in 2010.
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Permian Basin - We exited 2010 with Permian production of 45 MBoe per day, which represented a 16% increase compared to 2009. We have nearly one million net acres of leasehold in the region targeting various oil and liquids-rich play types.
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Jackfish - In 2010, our net production from our Jackfish oil sands project averaged 25 MBbls per day. Following scheduled facilities maintenance in the third quarter and a third-party pipeline system outage in the fourth quarter, our net Jackfish production ramped back up to 30 MBbls per day at year-end.
Construction of our second Jackfish project is now complete. We expect to begin injecting steam at Jackfish 2 in the second quarter, with first oil production expected by the end of 2011. We applied for regulatory approval of a third phase of Jackfish in the third quarter of 2010.
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Pike - We added to our Canadian oil position by acquiring a 50% interest in the Pike oil sands leases. The Pike acreage lies immediately adjacent to our highly successful Jackfish project and has estimated gross recoverable resources that may exceed Jackfish. We are the operator of the project and are currently drilling appraisal wells and acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development.
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Barnett Shale - Our 2010 production exit rate was 1.2 Bcfe per day, including 43 MBbls per day of liquids production. This represents a 16% increase in total production compared to the 2009 exit rate.
Financial Information about Segments and Geographical Areas
Notes 20 and 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain information on our segments and geographical areas.
Oil, Natural Gas and NGL Marketing and Delivery Commitments
The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) or short-term (less than one year) agreements. Regardless of the term of the contract, the vast majority of our production is sold at variable or market sensitive prices.
Additionally, we may periodically enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil and gas production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Oil Marketing
Our oil production is sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary daily, as of January 2011, approximately 81% of our oil production was sold under short-term contracts at variable or market-sensitive prices. The remaining 19% of oil production was sold under long-term, market-indexed contracts that are subject to market pricing variations.
Natural Gas Marketing
Our gas production is also sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary daily, as of January 2011, approximately 81% of our gas production was sold under short-term contracts at variable or market-sensitive prices. These market-sensitive sales are referred to as “spot market” sales. Another 18% of our production was committed under various long-term contracts, which dedicate the gas to a purchaser for an extended period of time, but still at market-sensitive prices. The remaining 1% of our gas production was sold under long-term, fixed-price contracts.
NGL Marketing
Our NGL production is sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary, as of January 2011, approximately 83% of our NGL production was sold under short-term contracts at variable or market-sensitive prices. Approximately 9% of our NGL production was sold under short-term, fixed-price contracts. The remaining 8% of NGL production was sold under long-term, market-sensitive price contracts.
Delivery Commitments
A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. Although exact amounts vary, as of January 2011, we were committed to deliver the following fixed quantities of our oil and natural gas production:
(1)
Gas volumes are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGLs are converted to Boe on a one-to-one basis with oil.
We expect to fulfill our delivery commitments over the next three years with production from our proved developed reserves. We expect to fulfill our longer-term delivery commitments beyond three years primarily with our proved developed reserves. In certain regions, we expect to fulfill these longer-term delivery commitments with our proved undeveloped reserves. See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for information related to our proved reserves, including the development of our proved undeveloped reserves.
Our proved reserves have been sufficient to satisfy our delivery commitments during the three most recent years, and we expect such reserves will continue to satisfy our future delivery commitments. However, should our proved reserves not be sufficient to satisfy our future delivery commitments, we can and may use spot market purchases to fulfill the commitments.
Marketing and Midstream Activities
The primary objective of our marketing and midstream operations is to add value to us and other producers to whom we provide such services by gathering, processing and marketing oil, gas and NGL production in a timely and efficient manner. Our most significant midstream asset is the Bridgeport processing plant and gathering system located in north Texas. These facilities serve not only our gas production from the Barnett Shale but also gas production of other producers in the area. We have other natural gas processing plants that support our operations, including a plant completed in 2010 that serves the Cana-Woodford Shale production. Our midstream assets also include our 50% interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our Jackfish heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale.
Our marketing and midstream revenues are primarily generated by:
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selling NGLs that are either extracted from the gas streams processed by our plants or purchased from third parties for marketing, and
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selling or gathering gas that moves through our transport pipelines and unrelated third-party pipelines.
Our marketing and midstream costs and expenses are primarily incurred from:
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purchasing the gas streams entering our transport pipelines and plants;
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purchasing fuel needed to operate our plants, compressors and related pipeline facilities;
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purchasing third-party NGLs;
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operating our plants, gathering systems and related facilities; and
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transporting products on unrelated third-party pipelines.
Customers
We sell our gas production to a variety of customers including pipelines, utilities, gas marketing firms, industrial users and local distribution companies. Gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries.
The principal customers for our crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is trucked or shipped to storage, refining or pipeline facilities.
Our NGL production is primarily sold to customers engaged in petrochemical, refining and heavy oil blending activities. Pipelines, railcars and trucks are utilized to move our products to market.
During 2010, 2009 and 2008, no purchaser accounted for over 10% of our revenues.
Seasonal Nature of Business
Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.
Public Policy and Government Regulation
The oil and natural gas industry is subject to various types of regulation throughout the world. Laws, rules, regulations and other policy implementations affecting the oil and natural gas industry have been pervasive and are under constant review for amendment or expansion. Pursuant to public policy changes, numerous government agencies have issued extensive laws and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas exploration, production and marketing and midstream activities. These laws and regulations increase the cost of doing business and, consequently, affect profitability. Because public policy changes affecting the oil and natural gas industry are commonplace and because existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. However, we do not expect that any of these laws and regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size and financial strength.
During 2010, as part of a strategic restructuring of the company, we sold our properties in the Gulf of Mexico and the majority of our assets outside North America, Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the divestitures. These divestitures reduce our vulnerability to laws, rules and regulations imposed by foreign governments, as well as those imposed in the United States for offshore exploration and production. The following are significant areas of government control and regulation affecting our operations in the United States and Canada.
Exploration and Production Regulation
Our oil and gas operations are subject to various federal, state, provincial, tribal and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to:
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acquisition of seismic data;
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location of wells;
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drilling and casing of wells;
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hydraulic fracturing;
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well production;
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spill prevention plans;
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emissions and discharge permitting;
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use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
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surface usage and the restoration of properties upon which wells have been drilled;
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calculation and disbursement of royalty payments and production taxes;
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plugging and abandoning of wells; and
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transportation of production.
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.
Certain of our U.S. natural gas and oil leases are granted by the federal government and administered by the Bureau of Land Management of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding and royalty payment obligations for production from federal lands.
Royalties and Incentives in Canada
The royalty system in Canada is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location and the type and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada also have established incentive programs such as royalty rate reductions, royalty holidays, tax credits and fixed rate and profit-sharing royalties for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our revenues, earnings and cash flow.
Pricing and Marketing in Canada
Any oil or gas export to be made pursuant to an export contract that exceeds a certain duration or a certain quantity requires an exporter to obtain export authorizations from Canada’s National Energy Board (“NEB”). The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere.
Environmental and Occupational Regulations
We are subject to various federal, state, provincial, tribal and local international laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things:
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assessing the environmental impact of seismic acquisition, drilling or construction activities;
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the generation, storage, transportation and disposal of waste materials;
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the emission of certain gases into the atmosphere;
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the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and
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the development of emergency response and spill contingency plans.
The application of worldwide standards, such as ISO 14000 governing environmental management systems, is required to be implemented for some international oil and gas operations.
We consider the costs of environmental protection and safety and health compliance necessary and manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and will likely continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, salt water or other substances. However, we do not maintain 100% coverage concerning any environmental claim, and no coverage is maintained with respect to any penalty or fine required to be paid because of a violation of law.
In 2010, the United States Environmental Protection Agency (“EPA”) issued rules requiring oil and natural gas companies to track and report their greenhouse gas emissions. For Devon, this involves collecting emissions data at more than 17,000 well sites and numerous natural gas plants and compressor stations. While these rules increase our cost of doing business, we do not anticipate that we would be impacted to any greater degree than other similar oil and natural gas companies.
The Kyoto Protocol was adopted by numerous countries in 1997 and implemented in 2005. The Protocol requires reductions of certain emissions of greenhouse gases. Although the United States has not ratified the Protocol, the other countries in which we operate have. In 2007, Canada ratified the Kyoto Protocol and committed to reducing Canada’s greenhouse gas emissions. This commitment was renewed by signing the Copenhagen Accord in 2009 and the Cancun Agreement in 2010. Although there is no framework in place, Canada remains focused on the original reduction target of the Kyoto Protocol and is working to align greenhouse gas policy with the United States. The mandatory reductions on greenhouse gas emissions will create additional costs for the Canadian oil and gas industry, including Devon. Provincially, British Columbia and Alberta have greenhouse gas legislation and regulation that carry some compliance burden for the oil and gas sector. Presently, it is not possible to accurately estimate the costs we could incur to comply with any future laws or regulations developed to achieve emissions reductions in Canada or elsewhere, but such expenditures could be substantial.
In 2006, we established our Corporate Climate Change Position and Strategy. Key components of the strategy include initiation of energy efficiency measures, tracking emerging climate change legislation and publication of a corporate greenhouse gas emission inventory. We last published our emission inventory on January 2008. We will publish another emission inventory on or before March 31, 2011 to comply with a reporting mandate issued by the EPA. Additionally, we continue to explore energy efficiency measures and
greenhouse emission reduction opportunities. We also continue to monitor legislative and regulatory climate change developments, such as the proposals described above.
Employees
As of December 31, 2010, we had approximately 5,000 employees. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.
Competition
See “

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ITEM 1A. RISK FACTORS
Item 1A.
Risk Factors
Our business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.
Oil, Gas and NGL Prices are Volatile
Our financial results are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. A significant downward movement of the prices for these commodities could have a material adverse effect on our revenues, operating cash flows and profitability. Such a downward price movement could also have a material adverse effect on our estimated proved reserves, the carrying value of our oil and gas properties, the level of planned drilling activities and future growth. Historically, market prices and our realized prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:
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consumer demand for oil, gas and NGLs;
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conservation efforts;
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OPEC production levels;
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weather;
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regional pricing differentials;
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differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);
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differing quality and NGL content of gas produced;
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the level of imports and exports of oil, gas and NGLs;
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the price and availability of alternative fuels;
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the overall economic environment; and
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governmental regulations and taxes.
Estimates of Oil, Gas and NGL Reserves are Uncertain
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Additional discussion of our policies and internal controls related to estimating and recording reserves is described in “Item 2. Properties - Preparation of Reserves Estimates and Reserves Audits.”
Discoveries or Acquisitions of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production
The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase, due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies, identify additional producing zones in existing wells, secondary or tertiary recovery techniques, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
Future Exploration and Drilling Results are Uncertain and Involve Substantial Costs
Substantial costs are often required to locate and acquire properties and drill exploratory wells. Such activities are subject to numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling and completing wells are often uncertain. In addition, oil and gas properties can become damaged or drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:
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unexpected drilling conditions;
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pressure or irregularities in reservoir formations;
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equipment failures or accidents;
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fires, explosions, blowouts and surface cratering;
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adverse weather conditions;
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lack of access to pipelines or other transportation methods;
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environmental hazards or liabilities; and
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shortages or delays in the availability of services or delivery of equipment.
A significant occurrence of one of these factors could result in a partial or total loss of our investment in a particular property. In addition, drilling activities may not be successful in establishing proved reserves. Such a failure could have an adverse effect on our future results of operations and financial condition. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.
Industry Competition For Leases, Materials, People and Capital Can Be Significant
Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and other independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Typically, during times of high or rising commodity prices, drilling and operating costs will also increase. Higher prices will also generally increase the costs of properties available for acquisition. Certain of our competitors have financial and other resources substantially larger than ours. They also may have established strategic long-term positions and relationships in areas in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuels, and the application of government regulations.
Midstream Capacity Constraints and Interruptions Impact Commodity Sales
We rely on midstream facilities and systems to process our natural gas production and to transport our production to downstream markets. Such midstream systems include the systems we operate, as well as systems operated by a number of different third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us.
Regardless of who operates the midstream systems we rely upon, a portion of our production in any region may be interrupted or shut in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third-parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.
Hedging Activities Limit Participation in Commodity Price Increases and Increase Exposure to Counterparty Credit Risk
We periodically enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.
Public Policy, Which Includes Laws, Rules and Regulations, Can Change
Our operations are generally subject to federal laws, rules and regulations in the United States and Canada. In addition, we are also subject to the laws and regulations of various states, provinces, tribal and local governments. Pursuant to public policy changes, numerous government departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Changes in such public policy have affected, and at times in the future could affect, our operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Existing laws and regulations can also require us to incur substantial costs to maintain regulatory compliance. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, income taxes and climate change as discussed below.
Hydraulic Fracturing - The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. This legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.
Income Taxes - The U.S. President’s recent budget proposals include provisions that would, if enacted, make significant changes to United States tax laws. The most significant change would eliminate the immediate deduction for intangible drilling and development costs.
Climate Change - Policy makers in the United States are increasingly focusing on whether the emissions of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policy makers at both the United States federal and state level have introduced legislation and proposed new regulations that are designed to quantify and limit the emission of greenhouse gases through inventories and limitations on greenhouse gas emissions. Legislative initiatives to date have focused on the development of cap-and-trade programs. These programs generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs would be relevant to our operations because the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases.
Environmental Matters and Costs Can Be Significant
As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.
Insurance Does Not Cover All Risks
Exploration, development, production and processing of oil, gas and NGLs can be hazardous and involve unforeseen occurrence including, but not limited to blowouts, cratering, fires and loss of well control. These occurrences can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. We maintain insurance against certain losses or liabilities in accordance with customary industry practices and in amounts that management believes to be prudent. However, insurance against all operational risks is not available to us.
