10-K 1 d71091e10vk.htm FORM 10-K e10vk
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2009
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File Number 001-32318
Devon Energy Corporation
(Exact name of registrant as specified in its charter)
 
     
Delaware   73-1567067
(State of other jurisdiction of incorporation or organization)   (I.R.S. Employer identification No.)
20 North Broadway, Oklahoma City, Oklahoma   73102-8260
(Address of principal executive offices)   (Zip code)
 
Registrant’s telephone number, including area code:
(405) 235-3611
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of each class
 
Name of each exchange on which registered
 
Common stock, par value $0.10 per share
  The New York Stock Exchange
 
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):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)       
 
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, 2009, was approximately $24.0 billion, based upon the closing price of $54.50 per share as reported by the New York Stock Exchange on such date. On February 15, 2010, 446.8 million shares of common stock were outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2010 annual meeting of stockholders — Part III
 


 

 
DEVON ENERGY CORPORATION
 
INDEX TO FORM 10-K ANNUAL REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION
 
                 
        Definitions     3  
        Information Regarding Forward-Looking Statements     3  
       
      Business     5  
      Risk Factors     12  
      Unresolved Staff Comments     16  
      Properties     16  
      Legal Proceedings     29  
      Submission of Matters to a Vote of Security Holders     29  
       
      Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     30  
      Selected Financial Data     32  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     33  
      Quantitative and Qualitative Disclosures about Market Risk     74  
      Financial Statements and Supplementary Data     76  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     140  
      Controls and Procedures     140  
      Other Information     140  
       
      Directors, Executive Officers and Corporate Governance     141  
      Executive Compensation     141  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     141  
      Certain Relationships and Related Transactions, and Director Independence     141  
      Principal Accounting Fees and Services     141  
       
      Exhibits and Financial Statement Schedules     142  
 EX-10.18
 EX-10.19
 EX-10.20
 EX-10.21
 EX-10.22
 EX-12
 EX-21
 EX-23.1
 EX-23.2
 EX-23.3
 EX-23.4
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1
 EX-99.2
 EX-99.3
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT


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DEFINITIONS
 
“Bbl” or “Bbls” means barrel or barrels.
 
“Bcf” means billion cubic feet.
 
“Bcfe” means billion cubic feet of gas equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
 
“Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
 
“Btu” means British thermal units, a measure of heating value.
 
“Canada” means the operations of Devon encompassing oil and gas properties located in Canada.
 
“Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.
 
“FPSO” means floating, production, storage and offloading facilities.
 
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
 
“International” means the discontinued operations of Devon that encompass oil and gas properties that lie outside the United States and Canada.
 
“LIBOR” means London Interbank Offered Rate.
 
“MBbls” means thousand barrels.
 
“MBoe” means thousand Boe.
 
“Mcf” means thousand cubic feet.
 
“MMBbls” means million barrels.
 
“MMBoe” means million Boe.
 
“MMBtu” means million Btu.
 
“MMcf” means million cubic feet.
 
“MMcfe” means million cubic feet of gas equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
 
“NGL” or “NGLs” means natural gas liquids.
 
“North American Onshore” means our operations encompassing oil and gas properties in the continental United States and Canada.
 
“NYMEX” means New York Mercantile Exchange.
 
“Oil” includes crude oil and condensate.
 
“SEC” means United States Securities and Exchange Commission.
 
“U.S. Offshore” means the operations of Devon encompassing oil and gas properties in the Gulf of Mexico.
 
“U.S. Onshore” means the operations of Devon encompassing oil and gas properties in the continental United States.
 
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
 
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


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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, 2009 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:
 
  •  energy markets, including the supply and demand for oil, gas, NGLs and other products or services, and the prices of oil, gas, NGLs, including regional pricing differentials, and other products or services;
 
  •  production levels, including Canadian production subject to government royalties, which fluctuate with prices and production, and international production governed by payout agreements, which affect reported production;
 
  •  reserve levels;
 
  •  competitive conditions;
 
  •  technology;
 
  •  the availability of capital resources within the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks;
 
  •  capital expenditure and other contractual obligations;
 
  •  currency exchange rates;
 
  •  the weather;
 
  •  inflation;
 
  •  the availability of goods and services;
 
  •  drilling risks;
 
  •  future processing volumes and pipeline throughput;
 
  •  general economic conditions, whether internationally, nationally or in the jurisdictions in which we or our subsidiaries conduct business;
 
  •  legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;
 
  •  terrorism;
 
  •  occurrence of property acquisitions or divestitures; and
 
  •  other factors disclosed under “Item 2. Properties — Proved Reserves and Estimated Future Net Revenue,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this report.
 
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.


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PART I
 
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 oil and gas operations are concentrated in various North American onshore areas in the United States and Canada. We also have offshore operations that are situated principally in the Gulf of Mexico and regions located offshore Azerbaijan, Brazil and China.
 
To complement our upstream oil and gas operations, we have marketing and midstream operations primarily in North America. 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 reserves, production, earnings and cash flows, all on a per share basis. We do this by:
 
  •  exercising capital discipline;
 
  •  investing in oil and gas properties with high operating margins;
 
  •  balancing our reserves and production mix between natural gas and liquids;
 
  •  maintaining a low overall cost structure;
 
  •  improving performance through our marketing and midstream operations; and
 
  •  preserving financial flexibility.
 
Over the past decade, 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 more than 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 high-growth, North American onshore exploration and production company. As part of this strategic repositioning, we plan to bring forward the value of our offshore assets located in the Gulf of Mexico and countries outside North America by divesting them.
 
This repositioning is driven by our desire to unlock and accelerate the realization of the value underlying the deep inventory of opportunities we have. We have assembled a valuable portfolio of offshore assets, and we have a considerable inventory of premier North American onshore assets. However, our North American onshore assets have consistently provided us our highest risk-adjusted investment returns. By selling our offshore assets, we can more aggressively pursue the untapped value of these North American onshore opportunities. Besides reducing debt, the offshore divestiture proceeds are expected to provide significant funds to redeploy into our prolific North American onshore opportunities. With these added funds, we plan to accelerate the growth and realization of the value of our North American onshore assets.


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Presentation of Discontinued Operations
 
As a result of the planned divestitures of our offshore assets, 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.
 
Even though we are also divesting our U.S. Offshore operations, these properties 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. 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 always been focused on growth and value creation for our shareholders. We increased our total proved reserves from 8 MMBoe at year-end 1987 to 2,733 MMBoe at year-end 2009. During this same time period, we increased annual production from 1 MMBoe in 1987 to 233 MMBoe in 2009. 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 2009 translate into annual per share growth rates of 11% for production and 8% for reserves.
 
As a result of this growth, we have become one of the largest independent oil and gas companies in North America. During 2009, we continued to build off our past successes with a number of key accomplishments, including those discussed below.
 
  •  Drilling Success — We drilled 1,135 gross wells with a 99% success rate. As a result of our success with the drill-bit, we replaced approximately 213% of our 2009 production. We added 496 MMBoe of proved reserves during the year with extensions, discoveries and performance revisions. These reserve additions were more than double the 233 MMBoe we produced during 2009. Besides increasing our proved reserves, our drilling success was also the main driver of our 5% production growth in 2009.
 
  •  Barnett Shale — We drilled 336 wells in the Barnett Shale field in north Texas in 2009, bringing our total producing wells in the field to almost 4,200 at year end. We exited 2009 with net Barnett Shale production at just over one Bcf of natural gas equivalent per day. We are currently running 16 operated drilling rigs in the Barnett and expect to drill 370 wells in the field in 2010.
 
  •  Cana-Woodford Shale — We drilled 47 successful wells in the Cana-Woodford Shale in western Oklahoma in 2009. We also increased our net production from this important new shale-gas resource by nearly 500% to an average of 39 MMcf of natural gas equivalent per day. We have increased our lease position in the Cana-Woodford Shale to 118,000 net acres and expect to drill approximately 85 wells in the field in 2010.
 
  •  Haynesville Shale — We drilled eight Haynesville Shale wells in the greater Carthage area of east Texas in 2009. These wells have significantly de-risked our 110,000 net Haynesville Shale acres in the Carthage area.
 
  •  Jackfish — In Canada, our 100-percent owned Jackfish oil sands project in Alberta was operational throughout 2009. As measured by production per well and steam-to-oil ratio, Jackfish is one of Canada’s most commercially successful steam-assisted gravity drainage projects. In late 2009, Jackfish’s gross production reached 33.7 MBbls of oil per day. The addition of four more producing wells is expected to push production to the facility’s capacity of 35 MBbls per day in early 2010.
 
Construction continued throughout 2009 on a second phase of the Jackfish project. Jackfish 2 is also sized to produce 35 MBbls of oil per day and will commence operations in 2011. We expect to file a regulatory application for a third phase of the project in the third quarter of 2010.


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  •  Brazil — Offshore Brazil, we participated in two significant deepwater discoveries in 2009. The Devon-operated Itaipu exploratory discovery followed a successful appraisal of the 2008 Wahoo discovery. Both Itaipu and Wahoo are pre-salt prospects located in the Campos Basin.
 
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
 
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 2010, 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 2010, approximately 86% 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 13% 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 2010, approximately 90% of our NGL production was sold under short-term contracts at variable or market-sensitive prices. The remaining 10% of NGL production was sold under short-term, fixed-price contracts.
 
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. 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 and transport the combined product to the Edmonton area for sale.


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Our marketing and midstream revenues are primarily generated by:
 
  •  selling NGLs that are either extracted from the gas streams processed by our plants or purchased from third parties for marketing, and
 
  •  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:
 
  •  purchasing the gas streams entering our transport pipelines and plants;
 
  •  purchasing fuel needed to operate our plants, compressors and related pipeline facilities;
 
  •  purchasing third-party NGLs;
 
  •  operating our plants, gathering systems and related facilities; and
 
  •  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 2009, 2008 and 2007, no purchaser accounted for over 10% of our revenues.
 
Seasonal Nature of Business
 
Generally, but not always, 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 gas industry is subject to various types of regulation throughout the world. Laws, rules, regulations and other policy implementations affecting the oil and 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 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 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 gas companies of similar size and financial strength.
 
The following are significant areas of government control and regulation in the United States, Canada and other international locations in which we operate.


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Exploration and Production Regulation
 
Our oil and gas operations are subject to various federal, state, provincial, tribal, local and international laws and regulations. These regulations relate to matters that include, but are not limited to:
 
  •  acquisition of seismic data;
 
  •  location of wells;
 
  •  drilling and casing of wells;
 
  •  well production;
 
  •  spill prevention plans;
 
  •  emissions permitting;
 
  •  use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
 
  •  surface usage and the restoration of properties upon which wells have been drilled;
 
  •  calculation and disbursement of royalty payments and production taxes;
 
  •  plugging and abandoning of wells;
 
  •  transportation of production; and
 
  •  in international operations, minimum investments in the country of operations.
 
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 various federal agencies, including the Bureau of Land Management and the Minerals Management Service (“MMS”) 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 MMS 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. The Federal Energy Regulatory Commission also has jurisdiction over certain U.S. offshore activities pursuant to the Outer Continental Shelf Lands Act.
 
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, field discovery date 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.


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The provincial government of Alberta enacted a new royalty regime effective January 1, 2009. The new regime links royalties to price and production levels and applies to both new and existing conventional oil and gas activities and oil sands projects. This regime has generally reduced our proved reserves and production in Alberta, as well as the related earnings and cash flows. Similar effects have been experienced throughout the oil and gas industry in Alberta. Acknowledging this impact on the industry, the government of Alberta has announced a competitiveness review to assess the impact to the industry as a result of the royalty changes. However, we are uncertain whether the current regime will be modified.
 
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.
 
Production Sharing Contracts
 
Some of our international licenses are governed by production sharing contracts (“PSCs”) between the concessionaires and the granting government agency. PSCs are contracts that define and regulate the framework for investments, revenue sharing, and taxation of mineral interests in foreign countries. Unlike most domestic leases, PSCs have defined production terms and time limits of generally 30 years. PSCs also generally contain sliding scale revenue sharing provisions. As a result, at either higher production rates or higher cumulative rates of return, PSCs generally allow the government agency to retain higher fractions of revenue.
 
Environmental and Occupational Regulations
 
We are subject to various federal, state, provincial, tribal, local and 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:
 
  •  assessing the environmental impact of seismic acquisition, drilling or construction activities;
 
  •  the generation, storage, transportation and disposal of waste materials;
 
  •  the emission of certain gases into the atmosphere;
 
  •  the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and
 
  •  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.


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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 the warming of the Earth’s atmosphere and other climatic changes. However, there is currently no settled scientific consensus on whether, or the extent to which, human-derived greenhouse gas emissions contribute to climatic change. As an oil and gas company, the debate on climate change is 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. As a result, some believe that combustion of carbon-based fuels contributes to climate change.
 
