Registrant’s telephone number, including area code:

(405) 235-3611

 

 

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

None

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ      No  o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  þ      No  o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2010, was approximately $26.6 billion, based upon the closing price of $60.92 per share as reported by the New York Stock Exchange on such date. On February 10, 2011, 427 million shares of common stock were outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2011 annual meeting of stockholders — Part III

 

 

 

Measurements of Oil, Natural Gas and Natural Gas Liquids

 

 

 

 

 

 

 

 

 

Geographic Areas

 

 

Other

 

 

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare the December 31, 2010 reserve reports and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

 

 

All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

 

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.

 

 

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.

 

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.

 

 

 

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:

 

 

Our marketing and midstream costs and expenses are primarily incurred from:

 

 

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:

 

 

 

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:

 

 

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 “Item 1A. Risk Factors.”

 

Availability of Reports

 

Through our website, http://www.devonenergy.com, we make available electronic copies of the charters of the committees of our Board of Directors, other documents related to our corporate governance (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer), and documents we file or furnish to the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.

 

 

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:

 

 

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:

 

 

 

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.

 

 

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.

 

 

 

 

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:

 

 

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:

 

 

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:

 

 

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:

 

 

 

 

 

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.

 

 

 

 

 

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.

 

 

 

 

 

 

 

 

 

 

 

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.

 

 

 

 

 

 

 

The following table presents the results, as of February 1, 2011, of our wells that were in progress as of December 31, 2010.