International Operations Have Uncertain Political, Economic and Other Risks
Our operations outside North America are based in Brazil and Angola. As noted earlier in this report, we are in the process of divesting our operations outside North America. However, until we cease operating in these locations, we face political and economic risks and other uncertainties in these areas that are more prevalent than what exist for our operations in North America. Such factors include, but are not limited to:
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general strikes and civil unrest;
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the risk of war, acts of terrorism, expropriation, forced renegotiation or modification of existing contracts;
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import and export regulations;
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taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;
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transportation regulations and tariffs;
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exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds;
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laws and policies of the United States affecting foreign trade, including trade sanctions;
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the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;
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the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and
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difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. These assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Various regions of the world have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. This could adversely affect our interests and our future profitability.
The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.
Certain of Our Investments Are Subject To Risks That May Affect Their Liquidity and Value
To maximize earnings on available cash balances, we periodically invest in securities that we consider to be short-term in nature and generally available for short-term liquidity needs. During 2007, we purchased asset-backed securities that have an auction rate reset feature (“auction rate securities”). Our auction rate securities generally have contractual maturities of more than 20 years. However, the underlying interest rates on our securities are scheduled to reset every seven to 28 days. Therefore, when we bought these securities, they were generally priced and subsequently traded as short-term investments because of the interest rate reset feature. At December 31, 2010, our auction rate securities totaled $94 million.
Since February 8, 2008, we have experienced difficulty selling our securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature. Due to continued auction failures throughout 2009 and 2010, we consider these investments to be long-term in nature and generally not available for short-term liquidity needs. Therefore, we have classified these investments as other long-term assets.
Our auction rate securities are rated AAA - the highest rating - by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. These investments are subject to general credit, liquidity, market and interest rate risks, which may be exacerbated by problems in the global credit markets, including but not limited to, U.S. subprime mortgage defaults and writedowns by major financial institutions due to deteriorating values of their asset portfolios. These and other
related factors have affected various sectors of the financial markets and caused credit and liquidity issues. If issuers are unable to successfully close future auctions and their credit ratings deteriorate, our ability to liquidate these securities and fully recover the carrying value of our investment in the near term may be limited. Under such circumstances, we may record an impairment charge on these investments in the future.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B.
Unresolved Staff Comments
Not applicable.

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ITEM 2. PROPERTIES
Item 2.
Properties
Property Overview
Our oil and gas operations are concentrated within various North American onshore basins across the United States and Canada. Our properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage in these regions. These ownership interests entitle us to drill for and produce oil, natural gas and NGLs from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, mineral, and other forms of direct and indirect ownership in oil and gas properties.
As previously mentioned, we have completed substantially all of our offshore divestitures, with the exception of assets in Brazil and Angola. We have entered into agreements to sell these assets and are waiting for the respective governments to approve the divestitures.
We also have a substantial midstream business that includes natural gas and NGL processing plants and pipeline systems across North America. In aggregate, we have ownership in approximately 13,000 miles of pipeline and 65 natural gas processing and treating plants. Our most significant concentration of midstream assets is located in north Texas at our Barnett Shale field. These assets include over 3,000 miles of pipeline, two natural gas processing plants with 750 MMcf per day of total capacity, and a 15 MBbls per day NGL fractionator. In 2010, we completed construction of a natural gas processing plant to support the growing development of our Cana-Woodford Shale properties. The Cana plant has an initial capacity of 200 MMcf per day with the design capacity to expand up to 600 MMcf per day.
Our midstream assets also include the Access Pipeline transportation system in Canada. This 220-mile dual pipeline system extends from our Jackfish operations in Alberta with connectivity to a 350 MBbls storage terminal near Edmonton. The dual pipeline system allows us to deliver diluents to Jackfish for the blending of our heavy oil production and transport the combined product to the Edmonton crude oil market for sale. We have a 50% ownership interest in the Access Pipeline.
The following sections provide additional details of our oil and gas properties, including information about proved reserves, production, wells, acreage and drilling activities.
Property Profiles
The locations of our key properties are presented on the following map.
The following table presents proved reserve information for our key properties as of December 31, 2010, along with their production volumes for the year 2010. Our key properties include those that currently have significant proved reserves or production. These key properties also include properties that do not have current significant levels of proved reserves or production, but are expected be the source of future significant growth in proved reserves and production.
(1)
Gas reserves and production are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL reserves and production are converted to Boe on a one-to-one basis with oil.
(2)
Percentage of proved reserves and production the property bears to total proved reserves and production based on actual figures and not the rounded figures included in this table.
The following profile information includes the location, acreage, formation type, average working interest and 2010 drilling activities of our key properties presented in the table above. Due to the continued depressed natural gas price environment, we are shifting the vast majority of our 2011 drilling activity to focus on the oil and liquids-rich gas properties within our portfolio. For the key properties that are primarily liquids-based, we also provide our 2011 drilling plans in the profile information below.
U.S.
Barnett Shale - The Barnett Shale, located in north Texas, is our largest property both in terms of production and proved reserves. Our leases include approximately 630,000 net acres located primarily in Denton, Johnson, Parker, Tarrant and Wise counties. The Barnett Shale is a non-conventional reservoir and it
produces natural gas and NGLs. We have an average working interest of 89%. We drilled 460 gross wells in 2010 and plan to drill approximately 320 gross wells in 2011.
Carthage - The Carthage area in east Texas includes primarily Harrison, Marion, Panola and Shelby counties. Our average working interest is 86% and we hold approximately 225,000 net acres. Our Carthage area wells produce primarily natural gas and NGLs from conventional reservoirs. We drilled 26 gross wells in 2010 in this area.
Cana-Woodford Shale - The Cana-Woodford Shale is located primarily in Canadian, Blaine, Caddo, and Dewey counties in western Oklahoma. Our average working interest is 52% and we hold more than 240,000 net acres. Our Cana-Woodford Shale properties produce natural gas, NGLs and condensate from a non-conventional reservoir. We drilled 87 gross wells in 2010 and plan to drill around 220 gross wells in 2011.
Permian Basin - Our oil and gas properties in the Permian Basin in west Texas and southeast New Mexico comprise approximately 950,000 net acres. Our drilling activity is targeting the liquids-rich targets within the Avalon Shale, Bone Spring, Wolfberry and undisclosed play types within other conventional reservoirs. Our average working interest in these properties is 53%. In 2010, we drilled 262 gross wells and plan to drill approximately 300 gross wells in 2011.
Washakie - Our Washakie area leases are concentrated in Carbon and Sweetwater counties in southern Wyoming. Our average working interest is about 76% and we hold about 160,000 net acres in the area. The Washakie wells produce primarily natural gas from conventional reservoirs. In 2010, we drilled 93 gross wells.
Arkoma-Woodford Shale - Our Arkoma-Woodford Shale properties in southeastern Oklahoma produce natural gas and NGLs from a non-conventional reservoir. Our more than 55,000 net acres are concentrated in Coal and Hughes counties, and we have an average working interest of about 31%. In 2010, we drilled 61 gross wells in this area.
Groesbeck - The Groesbeck area of east Texas includes portions of Freestone, Leon, Limestone and Robertson counties. Our average working interest is 72% and we hold about 130,000 net acres of land. The Groesbeck wells produce primarily natural gas from conventional reservoirs. In 2010, we drilled 20 gross wells in this area.
Granite Wash - The Granite Wash is concentrated in Hemphill and Wheeler counties in the Texas Panhandle and in western Oklahoma. Our average working interest is approximately 48% and we hold approximately 60,000 net acres of land. The Granite Wash wells produce liquids and natural gas from conventional reservoirs. In 2010, we drilled 29 gross wells in this area and plan to drill approximately 55 gross wells in 2011.
Haynesville-Bossier Shale - Our Haynesville Shale acreage position spans across east Texas and north Louisiana with an average working interest of 92%. To date, our drilling activity has been focused on approximately 150,000 acres located in Panola, Shelby and San Augustine counties in east Texas. We drilled 23 gross wells in 2010.
Canada
Jackfish - Jackfish is our 100%-owned thermal heavy oil project in the non-conventional oil sands of east central Alberta. We are employing steam-assisted gravity drainage at Jackfish. The first phase of Jackfish is fully operational with a gross facility capacity of 35 MBbls per day. We expect this project to maintain a flat production profile for greater than 20 years at an average net production rate of approximately 25-30 MBbls per day. We have completed construction of the second phase of Jackfish and we have filed a regulatory application for a third phase. The second and third phases of Jackfish are each expected to eventually produce approximately 30 MBbls per day of heavy oil production net of royalties over the life of the projects.
Northwest - The Northwest region includes acreage within west central Alberta and northeast British Columbia. We hold approximately 1.9 million net acres in the region, which produces primarily natural gas
from conventional reservoirs. Our average working interest in the area is approximately 73%. In 2010, we drilled 67 gross wells and plan to drill about 50 gross wells in 2011.
Lloydminster - Our Lloydminster properties are located to the south and east of Jackfish in eastern Alberta and western Saskatchewan. Lloydminster produces heavy oil by conventional means without steam injection. We hold 2.4 million net acres and have an 89% average working interest in our Lloydminster properties. In 2010, we drilled 181 gross wells and plan to drill a similar amount of gross wells in 2011.
Deep Basin - Our properties in Canada’s Deep Basin include portions of west central Alberta and east central British Columbia. We hold approximately 520,000 net acres in the Deep Basin. The area produces natural gas and liquids from conventional reservoirs. Our average working interest in the Deep Basin is 43%. In 2010, we drilled 39 gross wells and plan to drill approximately 30 gross wells in 2011.
Horn River Basin - The Horn River Basin, located in northeast British Columbia, is a non-conventional gas reservoir targeting the Devonian Shale. Our leases include approximately 170,000 net acres with a 100% working interest. We drilled 7 gross wells in 2010.
Pike - Our 50%-owned Pike oil sands acreage is situated directly to the south of our Jackfish acreage in east central Alberta. This position was attained in 2010 through a joint venture agreement with BP. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2010. We began appraisal drilling near the end of 2010 and are acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development. We expect to begin the regulatory application process for the first Pike phase around the end of 2011.
Preparation of Reserves Estimates and Reserves Audits
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment as discussed in “Item 1A. Risk Factors.” As a result, we have developed internal policies for estimating and recording reserves. Our policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators (“Qualified Estimators”), as defined by the Society of Petroleum Engineers’ standards.
The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the Group’s Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates. Such qualifications include any or all of the following:
•
an undergraduate degree in petroleum engineering from an accredited university, or equivalent;
•
a petroleum engineering license, or similar certification;
•
memberships in oil and gas industry or trade groups; and
•
relevant experience estimating reserves.
The current Director of the Group has all of the qualifications listed above. The current Director has been involved with reserves estimation in accordance with SEC definitions and guidance since 1987. He has experience in reserves estimation for projects in the United States (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America. He has been employed by Devon for the past ten years,
including the past three in his current position as Director of Reserves and Economics. During his career with Devon and others, he was the primary reservoir engineer for projects including, but not limited to:
•
Hugoton Gas Field (Kansas)
•
Sho-Vel-Tum CO2 Flood (Oklahoma)
•
West Loco Hills Unit Waterflood and CO2 Flood (New Mexico)
•
Dagger Draw Oil Field (New Mexico)
•
Clarke Lake Gas Field (Alberta, Canada)
•
Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea)
•
ACG Unit (Caspian Sea)
As the primary reservoir engineer, he was responsible for reserves estimation on each of these projects. These reserves estimates were utilized internally and for SEC filings.
From 2003 to 2010, he served as the reservoir engineering representative on our internal Peer Review Team, reviewing reserves and resource estimates for projects including, but not limited to:
•
Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf)
•
Cascade Lower Tertiary Development (Gulf of Mexico Deepwater)
•
Polvo Development (Campos Basin, Brazil)
Additionally, the Group reports independently of any of our operating divisions. The Group’s Director reports to our Vice President of Budget and Reserves, who reports to our Chief Financial Officer. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.
Throughout the year, the Group performs internal audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major additions and revisions to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants discussed below. The Group also ensures our Qualified Estimators obtain continuing education related to the fundamentals of SEC proved reserves assignments.
The Group also oversees audits and reserves estimates performed by third-party consulting firms. During 2010, we engaged two such firms to audit a significant portion of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2010 reserve estimates for 94% of our U.S. onshore properties. AJM Petroleum Consultants audited 89% of our Canadian reserves.
Set forth below is a summary of the North American reserves that were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2010, 2009 and 2008.
N/A Not applicable - We sold all our U.S. Offshore properties during 2010.
“Prepared” reserves are those quantities of reserves that were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of reserves that were estimated by our employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of an audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum
consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.
In addition to conducting these internal and external reviews, we also have a Reserves Committee that consists of three independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The Reserves Committee assists the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, the members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process.
The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies, and meets separately with our senior reserves engineering personnel and our independent petroleum consultants at those meetings. The responsibilities of the Reserves Committee include the following:
•
approve the scope of and oversee an annual review and evaluation of our consolidated oil, gas and NGL reserves;
•
oversee the integrity of our reserves evaluation and reporting system;
•
oversee and evaluate, prepare and disclose our compliance with legal and regulatory requirements related to our oil, gas and NGL reserves;
•
review the qualifications and independence of our independent engineering consultants; and
•
monitor the performance of our independent engineering consultants.
Proved Oil, Natural Gas and NGL Reserves
The following table presents our estimated proved reserves by continent and for each significant country as of December 31, 2010. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 22 to our consolidated financial statements included in this report.
(1)
Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
No estimates of our proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of 2010 except in filings with the SEC and the Department of Energy (“DOE”). Reserve estimates filed with the SEC correspond with the estimates of our reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do not operate.
Proved Developed Reserves
As presented in the previous table, we had 2,042 MMBoe of proved developed reserves at December 31, 2010. Proved developed reserves consist of proved developed producing reserves and proved developed non-producing reserves. The following table provides additional information regarding our proved developed reserves at December 31, 2010.
(1)
Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
Proved Undeveloped Reserves
The following table presents the changes in our total proved undeveloped reserves during 2010 (in MMBoe).