Despite the lack of a settled scientific consensus on human-derived impacts on climate change, 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. As a result of a gradually declining cap, the number of government-issued allowances and allowances available for trade would be reduced each year until the overall goal of greenhouse gas emission reductions is achieved.
 
Because no final legislation or regulations limiting greenhouse gas emissions have been enacted at this time, it is not possible to estimate the costs or operational impacts we could experience to comply with new legislative or regulatory developments. Although we do not anticipate that we would be impacted to any greater degree than other similar oil and gas companies, a stringent greenhouse gas control program could increase our cost of doing business and reduce demand for the oil and natural gas that we sell. However, to the extent that any particular greenhouse gas program directly or indirectly encourages the use of natural gas, demand for the natural gas we sell could increase.
 
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, certain countries in which we operate have. Canada ratified the Protocol in April 2007 and released its Regulatory Framework for Air Emissions. The Canadian framework is a plan to implement mandatory reductions in greenhouse gas emissions. The mandatory reductions on greenhouse gas emissions will create additional costs for the Canadian oil and gas industry, including us. Certain provinces in Canada also have implemented or are currently implementing legislation and regulations to report and reduce greenhouse gas emissions, which also will carry a cost associated with compliance. Presently, it is not possible to accurately estimate the costs we could incur to comply with any 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 United States Environmental Protection Agency. 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, 2009, we had approximately 5,400 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.”


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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.
 
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 prices of and demand for oil, gas and NGLs. 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, 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:
 
  •  consumer demand for oil, gas and NGLs;
 
  •  conservation efforts;
 
  •  OPEC production levels;
 
  •  weather;
 
  •  regional pricing differentials;
 
  •  differing quality of oil produced (i.e., sweet crude versus heavy or sour crude) and Btu content of gas produced;
 
  •  the level of imports and exports of oil, gas and NGLs;
 
  •  the price and availability of alternative fuels;
 
  •  the overall economic environment; and
 
  •  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.


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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 recovery reserves or tertiary recovery reserves, 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:
 
  •  unexpected drilling conditions;
 
  •  pressure or irregularities in reservoir formations;
 
  •  equipment failures or accidents;
 
  •  fires, explosions, blowouts and surface cratering;
 
  •  marine risks such as capsizing, collisions and hurricanes;
 
  •  other adverse weather conditions;
 
  •  lack of access to pipelines or other transportation methods;
 
  •  environmental hazards or liabilities; and
 
  •  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. We are currently performing exploratory drilling activities in certain international countries. We have been granted drilling concessions in these countries that require commitments on our behalf to incur capital expenditures. Even if future drilling activities are unsuccessful in establishing proved reserves, we will likely be required to fulfill our commitments to make such capital expenditures.
 
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


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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.
 
International Operations Have Uncertain Political, Economic and Other Risks
 
Our operations outside North America are based primarily in Azerbaijan, Brazil and China. 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:
 
  •  general strikes and civil unrest;
 
  •  the risk of war, acts of terrorism, expropriation, forced renegotiation or modification of existing contracts;
 
  •  import and export regulations;
 
  •  taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;
 
  •  transportation regulations and tariffs;
 
  •  exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds;
 
  •  laws and policies of the United States affecting foreign trade, including trade sanctions;
 
  •  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;
 
  •  the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and
 
  •  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. Even our smaller international 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.
 
Public Policy, Which Includes Laws, Rules and Regulations, Can Change
 
Our operations are subject to federal laws, rules and regulations in the United States, Canada and the other countries in which we operate. In addition, we are also subject to the laws and regulations of various


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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. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability. While public policy can change at any time in the future, those laws and regulations outside North America to which we are subject generally include greater risk of unforeseen change.
 
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, local and international 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 occurrences such as hurricanes, 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. Due to changes in the insurance marketplace following hurricanes in the Gulf of Mexico in recent years, we currently do not have coverage for any damage that may be caused by future named windstorms in the Gulf of Mexico.
 
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, 2009, our auction rate securities totaled $115 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, we consider these investments to be long-term in nature and generally not available for short-term liquidity needs.
 
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


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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.
 
Item 1B.   Unresolved Staff Comments
 
Not applicable.
 
Item 2.   Properties
 
Property Overview
 
Our oil and gas operations are concentrated in various North American onshore areas in the United States and Canada. We also have offshore operations that are situated principally in the Gulf of Mexico and regions located offshore Azerbaijan, Brazil and China. As previously mentioned, we are in the process of divesting our offshore assets. Our properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage in these regions. These interests entitle us to drill for and produce oil, 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 net profits interests, foreign government concessions and other forms of direct and indirect ownership in oil and gas properties.
 
We also have certain midstream assets, including natural gas and NGL processing plants and pipeline systems. Our most significant midstream assets are our assets serving the Barnett Shale region in north Texas. These assets include approximately 3,100 miles of pipeline, two natural gas processing plants with 750 MMcf per day of total capacity, and a 15 MBbls per day NGL fractionator. To support our continued development and growing production in the Woodford Shale, located in southeastern Oklahoma, we constructed the Northridge natural gas processing plant in 2008. The Northridge plant has a capacity of 200 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 northern Alberta to a 350 MBbls storage terminal near Edmonton. The dual pipeline system allows us to blend the Jackfish heavy oil production with condensate and transport the combined product to the Edmonton crude oil market for sale. We have a 50% ownership interest in the Access Pipeline.


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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 North American Onshore properties are presented on the following map.
 
Map


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The following table presents proved reserve information for our key properties as of December 31, 2009, along with their production volumes for the year 2009. Additional summary profile information for our key properties is provided following the table. 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.
 
                                 
    Proved
    Proved
             
    Reserves
    Reserves
    Production
    Production
 
    (MMBoe)(1)     %(2)     (MMBoe)(1)     %(2)  
 
U.S. Onshore
                               
Barnett Shale
    1,027       37.6 %     69       29.6 %
Carthage
    182       6.7 %     14       6.4 %
Permian Basin, Texas
    127       4.6 %     9       3.9 %
Washakie
    93       3.4 %     7       3.0 %
Cana-Woodford Shale
    73       2.7 %     3       1.0 %
Arkoma-Woodford Shale
    47       1.7 %     5       2.0 %
Groesbeck
    43       1.6 %     6       2.6 %
Haynesville Shale
    6       0.2 %     1       0.3 %
Other U.S. Onshore
    280       10.2 %     40       17.1 %
                                 
Total U.S. Onshore
    1,878       68.7 %     154       65.9 %
                                 
U.S. Offshore
    92       3.4 %     13       5.7 %
                                 
Total U.S. 
    1,970       72.1 %     167       71.6 %
                                 
Canada
                               
Jackfish
    403       14.7 %     8       3.4 %
Northwest
    117       4.3 %     16       7.3 %
Lloydminster
    81       3.0 %     16       6.7 %
Deep Basin
    59       2.2 %     12       5.0 %
Horn River Basin
    2                    
Other Canada
    101       3.7 %     14       6.0 %
                                 
Total Canada
    763       27.9 %     66       28.4 %
                                 
North America
    2,733       100.0 %     233       100.0 %
                                 
 
 
(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.
 
U.S. Onshore
 
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 663,000 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 336 gross wells in 2009 and plan to drill approximately 370 gross wells in 2010.


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Carthage — The Carthage area in east Texas includes primarily Harrison, Marion, Panola and Shelby counties. Our average working interest is about 86% and we hold approximately 218,000 net acres. Our Carthage area wells produce primarily natural gas and NGLs from conventional reservoirs. We drilled 39 gross wells in 2009 and plan to drill approximately 30 gross wells in 2010.
 
Permian Basin, Texas — Our oil and gas properties in the Permian Basin of west Texas comprise approximately 850,000 net acres located across several counties in west Texas. These properties produce both oil and gas from conventional reservoirs. Our average working interest in these properties is about 40%. In 2009, we drilled 80 gross wells and plan to drill approximately 220 gross wells in 2010.
 
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 157,000 net acres in the area. The Washakie wells produce primarily natural gas from conventional reservoirs. In 2009, we drilled 94 gross wells and plan to drill approximately 115 gross wells in 2010.
 
Cana-Woodford Shale — The Cana-Woodford Shale is located in Canadian, Blaine and Caddo counties in western Oklahoma. Our average working interest is approximately 46% and we hold approximately 117,000 net acres. Our Cana-Woodford Shale properties produce natural gas and NGLs from a non-conventional reservoir. We drilled 47 gross wells in 2009 and plan to drill approximately 85 gross wells in 2010. To support our growing production in the Cana-Woodford Shale, we are building a 200 MMcf per day natural gas processing facility. We expect to complete this facility in early 2011.
 
Arkoma-Woodford Shale — Our Arkoma-Woodford Shale properties in southeastern Oklahoma produce natural gas and NGLs from a non-conventional reservoir. Our 58,000 net acres are concentrated in Coal and Hughes counties, and we have an average working interest of about 32%. In 2009, we drilled 61 gross wells in this area and plan to drill approximately 85 gross wells in 2010.
 
Groesbeck — The Groesbeck area of east Texas includes portions of Freestone, Leon, Limestone and Robertson counties. Our average working interest is approximately 72% and we hold about 132,000 net acres of land. The Groesbeck wells produce primarily natural gas from conventional reservoirs. In 2009, we drilled 13 gross wells and plan to drill approximately 10 gross wells in 2010.
 
Haynesville Shale — Our Haynesville Shale acreage spans across east Texas and north Louisiana with an average working interest of 92%. To date, our drilling activity has been focused on de-risking the 157,000 acres located in Panola, Shelby and San Augustine counties in east Texas. We drilled 8 gross wells in 2009 and plan to drill approximately 30 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. In late 2009, Jackfish’s gross production reached 33.7 MBbls of oil per day. Gross peak production is expected to be 35 MBbls per day with a flat production profile for greater than 20 years. We are currently constructing the second phase of Jackfish and evaluating the potential for a third phase. The second and third phases of Jackfish are each expected to also eventually produce 35 MBbls per day of heavy oil production.
 
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 and NGLs from conventional reservoirs. Our average working interest in the area is approximately 73%. In 2009, we drilled 36 gross wells and plan to drill approximately 55 gross wells in 2010.
 
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 2.5 million net acres and have an 89% average working interest in our Lloydminster properties. In 2009, we drilled 239 gross wells and plan to drill approximately 140 gross wells in 2010.
 
Deep Basin — Our properties in Canada’s Deep Basin include portions of west central Alberta and east central British Columbia. We hold approximately 570,000 net acres in the Deep Basin. The area produces


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primarily natural gas and natural gas liquids from conventional reservoirs. Our average working interest in the Deep Basin is 45%. In 2009, we drilled 30 gross wells and plan to drill approximately 35 gross wells in 2010.
 
Horn River Basin — The Horn River Basin, located in northeast British Columbia, is a non-conventional reservoir targeting the Devonian Shale. Our leases include approximately 170,000 net acres with a 100% working interest. We drilled 2 gross wells in 2009. During 2010, we plan to drill 11 gross wells, consisting of 7 horizontal wells and 4 vertical stratigraphic-test wells.
 
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 and the Group’s key members all have the qualifications listed above. Additionally, the Group reports independently of any of our operating divisions. The Group’s Director reports to our Senior Vice President of Strategic Development, who reports to our President. 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 2009, we engaged three such firms to both prepare and audit a significant portion of our proved reserves. Ryder Scott Company, L.P. prepared the 2009 reserve estimates for all of our offshore Gulf of Mexico properties and for 99% of our International proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2009 reserve estimates for 93% of our domestic onshore properties. AJM Petroleum Consultants audited 91% of our Canadian reserves.


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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 2009, 2008 and 2007.
 
                                                 
    2009     2008     2007  
    Prepared     Audited     Prepared     Audited     Prepared     Audited  
 
U.S. Onshore
          93 %           92 %           88 %
U.S. Offshore
    100 %           100 %           100 %      
Total U.S. 
    5 %     89 %     5 %     87 %     6 %     82 %
Canada
          91 %           78 %     34 %     51 %
Total North America
    3 %     89 %     4 %     85 %     15 %     73 %
 
“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. 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 principles.
 
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. Although we are not required to have a Reserves Committee, we established ours in 2004 to provide additional oversight of our reserves estimation and certification process. The Reserves Committee was designed to assist 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 at least twice a year to discuss reserves issues and policies, and periodically meets separately with our senior reserves engineering personnel and our independent petroleum consultants. The responsibilities of the Reserves Committee include the following:
 
  •  perform an annual review and evaluation of our consolidated oil, gas and NGL reserves;
 
  •  verify the integrity of our reserves evaluation and reporting system;
 
  •  evaluate, prepare and disclose our compliance with legal and regulatory requirements related to our oil, gas and NGL reserves;
 
  •  investigate and verify the qualifications and independence of our independent engineering consultants;
 
  •  monitor the performance of our independent engineering consultants; and
 
  •  monitor and evaluate our business practices and ethical standards in relation to the preparation and disclosure of reserves.