At December 31, 2010, we had 831 MMBoe of proved undeveloped reserves. This represents a 2% increase as compared to 2009 and represents 29% of our total proved reserves. A large contributor to the increase was our 2010 drilling activities, which increased our proved undeveloped reserves 145 MMBoe. The divestiture of our Gulf of Mexico properties reduced our proved undeveloped reserves by 39 MMBoe.
As a result of 2010 development activities, we converted 91 MMBoe, or 11%, of the 2009 proved undeveloped reserves to proved developed reserves. This conversion rate implies a nine-year development cycle, which exceeds the five-year general guideline for recording proved undeveloped reserves. However, our
overall proved undeveloped conversion rate is largely impacted by the pace of development at Jackfish. Excluding our Jackfish reserves, our 2010 proved undeveloped conversion rate implies a development cycle that approximates five years.
At December 31, 2010 and 2009, our Jackfish proved undeveloped reserves were 396 MMBoe and 351 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their full capacity of 35,000 barrels of oil per day per facility. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves will remain classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2025. We have made significant funding commitments toward the development of the Jackfish reserves.
See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion of the contributions by project area of all changes to total proved reserves.
Proved Reserves Cash Flows
The following table presents estimated cash flow information related to our December 31, 2010 estimated proved reserves. Similar to reserves, the cash flow estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 22 to our consolidated financial statements included in this report.
(1)
Estimated pre-tax future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to depreciation, depletion and amortization, or to non-property related expenses such as debt service and income tax expense.
Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to December 31, 2010. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yielded average prices over the life of our properties of $59.94 per Bbl of oil, $3.73 per Mcf of gas and $31.11 per Bbl of NGLs. The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil, gas and NGL production subsequent to December 31, 2010. There can be no assurance that all of the proved reserves will be produced and sold within the periods
indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.
The present value of after-tax future net revenues discounted at 10% per annum (“standardized measure”) was $16.4 billion at the end of 2010. Included as part of standardized measure were discounted future income taxes of $6.1 billion. Excluding these taxes, the present value of our pre-tax future net revenue (“pre-tax 10% present value”) was $22.5 billion. We believe the pre-tax 10% present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10% present value assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors, which are more consistent from company to company. We also understand that securities analysts use the pre-tax 10% present value measure in similar ways.
(2)
See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Production, Production Prices and Production Costs
The following tables present our production and average sales prices by continent and for each significant field and country for the past three years.
(1)
Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
The following table presents our production cost per Boe by continent and for each significant field and country for the past three years. Production costs do not include ad valorem or severance taxes.
Drilling Activities and Results
The following tables summarize our development and exploratory drilling results for the past three years.
(1)
These well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests on the well.
The following table presents the results, as of February 1, 2011, of our wells that were in progress as of December 31, 2010.
(1)
Gross wells are the sum of all wells in which we own an interest.
(2)
Net wells are gross wells multiplied by our fractional working interests on the well.
Well Statistics
The following table sets forth our producing wells as of December 31, 2010.
(1)
Gross wells are the sum of all wells in which we own an interest.
(2)
Net wells are gross wells multiplied by our fractional working interests on the well.
Acreage Statistics
The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2010. The acreage in the table below includes 1.4 million, 0.5 million and 0.9 million net acres subject to leases that are scheduled to expire during 2011, 2012 and 2013, respectively.
(1)
Gross acres are the sum of all acres in which we own an interest.
(2)
Net acres are gross acres multiplied by our fractional working interests on the acreage.
Operation of Properties
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions.
We are the operator of 23,056 of our wells. As operator, we receive reimbursement for direct expenses incurred in the performance of our duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.
Title to Properties
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business.
As is customary in the industry, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, which generally include a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

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ITEM 3. LEGAL PROCEEDINGS
Item 3.
Legal Proceedings
We are involved in various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.

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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 2010.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5.
Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the New York Stock Exchange (the “NYSE”). On February 10, 2011, there were 12,704 holders of record of our common stock. The following table sets forth the quarterly high and low sales prices for our common stock as reported by the NYSE during 2010 and 2009. Also, included are the quarterly dividends per share paid during 2010 and 2009. We began paying regular quarterly cash dividends on our common stock in the second quarter of 1993. We anticipate continuing to pay regular quarterly dividends in the foreseeable future.
Performance Graph
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on Devon’s common stock with the cumulative total returns of the Standard & Poor’s 500 index (“the S&P 500 Index”) and the group of companies included in the Crude Petroleum and Natural Gas Standard Industrial Classification code (“the SIC Code”). The graph was prepared based on the following assumptions:
•
$100 was invested on December 31, 2005 in Devon’s common stock, the S&P 500 Index and the SIC Code, and
•
Dividends have been reinvested subsequent to the initial investment.
Comparison of 5-Year Cumulative Total Return
Devon, S&P 500 Index and SIC Code
The graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
Issuer Purchases of Equity Securities
The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2010. All purchases were part of publicly announced plans or programs.
(1)
In May 2010, our Board of Directors approved a $3.5 billion share repurchase program. This program expires December 31, 2011. As of December 31, 2010, we had repurchased 18.3 million common shares for $1.2 billion, or $65.58 per share under this program.
New York Stock Exchange Certifications
This Form 10-K includes as exhibits the certifications of our Chief Executive Officer and Chief Financial Officer, required to be filed with the SEC pursuant to Section 302 of the Sarbanes Oxley Act of 2002. We have also filed with the New York Stock Exchange the 2010 annual certification of our Chief Executive Officer confirming that we have complied with the New York Stock Exchange corporate governance listing standards.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6.
Selected Financial Data
The following selected financial information (not covered by the report of our independent registered public accounting firm) should be read in conjunction with “

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be reviewed in conjunction with our “Selected Financial Data” and “Financial Statements and Supplementary Data.” Our discussion and analysis relates to the following subjects:
•
Overview of Business
•
Overview of 2010 Results
•
Business and Industry Outlook
•
Results of Operations
•
Capital Resources, Uses and Liquidity
•
Contingencies and Legal Matters
•
Critical Accounting Policies and Estimates
•
Forward-Looking Estimates
Overview of Business
Devon is one of North America’s leading independent oil and gas exploration and production companies. Our operations are focused in the United States and Canada. We also own natural gas pipelines and treatment facilities in many of our producing areas, making us one of North America’s larger processors of natural gas liquids.
As an enterprise, we strive to optimize value for our shareholders by growing cash flows, earnings, production and reserves, all on a per debt-adjusted share basis. We accomplish this by replenishing our reserves and production and managing other key operational elements that drive our success. These items are discussed more fully below.
•
Reserves and production growth - Our financial condition and profitability are significantly affected by the amount of proved reserves we own. Oil and gas properties are our most significant assets, and the reserves that relate to such properties are key to our future success. To increase our proved reserves, we must replace quantities produced with additional reserves from successful exploration and development activities or property acquisitions. Additionally, our profitability and operating cash flows are largely dependent on the amount of oil, gas and NGLs we produce. Growing production from existing properties is difficult because the rate of production from oil and gas properties generally declines as reserves are depleted. As a result, we constantly drill for and develop reserves on properties that provide a balance of near-term and long-term production. In addition, we may acquire properties with proved reserves that we can develop and subsequently produce to help create value.
•
Capital investment discipline - Effectively deploying our resources into capital projects is key to maintaining and growing future production and oil and gas reserves. As a result, we have historically deployed virtually all our available cash flow into capital projects. Therefore, maintaining a disciplined approach to investing in capital projects is important to our profitability and financial condition. Our ability to control capital expenditures can be affected by changes in commodity prices. During times of high commodity prices, drilling and related costs often escalate due to the effects of supply versus demand economics. The inverse is also true.
•
High return projects - We seek to invest our capital resources into projects where we can generate the highest risk-adjusted investment returns. One factor that can have a significant impact on such returns is our drilling success. Combined with appropriate revenue and cost-management strategies,
high drilling success rates are important to generating competitive returns on our capital investment. During 2010, we drilled 1,588 gross wells and 99% of those were successful. This success rate is similar to our drilling achievements in recent years, demonstrating a proven track record of success. By accomplishing high drilling success rates, we provide an inventory of reserves growth and a platform of opportunities on our undrilled acreage that can be profitably developed.
•
Reserves and production balance - As evidenced by history, commodity prices are inherently volatile. In addition, oil and gas prices often diverge due to a variety of circumstances. Consequently, we value a balance of reserves and production between gas and liquids that can add stability to our revenue stream when either commodity price is under pressure. Our production mix in 2010 was approximately 68% gas and 32% oil and NGLs such as propane, butane and ethane. Our year-end reserves were approximately 60% gas and 40% liquids. With planned future growth in oil from Jackfish, Pike and other projects, combined with an inventory of shale natural gas plays, we expect to maintain this balance in the future.
•
Operating cost controls - To maintain our competitive position, we must control our lease operating costs and other production costs. As reservoirs are depleted and production rates decline, per unit production costs will generally increase and affect our profitability and operating cash flows. Similar to capital expenditures, our ability to control operating costs can be affected by significant changes in commodity prices. Our base production is focused in core areas of our operations where we can achieve economies of scale to help manage our operating costs.
•
Marketing and midstream performance improvement - We enhance the value of our oil and gas operations with our marketing and midstream business. By efficiently gathering and processing oil, gas and NGL production, our midstream operations enhance our project returns and contribute to our strategies to grow reserves and production and manage expenditures. Additionally, by effectively marketing our production, we maximize the prices received for our oil, gas and NGL production in relation to market prices. This is important because our profitability is highly dependent on market prices. These prices are determined primarily by market conditions. Market conditions for these products have been, and will continue to be, influenced by regional and worldwide economic and political conditions, weather, supply disruptions and other local market conditions that are beyond our control. To manage this volatility, we utilize financial hedging arrangements. As of February 10, 2011, approximately 29% of our 2011 gas production is associated with financial price swaps and fixed-price physicals. We also have basis swaps associated with 0.2 Bcf per day of our 2011 gas production. Additionally, approximately 36% of our 2011 oil production is associated with financial price collars. We also have call options that, if exercised, would relate to an additional 16% of our 2011 oil production.
•
Financial flexibility preservation - As mentioned, commodity prices have been and will continue to be volatile and will continue to impact our profitability and cash flow. We understand this fact and manage our debt levels accordingly to preserve our liquidity and financial flexibility. We generally operate within the cash flow generated by our operations. However, during periods of low commodity prices, we may use our balance sheet strength to access debt or equity markets, allowing us to preserve our business and maintain momentum until markets recover. When prices improve, we can utilize excess operating cash flow to repay debt and invest in our activities that not only maintain but also increase value per share.
Overview of 2010 Results
2010 was an outstanding year for Devon. We reported record net earnings and reserves and made significant progress on our offshore divestiture program announced in November 2009. We sold our properties in the Gulf of Mexico, Azerbaijan, China and other International regions, generating $5.6 billion in after-tax proceeds and after-tax gains of $1.7 billion. Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the
divestitures. Once the pending transactions are complete, we expect to have generated more than $8 billion in after-tax proceeds from all our divestitures.
These divestitures have allowed us to begin focusing entirely on our North American Onshore oil and natural gas portfolio. We grew North American Onshore production 1% in 2010 and replaced approximately 175% of our production with the drill bit at very attractive costs. The operational success we had with the drill bit increased our reserves to 2,873 MMBoe, the highest level in our history.
While our total North American Onshore production grew 1% in 2010, our oil and NGL production increased 6% over 2009. Liquids prices began to stabilize in 2009 and continued to strengthen throughout 2010. Although our realized price for gas increased 17% in 2010, gas prices continue to be weak. Considering the current and expected trends in commodity pricing, we have leveraged the value of our balanced portfolio and shifted capital spending toward the more profitable liquids-rich development opportunities currently available to us. The performance of these assets and higher price realizations are reflected in the 2010 earnings increase.
Key measures of our performance for 2010, as well as certain operational developments, are summarized below:
•
North America Onshore oil and NGL production grew 6% over 2009, to 71 million Boe.
•
North American Onshore gas production decreased 1% compared with 2009, to 152 million Boe.
•
The combined realized price for oil, gas and NGLs per Boe increased 22% to $31.91.
•
Oil, gas and NGL derivatives generated net gains of $811 million in 2010, including cash receipts of $888 million.
•
Per unit lease operating costs increased 4% to $7.42 per Boe.
•
Operating cash flow increased to $5.5 billion, representing a 16% increase over 2009.
•
Capitalized costs incurred in our oil and gas activities were $6.5 billion in 2010. This includes $1.2 billion for unproved acreage acquisitions.
•
Reserves increased to 2,873 MMBoe, an all-time high.
From an operational perspective, we completed another successful year with the drill-bit. We drilled 1,584 gross wells on our North America Onshore properties with a 99% success rate and grew our related proved reserves 9%.
During 2010, we more than doubled our industry-leading leasehold position in the liquids-rich Cana-Woodford shale play in western Oklahoma to more than 240,000 net acres. This allowed us to grow production more than 210% from the end of 2009 to the end of 2010. As a result of the success of our drilling and development efforts in the Cana-Woodford shale, we also constructed a gas processing plant in 2010.
In the Barnett Shale, we exited 2010 with production of 1.2 Bcfe per day, which includes 43 MBbls per day of liquids production. This represents a 16% increase in total production compared to the 2009 exit rate.
In the Permian Basin, we continued to assemble additional liquids-rich acreage. By the end of 2010, we had approximately one million net acres on liquids-rich development opportunities which led to an increase in production of 16% from the end of 2009 to the end of 2010.
Our net production from our Jackfish oil sands project in Canada averaged 25 MBbls per day. Jackfish continues to be one of Canada’s most successful steam-assisted gravity drainage projects. Construction of our second Jackfish project is now complete. We expect to have first oil production by the end of 2011. Additionally, we applied for regulatory approval of a third phase of Jackfish in 2010.
During 2010, we used a portion of our offshore divestiture proceeds to invest $1.2 billion in unproved leasehold acquisition focused on oil and liquids-rich gas plays. Our most significant single investment was our $500 million acquisition of a 50% interest in the Pike oil sands. The Pike acreage lies immediately adjacent to
the Jackfish project. We began appraisal drilling at Pike near the end of 2010 and are acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development. We expect to begin the regulatory application process for the first Pike phase around the end of 2011.
Our performance and offshore divestiture success throughout 2010 enabled us to end the year with a robust level of liquidity. At the end of 2010, we had $3.4 billion of cash and short-term investments and $2.6 billion of available credit.
Business and Industry Outlook
Even though we possess a great deal of financial strength and flexibility, we are fully committed to exercising capital discipline, maximizing profits, maintaining balance sheet strength and optimizing growth per debt-adjusted share. Our portfolio of assets provides a great deal of investment flexibility. At the end of 2010, our proved reserves were comprised of approximately 60% gas and 40% liquids. While gas prices remain challenged in the market, our near-term focus is on the oil and liquids-rich opportunities that exist within our balanced portfolio of properties. As a result, the vast majority of our 2011 drilling activity will be centered on our oil and liquids-rich gas properties. Should the outlook for commodity prices change, we have the flexibility to redirect our capital to ensure we continually focus on the highest-return assets in our portfolio.
Our ability to leverage the depth and breadth of our existing portfolio of properties will be key to the successful execution of our growth and value-creation objectives. With 2.9 billion Boe of proved reserves at the end of 2010, our North American onshore assets will provide many years of visible, economic growth and a good balance between liquids and natural gas. In 2011, we are targeting a 6-8% production increase. However, we expect this growth will be driven by oil and NGLs growth of at least 16%. Additionally, we will continue to use a portion of our offshore divestiture proceeds to repurchase common stock under our $3.5 billion share repurchase program. Therefore, our 2011 production growth will be even higher on a per debt-adjusted share basis.
Results of Operations
As previously stated, we are in the process of divesting our offshore assets. As a result, all amounts in this document related to our International operations are presented as discontinued. Therefore, the production, revenue and expense amounts presented in this “Results of Operations” section exclude amounts related to our International assets unless otherwise noted.
Even though we have divested our U.S. Offshore operations, these properties do not qualify as discontinued operations under accounting rules. As such, financial and operating data provided in this document that pertain to our continuing operations include amounts related to our U.S. Offshore operations. To facilitate comparisons of our ongoing operations subsequent to the planned divestitures, we have presented amounts related to our U.S. Offshore assets separate from those of our North American Onshore assets where appropriate.
Revenues
Our oil, gas and NGL production volumes are shown in the following table.
(1)
Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL volumes are converted to Boe on a one-to-one basis with oil.
(2)
All percentage changes included in this table are based on actual figures and not the rounded figures included in the table.
The following table presents the prices we realized on our production volumes. These prices exclude any effects due to our oil, gas and NGL derivatives.
(1)
Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL volumes are converted to Boe on a one-to-one basis with oil.
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between 2008 and 2010.
Oil Sales
2010 vs. 2009 Oil sales increased $557 million as a result of a 27% increase in our realized price. The largest contributor to the increase in our realized price was the increase in the average NYMEX West Texas Intermediate index price over the same time period.
Oil sales decreased $67 million due to a three percent decrease in production. The decrease was comprised of the net effects of a 62% decrease in our U.S. Offshore production and a five percent increase in our North America Onshore production. The decrease in our U.S. Offshore production was primarily due to the divestiture of such properties in the second quarter of 2010. The increased North America Onshore production resulted primarily from continued development of our Permian Basin properties in Texas and our Jackfish thermal heavy oil project in Canada.
2009 vs. 2008 Oil sales decreased $1.3 billion as a result of a 38% decrease in our realized price without hedges. The largest contributor to the decrease in our realized price was the decrease in the average NYMEX West Texas Intermediate index price over the same time period.
Oil sales increased $258 million due to a three million barrel, or 8%, increase in production. The increased production resulted primarily from the continued development of Jackfish in Canada.
Gas Sales
2010 vs. 2009 Gas sales increased $497 million as a result of a 16% increase in our realized price without hedges. This increase was largely due to increases in the North American regional index prices upon which our gas sales are based.
A four percent decrease in production during 2010 caused gas sales to decrease by $122 million. The decrease was primarily due to the divestiture of our U.S. Offshore properties in the second quarter of 2010, as well as higher Canadian government royalties. Also, our other North America Onshore properties decreased one percent due to reduced drilling during most of 2009 in response to lower gas prices. As a result of the reduced drilling activities during 2009, natural declines of existing wells outpaced production gains from new drilling in 2010.
2009 vs. 2008 Gas sales decreased $4.3 billion as a result of a 57% decrease in our realized price without hedges. This decrease was largely due to decreases in the North American regional index prices upon which our gas sales are based.
A three percent increase in production during 2009 caused gas sales to increase by $222 million. Our North America Onshore properties contributed 40 Bcf of higher volumes. This increase included 25 Bcf of higher production in Canada due to a decline in Canadian government royalties, resulting largely from lower gas prices. The remainder of the North America Onshore growth resulted from new drilling and development that exceeded natural production declines, primarily in the Barnett Shale field in north Texas. These increases were partially offset by 12 Bcf of lower production from our U.S. Offshore properties, largely resulting from natural production declines.
NGL Sales
2010 vs. 2009 NGL sales increased $254 million during 2010 as a result of a 32% increase in our realized price. The increase was largely due to an increase in the Mont Belvieu, Texas index price over the same time period. NGL sales increased $46 million in 2010 due to a six percent increase in production. The increase in production was primarily due to increased drilling in North America Onshore areas that have liquids-rich gas.
2009 vs. 2008 NGL sales decreased $585 million as a result of a 44% decrease in our realized price. This decrease was largely due to a decrease in the Mont Belvieu, Texas index price over the same time period. NGL sales increased $89 million in 2009 due to a seven percent increase in production. The increase in production is primarily due to drilling and development in the Barnett Shale.
Oil, Gas and NGL Derivatives
The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and unrealized gains and losses recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of unrealized gains and losses.
Our oil, gas, and NGL derivatives include price swaps, costless collars and basis swaps. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty. For the basis swaps, we receive a fixed differential between two index prices and pay a variable differential on the same two index prices to the contract counterparty. Cash settlements presented in the tables above represent net realized gains or losses related to these various instruments.
Additionally, to facilitate a portion of our price swaps, we have sold gas call options for 2012 and oil call options for 2011 and 2012. The call options give the counterparty the right to place us into a price swap at a predetermined fixed price. The terms of these call options are presented in “

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable for several years. See “Item 1A. Risk Factors.” Consequently, we periodically enter into financial hedging activities with respect to a portion of our oil, gas and NGL production through various financial transactions that hedge the future prices received. These transactions include financial price swaps, basis swaps and costless price collars. Additionally, to facilitate a portion of our price swaps, we have sold gas
call options for 2012 and oil call options for 2011 and 2012. The key terms of our derivatives in place as of December 31, 2010 are presented in the following tables.
Gas Price Swaps
Weighted
Volume
Average Price
Period
(MMBtu/d)
($/MMBtu)
Total year 2011
712,500
$
5.51
The fair values of our commodity derivatives presented in the tables above are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2010, a 10% increase in the forward curves associated with our gas derivative instruments would have decreased the fair value of such instruments by approximately $154 million. A 10% increase in the forward curves associated with our oil derivative instruments would have decreased the fair value of these instruments by approximately $142 million.
Interest Rate Risk
At December 31, 2010, we had debt outstanding of $5.6 billion with fixed rates averaging 7.1%.
As of December 31, 2010, our interest rate swaps consisted of instruments with a total notional amount of $2.1 billion. These consist of instruments with a notional amount of $1.15 billion in which we receive a fixed rate and pay a variable rate. The remaining instruments consist of forward starting swaps. Under the terms of the forward starting swaps, we will net settle these contracts in September 2011, or sooner should we
elect. The net settlement amount will be based upon us paying a weighted-average fixed rate of 3.92% and receiving a floating rate that is based upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to the notional amount for the 30-year period from September 30, 2011 to September 30, 2041. The key terms of these contracts are presented in the following tables.
The fair values of our interest rate instruments are largely determined by estimates of the forward curves of the Federal Funds rate and LIBOR. At December 31, 2010, a 10% increase in these forward curves would have increased the fair value of our interest rate swaps by approximately $68 million.
Foreign Currency Risk
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our December 31, 2010 balance sheet.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8.
Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2010 and 2009
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Comprehensive Earnings (Loss) for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008
Notes to Consolidated Financial Statements
All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, comprehensive earnings (loss), stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2010. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Devon Energy Corporation’s 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, included in Management’s Annual Report contained in “Item 9A. Controls and Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K. 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 opinions.
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 Devon Energy Corporation and subsidiaries as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
KPMG LLP
Oklahoma City, Oklahoma
February 23, 2011
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (LOSS)
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Accounting policies used by Devon Energy Corporation and subsidiaries (“Devon”) reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such policies are discussed below.
Nature of Business and Principles of Consolidation
Devon is engaged primarily in the acquisition, exploration, development and production of oil and gas properties. Such activities are concentrated in the following North American onshore geographic areas:
•
the Mid-Continent area of the central and southern United States, principally in north and east Texas, as well as Oklahoma;
•
the Permian Basin within Texas and New Mexico;
•
the Rocky Mountains area of the United States stretching from the Canadian border into northern New Mexico;
•
the onshore areas of the Gulf Coast, principally in south Texas and south Louisiana; and
•
the provinces of Alberta, British Columbia and Saskatchewan in Canada.
In November 2009, Devon announced plans to strategically reposition itself as a North American onshore exploration and development company. During 2010, Devon divested its properties in the Gulf of Mexico, Azerbaijan, China and other International regions. Additionally, Devon has entered into agreements to sell its remaining offshore assets in Brazil and Angola. These activities are more fully described in Note 5.
Devon also has marketing and midstream operations that perform various activities to support the oil and gas operations of Devon and unrelated third parties. Such activities include marketing gas, crude oil and NGLs, as well as constructing and operating pipelines, storage and treating facilities and natural gas processing plants.
The accounts of Devon’s controlled subsidiaries are included in the accompanying consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
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 net revenues;
•
the carrying value of oil and gas properties;
•
estimates of the fair value of reporting units and related assessment of goodwill for impairment;
•
derivative financial instruments;
•
income taxes;
•
asset retirement obligations;
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
•
obligations related to employee pension and postretirement benefits; and
•
legal and environmental risks and exposures.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not hold or issue derivative financial instruments for speculative trading purposes. Besides these derivative instruments, Devon also had an embedded option derivative related to the fair value of its debentures exchangeable into shares of Chevron common stock. Devon ceased to have this option when the exchangeable debentures matured on August 15, 2008.
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon’s derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional gas index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. Under the terms of a call option, Devon received a cash premium for selling call options. The call options then give the counterparty the right to place us into a price swap at a predetermined fixed price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon’s interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount. Devon also has forward starting swaps. Under the terms of the forward starting swaps, Devon will net settle these contracts in September 2011 or sooner should Devon elect. The net settlement amount will be based upon Devon paying a fixed rate and receiving a floating rate that is based upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to the notional amount for the 30-year period from September 30, 2011 to September 30, 2041.
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in the statement of operations unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2010, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties to Devon’s derivative financial instruments are also recorded in the statement of operations.
By using derivative financial instruments to hedge exposures to changes in commodity prices and interest rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are minimal credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
our contracts. As of December 31, 2010, the credit ratings of all Devon’s counterparties were investment grade.
Market risk is the change in the value of a derivative financial instrument that results from a change in commodity prices, interest rates or other relevant underlyings. The market risks associated with commodity price and interest rate contracts are managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The oil and gas reference prices upon which the commodity instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon.
See Note 3 for the amounts included in Devon’s accompanying consolidated balance sheets and consolidated statements of operations associated with its derivative financial instruments.
Fair Value Measurements
Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price”.
Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 measurements are based on inputs other than quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active. Level 3 measurements have the lowest priority and are based upon inputs that are not observable from objective sources. The most common Level 3 fair value measurement is an internally developed cash flow model. Devon uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
See Note 11 for fair value measurements included in Devon’s accompanying consolidated balance sheets.
Discontinued Operations
As a result of the November 2009 plan to divest Devon’s offshore assets, all amounts related to Devon’s International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying consolidated financial statements that pertain to continuing operations include amounts related to Devon’s offshore Gulf of Mexico operations. See Note 5 for additional details of the offshore divestiture program.
The captions assets held for sale and liabilities associated with assets held for sale in the accompanying consolidated balance sheets present the assets and liabilities associated with Devon’s discontinued operations. Devon measures its assets held for sale at the lower of its carrying amount or estimated fair value less costs to sell. Additionally, Devon does not recognize depreciation, depletion and amortization on its long-lived assets held for sale.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net revenues, discounted at 10% per annum, from proved oil, gas and NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties. Such limitations are imposed separately on a country-by-country basis and are tested quarterly.
Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prior to December 31, 2009, prices and costs used to calculate future net revenues were those as of the end of the appropriate quarterly period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2010 qualified for hedge accounting treatment.
Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to five years.
No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.
Depreciation of midstream pipelines are provided on a unit-of-production basis. Depreciation and amortization of other property and equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 39 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The asset retirement cost is
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
depreciated using a systematic and rational method similar to that used for the associated property and equipment.
Investments
Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity.
Devon’s primary investments consist of auction rate securities that totaled $94 million and $115 million at December 31, 2010 and 2009, respectively. These securities are rated AAA - the highest rating - by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. Although Devon’s auction rate securities generally have contractual maturities of more than 20 years, the underlying interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities were generally priced and subsequently traded as short-term investments because of the interest rate reset feature.
Since February 8, 2008, Devon has experienced difficulty selling its securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature.