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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, 2009. 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.
 
                                 
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Proved Reserves
                               
U.S. Onshore
    139       8,127       385       1,878  
U.S. Offshore
    33       342       2       92  
                                 
Total U.S. 
    172       8,469       387       1,970  
Canada
    514       1,288       34       763  
                                 
Total North America
    686       9,757       421       2,733  
                                 
Proved Developed Reserves
                               
U.S. Onshore
    119       6,447       293       1,486  
U.S. Offshore
    21       185       1       53  
                                 
Total U.S. 
    140       6,632       294       1,539  
Canada
    149       1,213       32       383  
                                 
Total North America
    289       7,845       326       1,922  
                                 
Proved Undeveloped Reserves
                               
U.S. Onshore
    20       1,680       92       392  
U.S. Offshore
    12       157       1       39  
                                 
Total U.S. 
    32       1,837       93       431  
Canada
    365       75       2       380  
                                 
Total North America
    397       1,912       95       811  
                                 
 
 
(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 2009 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.


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Proved Developed Reserves
 
As presented in the previous table, we had 1,922 MMBoe of proved developed reserves at December 31, 2009. 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, 2009.
 
                                 
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Proved Developed Producing Reserves
                               
U.S. Onshore
    111       5,859       265       1,354  
U.S. Offshore
    12       137       1       35  
                                 
Total U.S. 
    123       5,996       266       1,389  
Canada
    137       1,075       28       344  
                                 
Total North America
    260       7,071       294       1,733  
                                 
Proved Developed Non-Producing Reserves
                               
U.S. Onshore
    8       588       28       132  
U.S. Offshore
    9       48             18  
                                 
Total U.S. 
    17       636       28       150  
Canada
    12       138       4       39  
                                 
Total North America
    29       774       32       189  
                                 
 
 
(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 2009 (in MMBoe).
 
         
Proved undeveloped reserves as of December 31, 2008
    424  
Revisions due to prices
    174  
Revisions other than price
    (22 )
Extensions and discoveries
    316  
Conversion to proved developed reserves
    (81 )
         
Proved undeveloped reserves as of December 31, 2009
    811  
         
 
During 2009, our proved undeveloped reserves increased 91%. A large contributor to the increase was our 2009 drilling activities, which increased our proved undeveloped reserves 316 MMBoe. Also as a result of 2009 drilling activities, we converted 81 MMBoe, or 19%, of the 2008 proved undeveloped reserves to proved developed reserves.
 
Our proved undeveloped reserves at the end of 2009 largely relate to our operations at Jackfish and the Barnett Shale. Additionally, the 2009 positive revisions due to prices largely related to Jackfish. At the end of 2008, none of our Jackfish reserves were classified as proved due to low oil prices. However, as oil prices rebounded during 2009, our Jackfish reserves, including the reserves that were undeveloped at the end of 2008, once again became economic and were classified as proved at the end of 2009. The positive revision related to Jackfish reserves was partially offset by decreases in proved undeveloped gas reserves related to certain of our North American Onshore properties.


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At the end of 2009, approximately 1% of our proved reserves had been classified as proved undeveloped for more than five years. The majority of such reserves relate to our deepwater Gulf of Mexico operations where sanctioned development projects often take longer than five years to complete.
 
Proved Reserves Cash Flows
 
The following table presents estimated cash flow information related to our December 31, 2009 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.
 
                         
    Total
    Proved
    Proved
 
    Proved
    Developed
    Undeveloped
 
    Reserves     Reserves     Reserves  
    (In millions)  
 
Pre-Tax Future Net Revenue(1)
                       
United States
  $ 15,573     $ 13,381     $ 2,192  
Canada
    14,463       6,127       8,336  
                         
Total North America
  $ 30,036     $ 19,508     $ 10,528  
                         
Pre-Tax 10% Present Value(1)
                       
United States
  $ 7,630     $ 7,452     $ 178  
Canada
    7,243       4,210       3,033  
                         
Total North America
  $ 14,873     $ 11,662     $ 3,211  
                         
Standardized Measure of Discounted Future Net Cash Flows(1)(2)
                       
United States
  $ 5,880                  
Canada
    5,523                  
                         
Total North America
  $ 11,403                  
                         
 
 
(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, 2009. 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 $47.80 per Bbl of oil, $3.12 per Mcf of gas and $22.78 per Bbl of NGLs. Costs included in future net revenues are determined in a similar manner. 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, 2009. 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 $11.4 billion at the end of 2009. Included as part of standardized measure were discounted future income taxes of $3.4 billion. Excluding these taxes, the present value of our pre-tax future net revenue (“pre-tax 10% present value”) was $14.8 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,


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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.
 
                                 
    Year Ended December 31, 2009  
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Production
                               
Barnett Shale
          331       13       69  
Other United States fields
    17       412       13       98  
                                 
Total United States
    17       743       26       167  
                                 
Jackfish
    8                   8  
Other Canada fields
    17       223       4       58  
                                 
Total Canada
    25       223       4       66  
                                 
Total North America
    42       966       30       233  
                                 
 
                                 
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Combined(1)
 
    (Per Bbl)      (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Production Prices
                               
Barnett Shale
  $ 58.78     $ 2.99     $ 22.36     $ 19.08  
Total United States
  $ 57.56     $ 3.20     $ 23.51     $ 23.71  
Jackfish
  $ 41.07                 $ 41.07  
Total Canada
  $ 47.35     $ 3.66     $ 33.09     $ 32.29  
Total North America
  $ 51.39     $ 3.31     $ 24.71     $ 26.15  
 
                                 
    Year Ended December 31, 2008  
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Production
                               
Barnett Shale
          321       12       66  
Other United States fields
    17       405       12       96  
                                 
Total United States
    17       726       24       162  
                                 
Jackfish
    4                   4  
Other Canada fields
    18       212       4       57  
                                 
Total Canada
    22       212       4       61  
                                 
Total North America
    39       938       28       223  
                                 
 


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    Year Ended December 31, 2008  
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Combined(1)
 
    (Per Bbl)      (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Production Prices
                               
Barnett Shale
  $ 97.23     $ 7.38     $ 39.34     $ 43.71  
Total United States
  $ 98.83     $ 7.59     $ 41.21     $ 50.55  
Jackfish
  $ 50.67                 $ 50.67  
Total Canada
  $ 71.04     $ 8.17     $ 61.45     $ 57.65  
Total North America
  $ 83.35     $ 7.73     $ 44.08     $ 52.49  
 
                                 
    Year Ended December 31, 2007  
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Production
                               
Barnett Shale
          238       10       50  
Other United States fields
    19       397       12       96  
                                 
Total United States
    19       635       22       146  
Total Canada
    16       227       4       58  
                                 
Total North America
    35       862       26       204  
                                 
 
                                 
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Combined(1)
 
    (Per Bbl)      (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Production Prices
                               
Barnett Shale
  $ 70.61     $ 5.63     $ 34.68     $ 34.28  
Total United States
  $ 69.23     $ 5.87     $ 36.11     $ 39.77  
Total Canada
  $ 49.80     $ 6.24     $ 46.07     $ 41.51  
Total North America
  $ 60.30     $ 5.97     $ 37.76     $ 40.26  
 
 
(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.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
 
Barnett Shale
  $ 3.96     $ 4.34     $ 3.85  
Total United States
  $ 5.97     $ 6.62     $ 6.19  
Jackfish
  $ 12.75     $ 28.93        
Total Canada
  $ 10.15     $ 12.74     $ 10.80  
Total North America
  $ 7.16     $ 8.29     $ 7.50  

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Drilling Activities and Results
 
The following tables summarize our development and exploratory drilling results for the past three years.
 
                                                 
    Year Ended December 31, 2009  
    Development Wells(1)     Exploratory Wells(1)     Total Wells(1)  
    Productive     Dry     Productive     Dry     Productive     Dry  
 
U.S. Onshore
    506.5       3.0       6.8       1.5       513.3       4.5  
U.S. Offshore
    1.5       0.8             0.5       1.5       1.3  
                                                 
Total U.S. 
    508.0       3.8       6.8       2.0       514.8       5.8  
Canada
    307.2             28.2             335.4        
                                                 
Total North America
    815.2       3.8       35.0       2.0       850.2       5.8  
                                                 
 
                                                 
    Year Ended December 31, 2008  
    Development
             
    Wells(1)     Exploratory Wells(1)     Total Wells(1)  
    Productive     Dry     Productive     Dry     Productive     Dry  
 
U.S. Onshore
    1,024.0       17.5       12.8       2.0       1,036.8       19.5  
U.S. Offshore
    9.0       1.0       0.8       1.8       9.8       2.8  
                                                 
Total U.S. 
    1,033.0       18.5       13.6       3.8       1,046.6       22.3  
Canada
    528.9       3.2       50.1       3.3       579.0       6.5  
                                                 
Total North America
    1,561.9       21.7       63.7       7.1       1,625.6       28.8  
                                                 
 
                                                 
    Year Ended December 31, 2007  
    Development
             
    Wells(1)     Exploratory Wells(1)     Total Wells(1)  
    Productive     Dry     Productive     Dry     Productive     Dry  
 
U.S. Onshore
    974.4       21.1       10.1       4.0       984.5       25.1  
U.S. Offshore
    3.7             1.5       0.2       5.2       0.2  
                                                 
Total U.S. 
    978.1       21.1       11.6       4.2       989.7       25.3  
Canada
    531.2             83.3       1.5       614.5       1.5  
                                                 
Total North America
    1,509.3       21.1       94.9       5.7       1,604.2       26.8  
                                                 
 
 
(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, 2010, of our wells that were in progress as of December 31, 2009.
 
                                                                 
    Productive     Dry     Still in Progress     Total  
    Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)  
 
U.S. Onshore
    13       9.1                   46       33.2       59       42.3  
U.S. Offshore
                            3       1.5       3       1.5  
                                                                 
Total U.S. 
    13       9.1                   49       34.7       62       43.8  
Canada
    18       13.7                   3       2.5       21       16.2  
                                                                 
Total North America
    31       22.8                   52       37.2       83       60.0  
                                                                 
 
 
(1) Gross wells are the sum of all wells in which we own an interest.


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(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, 2009.
 
                                                 
    Oil Wells     Natural Gas Wells     Total Wells  
    Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)  
 
U.S. Onshore
    8,301       2,901       19,792       13,442       28,093       16,343  
U.S. Offshore
    359       284       204       138       563       422  
                                                 
Total U.S. 
    8,660       3,185       19,996       13,580       28,656       16,765  
Canada
    4,830       3,661       5,560       3,241       10,390       6,902  
                                                 
Total North America
    13,490       6,846       25,556       16,821       39,046       23,667  
                                                 
 
 
(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, 2009.
 
                                                 
    Developed     Undeveloped     Total  
    Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)  
                (In thousands)              
 
U.S. Onshore
    3,357       2,268       6,064       3,318       9,421       5,586  
U.S. Offshore
    258       139       1,809       1,029       2,067       1,168  
                                                 
Total U.S. 
    3,615       2,407       7,873       4,347       11,488       6,754  
Canada
    3,630       2,253       7,688       5,088       11,318       7,341  
                                                 
Total North America
    7,245       4,660       15,561       9,435       22,806       14,095  
                                                 
 
 
(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 24,221 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.


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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.
 
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.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
There were no matters submitted to a vote of security holders during the fourth quarter of 2009.


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PART II
 
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 15, 2010, there were 13,740 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 2009 and 2008. Also, included are the quarterly dividends per share paid during 2009 and 2008. 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.
 
                         
    Price Range of Common Stock     Dividends
 
    High     Low     Per Share  
 
2009:
                       
Quarter Ended March 31, 2009
  $ 73.11     $ 38.55     $ 0.16  
Quarter Ended June 30, 2009
  $ 67.40     $ 43.35     $ 0.16  
Quarter Ended September 30, 2009
  $ 72.91     $ 48.74     $ 0.16  
Quarter Ended December 31, 2009
  $ 75.05     $ 62.60     $ 0.16  
2008:
                       
Quarter Ended March 31, 2008
  $ 108.13     $ 74.56     $ 0.16  
Quarter Ended June 30, 2008
  $ 127.16     $ 101.31     $ 0.16  
Quarter Ended September 30, 2008
  $ 127.43     $ 82.10     $ 0.16  
Quarter Ended December 31, 2008
  $ 91.69     $ 54.40     $ 0.16  


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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, 2004 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
 
(COMPANY LOGO)
 
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
 
During 2009, we had two programs in effect in which our Board of Directors had authorized the repurchase of up to 54.8 million shares of our common stock. We did not repurchase any shares under these programs in 2009. These plans expired on December 31, 2009.
 