From February 2008, when auctions began failing, to December 31, 2010, issuers have redeemed $58 million of Devon’s auction rate securities holdings at par. However, based on continued auction failures and the current market for Devon’s auction rate securities, Devon has classified its auction rate securities as long-term investments as of December 31, 2010. These securities are included in other long-term assets in the accompanying consolidated balance sheet. Devon has the ability to hold the securities until maturity. At this time, Devon does not believe the values of its long-term securities are impaired.
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
Devon performed annual impairment tests of goodwill in the fourth quarters of 2010, 2009 and 2008. Based on these assessments, no impairment of goodwill was required.
The table below provides a summary of Devon’s goodwill, by assigned reporting unit, as of December 31, 2010 and 2009. The increase in Devon’s continuing operations goodwill from 2009 to 2010 is due to changes in the exchange rate between the U.S. dollar and the Canadian dollar. Devon removed all its International goodwill in conjunction with the Azerbaijan divestiture that closed in 2010. Such goodwill was presented in long-term assets held for sale in the accompanying December 31, 2009 consolidated balance sheet.
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Foreign Currency Translation Adjustments
The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Therefore, the assets and liabilities of Devon’s Canadian subsidiaries are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity. The following table presents the balances of Devon’s cumulative translation adjustments included in accumulated other comprehensive earnings (in millions).
December 31, 2007
$
2,566
December 31, 2008
$
December 31, 2009
$
1,616
December 31, 2010
$
1,993
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment. Reference is made to Note 10 for a discussion of amounts recorded for these liabilities.
Revenue Recognition and Gas Balancing
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck or a tanker lifting has occurred. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated statements of operations.
Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is priced based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells’ reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
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Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
During 2010, 2009 and 2008, no purchaser accounted for more than 10% of Devon’s revenues from continuing operations.
General and Administrative Expenses
General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Share Based Compensation
Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are recognized as a component of general and administrative expenses in the accompanying statements of operations over the applicable requisite service periods. As a result of Devon’s strategic repositioning announced in 2009, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying 2010 and 2009 statements of operations.
Generally, Devon uses new shares to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share based awards. However, Devon has historically cancelled these shares upon repurchase.
Income Taxes
Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the United States and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Devon does not recognize United States deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Devon recognizes the appropriate deferred income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
expense. Additional information regarding Devon’s unrecognized tax benefits, including changes in such amounts during 2010 and 2009, is provided in Note 17.
Net Earnings (Loss) Per Common Share
Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the potential dilution that could occur if Devon’s dilutive outstanding stock options were exercised.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
2.
Accounts Receivable
The components of accounts receivable include the following:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
3.
Derivative Financial Instruments
The following table presents the derivative fair values included in the accompanying consolidated balance sheets. Devon has elected not to designate any of its derivative instruments for hedge accounting treatment.
The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying consolidated statements of operations associated with these derivative financial instruments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
4.
Other Current Assets
The components of other current assets include the following:
5.
Property and Equipment
Property and equipment consists of the following:
The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2010.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Offshore Divestitures
In November 2009, Devon announced plans to reposition itself strategically as a North America onshore exploration and production company. As part of this strategic repositioning, Devon is bringing forward the value of its offshore assets by divesting them.
Closed Transactions
The following table presents Devon’s offshore divestiture transactions that closed in 2010. Gross proceeds represent contract prices based upon a January 1, 2010 effective date for the Gulf of Mexico and Azerbaijan divestitures, a May 1, 2010 effective date for the China - Panyu divestiture and a September 1, 2010 effective date for the China-Exploration divestiture. After-tax proceeds represent gross proceeds adjusted for customary purchase price adjustments, selling costs and income taxes. The purchase price adjustments consist primarily of net cash flow subsequent to the effective date of the divestitures. Proved reserves in the following table are based upon estimated proved reserves as of the divestiture dates.
Proceeds from these divestitures are being used to retire debt and repurchase Devon common shares. Additionally, Devon is using divestiture proceeds to fund North America Onshore exploration and development opportunities, including a joint-venture investment in the Pike oil sands discussed below.
Under full cost accounting rules, sales or other dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of gain or loss. However, if not recognizing a gain or loss on the disposition would otherwise significantly alter the relationship between a cost center’s capitalized costs and proved reserves, then a gain or loss must be recognized.
The Gulf of Mexico divestitures presented above did not significantly alter such relationship for Devon’s United States cost center. Therefore, Devon did not recognize a gain in connection with the Gulf of Mexico divestitures. The Azerbaijan divestiture included all of Devon’s properties in its Azerbaijan cost center. As a result, Devon recognized a $1,543 million ($1,524 million after-tax) gain during 2010 in connection with the Azerbaijan divestiture. Panyu was Devon’s only producing property in its China cost center. As a result, Devon recognized a $308 million ($235 million after-tax) gain in connection with the Panyu divestiture in 2010. These gains are included in “earnings from discontinued operations” in the accompanying 2010 consolidated statement of operations.
Pending Transactions
Devon has entered into agreements to sell its remaining offshore assets in Brazil and Angola and is waiting for the respective governments to approve the divestitures. The Brazil divestiture is valued at $3.2 billion, and Devon expects to record a gain upon the close of this transaction. For the Angola divestiture, Devon will receive $70 million at closing, and has the potential to receive future consideration that is contingent upon the buyer achieving certain milestones.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Deepwater Drilling Rigs
As part of its offshore operations, Devon was leasing three deepwater drilling rigs. The Seadrill West Sirius and Ocean Endeavor deepwater drilling rigs were used in Devon’s Gulf of Mexico operations. The Transocean Deepwater Discovery is currently being used in Devon’s operations in Brazil.
In conjunction with the deepwater Gulf of Mexico divestiture that closed in the second quarter of 2010, the buyer assumed Devon’s lease and remaining commitments for the Seadrill West Sirius rig. Subsequent to closing all its Gulf of Mexico divestitures, Devon agreed to pay $31 million to the owner of the Ocean Endeavor rig to terminate the lease. The $31 million lease termination cost is included in oil and gas property and equipment in the accompanying December 31, 2010, consolidated balance sheet. The buyer of Devon’s assets in Brazil will assume Devon’s lease and remaining commitments for the Transocean Deepwater Discovery rig when the divestiture transaction closes.
Oil Sands Joint Venture
In conjunction with certain offshore divestitures in the second quarter of 2010, Devon formed a heavy oil joint venture to operate and develop the Pike oil sands leases in Alberta, Canada. As a result, Devon acquired a 50 percent interest in the Pike oil sands leases for $500 million. Devon will also fund $155 million of Canadian dollar capital costs on behalf of its joint-venture partner in the form of a non-interest bearing promissory note. The majority of the capital costs are expected to be paid during 2011 and 2012. See Note 6 for more information regarding the promissory note.
Reductions of Carrying Value
In the first quarter of 2009 and the fourth quarter of 2008, Devon reduced the carrying values of its oil and gas properties due to full cost ceiling limitations. These reductions are discussed in Note 15.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
6.
Debt and Related Expenses
A summary of Devon’s debt is as follows:
Debt maturities as of December 31, 2010, excluding premiums and discounts, are as follows (in millions):
Credit Lines
Devon has a $2,650 million syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The maturity date for $2,187 million of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $463 million is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $500 million.
Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears. As of December 31, 2010, there were no borrowings under the Senior Credit Facility.
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The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2010, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at December 31, 2010, as calculated pursuant to the terms of the agreement, was 15.1%.
The following schedule summarizes the capacity of Devon’s Senior Credit Facility by maturity date, as well as its available capacity as of December 31, 2010 (in millions).
Commercial Paper
Devon also has access to approximately $2,200 million of short-term credit under its commercial paper program. Any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between one and 90 days, although it can have a maturity of up to 365 days, and bears 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.
During the first half of 2010, Devon repaid $1,432 million of commercial paper borrowings primarily with proceeds received from its Gulf of Mexico property divestitures. At December 31, 2010, Devon had no outstanding commercial paper borrowings. The average borrowing rate for Devon’s $1,432 million of commercial paper borrowings at December 31, 2009 was 0.29%.
$350 Million 7.25% Senior Notes Due October 1,
On June 25, 2010, Devon redeemed $350 million of 7.25% senior notes prior to their scheduled maturity of October 1, 2011, primarily with proceeds received from its Gulf of Mexico divestitures. The notes were redeemed for $384 million, which represented 100 percent of the principal amount, a make-whole premium of $28 million and $6 million of accrued and unpaid interest. On the date of redemption, these notes also had an unamortized premium of $9 million. The $28 million make-whole premium and $9 million amortization of the remaining premium are included in interest expense in the accompanying 2010 consolidated statements of operations.
Non-Interest Bearing Promissory Note Due June 29, 2014
On June 29, 2010, Devon issued a four-year $155 million Canadian dollar non-interest bearing promissory note in connection with the formation of the Pike oil sands joint venture described in Note 5. The present value of the note was $139 million on the issue date based upon an effective interest rate of 3.125%. At
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
December 31, 2010, the note had a carrying value of $144 million, of which $62 million is presented as short-term debt and the remainder is presented as long-term debt in the accompanying consolidated balance sheet.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2010, as listed in the table presented at the beginning of this note.
6.875% Notes due September 30, 2011 and 7.875% Debentures due September 30, 2031
On October 3, 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), a wholly-owned finance subsidiary, sold these notes and debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed on an unsecured and unsubordinated basis the obligations of Devon Financing under the debt securities. The proceeds from the issuance of these debt securities were used to fund a portion of the acquisition of Anderson Exploration.
5.625% Notes due January 15, 2014 and 6.30% Notes due January 15, 2019
On January 9, 2009, Devon sold these notes, which are unsecured and unsubordinated obligations of Devon. The net proceeds from issuance of this debt were used primarily to repay Devon’s outstanding commercial paper as of December 31, 2008.
Ocean Debt
As a result of the April 25, 2003 merger with Ocean Energy, Inc., Devon assumed certain debt instruments that remain outstanding at December 31, 2010. The table below summarizes the debt assumed, the fair value of the debt at April 25, 2003, and the effective interest rate of the debt assumed after determining the fair values of the respective notes using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. All of the notes are general unsecured obligations of Devon.
7.95% Notes due April 15, 2032
On March 25, 2002, Devon sold these notes, which are unsecured and unsubordinated obligations of Devon. The net proceeds received, after discounts and issuance costs, were $986 million and were used to retire other indebtedness.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Interest Expense
The following schedule includes the components of interest expense.
7.
Asset Retirement Obligations
The schedule below summarizes changes in Devon’s asset retirement obligations.
During 2010 and 2009, Devon recognized revisions to its asset retirement obligations totaling $194 million and $33 million, respectively. The primary factors causing the 2010 and 2009 increases were an overall increase in abandonment cost estimates and a decrease in the discount rate used to present value the obligations.
During 2010, Devon reduced its asset retirement obligations by $269 million primarily for those obligations that were assumed by purchasers of Devon’s Gulf of Mexico oil and gas properties.
8.
Retirement Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans (“Qualified Plans”) and nonqualified plans (“Supplemental Plans”). The Qualified Plans provide retirement benefits for certain U.S. and Canadian employees meeting certain age and service requirements. Benefits for the Qualified Plans are based on the employees’ years of service and compensation and are funded from assets held in the plans’ trusts.
The Supplemental Plans provide retirement benefits for certain employees whose benefits under the Qualified Plans are limited by income tax regulations. The Supplemental Plans’ benefits are based on the employees’ years of service and compensation. For certain Supplemental Plans, Devon has established trusts to
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
fund these plans’ benefit obligations. The total value of these trusts was $36 million and $39 million at December 31, 2010 and 2009, respectively, and is included in other long-term assets in the accompanying consolidated balance sheets. For the remaining Supplemental Plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.
Devon also has defined benefit postretirement plans (“Postretirement Plans”) that provide benefits for substantially all U.S. employees. The Postretirement Plans provide medical and, in some cases, life insurance benefits and are, depending on the type of plan, either contributory or non-contributory. Benefit obligations for the Postretirement Plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the Postretirement Plans is to fund the benefits as they become payable with available cash and cash equivalents.
Benefit Obligations and Funded Status
The following table presents the status of Devon’s pension and other postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans at December 31, 2010 and 2009 was $1,010 million and $873 million, respectively. Devon’s benefit obligations and plan assets are measured each year as of December 31.
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The plan assets for pension benefits in the table above exclude the assets held in trusts for the Supplemental Plans. However, employer contributions for pension benefits in the table above include $8 million and $9 million for 2010 and 2009, respectively, which were transferred from the trusts established for the Supplemental Plans.
Certain of Devon’s pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2010 and 2009 as presented in the table below.
The plan assets included in the above table exclude the Supplemental Plan trusts, which had a total value of $36 million and $39 million at December 31, 2010 and 2009, respectively.
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Net Periodic Benefit Cost and Other Comprehensive Earnings
The following table presents the components of net periodic benefit cost and other comprehensive earnings for Devon’s pension and other postretirement benefit plans.
The following table presents the estimated net actuarial loss and prior service cost for the pension and other postretirement plans that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2011.
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Assumptions
The following table presents the weighted average actuarial assumptions that were used to determine benefit obligations and net periodic benefit costs.
Discount rate - Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. High quality corporate bond yield indices are considered when selecting the discount rate.
Rate of compensation increase - For measurement of the 2010 benefit obligation for the pension plans, the 6.94% compensation increase in the table above represents the assumed increase through 2011. The rate was assumed to decrease to 5% in the year 2012 and remain at that level thereafter.
Expected return on plan assets - The expected rate of return on plan assets was determined by evaluating input from external consultants and economists as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types in such assets. See plan assets discussion below for more information on Devon’s target allocations.
Other assumptions - For measurement of the 2010 benefit obligation for the other postretirement medical plans, an 8.3% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have the following effects on the December 31, 2010 other postretirement benefits obligation and the 2011 service and interest cost components of net periodic benefit cost.
Pension Plan Assets
Devon’s overall investment objective for its pension plans’ assets is to achieve long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing.
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The vast majority of Devon’s plan assets are invested in diversified asset types to generate long-term growth and income. The remaining plan assets, generally less than 5%, are invested in assets that can be used for near-term benefit payments. Derivatives or other speculative investments considered high risk are generally prohibited.
At the end of 2010 and 2009, Devon’s target allocations for plan assets were 47.5% for equity securities, 40% for fixed-income securities and 12.5% for other investment types. The fair values of Devon’s pension assets at December 31, 2010 and 2009 are presented by asset class in the following tables.
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The following methods and assumptions were used to estimate the fair values of the assets in the tables above.
Equity securities - Devon’s equity securities consist of investments in United States large and small capitalization companies and international large capitalization companies. These equity securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.
Devon’s equity securities also include commingled funds that invest in large capitalization companies. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.
Fixed-income securities - Devon’s fixed-income securities consist of bonds issued by investment-grade companies from diverse industries, United States Treasury obligations and asset-backed securities. Devon’s fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.
Other securities - Devon’s other securities include commingled, short-term investment funds. These securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.
Devon’s other securities also include a hedge fund of funds that invests both long and short using a variety of investment strategies. Management of the hedge fund has the ability to shift investments from value to growth strategies, from small to large capitalization stocks, and from a net long position to a net short position. Devon’s hedge fund is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.
Included below is a summary of the changes in Devon’s Level 3 plan assets.
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Expected Cash Flows
The following table presents expected cash flow information for Devon’s pension and other postretirement benefit plans.
Expected contributions included in the table above include amounts related to Devon’s Qualified Plans, Supplemental Plans and Postretirement Plans. Of the benefits expected to be paid in 2011, $9 million of pension benefits is expected to be funded from the trusts established for the Supplemental Plans and all $4 million of other postretirement benefits is expected to be funded from Devon’s available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.
Other Benefit Plans
Devon’s 401(k) Plan covers all its employees in the United States. At its discretion, Devon may match a certain percentage of the employees’ contributions to the plan. The matching percentage is determined annually by the Board of Directors.
Devon also has an enhanced defined contribution structure related to its 401(k) Plan. Participants who elected to participate in this enhanced defined contribution structure when it was established, as well as all employees hired after the enhanced defined contribution structure was established, receive a discretionary match of a percentage of their contributions to the 401(k) Plan. The participants also receive additional, nondiscretionary contributions by Devon calculated as a percentage of annual compensation. The percentage will vary based on the employees’ years of service.
Devon has defined contribution pension plans for its Canadian employees. Devon makes a contribution to each employee that is based upon the employee’s base compensation and classification. Such contributions are subject to maximum amounts allowed under the Income Tax Act (Canada). Devon also has a savings plan for its Canadian employees. Under the savings plan, Devon contributes a base percentage amount to all employees and the employee may elect to contribute an additional percentage amount (up to a maximum amount) which is matched by additional Devon contributions.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table presents Devon’s expense related to these defined contribution plans.
9.
Stockholders’ Equity
The authorized capital stock of Devon consists of 1 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Devon’s Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”). At December 31, 2010, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share on all matters submitted to a vote of the stockholders. The Corporation, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of the Common Stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.
Stock Repurchases
During 2010, Devon’s Board of Directors announced a share repurchase program that authorizes the repurchase of up to $3,500 million of its common shares. This program, which expires December 31, 2011, was created as a result of the success experienced from the offshore divestiture program described in Note 5.
During 2008, Devon’s Board of Directors approved an ongoing, annual stock repurchase program to minimize dilution resulting from restricted stock issued to, and options exercised by, employees. Also, Devon’s Board of Directors approved a program in 2007 to repurchase up to 50 million shares. This program was created as a potential use of the proceeds received from Devon’s West African property divestitures. Both of these plans expired on December 31, 2009.
The following table summarizes Devon’s repurchases under approved plans (amounts and shares in millions).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Preferred Stock Redemption
On June 20, 2008, Devon redeemed all 1.5 million outstanding shares of its 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.
Dividends
Devon paid common stock dividends of $281 million (or $0.64 per share) in 2010 and $284 million (or $0.64 per share) in both 2009 and 2008, respectively. Devon paid dividends of $5 million in 2008 to preferred stockholders.
10.
Commitments and Contingencies
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals although actual amounts could differ materially from management’s estimate.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured costs associated with remediation. Devon’s monetary exposure for environmental matters is not expected to be material.
Royalty Matters
Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates, which resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold from federal and Indian owned or controlled lands. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
Commitments
The following is a schedule by year of purchase obligations, future minimum payments for drilling and facility obligations, firm transportation agreements and leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2010. The schedule includes separate amounts for Devon’s continuing and discontinued operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Devon has certain purchase obligations related to its heavy oil projects in Canada to purchase condensate at market prices. Devon entered into these agreements because the condensate is an integral part of the heavy oil production process and any disruption in Devon’s ability to obtain condensate could negatively affect its ability to produce and transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of these purchase obligations presented in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.
Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. Included in the discontinued operations obligations are amounts related to a long-term contract for a deepwater drilling rig being used in Brazil. Devon’s lease and remaining commitments for this rig will be assumed by the buyer of its assets in Brazil when the associated divestiture transaction closes.
Devon has certain firm transportation agreements that represent “ship or pay” arrangements whereby Devon has committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. Devon has entered into these agreements to aid the movement of its production to market. Devon expects to have sufficient production to utilize these transportation services.
Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in general and administrative expenses under operating leases, net of sub-lease income, was $57 million, $56 million and $44 million in 2010, 2009 and 2008, respectively.
Devon has a floating, production, storage and offloading facility (“FPSO”) that is being used in the Polvo project offshore Brazil and is being leased under operating lease arrangements. This lease will be assumed by the buyer when the associated divestiture transaction closes. However, the amounts in the table above reflect Devon’s full commitments under the lease. Total rental expense included in lease operating expenses for Devon’s FPSO’s was $25 million, $36 million and $25 million in 2010, 2009 and 2008, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
11.
Fair Value Measurements
Certain of Devon’s assets and liabilities are reported at fair value in the accompanying consolidated balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The following tables provide carrying value and fair value measurement information for Devon’s financial assets and liabilities.
The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes payable and other accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 2010 and 2009. These assets and liabilities are not presented in the following tables.
Information regarding the fair values of Devon’s pension plan assets is provided in Note 8.
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above.
Level 1 Fair Value Measurements
Debt - The fair value of Devon’s variable-rate commercial paper borrowings is the carrying value.
Short-term investments - Devon’s short-term investments consist entirely of United States Treasury bills with maturities over 90 days.
Level 2 Fair Value Measurements
Commodity derivatives - The fair values of commodity derivatives are estimated using internal discounted cash flow calculations based upon forward commodity price curves, quotes obtained from brokers for contracts with similar terms or quotes obtained from counterparties to the agreements. The most significant input to the cash flow calculations is Devon’s estimate of future commodity prices. Devon bases its estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Another key input to the cash flow calculations is Devon’s estimate of volatility for these forward curves, which is based primarily upon implied volatility. The resulting estimated future cash inflows or outflows over
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the lives of the contracts are discounted primarily using United States Treasury bill rates. These pricing and discounting inputs are sensitive to the period of the contract, as well as changes in forward prices and regional price differentials.
Interest rate derivatives - The fair values of the interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward interest-rate yield curves or quotes obtained from counterparties to the agreements. The most significant input to Devon’s cash flow calculations is its estimate of future interest rate yields. Devon bases its estimate of future yields upon its own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rate. These yield and discounting inputs are sensitive to the period of the contract, as well as changes in forward interest rate yields.
Debt - Devon’s Level 2 fixed-rate debt instruments do not actively trade in an established market. The fair values of this debt are estimated by discounting the principal and interest payments at rates available for debt with similar terms and maturity.
Level 3 Fair Value Measurements
Debt - Devon’s Level 3 debt consisted of the non-interest bearing promissory note discussed in Note 5. Due to the lack of an active market for Devon’s promissory note, quoted marked prices for this note were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt is estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125% interest rate. As a result of using these inputs, Devon concluded the estimated fair value of its non-interest bearing promissory note approximated the carrying value as of December 31, 2010.
Long-term investments - Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to the auction failures discussed in Note 1 and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available as of December 31, 2010 and December 31, 2009. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the United States government guarantees of substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of December 31, 2010 and December 31, 2009. At this time, Devon does not believe the values of its long-term securities are impaired.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Included below is a summary of the changes in Devon’s Level 3 fair value measurements.
12.
Share-Based Compensation
On June 3, 2009, Devon’s stockholders adopted the 2009 Long-Term Incentive Plan, which expires on June 2, 2019. This plan authorizes the Compensation Committee, which consists of non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, Canadian restricted stock units, performance units, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant of nonqualified stock options, restricted stock awards, restricted stock units and stock appreciation rights to directors. A total of 21.5 million shares of Devon common stock have been reserved for issuance pursuant to the plan. To calculate shares issued under the plan, options granted represent one share and other awards represent 1.84 shares.
Devon also has stock option plans that were adopted in 2005, 2003 and 1997 under which stock options and restricted stock awards were issued to key management and professional employees. Options granted under these plans remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under these plans. Devon also has stock options outstanding that were assumed as part of the acquisitions of Ocean and Mitchell Energy & Development Corp.
The following table presents the effects of share-based compensation included in Devon’s accompanying consolidated statement of operations. The vesting for certain share-based awards was accelerated as part of Devon’s strategic repositioning. The associated expense for these accelerated awards is included in restructuring costs in the accompanying consolidated statement of operations. See Note 13 for further details.
With the approval of Devon’s Compensation Committee, Devon modified the share-based compensation arrangements for certain of Devon’s executives in the second quarter of 2008. The modified compensation arrangements provide that executives who meet certain years-of-service and age criteria can retire and continue vesting in outstanding share-based grants. As a condition to receiving the benefits of these modifications, the executives must agree not to use or disclose Devon’s confidential information and not to solicit Devon’s employees and customers. The executives are required to agree to these conditions at retirement and again in each subsequent year until all grants have vested.
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Although this modification does not accelerate the vesting of the executives’ grants, it does accelerate the expense recognition as executives approach the years-of-service and age criteria. When the modification was made in the second quarter of 2008, certain executives had already met the years-of-service and age criteria. As a result, Devon recognized an additional $27 million of share-based compensation expense in the second quarter of 2008 related to this modification. This additional expense would have been recognized in future reporting periods if the modification had not been made and the executives continued their employment at Devon.
Stock Options
Under Devon’s 2009 Long-Term Incentive Plan, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Options granted generally have a vesting period that ranges from three to four years.
The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon’s common stock is based on the historical volatility of the market price of Devon’s common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon’s historical and current yield in effect at the date of grant. The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term of the option at the date of grant. The expected term of the options is based on historical exercise and termination experience for various groups of employees and directors. Each group is determined based on the similarity of their historical exercise and termination behavior.
The following table presents a summary of the grant-date fair values of stock options granted and the related assumptions. All such amounts represent the weighted-average amounts for each year.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table presents a summary of Devon’s outstanding stock options as of December 31, 2010, including changes during the year then ended.
The aggregate intrinsic value of stock options that were exercised during 2010, 2009 and 2008 was $47 million, $51 million and $263 million, respectively. As of December 31, 2010, Devon’s unrecognized compensation cost related to unvested stock options was $65 million. Such cost is expected to be recognized over a weighted-average period of 2.8 years.
Restricted Stock Awards and Units
Under Devon’s 2009 Long-Term Incentive Plan, restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, restricted stock awards and units vest over a minimum restriction period of at least three years from the date of grant. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. The fair value of restricted stock awards and units on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit.
The following table presents a summary of Devon’s unvested restricted stock awards as of December 31, 2010, including changes during the year then ended.
The aggregate fair value of restricted stock awards that vested during 2010, 2009 and 2008 was $184 million, $165 million and $185 million, respectively. As of December 31, 2010, Devon’s unrecognized
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
compensation cost related to unvested restricted stock awards and units was $311 million. Such cost is expected to be recognized over a weighted-average period of 2.8 years.
13.
Restructuring Costs
Employee Severance
In the fourth quarter of 2009, Devon recognized $153 million of estimated employee severance costs associated with the planned divestiture of its offshore assets that was announced in November 2009. This amount was based on estimates of the number of employees that would ultimately be impacted by the divestitures and included amounts related to cash severance costs and accelerated vesting of share-based grants. Of the $153 million total, $105 million related to Devon’s U.S. Offshore operations and the remainder related to its International discontinued operations.
As discussed in Note 5, during 2010 Devon divested all of its U.S. Offshore assets and a significant part of its International assets. As a result of these divestitures and associated employee terminations, Devon decreased its estimate of employee severance costs in 2010 by $31 million. More offshore employees than previously estimated received comparable positions with either the purchaser of the properties or in Devon’s U.S. Onshore operations, and this caused the $31 million decrease to the severance estimate. This decrease includes $27 million related to Devon’s U.S. Offshore operations and $4 million related to its International discontinued operations.
Lease Obligations
As a result of the divestitures discussed above, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, in 2010, Devon recognized $70 million of restructuring costs that represent the present value of its future obligations under the leases, net of anticipated sublease income. Devon’s estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that Devon may receive over the term of the leases, as well as the amount of variable operating costs that Devon will be required to pay under the leases.
Asset Impairments
In 2010, Devon recognized $11 million of asset impairment charges for leasehold improvements and furniture associated with the office space it ceased using.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Financial Statement Presentation
The schedule below summarizes the components of restructuring costs in the accompanying consolidated statements of operations.
Amounts related to cash severance and lease obligations are accrued for in other current liabilities and other long-term liabilities in the accompanying consolidated balance sheets, while amounts related to accelerated share-based awards are recorded as a reduction to Devon’s additional paid-in capital in the accompanying consolidated balance sheets. The schedule below summarizes activity and liability balances associated with Devon’s restructuring liabilities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
14.
Interest-Rate and Other Financial Instruments
The following table presents the changes in fair value and cash settlements related to Devon’s interest-rate and other financial instruments presented in the accompanying consolidated statements of operations.