New York Stock Exchange Certifications
 
This Form 10-K includes as exhibits the certifications of our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, 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 2009 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
 
The following selected financial information (not covered by the report of our independent registered public accounting firm) should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.”
 
                                         
    Year Ended December 31,  
    2009     2008     2007     2006     2005  
    (In millions, except per share data, ratios,
 
    prices and per Boe amounts)  
 
Operating Results
                                       
Revenues
  $ 8,015     $ 13,858     $ 9,975     $ 9,143     $ 9,630  
Total expenses and other income, net(1)
    12,541       18,018       6,648       5,957       5,477  
                                         
(Loss) earnings from continuing operations before income taxes
    (4,526 )     (4,160 )     3,327       3,186       4,153  
Total income tax (benefit) expense
    (1,773 )     (1,121 )     842       870       1,413  
                                         
(Loss) earnings from continuing operations
    (2,753 )     (3,039 )     2,485       2,316       2,740  
Earnings from discontinued operations(1)
    274       891       1,121       530       190  
                                         
Net (loss) earnings
  $ (2,479 )   $ (2,148 )   $ 3,606     $ 2,846     $ 2,930  
                                         
Net (loss) earnings applicable to common stockholders
  $ (2,479 )   $ (2,153 )   $ 3,596     $ 2,836     $ 2,920  
                                         
Basic net (loss) earnings per share:
                                       
(Loss) earnings from continuing operations
  $ (6.20 )   $ (6.86 )   $ 5.56     $ 5.22     $ 5.96  
Earnings from discontinued operations
    0.62       2.01       2.52       1.20       0.42  
                                         
Net (loss) earnings
  $ (5.58 )   $ (4.85 )   $ 8.08     $ 6.42     $ 6.38  
                                         
Diluted net (loss) earnings per share:
                                       
(Loss) earnings from continuing operations
  $ (6.20 )   $ (6.86 )   $ 5.50     $ 5.15     $ 5.86  
Earnings from discontinued operations
    0.62       2.01       2.50       1.19       0.40  
                                         
Net (loss) earnings
  $ (5.58 )   $ (4.85 )   $ 8.00     $ 6.34     $ 6.26  
                                         
Cash dividends per common share
  $ 0.64     $ 0.64     $ 0.56     $ 0.45     $ 0.30  
Ratio of earnings to fixed charges(1)(2)
    N/A       N/A       6.97       7.11       7.67  
Ratio of earnings to combined fixed charges and preferred stock dividends(1)(2)
    N/A       N/A       6.78       6.91       7.49  
Cash Flow Data
                                       
Net cash provided by operating activities
  $ 4,737     $ 9,408     $ 6,651     $ 5,993     $ 5,612  
Net cash used in investing activities
  $ (5,354 )   $ (6,873 )   $ (5,714 )   $ (7,449 )   $ (1,652 )
Net cash provided by (used in) financing activities
  $ 1,201     $ (3,408 )   $ (371 )   $ 593     $ (3,543 )
Production, Price and Other Data(3)
                                       
Production:
                                       
Oil (MMBbls)
    42       39       35       32       38  
Gas (Bcf)
    966       938       862       807       816  
NGLs (MMBbls)
    30       28       26       23       24  
Total (MMBoe)(4)
    233       223       204       190       198  
Realized prices without hedges:
                                       
Oil (per Bbl)
  $ 51.39     $ 83.35     $ 60.30     $ 56.18     $ 47.90  
Gas (per Mcf)
  $ 3.31     $ 7.73     $ 5.97     $ 6.03     $ 7.08  
NGLs (per Bbl)
  $ 24.71     $ 44.08     $ 37.76     $ 32.10     $ 29.05  
Combined (per Boe)(4)
  $ 26.15     $ 52.49     $ 40.26     $ 39.09     $ 41.96  
Lease operating expenses per Boe(4)
  $ 7.16     $ 8.29     $ 7.50     $ 6.48     $ 5.60  
Depreciation, depletion and amortization of oil and gas properties per Boe(4)
  $ 7.86     $ 13.20     $ 11.81     $ 10.28     $ 8.62  


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    December 31,  
    2009     2008     2007     2006     2005  
    (In millions)  
 
Balance Sheet Data
                                       
Total assets(1)
  $ 29,686     $ 31,908     $ 41,456     $ 35,063     $ 30,273  
Long-term debt
  $ 5,847     $ 5,661     $ 6,924     $ 5,568     $ 5,957  
Stockholders’ equity
  $ 15,570     $ 17,060     $ 22,006     $ 17,442     $ 14,862  
 
 
(1) During 2009 and 2008, we recorded noncash reductions of carrying value of oil and gas properties totaling $6.4 billion ($4.1 billion after income taxes) and $9.9 billion ($6.7 billion after income taxes), respectively, related to our continuing operations as discussed in Note 15 of the consolidated financial statements. During 2009, 2008 and 2007 we recorded noncash reductions of carrying value of oil and gas properties totaling $108 million ($105 million after taxes), $494 million ($465 million after taxes) and $68 million ($13 million after taxes) related to our discontinued operations as discussed in Note 18 of the consolidated financial statements.
 
(2) For purposes of calculating the ratio of earnings to fixed charges and the ratio of earnings to combined fixed charges and preferred stock dividends, (i) earnings consist of earnings from continuing operations before income taxes, plus fixed charges; (ii) fixed charges consist of interest expense and one-third of rental expense estimated to be attributable to interest; and (iii) preferred stock dividends consist of the amount of pre-tax earnings required to pay dividends on the preferred stock that was outstanding until June 2008.
 
     For 2009, earnings from continuing operations were inadequate to cover fixed charges by $4.6 billion. For 2008, earnings from continuing operations were inadequate to cover fixed charges and combined fixed charges and preferred stock dividends by $4.2 billion. These earnings relationships were primarily the result of the noncash reductions of the carrying values of certain oil and gas properties referred to above.
 
(3) The amounts presented under “Production, Price and Other Data” exclude the amounts related to our discontinued international operations. The price data presented excludes the effects of unrealized and realized gains and losses from our oil and gas derivative financial instruments.
 
(4) 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 respective prices of oil, gas and NGLs are affected by market and other factors in addition to relative energy content.
 
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 2009 Results
 
  •  Business and Industry Outlook
 
  •  Results of Operations
 
  •  Capital Resources, Uses and Liquidity
 
  •  Contingencies and Legal Matters


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  •  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 reserves, production, earnings and cash flows, all on a per 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 us meet our production goals.
 
  •  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.
 
Approximately two-thirds of our planned 2010 investment in capital projects is dedicated to a foundation of low-risk projects in our North American Onshore properties. The remainder of our capital has been identified for longer-term projects primarily in new unconventional natural gas plays in several U.S. Onshore regions, as well as offshore activities in the Gulf of Mexico. By deploying our capital in this manner, we are able to consistently deliver cost-efficient drill-bit growth and provide a strong source of cash flow while balancing short-term and long-term growth targets. The timing of closing the planned sales of our Gulf of Mexico properties will impact exactly how much of our 2010 capital is used on our Gulf of Mexico assets.
 
  •  High margin assets — Like many investors, 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 rates. Combined with appropriate revenue and cost-management strategies, high drilling success rates are important to generating competitive returns on our capital investment. During 2009, we drilled 1,135 wells and 99% of those were successful. The 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 2009 was


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  approximately 70% gas and 30% 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 our Jackfish 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 North American 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 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 activity, weather and other factors that are beyond our control. To manage this volatility, we utilize financial hedging arrangements and fixed-price physical delivery contracts. As of February 15, 2010, approximately 53% of our 2010 gas production is associated with financial price swaps and collars. Additionally, approximately 65% of our 2010 oil production is associated with financial price collars.
 
  •  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 2009 Results
 
2009 was a pivotal year for us as we began repositioning Devon to focus entirely on our high-return, North American Onshore natural gas and oil portfolio. We grew North American Onshore production more than six percent in 2009 and replaced more than twice our production with the drill bit at very attractive costs. The performance of these assets is reflected in our earnings, which steadily increased over the last three quarters of 2009.
 
However, our full year 2009 results were significantly impacted by the downward pressure in oil and natural gas prices that began in the last half of 2008 and continued throughout 2009. The Henry Hub natural gas index average for 2009 was 56% lower than 2008. Although crude prices have improved since the end of 2008, the 2009 West Texas Intermediate oil index average was 38% lower than 2008.
 
The lower oil and gas prices significantly impacted our first quarter 2009 earnings, which in turn impacted our full year earnings. During 2009, we incurred a net loss of $2.5 billion, or $5.58 per diluted share. These amounts are the result of a noncash impairment of our oil and gas properties that was recognized in the first quarter of 2009 and totaled $4.2 billion, net of income taxes. Substantially all of this noncash charge was the result of the drop in natural gas prices during the first quarter of 2009.
 
Key measures of our performance for 2009, as well as certain operational developments, are summarized below:
 
  •  Production grew 4% over 2008, to 233 million Boe.


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  •  The combined realized price for oil, gas and NGLs per Boe decreased 50% to $26.15.
 
  •  Oil and gas hedges generated net gains of $384 million in 2009, including cash receipts of $505 million.
 
  •  Marketing and midstream operating profit decreased 25% to $512 million.
 
  •  Per unit lease operating costs decreased 14% to $7.16 per Boe.
 
  •  Operating cash flow decreased to $4.7 billion, representing a 50% decrease over 2008.
 
  •  Capitalized costs incurred in our oil and gas activities were $4.1 billion in 2009.
 
From an operational perspective, we completed another successful year with the drill-bit. We drilled 1,135 gross wells with an overall 99% rate of success. This success rate enabled us to increase proved reserves by 496 million Boe, which was more than double our 2009 production. Our drilling success was driven by North American Onshore development wells, which represented 95% of the wells drilled.
 
Besides another successful year of North American Onshore drilling, we had several other key operational achievements during 2009. The first phase of our 100%-owned Jackfish thermal heavy oil project in the Alberta oil sands was operational throughout 2009. As measured by production per well and steam-to-oil ratio, Jackfish is one of Canada’s most successful steam-assisted gravity drainage projects. In late 2009, Jackfish’s gross production reached 33.7 MBbls of oil per day. The addition of four more producing wells is expected to push production to the facility’s capacity of 35 MBbls per day in early 2010.
 
We continued construction throughout 2009 on a second phase of the Jackfish project. Jackfish 2 is also sized to produce 35 MBbls of oil per day and will commence operations in 2011. Further expansion into a third phase of Jackfish is planned for 2010. We expect to file a regulatory application for Jackfish 3 in the third quarter of 2010.
 
Elsewhere in North America, we are expanding and developing five natural gas shale plays where we own a total of 1.6 million net acres. At the Barnett Shale, the most mature of our shale plays, we pushed our total producing wells to almost 4,200 at the end of 2009, and we exited the year producing just over one Bcfe per day. In the Cana-Woodford Shale and Arkoma-Woodford Shale, we drilled a total of 108 wells, increasing reserves to 120 MMBoe. In the Haynesville Shale, our drilling has been focused on de-risking our acreage in the greater Carthage area of east Texas. Finally, at Horn River, we have assembled a portfolio of acreage that requires minimal drilling to hold. We are in the early stages of evaluating the full potential of these leases and formulating a development plan.
 
Even with the net loss, we maintained a solid financial position throughout 2009. We used operating cash flow, borrowings and cash on hand to fund $5.3 billion of capital expenditures and pay $284 million of dividends. At the end of 2009, we had $1.0 billion of cash and $1.8 billion of availability under our credit lines.
 
Business and Industry Outlook
 
Over the past decade we captured an abundance of resources. We pioneered horizontal drilling in the Barnett Shale field in north Texas 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 more than 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 high-growth, North American onshore exploration and production company. As part of this strategic repositioning, we plan to bring forward the value of our offshore assets located in the Gulf of Mexico and countries outside North America by divesting them.


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This repositioning is driven by our desire to unlock and accelerate the realization of the value underlying the deep inventory of opportunities we have. We have assembled a valuable portfolio of offshore assets, and we have a considerable inventory of premier North American onshore assets. However, our North American Onshore assets have consistently provided us our highest risk-adjusted investment returns. By selling our offshore assets, we can more aggressively pursue the untapped value of these North American Onshore opportunities.
 
We expect to receive after-tax proceeds of between $4.5 billion and $7.5 billion as we divest our U.S. Offshore and International properties in 2010. By using a portion of these proceeds to reduce debt, we will further strengthen our balance sheet. Besides reducing debt, the offshore divestiture proceeds are expected to provide significant funds to redeploy into our prolific North American Onshore opportunities. With these added funds, we plan to accelerate the growth and realization of the value of our North American Onshore assets.
 
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 are also divesting 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.
 
Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
 
Revenues
 
Our oil, gas and NGL production volumes from 2007 to 2009 are shown in the following table.
 
                                         
    Year Ended December 31,  
          2009 vs.
          2008 vs.
       
    2009     2008(2)     2008     2007(2)     2007  
 
Oil (MMBbls)
                                       
U.S. Onshore
    12       +3 %     11       +0 %     11  
Canada
    25       +17 %     22       +34 %     16  
                                         
North American Onshore
    37       +12 %     33       +20 %     27  
U.S. Offshore
    5       −15 %     6       −24 %     8  
                                         
Total
    42       +8 %     39       +10 %     35  
                                         
Gas (Bcf)
                                       
U.S. Onshore
    698       +5 %     669       +20 %     558  
Canada
    223       +5 %     212       −6 %     227  
                                         
North American Onshore
    921       +5 %     881       +12 %     785  
U.S. Offshore
    45       −22 %     57       −25 %     77  
                                         
Total
    966       +3 %     938       +9 %     862  
                                         


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    Year Ended December 31,  
          2009 vs.
          2008 vs.
       
    2009     2008(2)     2008     2007(2)     2007  
 
NGLs (MMBbls)
                                       
U.S. Onshore
    25       +9 %     24       +14 %     21  
Canada
    4       −5 %     4       −6 %     4  
                                         
North American Onshore
    29       +7 %     28       +11 %     25  
U.S. Offshore
    1       +27 %           −26 %     1  
                                         
Total
    30       +7 %     28       +10 %     26  
                                         
Total (MMBoe)(1)
                                       
U.S. Onshore
    154       +5 %     146       +17 %     124  
Canada
    66       +9 %     61       +5 %     58  
                                         
North American Onshore
    220       +6 %     207       +13 %     182  
U.S. Offshore
    13       −18 %     16       −25 %     22  
                                         
Total
    233       +4 %     223       +9 %     204  
                                         
 
 
(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 from 2007 to 2009. These prices exclude any effects due to our oil and gas derivative financial instruments.
 
                                         
    Year Ended December 31,  
          2009 vs.
          2008 vs.
       
    2009     2008(2)     2008     2007(2)     2007  
 
Oil (per Bbl)
                                       
U.S. Onshore
  $ 56.17       −41 %   $ 95.63       +42 %   $ 67.34  
Canada
  $ 47.35       −33 %   $ 71.04       +43 %   $ 49.80  
North American Onshore
  $ 50.11       −37 %   $ 79.45       +39 %   $ 56.99  
U.S. Offshore
  $ 60.75       −42 %   $ 104.90       +46 %   $ 71.95  
Total
  $ 51.39       −38 %   $ 83.35       +38 %   $ 60.30  
Gas (per Mcf)
                                       
U.S. Onshore
  $ 3.14       −58 %   $ 7.43       +30 %   $ 5.69  
Canada
  $ 3.66       −55 %   $ 8.17       +31 %   $ 6.24  
North American Onshore
  $ 3.27       −57 %   $ 7.61       +30 %   $ 5.85  
U.S. Offshore
  $ 4.20       −56 %   $ 9.53       +33 %   $ 7.17  
Total
  $ 3.31       −57 %   $ 7.73       +29 %   $ 5.97  

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    Year Ended December 31,  
          2009 vs.
          2008 vs.
       
    2009     2008(2)     2008     2007(2)     2007  
 
NGLs (per Bbl)
                                       
U.S. Onshore
  $ 23.40       −43 %   $ 40.97       +14 %   $ 36.08  
Canada
  $ 33.09       −46 %   $ 61.45       +33 %   $ 46.07  
North American Onshore
  $ 24.65       −44 %   $ 43.94       +16 %   $ 37.80  
U.S. Offshore
  $ 27.42       −46 %   $ 51.11       +39 %   $ 36.78  
Total
  $ 24.71       −44 %   $ 44.08       +17 %   $ 37.76  
Combined (per Boe)(1)
                                       
U.S. Onshore
  $ 22.41       −53 %   $ 47.91       +28 %   $ 37.45  
Canada
  $ 32.29       −44 %   $ 57.65       +39 %   $ 41.51  
North American Onshore
  $ 25.38       −50 %   $ 50.78       +31 %   $ 38.74  
U.S. Offshore
  $ 38.83       −48 %   $ 74.55       +40 %   $ 53.30  
Total
  $ 26.15       −50 %   $ 52.49       +30 %   $ 40.26  
 
 
(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 volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between 2007 and 2009.
 
                                 
    Oil     Gas     NGL     Total  
          (In millions)        
 
2007 sales
  $ 2,117     $ 5,138     $ 970     $ 8,225  
Changes due to volumes
    222       459       95       776  
Changes due to prices
    894       1,647       178       2,719  
                                 
2008 sales
    3,233       7,244       1,243       11,720  
Changes due to volumes
    258       222       89       569  
Changes due to prices
    (1,338 )     (4,269 )     (585 )     (6,192 )
                                 
2009 sales
  $ 2,153     $ 3,197     $ 747     $ 6,097  
                                 
 
Oil Sales
 
2009 vs. 2008 Oil sales decreased $1.3 billion as a result of a 38% decrease in our realized price without hedges. The average NYMEX West Texas Intermediate index price decreased 38% during the same time period, accounting for the majority of the decrease in our realized price.
 
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 our Jackfish thermal heavy oil project in Canada.
 
2008 vs. 2007 Oil sales increased $894 million as a result of a 38% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 38% during the same time period, accounting for the majority of the increase in our realized price.
 
Oil sales increased $222 million due to a four million barrel, or 10%, increase in production. Production from our Canadian operations increased approximately six million barrels in 2008 as a result of first oil sales

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at Jackfish and heavy oil development activity at Lloydminster. This increase was partially offset by the deferral of 0.5 million barrels of oil production from our U.S. Offshore properties due to hurricanes.
 
Gas Sales
 
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 28 Bcf, or 3%, increase in production during 2009 caused gas sales to increase by $222 million. Our North American 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 American 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.
 
2008 vs. 2007 Gas sales increased $1.6 billion as a result of a 29% 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 76 Bcf, or 9%, increase in production during 2008 caused gas sales to increase by $459 million. Our North American Onshore properties contributed 96 Bcf to our growth as a result of new drilling and development that exceeded natural production declines. This increase was led by our drilling and development program in the Barnett Shale, which contributed 83 Bcf to the gas production increase. This increase and the effect of new drilling and development in our other North American Onshore properties were partially offset by natural production declines and the deferral of seven Bcf of production in our U.S. Offshore properties in 2008 due to hurricanes.
 
NGL Sales
 
2009 vs. 2008 NGL sales decreased $585 million as a result of a 44% decrease in our realized price without hedges. This decrease was largely due to decreases in the regional index prices upon which our U.S. Onshore NGL sales are based. NGL sales increased $89 million in 2009 due to a two million barrel, or 7%, increase in production. The increase in production is primarily due to drilling and development in the Barnett Shale.
 
2008 vs. 2007 NGL sales increased $178 million as a result of a 17% increase in our realized price without hedges. This increase was largely due to increases in the regional index prices upon which our U.S. Onshore NGL sales are based. NGL sales increased $95 million in 2008 due to a two million barrel, or 10%, increase in production. The increase in production is primarily due to Barnett Shale drilling and development.


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Net Gain (Loss) on Oil and Gas Derivative Financial Instruments
 
The following tables provide financial information associated with our oil and gas derivative financial instruments from 2007 to 2009. 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 from 2007 to 2009. The prices do not include the effects of unrealized gains and losses.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In millions)  
 
Cash settlement receipts (payments):
                       
Gas price collars
  $ 450     $ (221 )   $ 2  
Gas price swaps
    55       (203 )     38  
Oil price collars
          27        
                         
Total cash settlements
    505       (397 )     40  
                         
Unrealized (losses) gains on fair value changes:
                       
Gas price collars
    (255 )     255       (4 )
Gas price swaps
    169       (12 )     (22 )
Gas basis swaps
    3              
Oil price collars
    (38 )            
                         
Total unrealized (losses) gains on fair value changes
    (121 )     243       (26 )
                         
Net gain (loss)
  $ 384     $ (154 )   $ 14  
                         
 
                                 
    Year Ended December 31, 2009  
    Oil
    Gas
    NGLs
    Total
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Realized price without hedges
  $ 51.39     $ 3.31     $ 24.71     $ 26.15  
Cash settlements of hedges
          0.52             2.16  
                                 
Realized price, including cash settlements
  $ 51.39     $ 3.83     $ 24.71     $ 28.31  
                                 
 
                                 
    Year Ended December 31, 2008  
    Oil
    Gas
    NGLs
    Total
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Realized price without hedges
  $ 83.35     $ 7.73     $ 44.08     $ 52.49  
Cash settlements of hedges
    0.70       (0.46 )           (1.78 )
                                 
Realized price, including cash settlements
  $ 84.05     $ 7.27     $ 44.08     $ 50.71  
                                 
 
                                 
    Year Ended December 31, 2007  
    Oil
    Gas
    NGLs
    Total
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Realized price without hedges
  $ 60.30     $ 5.97     $ 37.76     $ 40.26  
Cash settlements of hedges
          0.04             0.20  
                                 
Realized price, including cash settlements
  $ 60.30     $ 6.01     $ 37.76     $ 40.46  
                                 
 
Our oil and gas derivative financial instruments include price swaps, basis swaps and costless price collars. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. For the basis swaps, we receive a fixed differential between two regional gas index prices and pay a variable differential on the same two index prices 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


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floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty to the collars. Cash settlements as presented in the tables above represent realized gains or losses related to our price swaps and collars.
 
In addition to recognizing these cash settlement effects, we also recognize unrealized changes in the fair values of our oil and gas derivative instruments in each reporting period. We estimate the fair values of our oil and gas derivative financial instruments primarily by using internal discounted cash flow calculations. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers.
 
The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our 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. Based on the amount of volumes subject to our gas price swaps and collars at December 31, 2009, a 10% increase in these forward curves would have increased our 2009 unrealized losses for our gas derivative financial instruments by approximately $264 million. A 10% increase in the forward curves associated with our oil derivative financial instruments would have increased our 2009 unrealized losses by approximately $108 million. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility.
 
Counterparty credit risk is also a component of commodity derivative valuations. We have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with twelve separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our 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 our contracts. As of December 31, 2009, the credit ratings of all our counterparties were investment grade.
 
During 2009, the fair value of our oil and gas derivative financial instruments dropped by $121 million. This reduction largely resulted from the reversal of previously recorded unrealized gains on our gas price collar contracts, which was expected as the contracts settled throughout 2009 and expired on December 31, 2009. This reduction, as well as the reduction related to our oil price collars, were partially offset by unrealized gains on gas swap contracts that we entered into during 2009 and will be settled throughout 2010.
 
During 2008, the fair value of our gas derivative financial instruments increased by $243 million, which was largely due to a decrease in the Inside FERC Henry Hub forward curve.
 
Marketing and Midstream Revenues and Operating Costs and Expenses
 
The changes in marketing and midstream revenues, operating costs and expenses and the resulting operating profit between 2007 and 2009 are shown in the table below.
 
                                         
    Year Ended December 31,  
          2009 vs
          2008 vs
       
    2009     2008(1)     2008     2007(1)     2007  
    ($ in millions)  
 
Marketing and midstream:
                                       
Revenues
  $ 1,534       −33 %   $ 2,292       +32 %   $ 1,736  
Operating costs and expenses
    1,022       −37 %     1,611       +32 %     1,217  
                                         
Operating profit
  $ 512       −25 %   $ 681       +31 %   $ 519  
                                         
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
2009 vs. 2008 Marketing and midstream revenues decreased $758 million and operating costs and expenses decreased $589 million, causing operating profit to decrease $169 million. Both revenues and


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expenses decreased primarily due to lower natural gas and NGL prices, partially offset by higher NGL production and gas pipeline throughput.
 
2008 vs. 2007 Marketing and midstream revenues increased $556 million and operating costs and expenses increased $394 million, causing operating profit to increase $162 million. Both revenues and expenses increased primarily due to higher natural gas and NGL prices and increased gas pipeline throughput.
 
Lease Operating Expenses (“LOE”)
 
The changes in LOE between 2007 and 2009 are shown in the table below.
 
                                         
    Year Ended December 31,  
          2009 vs.
          2008 vs.
       