Until October 31, 2008, Devon owned 14.2 million shares of Chevron common stock. These shares were held in connection with debt owed by Devon that contained an exchange option. The exchange option allowed the debt holders, prior to the debt’s maturity of August 15, 2008, to exchange the debt for shares of Chevron common stock owned by Devon. However, Devon had the option to settle any exchanges with cash equal to the market value of Chevron common stock at the time of the exchange. Devon settled remaining exchange requests during 2008 by paying $1.0 billion. On October 31, 2008, Devon transferred its 14.2 million shares of Chevron common stock to Chevron. In exchange, Devon received Chevron’s interest in the Drunkard’s Wash coalbed natural gas field in east-central Utah and $280 million in cash.
15.
Reduction of Carrying Value of Oil and Gas Properties
During 2009 and 2008, Devon reduced the carrying values of certain of its oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.
The 2009 reduction was recognized in the first quarter and the 2008 reductions were recognized in the fourth quarter. The reductions resulted from significant decreases in each country’s full cost ceiling compared to the immediately preceding quarter. The lower United States ceiling value in the first quarter of 2009 largely resulted from the effects of declining natural gas prices subsequent to December 31, 2008. The lower ceiling values in the fourth quarter of 2008 largely resulted from the effects of sharp declines in oil, gas and NGL prices compared to September 30, 2008.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
16.
Other, net
The components of other, net in the accompanying consolidated statements of operations include the following:
Deep water Gulf of Mexico leases issued in certain years by the Minerals Management Service (the “MMS”) contained price thresholds, such that if the market prices for oil or gas exceeded the thresholds for a given year, royalty relief would not be granted for that year. In October 2007, a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in deep water leases. This judgment was later appealed to the United States Supreme Court, which, in October 2009, declined to review the appellate court’s ruling. The Supreme Court’s decision ended the MMS’s judicial course to enforce the price thresholds. At the time of the Supreme Court’s decision, Devon had $84 million accrued for potential royalties on various deep water leases. Based upon the Supreme Court’s decision, Devon reduced to zero the $84 million loss contingency accrual in 2009.
In 2008, Devon recognized $162 million of excess insurance recoveries for damages suffered in 2005 related to hurricanes that struck the Gulf of Mexico. The excess recoveries resulted from business interruption claims on policies that were in effect when the 2005 hurricanes occurred.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
17.
Income Taxes
Income Tax Expense (Benefit)
The earnings (loss) from continuing operations before income taxes and the components of income tax expense (benefit) were as follows:
The taxes on the results of discontinued operations presented in the accompanying consolidated statements of operations were all related to Devon’s international operations outside North America.
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) from continuing operations before income taxes as a result of the following:
During 2010 and 2009, pursuant to the completed and planned divestitures of its International assets located outside North America, a portion of Devon’s foreign earnings were no longer deemed to be permanently reinvested. Accordingly, Devon recognized deferred tax expense of $144 million and $55 million during 2010 and 2009, respectively, related to assumed repatriations of earnings from certain of its foreign subsidiaries.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During 2008, Devon recognized $312 million of additional income tax expense that resulted from two related factors associated with its foreign operations. First, during 2008, Devon repatriated $2.6 billion from certain foreign subsidiaries to the United States. Second, Devon made certain tax policy election changes in the second quarter of 2008 to minimize the taxes it otherwise would pay for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, Devon recognized $295 million of additional current tax expense and $17 million of additional deferred tax expense.
Deferred Tax Assets and Liabilities
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities are presented below:
As shown in the above table, Devon has recognized $957 million of deferred tax assets as of December 31, 2010. Included in total deferred tax assets is $159 million related to various carryforwards available to offset future income taxes. The carryforwards consist of $538 million of Canadian net operating loss carryforwards, which expire between 2023 and 2030, and $161 million of state net operating loss carryforwards, which expire primarily between 2011 and 2024. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be “more likely than not.” When the future utilization of some portion of the carryforwards is determined not to be “more likely than not,” a valuation allowance is provided to reduce the recorded tax benefits from such assets.
Devon expects the tax benefits from the Canadian net operating loss carryforward to be utilized between 2011 and 2016. Also, Devon expects the tax benefits from the state net operating loss carryforwards to be utilized between 2012 and 2015. Such expectations are based upon current estimates of taxable income during these periods, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no
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assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon’s future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expiration.
As of December 31, 2010, approximately $4.3 billion of Devon’s unremitted earnings from its foreign subsidiaries were deemed to be permanently reinvested. As a result, Devon has not recognized a deferred tax liability for United States income taxes associated with such earnings. If such earnings were to be remitted to the United States, Devon may be subject to United States income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits (in millions).
Devon’s unrecognized tax benefit balance at December 31, 2010 and 2009 included $27 million and $35 million of interest and penalties, respectively. If recognized, all of Devon’s unrecognized tax benefits as of December 31, 2010 would affect Devon’s effective income tax rate.
Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.
18.
Discontinued Operations
For the three-year period ended December 31, 2010, Devon’s discontinued operations include amounts related to its assets in Azerbaijan, Brazil, China, Angola and other minor International properties. Additionally, during 2008, Devon’s discontinued operations included amounts related to its assets in Egypt and West Africa, including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region, until they were sold.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Revenues related to Devon’s discontinued operations totaled $693 million, $945 million and $1,702 million during 2010, 2009 and 2008, respectively. Earnings from discontinued operations before income taxes totaled $2,385 million, $322 million and $1,258 million during 2010, 2009 and 2008, respectively. Earnings before income taxes in each of these years were largely impacted by gains on the divestiture transactions. The following table presents the gains on the divestitures by year.
The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Reductions of Carrying Value of Oil and Gas Properties
During 2009 and 2008, Devon reduced the carrying values of certain of its oil and gas properties that are now held for sale. These reductions primarily resulted from full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.
Brazil’s 2009 reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin. After drilling this well in the first quarter of 2009, Devon concluded that the well did not have adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs associated with this well contributed to the reduction recognized in the first quarter of 2009.
Brazil’s 2008 reduction was recognized in the fourth quarter of 2008 and resulted primarily from a significant decrease in its full cost ceiling. The lower ceiling value largely resulted from the effects of sharp declines in oil prices compared to previous quarter-end prices.
19.
Earnings (Loss) Per Share
The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings (loss) per share. Because a net loss from continuing operations was incurred during 2009 and 2008, the dilutive shares produce an antidilutive net loss per share result.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Therefore, the diluted loss per share from continuing operations reported in the accompanying 2009 and 2008 consolidated statements of operations are the same as the basic loss per share amounts.
Certain options to purchase shares of Devon’s common stock were excluded from the dilution calculations because the options were antidilutive. These excluded options totaled 6 million, 9 million and 5 million in 2010, 2009 and 2008, respectively.
20.
Segment Information
Devon manages its North American onshore operations through six distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its United States divisions into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian and International divisions are reported as separate reporting segments primarily due to significant differences in the respective regulatory environments.
Devon’s segments are all primarily engaged in oil and gas producing activities, and certain information regarding such activities for each segment is included in Note 22. Following is certain financial information regarding Devon’s segments for 2010, 2009 and 2008. The revenues reported are all from external customers.
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21.
Supplemental Information to Statements of Cash Flows
Information related to Devon’s cash flows are presented below:
22.
Supplemental Information on Oil and Gas Operations (Unaudited)
Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country and continent. Additionally, the costs incurred and reserves information for the United States is segregated between Devon’s onshore and offshore operations. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon’s discontinued operations.
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $311 million, $332 million and $337 million in the years 2010, 2009 and 2008, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $37 million, $74 million and $71 million in the years 2010, 2009 and 2008, respectively.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Results of Operations
The following tables include revenues and expenses directly associated with Devon’s oil and gas producing activities, including general and administrative expenses directly related to such producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Proved Reserves
The following tables present Devon’s estimated proved developed and proved undeveloped reserves by product for each significant country for the three years ended December 31, 2010. The significant changes in Devon’s reserves are discussed following the tables.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Price Revisions
2010 - Reserves increased 72 MMBoe due to higher gas prices, partially offset by the effect of higher oil prices. The higher oil prices increased Devon’s Canadian royalty burden, which reduced Devon’s oil reserves. Of the 72 MMBoe price revisions, 43 MMBoe related to the Barnett Shale in north Texas and 22 MMBoe related to the Rocky Mountain area.
2009 - Reserves increased 177 MMBoe due to higher oil prices, partially offset by lower gas prices. The increase in oil reserves primarily related to Devon’s Jackfish thermal heavy oil reserves in Canada. At the end of 2008, 331 MMBoe of reserves related to Jackfish were not considered proved. However, due to higher prices, these reserves were considered proved as of December 31, 2009. Significantly lower gas prices caused Devon’s reserves to decrease 116 MMBoe, which primarily related to its United States reserves.
2008 - Due to significantly lower oil, gas and NGL prices as of December 31, 2008 compared to December 31, 2007, 487 MMBoe of reserves were not considered proved as of December 31, 2008. Of the 487 MMBoe price revisions, 331 MMBoe related to Jackfish.
The 487 MMBoe price revision also included 28 MMBoe related to Devon’s proved reserves in the Canadian province of Alberta. In December 2008, the provincial government of Alberta enacted a new royalty regime. The new regime for conventional oil, gas, NGL and heavy oil production was effective January 1, 2009. As a result of the newly enacted royalties, Devon’s proved reserves decreased as of December 31, 2008.
Revisions Other Than Price
Total revisions other than price for 2010, 2009 and 2008 primarily related to Devon’s drilling and development in the Barnett Shale.
Extensions and Discoveries
2010 - Of the 354 MMBoe of 2010 extensions and discoveries, 101 MMBoe related to the Cana-Woodford Shale in western Oklahoma, 87 MMBoe related to the Barnett Shale, 55 MMBoe related to Jackfish, 19 MMBoe related to the Permian Basin, 15 MMBoe related to the Rocky Mountain area and 14 MMBoe related to the Carthage area in east Texas.
The 2010 extensions and discoveries included 107 MMBoe related to additions from Devon’s infill drilling activities, including 43 MMBoe at the Barnett Shale and 47 MMBoe at the Cana-Woodford Shale.
2009 - Of the 458 MMBoe of 2009 extensions and discoveries, 204 MMBoe related to the Barnett Shale, 118 MMBoe related to Jackfish, 49 MMBoe related to the Cana-Woodford Shale, 14 MMBoe related to the Rocky Mountain area, 11 MMBoe related to Deepwater Production in the Gulf, 8 MMBoe related to the Carthage conventional area, and 7 MMBoe related to the Haynesville Shale area in east Texas.
The 2009 extensions and discoveries included 371 MMBoe related to additions from Devon’s infill drilling activities, including 203 MMBoe at the Barnett Shale, 118 MMBoe at Jackfish and 24 MMBoe at the Cana-Woodford Shale.
2008 - Of the 546 MMBoe of 2008 extensions and discoveries, 252 MMBoe related to the Barnett Shale, 101 MMBoe related to Jackfish, 44 MMBoe related to Carthage conventional, 21 MMBoe related to the Cana-Woodford Shale, 19 MMBoe related to the Lloydminster heavy oil development in Canada and 17 MMBoe related to the Arkoma-Woodford Shale area in southeastern Oklahoma.
The 2008 extensions and discoveries included 420 MMBoe related to additions from Devon’s infill drilling activities, including 243 MMBoe at the Barnett Shale, 101 MMBoe at Jackfish, 22 MMBoe at Carthage conventional, 18 MMBoe at Lloydminster and 11 MMBoe at the Cana-Woodford Shale.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Purchase of Reserves
The 2008 total included 34 MMBoe located in Utah and 27 MMBoe located in the Permian Basin.
Sale of Reserves
The 2010 total primarily relates to the divestiture of Devon’s Gulf of Mexico properties.
SEC’s Modernization of Oil and Gas Reporting
At the end of 2009, Devon adopted the SEC’s Modernization of Oil and Gas Reporting, as well as the conforming rule changes issued by the Financial Accounting Standards Board. Upon adoption, the two primary rule changes that impacted Devon’s year-end reserves estimates were those related to assumptions for pricing and reasonable certainty.
The SEC’s prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. The revised rules require reserves estimates to be calculated using an average of the first-day-of-the-month price for the preceding 12-month period.
The revised rules amend the definition of proved reserves to permit the use of reliable technologies to establish the reasonable certainty of proved reserves. This revision includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations. This revision also allows proved reserves to be claimed beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty based on reliable technologies. As a result of adopting these provisions of the new rules, Devon’s 2009 reserves increased approximately 65 MMBoe, or 2%. This increase is included in the 2009 extensions and discoveries total.
Prepared and Audited Reserves
Set forth below is a summary of the reserves that were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2010, 2009 and 2008.
N/A Not applicable - Devon sold its U.S. Offshore properties during 2010.
“Prepared” reserves are those quantities of reserves that were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of reserves that were estimated by Devon employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of an audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.
In 2010, the U.S. reserves were evaluated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. In 2009 and 2008, the U.S. reserves were evaluated by the independent petroleum
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
consultants of LaRoche Petroleum Consultants, Ltd. and Ryder Scott Company, L.P. The Canadian reserves were evaluated by the independent petroleum consultants of AJM Petroleum Consultants in each of the years presented.
Standardized Measure
The tables below reflect the standardized measure of discounted future net cash flows related to Devon’s interest in proved reserves.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2010, the prices averaged $59.94 per barrel of oil, $3.73 per Mcf of gas and $31.11 per barrel of natural gas liquids. Of the $10,746 million of future development costs as of the end of 2010, $1,418 million, $1,447 million and $972 million are estimated to be spent in 2011, 2012 and 2013, respectively.
Future development costs include not only development costs, but also future dismantlement, abandonment and rehabilitation costs. Included as part of the $10,746 million of future development costs are $2,263 million of future dismantlement, abandonment and rehabilitation costs.