    2009     2008(1)     2008     2007(1)     2007  
 
Lease operating expenses ($ in millions):
                                       
U.S. Onshore
  $ 838       −6 %   $ 893       +25 %   $ 712  
Canada
    673       −13 %     776       +24 %     627  
                                         
North American Onshore
    1,511       −10 %     1,669       +25 %     1,339  
U.S. Offshore
    159       −13 %     182       −6 %     193  
                                         
Total
  $ 1,670       −10 %   $ 1,851       +21 %   $ 1,532  
                                         
Lease operating expenses per Boe:
                                       
U.S. Onshore
  $ 5.46       −11 %   $ 6.11       +7 %   $ 5.70  
Canada
  $ 10.15       −20 %   $ 12.74       +18 %   $ 10.80  
North American Onshore
  $ 6.87       −15 %   $ 8.06       +10 %   $ 7.32  
U.S. Offshore
  $ 11.98       +6 %   $ 11.29       +25 %   $ 9.04  
Total
  $ 7.16       −14 %   $ 8.29       +11 %   $ 7.50  
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
2009 vs. 2008 LOE decreased $181 million in 2009. LOE dropped $182 million due to declining costs for fuel, materials, equipment and personnel, as well as declines in maintenance and well workover projects. Such declines largely resulted from decreasing demand for field services due to lower oil and gas prices. Changes in the exchange rate between the U.S. and Canadian dollar reduced LOE $49 million. Additionally, LOE decreased $31 million as a result of hurricane damages in 2008 to certain of our U.S. Offshore facilities and transportation systems. These factors were also the main contributors to the decrease in LOE per Boe on our North American Onshore properties. Production growth at our large-scale Jackfish project also contributed to a decrease in LOE per Boe. As Jackfish production approached the facility’s capacity during 2009, its per-unit costs declined, contributing to lower overall LOE per Boe. The remainder of our 4% production growth added $81 million to LOE during 2009.
 
2008 vs. 2007 LOE increased $319 million in 2008. The largest individual contributor to this increase, as well as the increase in LOE per Boe, was higher per-unit costs associated with the new thermal heavy oil production at Jackfish in 2008. When large-scale projects such as Jackfish are in the early phases of production, per-unit operating costs are normally higher than the per-unit costs for our overall portfolio of producing properties. LOE also increased $144 million due to our 9% growth in production. Additionally, LOE increased $31 million due to hurricane damages in 2008 to certain of our U.S. Offshore facilities and transportation systems. These hurricane damages also contributed to the increase in LOE per Boe.


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Taxes Other Than Income Taxes
 
Taxes other than income taxes primarily consist of production taxes and ad valorem taxes assessed by various government agencies on our U.S. Onshore properties. Production taxes are based on a percentage of production revenues that varies by property and government jurisdiction. Ad valorem taxes generally are based on property values as determined by the government agency assessing the tax. The following table details the changes in our taxes other than income taxes between 2007 and 2009.
 
                                         
    Year Ended December 31,  
          2009 vs
          2008 vs
       
    2009     2008(1)     2008     2007(1)     2007  
    ($ in millions)  
 
Production
  $ 132       −57 %   $ 306       +41 %   $ 216  
Ad valorem
    175       +8 %     162       +19 %     135  
Other
    7       −4 %     8       +20 %     7  
                                         
Total
  $ 314       −34 %   $ 476       +33 %   $ 358  
                                         
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
2009 vs. 2008 Production taxes decreased $174 million in 2009. This decrease was largely due to lower U.S. Onshore revenues, as well as an increase in tax credits associated with certain properties in the state of Texas. Ad valorem taxes increased $13 million primarily due to higher assessed oil and gas property and equipment values.
 
2008 vs. 2007 Production taxes increased $90 million in 2008 primarily due to an increase in our U.S. Onshore revenues. Ad valorem taxes increased $27 million primarily due to higher assessed oil and gas property and equipment values.
 
Depreciation, Depletion and Amortization of Oil and Gas Properties (“DD&A”)
 
DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the year, by the “depletable base.” The depletable base represents our capitalized investment, net of accumulated DD&A and reductions of carrying value, plus future development costs related to proved undeveloped reserves. Generally, when reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, when the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.
 
The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties between 2007 and 2009 are shown in the table below.
 
                                         
    Year Ended December 31,  
          2009 vs
          2008 vs
       
    2009     2008(1)     2008     2007(1)     2007  
 
Total production volumes (MMBoe)
    233       +4 %     223       +9 %     204  
DD&A rate ($ per Boe)
  $ 7.86       −40 %   $ 13.20       +12 %   $ 11.81  
                                         
DD&A expense ($ in millions)
  $ 1,832       −38 %   $ 2,948       +22 %   $ 2,412  
                                         
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.


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The following table details the changes in DD&A of oil and gas properties between 2007 and 2009 due to the changes in production volumes and DD&A rate presented in the table above.
 
         
    (In millions)  
 
2007 DD&A
  $ 2,412  
Change due to volumes
    224  
Change due to rate
    312  
         
2008 DD&A
    2,948  
Change due to volumes
    130  
Change due to rate
    (1,246 )
         
2009 DD&A
  $ 1,832  
         
 
2009 vs. 2008 Oil and gas property related DD&A decreased $1.2 billion due to a 40% decrease in the DD&A rate. The largest contributors to the rate decrease were reductions of the carrying values of certain of our oil and gas properties recognized in the first quarter of 2009 and the fourth quarter of 2008. These reductions totaled $16.3 billion and resulted from full cost ceiling limitations in the United States and Canada. In addition, the effects of changes in the exchange rate between the U.S. and Canadian dollar also contributed to the rate decrease. These factors were partially offset by the effects of costs incurred and the transfer of previously unproved costs to the depletable base as a result of 2009 drilling activities. Partially offsetting the impact from the lower 2009 DD&A rate was our 4% production increase, which caused oil and gas property related DD&A expense to increase $130 million.
 
Our 2009 DD&A rate reflects our adoption of the SEC’s Modernization of Oil and Gas Reporting. The impact of adopting the SEC’s new rules at the end of 2009 had virtually no impact on our 2009 DD&A rate.
 
2008 vs. 2007 Oil and gas property related DD&A increased $312 million due to a 12% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on both the costs incurred during 2008 as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors that contributed to the rate increase were reductions in reserve estimates due to lower 2008 year-end commodity prices and the transfer of previously unproved costs to the depletable base as a result of 2008 drilling activities. In addition to the impact from the higher 2008 rate, the 9% production increase caused oil and gas property related DD&A expense to increase $224 million.
 
General and Administrative Expenses (“G&A”)
 
Our net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially offset by two components. One is the amount of G&A capitalized pursuant to the full cost method of accounting related to exploration and development activities. The other is the amount of G&A reimbursed by working interest owners of properties for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. Net G&A includes expenses related to oil, gas and NGL exploration


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and production activities, as well as marketing and midstream activities. See the following table for a summary of G&A expenses by component.
 
                                         
    Year Ended December 31,  
          2009 vs
          2008 vs
       
    2009     2008(1)     2008     2007(1)     2007  
    ($ in millions)  
 
Gross G&A
  $ 1,107       +0 %   $ 1,103       +24 %   $ 903  
Capitalized G&A
    (332 )     −2 %     (337 )     +26 %     (277 )
Reimbursed G&A
    (127 )     +5 %     (121 )     +7 %     (113 )
                                         
Net G&A
  $ 648       +0 %   $ 645       +26 %   $ 513  
                                         
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
2009 vs. 2008 Gross G&A increased $4 million. This increase was due to approximately $60 million of higher costs for employee compensation and benefits, mostly offset by the effects of our 2009 reduced spending initiatives for certain discretionary cost categories.
 
Employee cost increases in 2009 included an additional $57 million of severance costs. This increase was primarily due to Gulf of Mexico employees that were impacted by the integration of our Gulf of Mexico and International operations into one offshore unit in the second quarter of 2009 and other employee departures during 2009. Additionally, postretirement benefits costs increased approximately $50 million. The increases in employee costs were partially offset by a $27 million decrease due to accelerated share-based compensation expense recognized in 2008 as discussed below.
 
2008 vs. 2007 Gross G&A increased $200 million. The largest contributors to the increase were higher employee compensation and benefits costs. These cost increases, which were largely related to our growth and industry inflation during most of 2008, caused gross G&A to increase $164 million. Of this increase, $65 million related to higher stock compensation.
 
Stock compensation increased $43 million in 2008 due to a modification of the share-based compensation arrangements for certain executives. 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.
 
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 2008, certain executives had already met the years-of-service and age criteria. As a result, we recognized $27 million of share-based compensation expense in the second quarter of 2008 related to this modification. In the fourth quarter of 2008, we recognized an additional $16 million of stock compensation for grants made to these executives. The additional expenses would have been recognized in future reporting periods if the modification had not been made and the executives continued their employment at Devon.
 
The higher employee compensation and benefits costs, exclusive of the accelerated stock compensation expense, were also the primary factors that caused the $60 million increase in capitalized G&A in 2008.
 
Restructuring Costs
 
In the fourth quarter of 2009, we recognized $153 million of estimated employee severance costs associated with the planned divestitures of our offshore assets that was announced in November 2009. This amount was based on our estimates of the number of employees that will ultimately be impacted by the divestitures, and includes $63 million related to accelerated vesting of share-based grants. Of the $153 million


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total, $105 million relates to our U.S. Offshore operations and the remainder relates to our International discontinued operations.
 
As of the date of this report, only one of the properties we intend to sell had actually been sold. Furthermore, the vast majority of employees will not be impacted by the divestitures until the properties are sold. Therefore, our estimate of employee severance costs recognized in the fourth quarter of 2009 was based upon certain key estimates that could change as properties are sold. These estimates include the number of impacted employees, the number of employees offered comparable positions with the buyers and the date of separation for impacted employees. If our estimate of the number of impacted employees were to increase 10%, our estimate of employee severance costs would increase approximately $10 million. If our estimate of the number of employees offered comparable positions with the buyers were to decrease by 10%, our estimate of employee severance costs would increase approximately $15 million. Additionally, if the date of separation were to occur one month after our current estimates, our estimate of employee severance costs would increase approximately $2 million.
 
Interest Expense
 
The following table includes the components of interest expense between 2007 and 2009.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In millions)  
 
Interest based on debt outstanding
  $ 437     $ 426     $ 508  
Capitalized interest
    (94 )     (111 )     (102 )
Other
    6       14       24  
                         
Total interest expense
  $ 349     $ 329     $ 430  
                         
 
2009 vs. 2008 Interest based on debt outstanding increased $11 million from 2008 to 2009. This increase was primarily due to interest paid on the $500 million of 5.625% senior unsecured notes and $700 million of 6.30% senior unsecured notes that we issued in January 2009. This was partially offset by lower interest resulting from the retirement of our exchangeable debentures during the third quarter of 2008 and lower interest rates on our floating-rate commercial paper borrowings.
 
Capitalized interest decreased from 2008 to 2009 primarily due to the sales of our West African exploration and development properties in 2008 and the completion of the Access pipeline transportation system in Canada in the second quarter of 2008.
 
2008 vs. 2007 Interest based on debt outstanding decreased $82 million from 2007 to 2008. This decrease was largely due to lower average outstanding amounts for commercial paper and credit facility borrowings in 2008 than in 2007. The decrease in borrowings resulted largely from the use of proceeds from our West African divestiture program and cash flow from operations to repay all commercial paper and credit facility borrowings in the second quarter of 2008. Additionally, we retired debentures with a face value of $652 million during 2008, primarily during the third quarter.
 
Capitalized interest increased from 2007 to 2008 primarily due to higher cumulative costs related to large-scale development projects in the Gulf of Mexico, partially offset by lower capitalized interest resulting from the completion of the Access pipeline in the second quarter of 2008.


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Change in Fair Value of Other Financial Instruments
 
The details of the changes in fair value of other financial instruments between 2007 and 2009 are shown in the table below.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In millions)  
 
(Gains) losses from:
                       
Interest rate swaps — fair value changes
  $ (66 )   $ (104 )   $ (1 )
Interest rate swaps — settlements
    (40 )     (1 )      
Chevron common stock
          363       (281 )
Option embedded in exchangeable debentures
          (109 )     248  
                         
Total
  $ (106 )   $ 149     $ (34 )
                         
 
Interest Rate Swaps
 
We recognize unrealized changes in the fair values of our interest rate swaps each reporting period. We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest-rate yields. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers. In 2009 and 2008, we recorded unrealized gains of $66 million and $104 million, respectively, as a result of changes in interest rates. Also, during 2009 and 2008, we received cash settlements totaling $40 million and $1 million, respectively, from counterparties to settle our interest rate swaps. There were no cash settlements in 2007.
 
The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by a third party. Based on the notional amount subject to the interest rate swaps at December 31, 2009, a 10% increase in these forward curves would have increased our 2009 unrealized gain for our interest rate swaps by approximately $46 million.
 
Similar to our commodity derivative contracts, counterparty credit risk is also a component of interest rate derivative valuations. We have mitigated our exposure to any single counterparty by contracting with several counterparties. Our interest rate derivative contracts are held with seven separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our 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 our contracts. The credit ratings of all our counterparties were investment grade as of December 31, 2009.
 
Chevron Common Stock and Related Embedded Option
 
Until October 31, 2008, we owned 14.2 million shares of Chevron common stock and recognized unrealized changes in the fair value of this investment. On October 31, 2008, we exchanged these shares of Chevron common stock for Chevron’s interest in the Drunkard’s Wash properties located in east-central Utah and $280 million in cash. In accordance with the terms of the exchange, the fair value of our investment in the Chevron shares was estimated to be $67.71 per share on the exchange date. Prior to the exchange of these shares, we calculated the fair value of our investment in Chevron common stock using Chevron’s published market price.
 
We also recognized unrealized changes in the fair value of the conversion option embedded in the debentures exchangeable into shares of Chevron common stock. The embedded option was not actively traded in an established market. Therefore, we estimated its fair value using quotes obtained from a broker for trades occurring near the valuation date.


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The loss during 2008 on our investment in Chevron common stock was directly attributable to a $25.62 per share decrease in the estimated fair value while we owned Chevron’s common stock during the year. The gain on the embedded option during 2008 was directly attributable to the change in fair value of the Chevron common stock from January 1, 2008 to the maturity date of August 15, 2008. The gain on our investment in Chevron common stock and loss on the embedded option during 2007 were directly attributable to a $19.80 increase in the price per share of Chevron’s common stock during 2007.
 
Reduction of Carrying Value of Oil and Gas Properties
 
During 2009 and 2008, we reduced the carrying values of certain of our oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.
 
                                 
    Year Ended December 31,  
    2009     2008  
          Net of
          Net of
 
    Gross     Taxes     Gross     Taxes  
    (In millions)  
 
United States
  $ 6,408     $ 4,085     $ 6,538     $ 4,168  
Canada
                3,353       2,488  
                                 
Total
  $ 6,408     $ 4,085     $ 9,891     $ 6,656  
                                 
 
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.
 
To demonstrate these declines, the March 31, 2009, December 31, 2008 and September 30, 2008 weighted average wellhead prices are presented in the following table.
 
                                                                         
    March 31, 2009     December 31, 2008     September 30, 2008  
    Oil
    Gas
    NGLs
    Oil
    Gas
    NGLs
    Oil
    Gas
    NGLs
 
Country
  (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Bbl)     (Per Mcf)     (Per Bbl)  
 
United States
  $ 47.30     $ 2.67     $ 17.04     $ 42.21     $ 4.68     $ 16.16     $ 97.62     $ 5.28     $ 38.00  
Canada
    N/A       N/A       N/A     $ 23.23     $ 5.31     $ 20.89     $ 59.72     $ 6.00     $ 62.78  
 
 
N/A Not applicable.
 
The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $49.66 per Bbl for crude oil and the Henry Hub spot price of $3.63 per MMBtu for gas. The December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas. The September 30, 2008, wellhead prices in the table compare to the NYMEX cash price of $100.64 per Bbl for crude oil and the Henry Hub spot price of $7.12 per MMBtu for gas.


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Other Income
 
The following table includes the components of other income between 2007 and 2009.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In millions)  
 
Interest and dividend income
  $ 8     $ 54     $ 48  
Reduction of deep water royalties
    84              
Hurricane insurance proceeds
          162        
Other
    (24 )     1       3  
                         
Total
  $ 68     $ 217     $ 51  
                         
 
Interest and dividend income decreased from 2008 to 2009 due to a decrease in dividends received on our previously owned investment in Chevron common stock and a decrease in interest received on cash equivalents due to lower rates and balances. Interest and dividend income increased from 2007 to 2008 primarily due to higher cash balances partially offset by lower interest rates and a decrease in dividends received on our investment in Chevron common stock.
 
In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain years by the Minerals Management Service (the “MMS”) have 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. Additionally, in January 2009 a federal appellate court upheld this district court ruling. 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.
 
Prior to September 30, 2009, we had $84 million accrued for potential royalties on various deep water leases. Based upon the Supreme Court’s decision, we reduced to zero the $84 million loss contingency accrual in the third quarter of 2009.
 
In 2008, we 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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Income Taxes
 
The following table presents our total income tax (benefit) expense related to continuing operations and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate for each of the past three years. The primary factors causing our effective rates to vary from 2007 to 2009, and differ from the U.S. statutory rate, are discussed below.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
 
Total income tax (benefit) expense (In millions)
  $ (1,773 )   $ (1,121 )   $ 842  
                         
U.S. statutory income tax rate
    (35 )%     (35 )%     35 %
State income taxes
    (2 )%     (1 )%     1 %
Taxation on Canadian operations
    (1 )%     5 %      
Repatriations and tax policy election changes
          7 %      
Canadian statutory rate reduction
                (8 )%
Other
    (1 )%     (3 )%     (3 )%
                         
Effective income tax (benefit) expense rate
    (39 )%     (27 )%     25 %
                         
 
For 2008, our effective income tax rate differed from the U.S. statutory income tax rate largely due to two related factors. First, during 2008, we repatriated $2.6 billion from certain foreign subsidiaries to the United States. Second, we made certain tax policy election changes in the second quarter of 2008 to minimize the taxes we 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, we recognized additional tax expense of $312 million during 2008. Of the $312 million, $295 million was recognized as current income tax expense, and $17 million was recognized as deferred tax expense. Excluding the $312 million of additional tax expense, our effective income tax benefit rate would have been 34% for 2008.
 
In 2007, deferred income taxes were reduced $261 million due to a Canadian statutory rate reduction that was enacted in that year.
 
Earnings From Discontinued Operations
 
For all years presented in the following tables, our discontinued operations include amounts related to our assets in Azerbaijan, Brazil, China and other minor International properties that we are in the process of divesting. Additionally, during 2007 and 2008, our discontinued operations included amounts related to our assets in Egypt and West Africa, including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the


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region until they were sold. Following are the components of earnings from discontinued operations between 2007 and 2009.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
 
Total production (MMBoe)
    16       18       32  
Combined price without hedges (per Boe)
  $ 59.25     $ 92.72     $ 68.11  
     
    (In millions)
Operating revenues
  $ 945     $ 1,702     $ 2,168  
                         
Expenses and other income, net:
                       
Operating expenses
    484       769       597  
Restructuring costs
    48              
Reduction of carrying value of oil and gas properties
    108       494       68  
Gain on sale of oil and gas properties
    (17 )     (819 )     (90 )
                         
Total expenses and other income, net
    623       444       575  
                         
Earnings before income taxes
    322       1,258       1,593  
Income tax expense
    48       367       472  
                         
Earnings from discontinued operations
  $ 274     $ 891     $ 1,121  
                         
 
Our African sales generated total proceeds of $3.0 billion. The following table presents the gains on the African divestiture transactions by year.
 
                                                 
    Year Ended December 31,  
    2009     2008     2007  
          Net of
          Net of
          Net of
 
    Gross     Taxes     Gross     Taxes     Gross     Taxes  
    (In millions)  
 
Egypt
  $     $     $     $     $ 90     $ 90  
Equatorial Guinea
                619       544              
Gabon
                117       122              
Cote d’Ivoire
    17       17       83       95              
Other
                      8              
                                                 
Total
  $ 17     $ 17     $ 819     $ 769     $ 90     $ 90  
                                                 
 
2009 vs. 2008 Earnings from discontinued operations decreased $617 million in 2009. Our discontinued earnings were impacted by several factors. First, operating revenues declined largely due to a 36% decrease in the price realized on our production, which was driven by a decline in crude oil index prices. Second, both operating revenues and expenses declined due to divestitures that closed in 2008. Discontinued earnings also decreased due to $48 million of restructuring costs that relate to our planned divestitures and were recognized in the fourth quarter of 2009. These costs consist of employee severance costs. Earnings also decreased $752 million in 2009 due to larger gains recognized on West African asset divestitures in 2008.
 
Partially offsetting these decreased earnings in 2009 was the larger reduction of carrying value recognized in 2008 compared to 2009. The reductions largely consisted of full cost ceiling limitations related to our assets in Brazil that were caused by a decline in oil prices.
 
2008 vs. 2007 Earnings from discontinued operations decreased $230 million in 2008. Our earnings were impacted by several factors. First, operating revenues and expenses, including the related production volumes, decreased largely due to the timing of our 2008 and 2007 divestitures, partially offset by the effects of first production in Brazil. Discontinued earnings also decreased due to the net effect of reductions in carrying value recognized in 2008 and 2007, which largely related to our assets in Brazil. Discontinued earnings increased $679 million in 2008 due to the larger African divestiture gains in 2008.


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Capital Resources, Uses and Liquidity
 
The following discussion of capital resources, uses and liquidity should be read in conjunction with the consolidated financial statements included in “Financial Statements and Supplementary Data.”
 
Sources and Uses of Cash
 
The following table presents the sources and uses of our cash and cash equivalents from 2007 to 2009. The table presents capital expenditures on a cash basis. Therefore, these amounts differ from capital expenditure amounts that include accruals and are referred to elsewhere in this document. Additional discussion of these items follows the table.
 
                         
    2009     2008     2007  
    (In millions)  
 
Sources of cash and cash equivalents:
                       
Operating cash flow — continuing operations
  $ 4,232     $ 8,448     $ 5,308  
Sales of property and equipment
    34       117       76  
Net credit facility borrowings
                1,450  
Net commercial paper borrowings
    1,431       1        
Proceeds from debt issuance, net of commercial paper repayments
    182              
Net decrease in investments
    7       250       202  
Stock option exercises
    42       116       91  
Proceeds from exchange of Chevron stock
          280        
Cash distributed from discontinued operations
          1,898        
Other
    8       59       43  
                         
Total sources of cash and cash equivalents
    5,936       11,169       7,170  
                         
Uses of cash and cash equivalents:
                       
Capital expenditures
    (4,879 )     (8,843 )     (5,709 )
Net credit facility repayments
          (1,450 )      
Net commercial paper repayments
                (804 )
Debt repayments
    (178 )     (1,031 )     (567 )
Repurchases of common stock
          (665 )     (326 )
Redemption of preferred stock
          (150 )      
Dividends
    (284 )     (289 )     (259 )
Other
    (17 )            
                         
Total uses of cash and cash equivalents
    (5,358 )     (12,428 )     (7,665 )
                         
Increase (decrease) from continuing operations
    578       (1,259 )     (495 )
Increase from discontinued operations, net of distributions to continuing operations
    6       386       1,061  
Effect of foreign exchange rates
    43       (116 )     51  
                         
Net increase (decrease) in cash and cash equivalents
  $ 627     $ (989 )   $ 617  
                         
Cash and cash equivalents at end of year
  $ 1,011     $ 384     $ 1,373  
                         
Short-term investments at end of year
  $     $     $ 372  
                         


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Operating Cash Flow — Continuing Operations
 
Net cash provided by operating activities (“operating cash flow”) continued to be our primary source of capital and liquidity in 2009. Changes in operating cash flow from our continuing operations are largely due to the same factors that affect our net earnings, with the exception of those earnings changes due to such noncash expenses as DD&A, financial instrument fair value changes, property impairments and deferred income taxes. As a result, our operating cash flow decreased 50% during 2009 primarily due to the significant decrease in oil, gas and NGL sales, net of commodity hedge settlements, as discussed in the “Results of Operations” section of this report.
 
During 2009, our operating cash flow funded approximately 87% of our cash payments for capital expenditures. Commercial paper borrowings were used to fund the remainder of our cash-based capital expenditures. During 2008 and 2007 our capital expenditures were primarily funded by our operating cash flow and pre-existing cash balances.
 
Other Sources of Cash — Continuing and Discontinued Operations
 
As needed, we supplement our operating cash flow with cash on hand and access to our available credit under our credit facilities and commercial paper program. We may also issue long-term debt to supplement our operating cash flow while maintaining adequate liquidity under our credit facilities. Additionally, we sometimes acquire short-term investments to maximize our income on available cash balances. As needed, we may reduce our investment balances to further supplement our operating cash flow.
 
In January 2009, we issued $500 million of 5.625% senior unsecured notes due January 15, 2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds received of $1.187 billion, after discounts and issuance costs, were used primarily to repay Devon’s $1.005 billion of outstanding commercial paper as of December 31, 2008.
 
Subsequent to the $1.0 billion commercial paper repayment in January 2009, we utilized additional commercial paper borrowings of $1.4 billion to fund capital expenditure and dividend payments in excess of our operating cash flow during 2009.
 