Future production costs include general and administrative expenses directly related to oil and gas producing activities. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.
The principal changes in the standardized measure of discounted future net cash flows attributable to Devon’s proved reserves are as follows:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
23.
Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of the unaudited interim results of operations for the years ended December 31, 2010 and 2009.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Earnings (Loss) from Continuing Operations
The third quarter of 2010 includes restructuring costs that relate to Devon’s offshore asset divestitures and total $63 million ($40 million after income taxes, or $0.09 per diluted share).
The first quarter of 2009 includes a reduction of the carrying values of United States oil and gas properties totaling $6,408 million ($4,085 million after income taxes, or $9.20 per diluted share).
The fourth quarter of 2009 includes restructuring costs that relate to Devon’s planned asset divestitures and total $105 million ($67 million after income taxes, or $0.15 per diluted share).
Earnings (Loss) from Discontinued Operations
The second quarter of 2010 includes the divestiture of our Panyu operations in China and the related gain was $308 million ($235 million after income taxes, or $0.52 per diluted share).
The third quarter of 2010 includes the divestiture of our Azerbaijan operations and the related gain was $1.541 million ($1.522 million after income taxes, or $3.49 per diluted share).
The first quarter of 2009 includes reductions of the carrying values of oil and gas properties totaling $109 million ($105 million after income taxes, or $0.24 per diluted share).
The fourth quarter of 2009 includes restructuring costs that relate to Devon’s planned asset divestitures and total $48 million ($31 million after income taxes, or $0.07 per diluted share).

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A.
Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2010 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Management’s Annual Report on Internal Control Over Financial Reporting
Devon’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, Devon conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework, which was completed on February 21, 2011, management concluded that its internal control over financial reporting was effective as of December 31, 2010.
The effectiveness of Devon’s internal control over financial reporting as of December 31, 2010 has been audited by KPMG LLP, an independent registered public accounting firm who audited Devon’s consolidated financial statements as of and for the year ended December 31, 2010, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data.”
Changes in Internal Control Over Financial Reporting
There was no change in Devon’s internal control over financial reporting during the fourth quarter of 2010 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B.
Other Information
Danny Heatly, our Senior Vice President, Accounting and Chief Accounting Officer, has notified Devon of his retirement, effective March 4, 2011. In connection with Mr. Heatly’s retirement, Mr. Heatly and Devon entered into a Retirement Agreement, dated February 23, 2011 (the “Retirement Agreement”), in which Devon agreed to provide continued vesting of Mr. Heatly’s outstanding equity awards and Mr. Heatly made certain representations and covenants in favor of Devon. The Retirement Agreement is attached as Exhibit 10.21 to this Annual Report on Form 10-K.
Following Mr. Heatly’s retirement, Jeffrey A. Agosta, 43, Devon’s Executive Vice President and Chief Financial Officer will also serve as principal accounting officer.
PART III

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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
Item 10.
Directors, Executive Officers and Corporate Governance
The information called for by this Item 10 is incorporated hereby by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11.
Executive Compensation
The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.

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ITEM 12. SECURITY OWNERSHIP
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Item 14.
Principal Accounting Fees and Services
The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.
PART IV

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 15.
Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at Item 8. “Financial Statements and Supplementary Data” in this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated financial statements or notes thereto.
3. Exhibits
Exhibit No.
Description
.1
Underwriting Agreement, dated as of January 6, 2009, among Devon Energy Corporation and Banc of America Securities LLC, J.P. Morgan Securities Inc. and UBS Securities LLC, as representatives of the several Underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed on January 9, 2009).
.1
Agreement and Plan of Merger, dated as of February 23, 2003, by and among Registrant, Devon NewCo Corporation, and Ocean Energy, Inc. (incorporated by reference to Registrant’s Amendment No. 1 to Form S-4 Registration No. 333-103679, filed March 20, 2003).
.2
Amended and Restated Agreement and Plan of Merger, dated as of August 13, 2001, by and among Registrant, Devon NewCo Corporation, Devon Holdco Corporation, Devon Merger Corporation, Mitchell Merger Corporation and Mitchell Energy & Development Corp. (incorporated by reference to Annex A to Registrant’s Joint Proxy Statement/Prospectus of Form S-4 Registration Statement No. 333-68694 as filed August 30, 2001).
.3
Offer to Purchase for Cash and Directors’ Circular dated September 6, 2001 (incorporated by reference to Registrant’s and Devon Acquisition Corporation’s Schedule 14D-1F filing, filed September 6, 2001).
.4
Pre-Acquisition Agreement, dated as of August 31, 2001, between Registrant and Anderson Exploration Ltd. (incorporated by reference to Exhibit 2.2 to Registrant’s Registration Statement on Form S-4, File No. 333-68694 as filed September 14, 2001).
.5
Amendment No. One, dated as of July 11, 2000, to Agreement and Plan of Merger by and among Registrant, Devon Merger Co. and Santa Fe Snyder Corporation dated as of May 25, 2000 (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on July 12, 2000).
.6
Amended and Restated Agreement and Plan of Merger among Registrant, Devon Energy Corporation (Oklahoma), Devon Oklahoma Corporation and PennzEnergy Company dated as of May 19, 1999 (incorporated by reference to Exhibit 2.1 to Registrant’s Form S-4, File No. 333-82903).
.1
Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-K filed on March 7, 2005).
.2
Registrant’s Certificate of Amendment of Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-Q filed on August 7, 2008).
.3
Registrant’s Bylaws (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed on March 6, 2009).
.1
Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to senior debt securities issuable by Registrant (the “Senior Indenture”) (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002).
.2
Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed on April 9, 2002).
Exhibit No.
Description
.3
Supplemental Indenture No. 3, dated as of January 9, 2009, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 5.625% Senior Notes due 2014 and the 6.30% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed on January 9, 2009).
.4
Indenture dated as of October 3, 2001, by and among Devon Financing Corporation, U.L.C. as Issuer, Registrant as Guarantor, and The Bank of New York Mellon Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 6.875% Senior Notes due 2011 and the 7.875% Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4, File No. 333-68694 as filed October 31, 2001).
.5
Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 10.24 to the Form 10-Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0-25058)).
.6
First Supplemental Indenture, dated March 30, 1999 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.5 to Ocean Energy, Inc.’s Form 10-Q for the period ended March 31, 1999).
.7
Second Supplemental Indenture, dated as of May 9, 2001 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 99.2 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 14, 2001).
.8
Third Supplemental Indenture, dated January 23, 2006 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.23 of Registrant’s Form 10-K for the year ended December 31, 2005).
.9
Senior Indenture dated September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., as Trustee, and Specimen of 7.50% Senior Notes (incorporated by reference to Exhibit 4.4 to Ocean Energy’s Annual Report on Form 10-K for the year ended December 31, 1997)).
.10
First Supplemental Indenture, dated as of March 30, 1999 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 4.10 to Ocean Energy’s Form 10-Q for the period ended March 31, 1999).
.11
Second Supplemental Indenture, dated as of May 9, 2001 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 14, 2001).
.12
Third Supplemental Indenture, dated December 31, 2005 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K for the year ended December 31, 2005).
.1
Amended and Restated Investor Rights Agreement, dated as of August 13, 2001, by and among Registrant, Devon Holdco Corporation, George P. Mitchell and Cynthia Woods Mitchell (incorporated by reference to Annex C to the Joint Proxy Statement/Prospectus of Form S-4 Registration Statement No. 333-68694 as filed August 30, 2001).
Exhibit No.
Description
.2
First Amendment to Credit Agreement dated as of December 19, 2007, among Registrant as Borrower, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-K filed February 27, 2009).
.3
Amended and Restated Credit Agreement dated March 24, 2006, effective as of April 7, 2006, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as Canadian Borrowers, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer; JPMorgan Chase Bank, N.A. as Syndication Agent, Bank of Montreal D/B/A “Harris Nesbitt”, Royal Bank of Canada, Wachovia Bank, National Association as Co-Documentation Agents and The Other Lenders Party Hereto, Banc of America Securities L.L.C. and J.P. Morgan Securities Inc., as Joint Lead Arrangers and Book Managers for the $2.0 billion five-year revolving credit facility (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 4, 2006).
.4
First Amendment to Amended and Restated Credit Agreement dated as of June 1, 2006, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment. (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed on November 7, 2007).
.5
Second Amendment to Amended and Restated Credit Agreement dated as of September 19, 2007, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment. (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed on November 7, 2007).
.6
Third Amendment to Amended and Restated Credit Agreement dated as of December 19, 2007, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-K filed February 27, 2009).
.7
Fourth Amendment to Amended and Restated Credit Agreement dated as of April 7, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Form 10-Q filed on May 7, 2008).
.8
Fifth Amendment to Amended and Restated Credit Agreement dated as of November 5, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.2 of Registrant’s Form 10-Q filed on November 6, 2008).
.9
Devon Energy Corporation 2009 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-159796, filed June 5, 2009).*
.10
Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-127630, filed August 17, 2005) .*
.11
First Amendment to Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Appendix A to Registrant’s Proxy Statement for the 2006 Annual Meeting of Stockholders filed on April 28, 2006).*
.12
Devon Energy Corporation 2003 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-104922, filed May 1, 2003).*
.13
Devon Energy Corporation 1997 Stock Option Plan (as amended August 29, 2000) (incorporated by reference to Exhibit A to Registrant’s Proxy Statement for the 1997 Annual Meeting of Shareholders filed on April 3, 1997).*
.14
Amended and Restated Form of Employment Agreement between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt dated December 15, 2008 (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009).*
Exhibit No.
Description
.15
Form of Incentive Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for incentive stock options granted.*
.16
Form of Employee Nonqualified Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for nonqualified stock options granted.*
.17
Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for nonqualified stock options granted (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed on February 25, 2010).*
.18
Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for restricted stock awards.*
.19
Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for restricted stock awards (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed on February 25, 2010).*
.20
Amended and Restated Severance Agreement between Registrant and Danny J. Heatly, dated December 15, 2008 (incorporated by reference to Exhibit 10.27 to Registrant’s Form 10-K filed on February 27, 2009).*
.21
Retirement Agreement between Registrant and Danny J. Heatly, dated February 23, 2011.*
.22
Form of Letter Agreement amending the restricted stock award agreements, nonqualified stock option agreements and incentive stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and J. Larry Nichols, John Richels and Darryl G. Smette.*
Statement of computations of ratios of earnings to fixed charges and to combined fixed charges and preferred stock dividends.
Registrant’s Significant Subsidiaries.
.1
Consent of KPMG LLP.
.2
Consent of LaRoche Petroleum Consultants.
.3
Consent of AJM Petroleum Consultants.
.1
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
.2
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
.1
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
.2
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
.1
Report of LaRoche Petroleum Consultants.
.2
Report of AJM Petroleum Consultants.
.INS
XBRL Instance Document
.SCH
XBRL Taxonomy Extension Schema Document
.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
.LAB
XBRL Taxonomy Extension Labels Linkbase Document
.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
.DEF
XBRL Taxonomy Extension Definition Linkbase Document
*
Compensatory plans or arrangements
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.
DEVON ENERGY CORPORATION
By:
/s/ JOHN RICHELS
John Richels,
President and Chief Executive Officer
February 23, 2011
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 and on the dates indicated.
/s/ John Richels
John Richels
President, Chief Executive Officer and Director
February 23, 2011
/s/ J. Larry Nichols
J. Larry Nichols
Executive Chairman and Director
February 23, 2011
/s/ Jeffrey A. Agosta
Jeffrey A. Agosta
Executive Vice President and Chief Financial Officer
February 23, 2011
/s/ Danny J. Heatly
Danny J. Heatly
Senior Vice President - Accounting and Chief Accounting Officer
February 23, 2011
/s/ Robert H. Henry
Robert H. Henry
Director
February 23, 2011
/s/ John A. Hill
John A. Hill
Director
February 23, 2011
/s/ Michael M. Kanovsky
Michael M. Kanovsky
Director
February 23, 2011
/s/ J. Todd Mitchell
J. Todd Mitchell
Director
February 23, 2011
/s/ Robert A. Mosbacher, Jr.
Robert A. Mosbacher, Jr.
Director
February 23, 2011
/s/ Duane C. Radtke
Duane C. Radtke
Director
February 23, 2011
/s/ Mary P. Ricciardello
Mary P. Ricciardello
Director
February 23, 2011
INDEX TO EXHIBITS
Exhibit No.
Description
.15
Form of Incentive Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for incentive stock options granted.*
.16
Form of Employee Nonqualified Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for nonqualified stock options granted.*
.18
Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for restricted stock awards.*
.21
Retirement Agreement between Registrant and Danny J. Heatly, dated February 23, 2011.*
.22
Form of Letter Agreement amending the restricted stock award agreements, nonqualified stock option agreements and incentive stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and J. Larry Nichols, John Richels and Darryl G. Smette.*
Statement of computations of ratios of earnings to fixed charges and to combined fixed charges and preferred stock dividends.
Registrant’s Significant Subsidiaries.
.1
Consent of KPMG LLP.
.2
Consent of LaRoche Petroleum Consultants.
.3
Consent of AJM Petroleum Consultants.
.1
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
.2
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
.1
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
.2
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
.1
Report of LaRoche Petroleum Consultants.
.2
Report of AJM Petroleum Consultants.
.INS
XBRL Instance Document
.SCH
XBRL Taxonomy Extension Schema Document
.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
.LAB
XBRL Taxonomy Extension Labels Linkbase Document
.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
.DEF
XBRL Taxonomy Extension Definition Linkbase Document
*
Compensatory plans or arrangements

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Stock Performance Metrics:
Return: 0.02263723872601986
1-Day Return: $1_day_return
3-Day Return: $3_day_return
5-Day Return: $5_day_return
10-Day Return: $10_day_return
20-Day Return: $20_day_return
40-Day Return: $40_day_return
60-Day Return: $60_day_return
80-Day Return: $80_day_return
100-Day Return: $100_day_return
150-Day Return: $150_day_return
252-Day Return: $252_day_return