During 2008, we reduced our short-term investment balances by $250 million. We also received $280 million from the exchange of our investment in Chevron common stock, $117 million from the sale of non-oil and gas property and equipment and $116 million from stock option exercises. Another significant source of cash was our African divestiture program. In 2008, we received $2.6 billion in proceeds ($1.9 billion net of income taxes and purchase price adjustments) from sales of assets located in Equatorial Guinea and other West African countries. Also, in conjunction with these asset sales, we repatriated an additional $2.6 billion of earnings from certain foreign subsidiaries to the United States. We used these combined sources of cash in 2008 to fund debt repayments, common stock repurchases, redemptions of preferred stock and dividends on common and preferred stock.
 
During 2007, we borrowed $1.5 billion under our unsecured revolving line of credit and reduced our short-term investment balances by $202 million. We also received $341 million of proceeds from the sale of our Egyptian operations. These sources of cash were used primarily to fund net commercial paper repayments, long-term debt repayments, common stock repurchases and dividends on common and preferred stock.


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Capital Expenditures
 
Following are the components of our capital expenditures for the years ended 2009, 2008 and 2007. The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred. Capital expenditures actually incurred during 2009, 2008 and 2007 were approximately $4.7 billion, $10.0 billion and $5.9 billion, respectively.
 
                         
    2009     2008     2007  
    (In millions)  
 
U.S. Onshore
  $ 2,413     $ 5,606     $ 3,280  
Canada
    1,064       1,459       1,232  
                         
North American Onshore
    3,477       7,065       4,512  
U.S. Offshore
    845       1,157       687  
                         
Total exploration and development
    4,322       8,222       5,199  
Midstream
    323       451       370  
Other
    234       170       141  
                         
Total continuing operations
  $ 4,879     $ 8,843     $ 5,710  
                         
 
Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling or development of oil and gas properties, which totaled $4.3 billion, $8.2 billion and $5.2 billion in 2009, 2008 and 2007, respectively. The decrease in capital expenditures from 2008 to 2009 was due to decreased drilling activities in most of our operating areas in response to lower commodity prices in 2009 compared to recent years. The 2008 capital expenditures include $2.6 billion related to acquisitions of properties in Texas, Louisiana, Oklahoma and Canada. Excluding the effect of the 2008 acquisitions, the increase in capital expenditures from 2007 to 2008 was due to increased drilling activities in the Barnett Shale, Gulf of Mexico, Carthage, Groesbeck and Washakie areas of the United States and the Lloydminster and Jackfish projects in Canada. Expenditures in the first half of 2008 also increased due to inflationary pressure driven by increased competition for field services.
 
Our capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. These midstream facilities exist primarily to support our oil and gas development operations. The majority of our midstream expenditures from 2007 to 2009 were related to development activities in the Barnett Shale, the Arkoma-Woodford Shale in southeastern Oklahoma, the Cana-Woodford Shale in western Oklahoma and Jackfish in Canada.
 
Net Repayments of Debt
 
Debt repayments in 2009 include the retirement of $177 million of 10.125% notes upon maturity in the fourth quarter.
 
During 2008, we repaid $1.5 billion in outstanding credit facility borrowings primarily with proceeds received from the sales of assets under our African divestiture program. Also during 2008, virtually all holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock owned by us. The debentures matured on August 15, 2008. In lieu of delivering our shares of Chevron common stock, we exercised our option to pay the exchanging debenture holders cash totaling $1.0 billion. This amount included the retirement of debentures with a book value of $652 million and a $379 million payment of the related embedded derivative option.
 
During 2007, we repaid the $400 million 4.375% notes, which matured on October 1, 2007. Also during 2007, certain holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock prior to the debentures’ August 15, 2008 maturity date. In lieu of delivering shares of Chevron common stock, we exercised our option to pay the exchanging debenture holders an amount of cash equal to the market value of Chevron common stock. We paid $167 million in cash to exchangeable


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debenture holders who exercised their exchange rights. This amount included the retirement of debentures with a book value of $105 million and a $62 million payment of the related embedded derivative option.
 
Repurchases of Common Stock
 
During 2008 and 2007, we repurchased 10.6 million shares at a total cost of $1.0 billion, or an average of $93.76 per share, under approved repurchase programs. No shares were repurchased in 2009. The following table summarizes our repurchases under approved plans during 2008 and 2007 (amounts and shares in millions). Both programs expired on December 31, 2009.
 
                                                 
    2008     2007  
Repurchase Program
  Amount     Shares     Per Share     Amount     Shares     Per Share  
 
Annual program
  $ 178       2.0     $ 87.83     $           $  
2007 program
    487       4.5     $ 109.25       326       4.1     $ 79.80  
                                                 
Totals
  $ 665       6.5     $ 102.56     $ 326       4.1     $ 79.80  
                                                 
 
Redemption of Preferred Stock
 
On June 20, 2008, we redeemed all 1.5 million outstanding shares of our 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
 
Our common stock dividends were $284 million (or a quarterly rate of $0.16 per share) in both 2009 and 2008, and $249 million (or a quarterly rate of $0.14) in 2007. Common dividends increased from 2007 to 2008 primarily due to the higher quarterly dividend rates.
 
We also paid $5 million of preferred stock dividends in 2008 and $10 million of preferred stock dividends in 2007. The decrease in the preferred dividends in 2008 was due to the redemption of our preferred stock in the second quarter of 2008.
 
Liquidity
 
Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities, as well as our automatically effective registration statement on Form S-3ASR filed with the SEC. This registration statement can be used to offer short-term and long-term debt securities. In 2010, another major source of liquidity will be proceeds from the sales of our offshore operations, which we estimate will range from $4.5 billion to $7.5 billion after taxes. We expect the combination of these sources of capital will be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed later in this section.
 
Operating Cash Flow
 
Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs we produce. Due to sharp declines in commodity prices, our operating cash flow decreased approximately 50% to $4.7 billion in 2009 as compared to 2008. In spite of the recent commodity price declines, we expect operating cash flow will continue to be a primary source of liquidity, and we will need to manage our capital expenditures and other cash uses accordingly. However, as a result of depressed commodity prices, debt borrowings have been a significant source of liquidity during 2009. During 2009, our net borrowings of long-term debt and commercial paper totaled $1.6 billion. We anticipate utilizing commercial paper borrowings as needed to supplement operating cash flow in 2010. As the offshore divestiture transactions close, we anticipate using a portion of the proceeds to repay our commercial paper borrowings.


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Commodity Prices — Prices for oil, gas and NGLs are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in oil, gas and NGL prices and are beyond our control. We expect this volatility to continue throughout 2010.
 
To mitigate some of the risk inherent in prices, we have utilized various price swap, fixed-price physical delivery and price collar contracts to set minimum and maximum prices on our 2010 production. As of February 15, 2010 approximately 65% of our estimated 2010 oil production is subject to price collars and approximately 54% of our estimated 2010 gas production is subject to price collars, price swaps and fixed-price physicals. We also have basis swaps associated with 0.2 Bcf per day of our 2010 gas production.
 
Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases, as experienced in recent years, can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow. However, the inverse is also true during periods of depressed commodity prices such as what we are currently experiencing.
 
Interest Rates — Our operating cash flow can also be sensitive to interest rate fluctuations. As of February 15, 2010, we had total debt of $7.1 billion with an overall weighted average borrowing rate of 5.93%. To manage our exposure to interest rate volatility, we have interest rate swap instruments with a total notional amount of $1.85 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, based upon us paying a fixed rate and receiving a floating rate. Including the effects of these swaps, the weighted-average interest rate related to our fixed-rate debt was 5.36% as of February 15, 2010.
 
Credit Losses — Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. We are also exposed to the credit risk of counterparties to our derivative financial contracts as discussed previously in this report.
 
The recent deterioration of the global financial and capital markets, combined with the drop in commodity prices, has increased our credit risk exposure. However, we utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, posting of letters of credit, prepayment requirements and collateral posting requirements.
 
Credit Availability
 
We have two revolving lines of credit and a commercial paper program which we can access to provide liquidity.
 
We have a $2.65 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The maturity date for $2.15 billion of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $0.5 billion 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, we have 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 our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As February 15, 2010, there were no borrowings under the Senior Credit Facility.
 
We also have a $700 million 364-day, syndicated, unsecured revolving senior credit facility (the “Short-Term Facility”) that matures on November 2, 2010. On the maturity date, all amounts outstanding will be due


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and payable at that time. Amounts borrowed under the Short-Term Facility bear interest at various fixed rate options for periods of up to 12 months. Such rates are generally based on LIBOR or the prime rate. As of February 15, 2010, there were no borrowings under the Short-Term Facility.
 
We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $2.85 billion. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility or the Short-Term 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. As of February 15, 2010, we had $1.3 billion of commercial paper debt outstanding at an average rate of 0.25%.
 
The Senior Credit Facility and Short-Term Facility contain only one material financial covenant. This covenant requires our 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, 2009, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2009, as calculated pursuant to the terms of the agreement, was 20.5%.
 
Our access to funds from the Senior Credit Facility and Short-Term Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our credit facilities include covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facilities is not conditioned on the absence of a material adverse effect.
 
The following schedule summarizes the capacity of our credit facilities by maturity date, as well as our available capacity as of February 15, 2010 (in millions).
 
         
 
Senior Credit Facility:
       
April 7, 2012 maturity
  $ 500  
April 7, 2013 maturity
    2,150  
         
Total Senior Credit Facility
    2,650  
Short-Term Facility — November 2, 2010 maturity
    700  
         
Total credit facilities
    3,350  
Less:
       
Outstanding credit facility borrowings
     
Outstanding commercial paper borrowings
    1,257  
Outstanding letters of credit
    88  
         
Total available capacity
  $ 2,005  
         
 
Debt Ratings
 
We receive debt ratings from the major ratings agencies in the United States. In determining our debt ratings, the agencies consider a number of items including, but not limited to, debt levels, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Liquidity, asset quality, cost structure, reserve mix, and commodity pricing levels are also considered by the rating agencies. Our current debt ratings are BBB+ with a stable outlook by both Fitch and Standard & Poor’s, and Baa1 with a stable outlook by Moody’s.


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There are no “rating triggers” in any of our contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs from LIBOR plus 35 basis points to a new rate of LIBOR plus 45 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future. As of December 31, 2009, we were not aware of any potential ratings downgrades being contemplated by the rating agencies.
 
Capital Expenditures
 
Our 2010 capital expenditures are expected to range from $6.0 billion to $6.8 billion, including amounts related to our discontinued operations. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if oil and gas prices fluctuate from current estimates, we could choose to defer a portion of these planned 2010 capital expenditures until later periods, or accelerate capital expenditures planned for periods beyond 2010 to achieve the desired balance between sources and uses of liquidity. The amount and timing of the planned offshore asset divestitures in 2010 could also result in acceleration of capital spending on our North American Onshore opportunities. Based upon current price expectations for 2010 and the commodity hedging contracts we have in place, we anticipate having adequate capital resources to fund our 2010 capital expenditures.
 
Common Stock Repurchase Programs
 
All of our common stock repurchase programs expired on December 31, 2009. None of our programs were extended to 2010.
 
Contractual Obligations
 
A summary of our contractual obligations as of December 31, 2009, is provided in the following table.
 
                                         
    Payments Due by Period  
          Less Than
    1-3
    3-5
    More Than
 
    Total     1 Year     Years     Years     5 Years  
    (In millions)  
 
North American Onshore:
                                       
Debt(1)
  $ 7,267     $ 1,432     $ 2,110     $ 500     $ 3,225  
Interest expense(2)
    4,998       406       666       508       3,418  
Drilling and facility obligations(3)
    1,136       659       395       81       1  
Firm transportation agreements(4)
    1,939       298       508       419       714  
Asset retirement obligations(5)
    1,068       44       115       150       759  
Lease obligations(6)
    347       57       94       49       147  
Other(7)
    518       129       128       57       204  
                                         
Total North American Onshore
    17,273       3,025       4,016       1,764       8,468  
                                         
Offshore:
                                       
Drilling and facility obligations(3)
    2,113       955       775       383        
Asset retirement obligations(5)
    554       51       141       61       301  
Lease obligations(6)
    602       121       182       176       123  
                                         
Total Offshore
    3,269       1,127       1,098       620       424  
                                         
Grand Total
  $ 20,542     $ 4,152     $ 5,114     $ 2,384     $ 8,892  
                                         


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(1) Debt amounts represent scheduled maturities of our debt obligations at December 31, 2009, excluding $12 million of net premiums included in the carrying value of debt.
 
(2) Interest expense related to our fixed-rate debt represents the scheduled cash payments. Interest related to our variable-rate commercial paper borrowings was estimated based upon expected future interest rates as of December 31, 2009.
 
(3) Drilling and facility obligatio